Cluster Level 1,Cluster Level 2,AF,TI,DE,"ID",AB,TC,Z9,U1
Fracture,Natural Fractures,"Taleghani, Arash Dahi; Gonzalez-Chavez, Miguel; Yu, Hao; Asala, Hope",Numerical simulation of hydraulic fracture propagation in naturally fractured formations using the cohesive zone model,Hydraulic fracturing; Cohesive zone model; Fracture intersections; Natural fractures; Complex fracture network; Traction separation law,BARNETT SHALE; STRESS; PRODUCTIVITY; RESERVOIRS; SYSTEMS; IMPACT; JOINTS,"This paper presents an integrated methodology that utilizes the cohesive zone model (CZM) to simulate propagation of hydraulic fractures, and their interactions with pre-existing natural fractures. CZM has the advantage of capturing the non-elastic behavior of shales; usually induced by total organic carbon (TOC) as well as dissimilar mechanical properties of cemented natural fractures. At the intersection of an advancing hydraulic fracture and a stationary natural fracture, the hydraulic fracture may arrest, cross, or divert into a pre-existing natural fracture depending on the rock mechanical properties, magnitude and direction of rock principal stresses, and fracture intersection angle. The activation of natural fractures during hydraulic fracture treatments improves fracture complexity and expands reservoir drainage area, making stimulation treatments more effective. In this work, triaxiality effects are incorporated into the cohesive zone model. Utilizing triaxiality makes the traction separation law (TSL) tied to confining pressure and this ensures a more reliable transition from laboratory test environment to bottomhole conditions. We present a methodology to determine the cohesive properties or TSL characteristics of rock, after performing semicircular bending tests (SCBT). Finite element analysis (FEA) is then used to calibrate the cohesive properties of both rock and natural fractures. The calibrated parameters were utilized in a field-scale FEA to simulate the growth of complex fracture networks. The results show how fracture intersection angle and the nature of cemented materials inside the natural fractures might divert a hydraulic fracture initially propagating in a direction perpendicular to the minimum horizontal stress. The sensitivity analysis of primary parameters such as fluid viscosity, natural fracture distribution, fracture intersection angle, and differential stresses is implemented to provide a better insight into the performance of hydraulic fracturing jobs in naturally fractured reservoirs. Results indicate the importance of nonlinear fracture tip effects as in-situ stress differences increase.",77,79,8
Fracture,Natural Fractures,"Hou, Bing; Zhang, Ruxin; Zeng, Yijin; Fu, Weineng; Muhadasi, Yeerfulati; Chen, Mian",Analysis of hydraulic fracture initiation and propagation in deep shale formation with high horizontal stress difference,Hydraulic fracture; Complex fracture network; Discontinuities; Pump rate; AE monitoring,GAS-RESERVOIRS; BEHAVIOR; ROCK,"Deeply buried shale formations (vertical depth > 3500 m) that are rich in shale gas are abundant in south China. The primary problems in the exploitation of these formations are the relatively small stimulated reservoir volume (SRV) and low production rates in comparison with their shallower counterparts. These issues are attributed to the high fracturing pressure, limited fracture extension because of sand plugging, significant horizontal stress contrast, and discontinuities produced during hydraulic fracturing. To accurately evaluate and improve the SRV in deep shale formations, the mechanism of fracture propagation must be understood and described. In this regard, a series of large-scale true tri-axial experiments with acoustic emission (AE) monitoring were conducted to characterize the fracture initiation and propagation in a selected deep shale formation. It was found that the difficulty in the complex fracture network formation was because the high stress contrast controls the fracture propagation path to generate large main fractures instead of activating discontinuities. The hydraulic fractures initiated either from open-hole positions or stress concentration locations on a wellbore wall that displayed two types of intersection in terms of crossing and deflection. In general, four types of fracture morphologies were identified: transverse fracture, transverse fracture with bedding planes, natural fracture with bedding planes, and transverse fracture with bedding planes and natural fractures. In addition, the horizontal stress contrast, fluid viscosity, pump rate and fracturing procedure on fracture propagation were evaluated for their effect on the resulting SRV. A low-viscosity fluid can activate discontinuities to form a complex fracture network, whereas a high-viscosity fluid is likely to produce large fractures under a high contrast in the horizontal stresses. On the basis of the above-mentioned analyses, a fracturing procedure applying a periodically varying pump rate and shut-in using a low-viscosity fluid was suggested to be an effective approach to enhance the interaction between the hydraulic fractures and discontinuities as well as to increase the fracture length.",58,65,4
Fracture,Natural Fractures,"Sun, Jiaxin; Ning, Fulong; Lei, Hongwu; Gai, Xuerui; Sanchez, Marcelo; Lu, Jingan; Li, Yanlong; Liu, Lele; Liu, Changling; Wu, Nengyou; He, Yong; Wu, Min",Wellbore stability analysis during drilling through marine gas hydrate-bearing sediments in Shenhu area: A case study,Natural gas hydrates; Drilling mud invasion; Wellbore stability; Drilling mud property; Reservoir physical property,METHANE HYDRATE; NUMERICAL-SIMULATION; RESERVOIR DISSOCIATION; MECHANICAL-BEHAVIOR; EAST-COAST; TEST-SITE; MODEL; FLUID; TEMPERATURE; INVASION,"Because of the metastable character of natural gas hydrate-bearing sediments (GHBS), they can be easily affected by drilling operations, thereby inducing the wellbore instability risk. This issue is studied in this paper by means of numerical simulations based on the first exploration well performed in the Shenhu area of the South China Sea in 2007. The corresponding simulated results were compared against the field caliper logging curve. Besides this analysis, the effects of both drilling mud properties (i.e., temperature, density, and salinity) and initial reservoir conditions (i.e., permeability, and saturation) on the wellbore stability were further investigated under the condition of drilling mud invasion into the GHBS. It is anticipated that the coupled multiphysics phenomena triggered under operation conditions can lead to wellbore instability and may also trigger the formation of fractures. The simulation results show that the predicted yield region around the borehole of well SH2 conforms to the borehole enlargement observed in the field. The sensitivity analyses indicate that a local increase in the pore pressure is likely to be generated in the wellbore vicinity, triggered by the large amount of free gas to be released during hydrate dissociation, which is in turn induced by heating (i.e., coming from the drilling-friction effects) and the high salinity of the drilling muds typically used. This study shows that by engineering the salinity of the drilling mud, the amount of free gas to be produced from marine GHBS can be controlled, preventing in this way further wellbore instability issues. This research also shows that an increase in the drilling-mud density not only impact on the development of pore pressures near the borehole, but it also affects the extent of drilling-mud invasion. This effect will extend the hydrate dissociation to a wider area and will also reduce the resistance of the formation, leading to further deformation and potential failure. The analyses also show that the increase in the initial hydrate saturation is associated with a stronger sediment and a more stable wellbore. The model also predicts that GHBS with higher absolute permeability will dissipate faster the excess of pore pressure in the surrounding sediment, contributing to wellbore stability; however, the extent of the hydrate dissociation zone will expand and thereby will increase the yield region.",49,54,11
Fracture,Natural Fractures,"Jia, Bao; Tsau, Jyun-Syung; Barati, Reza","Role of molecular diffusion in heterogeneous, naturally fractured shale reservoirs during CO2 huff-n-puff",Bakken shale reservoirs; Molecular diffusion; Heterogeneity; Correlation length; CO2 huff-n-puff,OIL; INJECTION; RECOVERY,"Shale reservoirs are characterized by high degree of heterogeneity and ultra-low matrix permeability. Natural fracture (both macro and micro) systems are important to increase the performance of shale reservoirs by providing flow path for the hydrocarbon from the nanopores in the matrix to the wellbore. Configurations of natural fractures also have significant implications for the recovery performance of shale gas and oil reservoirs. CO2 huff-n-puff or cyclic injection has been suggested to be a feasible way to recover oil from shales and the flow process is complex. Molecular diffusion is an important transport mechanism of the mixture of CO2 and oil, especially in tight formations. Based on these knowledge, various configurations of the natural fracture system in shale reservoirs with the dual porosity and dual permeability model were constructed, regarding Dykstra-Parsons (DP) coefficient and correlation length. Dykstra-Parson (DP) coefficient ranges from 0.40 to 0.78, and correlation length ranges from 50 ft to 3000 ft. Based on the geological setting of the Middle Bakken formation and the Bakken live oil PVT data, compositional models were performed to simulate the CO2 huff-n-puff process. CO2 injection begins after the primary recovery factor reaches 3% and both multiple-cycle and single-cycle of injection were investigated regarding the oil recovery performance and CO2 injectivity behavior. In the multiple-cycle scheme the period of one cycle is short; the injection, soak and production time are 10 days, 10 days and 100 days, respectively. In the single-cycle scheme, the period of one cycle is long, and gas injection volume is set to be constant with the soak time of 100 days. The impact of molecular diffusion during the huff-n-puff process is compared in different simulation scenarios. Findings in this work reveal the importance of the configuration of the pre-existing natural fracture system for the performance of the huff-n-puff process. Reservoir heterogeneity hampers primary production. However, during the puff production process, the negative impact of heterogeneity is less as the correlation length increases when the molecular diffusion is taken into account. There exists a threshold correlation length value wherein heterogeneity becomes favorable for improved oil recovery instead of hampering oil recovery, after taking into account of the molecular diffusion, which is approximately 1500 ft in this simulation study. The value of correlation length also affects the performance of multiple-cycle and single-cycle huff-n-puff processes differently because CO2 injectivity behavior is different in reservoirs characterized by different DP coefficients and correlation length: there exists a threshold time point when a longer correlation length begins to favor the injectivity, and the threshold time point is delayed for a scenario with a larger DP coefficient.",41,42,2
Fracture,Natural Fractures,"Zhou, Dawei; Zhang, Guangqing; Zhao, Pengyun; Wang, Yuanyuan; Xu, Shengfan",Effects of post-instability induced by supercritical CO2 phase change on fracture dynamic propagation,Supercritical CO2 fracturing; Phase change; Post-instability; Equilibrium energy model; Fracture propagation coefficient,CARBON-DIOXIDE; GAS; FLUID; SHALE; WATER; STIMULATION; PRESSURE,"The effects of non-aqueous fracturing on unconventional reservoir stimulation have been investigated by laboratory and field work. Supercritical carbon dioxide (SC-CO2) is a notable non-aqueous fracturing fluid due to its potential to increase production, to reduce water requirements, and to minimize environmental impacts. In this paper, laboratory experiments conducted on polymethyl methacrylate (PMMA) are used to study the post-instability induced by SC-CO2 phase change on fracture dynamic propagation. Experimental results show that the fracture propagating speed of SC-CO2 fracturing is two order greater than that of hydraulic fracturing, and extensive hackle fractures occur in SC-CO2 fracturing. SC-CO2 phase change are mainly responsible for fracture post-instability, which dominates fracture propagation in SC-CO2 fracturing. Meanwhile, an equilibrium energy model of fracture dynamic propagation is proposed to describe the energy variation and transformation in porous medium. The concept of fracture propagation coefficient, i.e., the ratio of energy supplied by injection to fracture energy, is defined. SC-CO2 fracture propagation coefficient is much larger compared to hydraulic fracturing, suggesting that enough kinetic energy can accelerate fracture growth. This research may contribute to field application that SC-CO2 fracturing is likely to be an effective stimulation treatment, even in reservoir of undeveloped natural fractures.",34,35,4
Fracture,Natural Fractures,"Chen, Zhiqiang; Yang, Zhengming; Wang, Moran",Hydro-mechanical coupled mechanisms of hydraulic fracture propagation in rocks with cemented natural fractures,Hydraulic fracture; Cemented fracture; Natural fracture; LBM-DEM,LATTICE-BOLTZMANN METHOD; GENERAL SHAPES; BARNETT SHALE; FLUID-FLOW; PERMEABILITY; MODEL; DISCONTINUITIES; CRITERION,"Natural fractures commonly exist in unconventional reservoirs such as shale and tight gas sandstone, which are mostly cemented (or sealed) with minerals and not able to contribute to reservoir storage or rock permeability. However, during hydraulic fracture stimulation, these cemented natural fractures will be encountered and influence hydraulic fracture geometry greatly and, thereby, gas production. In this work, hydraulic fracture propagation in rock with cemented natural fracture is investigated using our recently developed and validated hydromechanical coupled LBM-DEM model. The numerical results show that both the strength ratio (between cemented natural fracture and host rock) and the approach angle (between hydraulic and cemented natural fracture) significantly affect the hydraulic fracture propagation. A larger strength contrast or a smaller approach angle will be more conducive to deflection, which is consistent with experimental observation. For rocks with weakly cemented natural fractures, deflection is mainly caused by shear failure in weakly cemented fracture. However, for rocks with strongly cemented natural fractures, deflection happens accompanying with tensile failure in host rock along the cement wall, which cannot be captured by the previous numerical models where the cemented natural fracture is treated as a bonded interface. In addition, complex fracture network is more easily formed if multiple weakly cemented natural fractures are orthogonal to the hydraulic fracture propagation direction.",31,32,3
Fracture,Natural Fractures,"Wang, Weiwei; Olson, Jon E.; Prodanovic, Masa; Schultz, Richard A.",Interaction between cemented natural fractures and hydraulic fractures assessed by experiments and numerical simulations,Hydraulic fracturing; Cemented natural fractures; Fracture; Fracture interaction; Semi-circular bend experiment,ROCK; PROPAGATION; SHALE; INTERFACES; SPECIMEN; MODE; DISCONTINUITIES; BRITTLE; BASIN; VEINS,"Microseismic events suggest that a complicated fracture network develops during hydraulic fracturing treatment in many naturally fractured unconventional reservoirs. One reason for the complexity is the deformation along weak planes such as faults and cemented natural fractures. The interaction of cemented natural fractures with hydraulic fractures generated as part of reservoir stimulation may impede or terminate hydraulic fracture propagation, which depends on several factors such as interfacial bond strength between the cemented natural fractures and the reservoir rock. Most previous studies treat natural fractures as interfaces without considering their thickness. In this study, the semi-circular bend (SCB) tests for specimens with heterogeneity are used to study the fracture-fracture interactions, because the tensile fracture in the SCB test is analogous to the induced hydraulic fracture. With simple experimental setup and good repeatability, the SCB test results provide insights into real hydraulic fracture propagation behavior in naturally fractured reservoirs. We analyze the effects of natural fracture thickness and rock-cement interfacial bond strength, which are not commonly considered. Results show that hydraulic fracture crossing/diverting behavior depends on the approach angle, the rock-cement interfacial bond strength, and the thickness of natural fracture. Results also imply that as hydraulic fractures approach cemented natural fractures, the hydraulic fracture near. tip stress state is influenced by the tensile and shear strength of the rock-cement interface. In the SCB test, the sample geometry induces shearing along the cemented natural fracture-rock interface, analogous to a frictionally slipping interface in the subsurface. Depending on the frictional strength and the approach angle, the interface may crack apart, and attract a propagating fracture.",30,31,12
Fracture,Natural Fractures,"Ren, Lan; Lin, Ran; Zhao, Jinzhou; Rasouli, Vamegh; Zhao, Jiangyu; Yang, Hao",Stimulated reservoir volume estimation for shale gas fracturing: Mechanism and modeling approach,Hydraulic fracturing; Stimulated reservoir volume; Fractures propagation; Shale gas; Mathematical model,HYDRAULIC FRACTURE; HORIZONTAL WELL; PROPAGATION; PERMEABILITY,"Multi-stage fracturing, following horizontal well drilling, is the key technology in shale gas reservoir development to enhance the recovery from such tight formations for economic production. The stimulated reservoir volume (SRV), which correlates closely to fracturing performance, is a quantitative measure for both pre-fracturing design and post-fracturing evaluation. However, an accurate estimation of the SRV is a long-standing challenge, because it requires a great knowledge of various parameters and complex mechanisms. In this study, we developed a mathematical model to estimate the SRV through simulating the main process during shale fracturing-multiple simultaneous hydraulic fractures propagate, perturbing the formation stress and raising the reservoir pressure; meanwhile, the stress change and pressure rise may jointly make natural fractures occur failure, and the SRV is estimated based on the volume of the naturally fractured zone that experiences tensile or shear failure. Hybrid numerical methods have been employed in this study. It applies displacement discontinuity method (DDM) to simulate non-planar hydraulic fractures propagation and represent the induced stress triggered by hydraulic fractures. The reservoir pressure is calculated by finite difference method (FDM). The failure state of natural fractures is predicted by the tensor equations deduced from Warpinski's failure theory. The model considers complex but important physical mechanisms that involved in the shale fracturing, including unequal flowrate distribution among each hydraulic fracture, non-planar hydraulic fractures propagation under stress interference, reservoir permeability increase with SRV extending (pressure & stress-depend), different failure states of natural fractures, etc. We validated our model by comparing its simulation results with analytical solution, published papers and onsite microseismic monitoring data. A field case study was performed to show the dynamic processes of hydraulic fractures propagation, reservoir permeability increase, and the SRV expansion during shale gas fracturing. Sensitivity analysis was conducted to investigate the influence of geological condition and fracturing parameters on SRV.",29,30,3
Fracture,Natural Fractures,"Wang, Xinghua; Ding, Wenlong; Cui, Long; Wang, Ruyue; He, Jianhua; Li, Ang; Gu, Yang; Liu, Jingshou; Xiao, Zikang; Fu, Fuquan","The developmental characteristics of natural fractures and their significance for reservoirs in the Cambrian Niutitang marine shale of the Sangzhi block, southern China",Sangzhi block; Niutitang Shale; Natural fracture; Characteristics; Controlling factors,ORGANIC-RICH SHALE; CENGONG BLOCK; NUMERICAL-SIMULATION; DOMINANT FACTORS; BASIN,"The great potential that southern China has for marine shale gas resources is well known, yet shale gas production is very small. Exploration and development of southern China has lagged because of the complicated structural history of this region. Thus, it is important to recognize the tectonic history of this region and to carefully describe the developmental characteristics of natural fractures associated with the tectonic evolution of southern China. In this paper, we discuss the developmental characteristics of natural fractures based on the description and statistical analysis of natural fractures in outcrops, cores and thin sections, and from several experimental tests. Fractures examined in outcrop appear to be principally fold-fault related, regional tectonic, bedding or weathering fractures. Fractures observed in core are mainly shear fractures, tension fractures, and shear-tension fractures. Most of these fractures are sealed by calcite. Micro fractures and pores are well developed. Analysis of the crosscutting relation of micro fractures suggests that the study area has been subject to at least two tectonic movements, consistent with our investigation of core. Fracture development appears to have been strongly influenced by structural evolution. However, fracture density displays a weak negative correlation with organic matter content. Further, fracture density appears to correlate positively with quartz content. Vertical variations of mineralogy appear to have influenced fracture generation and, therefore, hydrocarbon migration within the Niutitang Shale.",29,29,0
Fracture,Natural Fractures,"Zhao, Zhiheng; Li, Xiao; He, Jianming; Mao, Tianqiao; Zheng, Bo; Li, Guanfang",A laboratory investigation of fracture propagation induced by supercritical carbon dioxide fracturing in continental shale with interbeds,Continental shale; Supercritical carbon dioxide fracturing; Stress; Interbed; Fracture propagation; Fracture quantification,,"Supercritical carbon dioxide (SC-CO2) used as a fracturing fluid in the shale fracturing stimulation is a promising technology as it can save much water and have some particular properties, such as low surface tension, large diffusion coefficient, strong permeable ability and adsorption capacity in shale. In previous studies, SC-CO2 fracturing presents great advantages in marine shale, granite and tuff. In this work, continental shale with interbeds from the Ordos Basin, China was used to conduct SC-CO2 fracturing experiments under the different stress conditions. Based on the observation of visible fractures before and after experiments, the fractures on the surface mainly propagate along natural fractures, bedding planes and interbeds, where crossing beddings and interbeds can also be observed. Besides, according to visualization and quantification of the main fractures and the main fracture surfaces by electronic microscope and three-dimensional scanner, with the increase in the stress difference, the main fracture can easily cross shale beddings and interbeds, and partial vertical fractures are formed, so tortuosity of the main fracture and roughness of the main fracture surface tend to increase. Furthermore, four main types of interactions between the main fracture and the fracture branch are obtained and the number of the fracture branches induced by the SC-CO2 fracturing is generally larger than that induced by the water fracturing. Meanwhile, compared with the water fracturing, it is implied that the breakdown pressure of SC-CO2 is generally lower, and its tortuosity of the main fracture and roughness of the main fracture surface tend to be higher under the same experimental conditions. Therefore, more curved and wavelike fractures with more branches can be generated in the continental shale SC-CO2 fracturing.",28,30,6
Fracture,Natural Fractures,"Liu, Jun; Yao, Yanbin; Liu, Dameng; Xu, Lulu; Elsworth, Derek; Huang, Saipeng; Luo, Wanjing","Experimental simulation of the hydraulic fracture propagation in an anthracite coal reservoir in the southern Qinshui basin, China",Coalbed methane; Anthracite coal; Hydraulic fracture propagation; Reservoir stimulation; Qinshui basin,ROCK STRESS ESTIMATION; NUMERICAL-SIMULATION; METHANE RESERVOIR; SHALE RESERVOIRS; STIMULATION; PREDICTION; BEHAVIOR; VOLUME,"As coalbed methane (CBM) reservoirs have extremely low permeability, hydraulic fracturing is a common stimulation process for enhancing the CBM production. An in-depth understanding about the propagation mechanism of hydraulic fractures in coal is important for designing a hydraulic fracturing process and thus for improving the CBM production. This study performed a set of true tri-axial fracturing experiments on six block samples (300 mm x 300 mm x 300 mm, including raw coal and artificial roof/floor) with consideration of in situ conditions, aiming at simulating the propagation of hydraulic fractures in the CBM reservoir in the Changzhi field, southern Qinshui basin. Four groups of experiments were organized to evaluate the influences from the pre-existing natural fracture, in situ stresses and injection flow rates on the hydraulic fracture propagation. Meanwhile, five series of numerical simulations were constructed to model the relationship between in situ horizontal stresses and hydraulic fracture propagation. The results show that the hydraulic fracture propagates only along the pre-existing natural fracture direction under a small approaching angle, while it propagates along both the directions of the pre-existing natural fracture and the maximum horizontal principal stress (sigma < SUB > H < /SUB >) under a large approaching angle. Whether pre-existing natural fractures exist or not can result in a distinct influence on hydraulic fracture propagation. Hydraulic fractures straightly propagate along the sigma < SUB > H < /SUB > direction under a high value of horizontal stresses difference coefficient (K-h), while they tend to deviate from the sigma < SUB > H < /SUB > direction under a low K-h value. The influence of K-h is greater than that of the horizontal stresses difference (Delta sigma) in determining fracture propagation to extend along the sigma < SUB > H < /SUB > direction in the coal seam. Large approaching angle, high in situ stresses and a high injection flow rate are three major factors to cause the roof/floor broken by hydraulic fluids.",28,30,5
Fracture,Natural Fractures,"Chai, Z.; Yan, B.; Killough, J. E.; Wang, Y.",An efficient method for fractured shale reservoir history matching: The embedded discrete fracture multi-continuum approach,Fractured reservoir; EDFM; History matching; Uncertainty quantification; Neural network,,"In this study, we established a more efficient approach for fractured shale reservoir modeling with an emphasis on simplifying and automating the workflow for assisted history matching and uncertainty quantification. The improvement is especially notable for the process of history matching since the fracture geometry and properties can be directly set as parameters to be history matched. The resultant approach not only shows a significant reduction in the computational time while maintaining model accuracy, but also provides an automatic method for modifying the fracture related parameters - a laborious process in the traditional workflow. In the forward reservoir model, we implemented and extended the Embedded Discrete Fracture Model (Embedded DFM) approach for fractures with arbitrary strike and dip angle to a multiple porosity/permeability setting. The fractures are naturally discretized by the boundary of parent matrix grid blocks. Control volumes of fracture segments are generated according to the specific geometry of each of the segments. Three types of non-neighbor connections are then generated, namely the connection between the fracture segment and its parent matrix grid blocks, the connection between two intersecting fracture segments from different fractures, and the connection between two neighbor fracture segments from the same fracture. For each of the non-neighbor connections, transmissibility can be calculated honoring the physics of the flow. In our approach with Embedded Discrete Fracture Multiple-Porosity Model, the matrix is sub-divided into three porosity types, namely organic matrix (kerogen), inorganic matrix and natural fractures, with the necessary physics included for each of the porosity types. The macro fractures are explicitly represented with Embedded DFM. The proposed model provides a coherent method for characterizing the organic matrix, inorganic matrix, micro fractures as well as the hydraulic fractures of shale reservoirs. It offers a computationally efficient approach for modeling the severe heterogeneity due to hydraulic and natural fractures. Compared with traditional discrete fracture models, fewer grid blocks and lower levels of refinement are required. Compared with multiple porosity method, the proposed model has desirable accuracy for the simulation of reservoirs with large scale fractures. In the history matching and uncertainty quantification stage, due to the low efficiency of traditional Markov Chain Monte Carlo (MCMC) method when applied to reservoir history matching, a more advanced algorithm of two-stage MCMC is employed to evaluate the uncertainty for all the parameters. Since no upscaling of the fracture related parameters is required, the reservoir model can be generated by a pre-processor based on the proposed parameter, which maintains the adequacy of a Gaussian distribution assumption. Therefore, the workflow can be completely automated. By incorporating Embedded DFM and multiple porosity/permeability approaches, the improved model facilitates the history matching of fractured shale reservoirs by cutting the total amount of grid blocks, reducing the complexity of the gridding process, as well as improving the accuracy of fluid transportation within and among different porosity types.",28,28,1
Fracture,Natural Fractures,"Teklu, Tadesse Weldu; Li, Xiaopeng; Zhou, Zhou; Alharthy, Najeeb; Wang, Lei; Abass, Hazim",Low-salinity water and surfactants for hydraulic fracturing and EOR of shales,Low-salinity water; Low-salinity water plus srufactnat; Osmosis; Capillary pressure; Wettability alteration; IFT decrease; Hydraulic fracturing and EOR of shales,OIL-RECOVERY; UNCONVENTIONAL RESERVOIRS; IMBIBITION; WETTABILITY; TRANSPORT,"There are significant recoverable oil and gas resources stored in shale reservoirs throughout the world. Horizontal well with multistage hydraulic fracturing is an enabling technology for economic production of these shale resources. Recovery factors of liquid rich shale reservoirs is typically less than 10%, hence, there is an incentive for implementing enhanced oil recovery (EOR) technologies to improve oil production from these very tight reservoirs. Brine, chemical (surfactant), gas, or combination of these fluids imbibition or injection in huff-n-puff scenario could improve oil recovery of liquid rich shale reservoirs. In this study, low-salinity water and low-salinity water + surfactant imbibition are assessed as both hydraulic fracturing and EOR fluids in liquid rich shale reservoirs. Osmosis, capillary pressure, wettability alteration, and other effects are among the mechanisms by which these fluids can improve oil recovery from shale reservoirs. These favorable effects were investigated through imbibition experiments. Experiments show: (a) low-salinity water huff-n-puff in tight formations can improve oil production from tight formations. This is because wettability alteration, capillary, and osmotic forces; (b) surfactant + low-salinity-water huff-n-puff can further improve oil production due to additional IFT decrease and wettability alteration by surfactants; hence, improve oil production from stimulated ultra-tight formations. Based on experimental observations and literature reviewed, low-salinity water huff-n-puff (until economical), followed by low-salinity water + surfactant huff-n-puff EOR process is recommended to optimize production from liquid rich shale reservoirs, while minimizing cost. These fluids can be used to reduce matrix-fracture skin damage. The effectiveness of these hydraulic fracturing and EOR fluids in shales is highly dependent on the existence and extent of natural fractures or laminations within the stimulated reservoir volume; this is because osmosis and diffusion are very slow processes.",27,29,7
Fracture,Natural Fractures,"Sheng, Mao; Li, Gensheng; Sutula, Danas; Tian, Shouceng; Bordas, Stephane P. A.",XFEM modeling of multistage hydraulic fracturing in anisotropic shale formations,Hydraulic fracturing; Crack propagation; Shale; Extended finite element method,EXTENDED FINITE-ELEMENT; DEFORMABLE POROUS-MEDIA; CRACK-GROWTH; FLUID-FLOW; PROPAGATION; ENRICHMENT; SIMULATION; SCHEMES; SOLIDS,"The aim of the present study is to help understand hydraulic fracture propagation in shale formations through numerical simulations. The hydraulic fracture propagation regime in shale is analyzed considering the anisotropic nature of the shale rock formation and slick-water fracturing fluid. It is determined that the dominant mechanism of hydraulic fracture propagation is the so-called transitional regime that is characterized by a negligibly small fluid lag region and zero fluid front pressure. For the modeling of the hydraulic fracture evolution over time, we assume orthotropic linear-elastic rock media and that the flow of the fracturing fluid is governed by the Reynold's lubrication equation. For the discretization of the coupled solid-fluid equations within the 2D plane-strain context we use the extended finite element method for the rock media and the finite volume method for the lubrication equation. The problem of the hydraulic fracture evolution over time is modeled as stable quasi-static crack growth where time is the result of upholding the mass conservation principle between the fluid inflow and the crack volume. The Picard iterative approach is used to solve the discrete non-linearly coupled solid-fluid equations. Our model is verified against several analytical solutions. Subsequently, a five-stage hydraulic fracturing problem is simulated to study the interactions between the different fractures. Results show that the on-going hydraulic fractures are attracted by the pre-existing hydraulic fractures as a result of the change of the local stress field relative to the initial in-situ stress field. For the cases considered, fracture deflections are found to be most extensive with decreasing fracture spacing and in-situ stress difference, but insensitive with the increasing the ratio of Young's moduli.",27,27,4
Fracture,Natural Fractures,"Wu, Xiaoguang; Huang, Zhongwei; Li, Gensheng; Li, Ran; Yan, Pengsen; Deng, Xiao; Mu, Kaiwen; Dai, Xianwei",Experiment on coal breaking with cryogenic nitrogen jet,Liquid nitrogen; Jet; Coal breaking; Coal bed methane; Drilling,LIQUID-NITROGEN; METALLIC SURFACES; VELOCITY; STIMULATION; IMPINGEMENT; TECHNOLOGY; IMPACT; ROCKS; WELLS,"Severe leakage of drilling fluid and reservoir damage due to water and solid invasion during well drilling are the key factors that restrict economic exploitation of coal bed methane (CBM) in China. To solve these issues, this paper presents a method of CBM well drilling with the assistance of cryogenic nitrogen jet, in which no aqueous phase and solid phase are contained. To determine the feasibility of coal breaking by cryogenic nitrogen jet and the effects of different parameters, such as nozzle diameter, dimensionless standoff distance, nozzle pressure difference and exposure time, we conducted corresponding rock breaking experiments on artificial and natural coals with the cryogenic nitrogen jet and the water jet. Rock breaking features and the energy consumption by the two jets were compared. The results indicate that the cryogenic nitrogen jet has better rock breaking performances and consumes less energy. Under the same conditions, the average rock erosion volume and the energy consumption with the cryogenic nitrogen jet were 18.34 times larger and 90.8% lower than those with water jet, respectively. Visible netted fractures could be created on the surface of coal samples blasted with the cryogenic nitrogen jet, and thus rock breaking could be facilitated effectively. The outstanding rock breaking performances of cryogenic nitrogen jet are attributed to three mechanisms: high-velocity jet impact, thermal shock and gasification cracking effect. In addition, under our experimental conditions, the erosion volume and depth were proportional to the pressure difference and inversely proportional to the dimensionless standoff distance. When the nozzle diameter changed from 1.5 mm to 3 mm, the increases of erosion volume were 3% at the pressure difference of 5 MPa and 41.7% at the pressure difference of 10 MPa respectively. This indicates that the effect of nozzle diameter is more significant at relatively higher pressure drops. With the increase of exposure time, both of the rock erosion depth and volume rose, while with a smoother trend. The results of this study are expected to promote the application of cryogenic nitrogen jet in CBM well drilling.",27,31,3
Fracture,Natural Fractures,"Ghaderi, Amir; Taheri-Shakib, Jaber; Nik, Mohammad Amin Sharif",The distinct element method (DEM) and the extended finite element method (XFEM) application for analysis of interaction between hydraulic and natural fractures,Hydraulic fracture; Natural fractures; Production; Debonding; Shear failure; Tensile failure,MECHANICS MODEL; FLUID-FLOW; SIMULATION; PROPAGATION; JOINTS; ROCKS,"Hydraulic fracturing can be considered one of the most effective stimulation methods for fractured network formation. The interaction between induced and natural fractures greatly affects the success of the treatment. In this paper, the extended finite element method (XFEM) and distinct element method (DEM) have been combined to identify the propagation of hydraulic fractures in a porous medium with naturally fractured blocks. DEM is used to investigate hydraulic fractures in a natural-fracture network and evaluate the production flow rate under different apertures and lengths of hydraulic fracture. XFEM is used to simulate the deformation of the natural-fracture interface during the approaching phase of induced fractures as a no-remeshing tool. The results of DEM reveal that length of hydraulic fracturing has a significantly greater effect on production than aperture. Results from XFEM show that tensile and shear debonding of natural fractures change as a function of angle and distance from an induced fracture.",26,27,3
Fracture,Natural Fractures,"Hu, Yuqi; Weijermars, Ruud; Zuo, Lihua; Yu, Wei",Benchmarking EUR estimates for hydraulically fractured wells with and without fracture hits using various DCA methods,Production forecasting; EUR estimates; Modified Hyperbolic Decline Model; Duong model; Logistic Growth Analysis Model; Power Law Exponential,SHALE GAS-RESERVOIRS,"Various decline curve analysis (DCA) methods can be applied to forecast the production performance of hydrocarbon wells, including horizontal wells stimulated with hydraulic fracturing. Yet, which method is more preferable remains in doubt. The objective of this study is to evaluate various DCA methods by history matching and hindcasting both synthetic and field production data in order to assess for each method the reliability of production forecasts and the estimated ultimate recovery (EUR). Five DCA methods have been evaluated because of their computational simplicity and broad application. These methods are the Modified Hyperbolic Decline model (MHD), Duong model, Logistic Growth Analysis Model (LGM), and the Power Law Exponential (PLE, with D-infinity = 0 and D-infinity = 8) Decline models. Each method was evaluated using three data sets: synthetic shale oil production rates based on a CMG reservoir model using Eagle Ford reservoir characteristics, data from producing Eagle Ford wells and from Austin Chalk wells. The hindcast method was applied to the Eagle Ford synthetic wells to establish the EUR deviation between the synthetic reservoir model production forecast and the various DCA methods. The weighted residuals of history matched production rates for Eagle Ford indicate that the MHD and Duong models give the lowest matching errors (as low as 1.32%) and the highest EUR estimations (as high as 3,447,609 stb). The PLE model (with D-infinity not equal 0) gives the most conservative EUR estimation, and also the least reliable history matching method (on our Eagle Ford data sets), which therefore is the least preferable DCA method. For the Austin Chalk wells in our study, all methods generate fairly similar EUR predictions with similar matching errors (from 13% to 15%) so that the DCA method preference becomes indifferent. This study also touches upon the relationship between DCA results when well interference occurs due to various hydraulic fracture hits. Shale wells that primarily contain hydraulic fractures and few natural fractures (Eagle Ford) give the most reliable forecasts using the MHD and Duong DCA methods. However, wells in the Austin Chalk, a naturally fractured reservoir, show little difference between the forecast accuracy from the various DCA methods.",25,28,0
Fracture,Natural Fractures,"AlTwaijri, Mohammad; Xia, Zhaohui; Yu, Wei; Qu, Liangchao; Hu, Yunpeng; Xu, Yifei; Sepehrnoori, Kamy",Numerical study of complex fracture geometry effect on two-phase performance of shale-gas wells using the fast EDFM method,Shale gas; Complex fractures; Natural fractures; Two-phase flow; Water flowback,WATER; SIMULATION; TRANSPORT; RESERVOIR; MODEL; FLOWBACK; OIL,"Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced ( hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of local grid refinement approach, hydraulic fractures are assumed to be planar ( orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational resources. In this paper, we introduce an embedded discrete fracture model (EDFM) to explicitly model complex fracture geometries. The EDFM efficient approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, we constructed a 3D reservoir model to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In our investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set of natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of nonorthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells.",23,23,3
Fracture,Natural Fractures,"Wang, HanYi; Sharma, Mukul M.",Modeling of hydraulic fracture closure on proppants with proppant settling,Hydraulic fracture; Fracture closure; Proppant transport; Proppants settlement; Proppant dune; Stress amplification,SHALE-GAS-PRODUCTION; CONDUCTIVITY; PROPAGATION; SYSTEMS; EMBEDMENT; TRANSPORT; DESIGN; ROCKS; WIDTH,"The placement of proppants in a hydraulic fracture is governed by slurry flow, proppant transport and settlement. The proppant distribution can significantly affect the conductivity of the hydraulic fracture, and hence will impact the productivity of hydraulic fractured wells. Past studies have investigated fracture closure on proppants by envisioning hydraulic fractures as two parallel plates with uniformly distributed proppants. However, in reality, hydraulically induced fractures are wider in the middle and narrower near the fracture edges. In addition, a proppant dune is likely to be accumulated at the bottom of the fracture because of proppant settling. As a result, fracture closure on proppants is controlled by both fracture geometry and the distribution of proppant in the fracture. This is a dynamic process where fracture geometry and the proppant pack will evolve as a function of pressure, and the associated surface contact problem is notoriously challenging to solve because of its non-linear and nonlocal nature. In this study, we proposed a general approach to model hydraulic fracture closure. The residual fracture width profile for both propped and un-propped sections can be obtained at different drawdown pressures for rocks with different clay content. The maximum stress acting on proppants can be calculated to guide the selection of proppants with appropriate strength. Most importantly, the effect of stress concentration and stress amplification can be quantified when a proppant dune or bank is formed. We also show that the traditional method of estimating the maximum stress on a proppant pack is an underestimation.",23,23,2
Fracture,Natural Fractures,"Wang, HanYi",Discrete fracture networks modeling of shale gas production and revisit rate transient analysis in heterogeneous fractured reservoirs,Discrete fracture network (DFN); Shale gas production; Rate transient analysis (RTA); Complex fracture networks; Naturally fractured reservoirs; Heterogeneous reservoirs,WELL PRODUCTION; LINEAR FLOW; PERMEABILITY; SLIPPAGE; BEHAVIOR; IMPACT,"Horizontal wells with multiple hydraulic fractures are necessary stimulation technique for economically developing tight and shale gas reservoirs. In such reservoirs, the conventional well-test techniques are not suitable because of ultralow formation permeability. Rate transient analysis (RTA) is the widely used tool for analyzing these reservoirs for the purpose of reserves estimation, hydraulic fracture stimulation optimization, and development planning. However, the conventional rate transient analysis is based on the models that were derived from idealistic assumptions for homogenous reservoirs. In this article, we first review the industry's common practice for rate transient analysis and discuss why the idealized conceptual model may not be adequate for analyzing production data from shale gas reservoirs. Then, a unified shale gas reservoir model based on Discrete Fracture Networks (DFN) is presented to investigate how each mechanism influences shale gas production and the corresponding rate transient behavior. It is found that shale gas production and rate transient behavior are significantly impacted by reservoir heterogeneity, fracture networks, non-Darcy flow, gas adsorption and completion efficiency. Short early-time linear flow with long transitional flow period is an indication of either existence of abundant complex fracture networks or heterogeneous completion with unevenly distributed hydraulic fractures. Consider the nature of non-unique results of RTA, information from other independent sources is required to achieve a consistent and holistic interpretation.",23,23,2
Fracture,Natural Fractures,"Luo, Zhifeng; Zhang, Nanlin; Zhao, Liqiang; Yao, Liming; Liu, Fei",Seepage-stress coupling mechanism for intersections between hydraulic fractures and natural fractures,Hydraulic fracturing; Natural fracture; Seepage-stress coupling; Staged fracturing; Extended finite element method; Stress shadow effect,PROPAGATION; CRITERION,"Most unconventional oil and gas reservoirs contain some natural fractures, which play an essential role during reservoir reconstruction. Given the strong discontinuities in the displacement on both sides of the fracture as well as weak discontinuities in the pore fluid pressure, a novel three-dimensional seepage-stress coupling model using extended finite element method is proposed for fractured reservoirs. This directly coupled scheme for displacement field and stress field avoids the cumbersome process during calculating the fluid pressure in complicated fracture networks and translating into equivalent nodal force. Numerical examples are presented to simulate the fracture propagation pathway during the laboratory experiment on the staged synchronous fracturing of a horizontal well, revealing the deformation response and interaction mechanism between hydraulic fractures and natural fractures at orthotropic and non-orthotropic angles. The results show that due to the stress shadow effects, a non-planar fracture deflecting to wellbore would be formed during the progress of staged synchronous fracturing for a horizontal well. Moreover, the adjacent section to the intersection is opened and the others are closed for orthogonal natural fracture. In contrast, the non-orthogonal natural fracture is activated near the intersection at first and then fully opens as time increases; eventually, it is in the tensile-shear and composite state. In other words, the hydraulic fracture tends to traverse the orthogonal natural fracture and continue to propagate, as it is more easily arrested by the oblique natural fracture and transferred to propagation.",22,23,2
Fracture,Natural Fractures,"Nath, Fatick; Mokhtari, Mehdi",Optical visualization of strain development and fracture propagation in laminated rocks,Laminated formations; Fracture propagation; Full-field strain development; Fracture pattern; Indirect tensile test; Digital image correlation,ANISOTROPY; FAILURE; VELOCITY,"Shales are commonly anisotropic in nature due to layering and natural fractures which consequently impact the m0echanical behavior of shale in terms of stress-strain distribution, fracture initiation, propagation and fracture pattern. The classical method of strain measurement with strain gauges can not reveal the complex process of strain accumulation and fracture propagation in such anisotropic rocks. Therefore, we applied optical techniques along with image processing to measure strain on the surface of laminated Green River shale samples with various lamination angles under indirect tensile testing conditions. Full-field strain development was monitored over time and fracture patterns were identified utilizing digital image correlation (DIC) technique. A load-strain nature were established as a function of lamination angles incorporated with DIC generated horizontal, vertical and shear strain maps which results in better understanding of sequences in strain development and fracture pattern due to laminations. Variation in indirect tensile strengths are evaluated and reported with applied energy which shows that sample with higher tensile strength required higher applied energy to fail it. Fracture pattern obtained from DIC visualization are characterized which show that shear failure is dominant when failure occurred through laminations and tension for central failure samples. Finally, the measured axial strain from load frame is compared with DIC and achieved a considerable agreement in both measurement. The knowledge of this study can help in evaluating fracture behavior of laminated formations which can be important for energy-related activities including fracturing, fluid injection and extraction.",22,24,1
Fracture,Natural Fractures,"Hou, Jirui; Luo, Min; Zhu, Daoyi",Foam-EOR method in fractured-vuggy carbonate reservoirs: Mechanism analysis and injection parameter study,Carbonate reservoirs; Fracture; Vug; Foam; EOR; Injection parameters,3-DIMENSIONAL PHYSICAL SIMULATION; FLOW,"Fractured vuggy carbonate reservoirs in the Tahe Oilfield, China, have many diverse and unevenly distributed reservoir spaces. These spaces mainly consist of corrosion pores, high-density fractures, and large vugs. Reservoir development began with natural energy and pressure maintenance methods. However, a rapid rise of the water cut always led to poor oil production. Gas enhanced oil recovery (EOR) has shown notable improvement in the Tahe Oilfield; however, the recovery efficiency was limited by gas channeling. In this paper, a two-dimensional (2D) physical model was developed for a more detailed visual of the flow characteristics and the effect of the injection parameters (i.e., the injection rate, the injection slug size, the injection timing and the injection position) were evaluated. Water flooding can produce a certain amount of oil; however, the remaining oil types are the same as those found during the bottom water invasion period, that is, attic oil, bypass oil, and oil films. A better approach is N-2 flooding, which can replace the attic oil at the top of the vug by gravitational differentiation. An even better method is N-2 foam flooding. When the injection volume of N-2 foam reached a certain level, foams accumulated in the flow channels, decreased fluid mobility, inhibited the gas channeling, and expanded sweep efficiency. Moreover, the N-2 foam had excellent effects on oil film stripping, crude oil emulsification, and carrying oil droplets, thereby improving the microscopic displacement efficiency. In addition, the results of injection parameter effect can help researchers and reservoir engineers better understand and implement the foam-EOR method in the fractured vuggy carbonate reservoirs.",21,22,12
Fracture,Natural Fractures,"Brattekas, B.; Seright, R. S.",Implications for improved polymer gel conformance control during low-salinity chase-floods in fractured carbonates,Polymer gel; Low-salinity chase-flooding; Improved blocking capacity; Fractured carbonates; Influence of oil; PET imaging,PREFORMED-PARTICLE-GEL; PERFORMANCE; PLACEMENT; FLOW,"Polymer gel is often used to reduce flow through highly conductive fracture networks, frequently present in naturally fractured carbonate reservoirs. When in place, polymer gel efficiently reduces fracture flow and may improve sweep efficiency and oil recovery during water chase-floods. Polymer gel treatments have in some cases been less efficient than expected in reducing fracture conductivity. This may occur because the polymer gel only partially fills the fracture volume, and allows fracture channeling of injected fluids. Low-salinity waterfloods may improve polymer gel blocking of fractures and remedy less efficient polymer gel treatments. Previous experimental work has shown that low-salinity waterfloods, where the salinity is reduced with respect to the gel solvent, reduces fracture channeling and restores matrix flow. This work further investigates low-salinity waterflooding as a method to improve conformance during polymer gel treatments in fractured, low permeable, carbonate rock. The low flow capacity of carbonate may cause a less efficient gel blocking of fractures, although the gel behaves according to established models during injection. Low-permeable carbonate core plugs with open, highly conductive fractures were used for this study. Water flow paths during high-salinity and low-salinity waterflooding were evaluated by positron emission tomography (PET). We found that gel blocking efficiency during chase waterfloods depends on: 1) the salinity of the chase water. Gel blocking efficiency increases with low-salinity water throughput; opposite to high-salinity waterfloods, where the gel blocking is reduced with water throughput. 2) The core material. As expected, a higher pressure was required to maintain flow through the matrix during water chase-floods in low-permeable carbonates. Water was diverted into the matrix for all ranges of permeability: sandstone and low-permeable carbonates, during low-salinity waterfloods. 3) The presence of oil. Fracture channeling prevailed during low-salinity waterfloods in chalk cores with residual oil present.",19,19,2
Fracture,Natural Fractures,"Ren, Guangwei; Nguyen, Quoc P.; Hon Chung Lau",Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants,CO2 soluble surfactants; Partition coefficient; CO2 foam; Fractured carbonate reservoir; EOR,INTERFACIAL-TENSION; GRAVITY DRAINAGE; MOBILITY CONTROL; CRUDE-OIL; DISPLACEMENT; EOR; MICROEMULSIONS; WETTABILITY; SOLUBILITY; REDUCTION,"Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions. A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 degrees C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water. RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam. These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.",19,20,2
Fracture,Natural Fractures,"Abbasi, Jassem; Ghaedi, Mojtaba; Riazi, Masoud",A new numerical approach for investigation of the effects of dynamic capillary pressure in imbibition process,Dynamic capillary pressure; Imbibition; Scaling; Two-phase flow,POROUS-MEDIA; 2-PHASE FLOW,"Capillary pressure is important in simulation of fluid flow in porous media at different scales. In ongoing simulation methods, capillary pressure is considered as a static process. However, recent researches have shown that capillary pressure is dynamic parameter. That is, its value directly depends on the rate of saturation changes. Including the effects of dynamic capillary pressure is especially important in prediction of imbibition process, which is an important mechanism in oil production from naturally fractured reservoirs. In this study, to investigate the effects of dynamic capillary pressure in two-phase flow process, an implicit and iterative method is proposed, and it is implemented in an open-source simulator named Matlab Reservoir Simulation Toolbox (MRST). The convergence results show that the proposed algorithm works well and the obtained results are acceptable. Furthermore, the analysis is made on the effects of dynamic capillary pressure functions in vertical imbibition process cases. The results confirm that considering dynamic capillary effects is critical in the simulation of two-phase flow in porous media. This is more important in imbibition process, where the capillary force is the dominant driving force. It is also found that at high permeability cases, considering dynamic capillary pressure effects is more crucial. Also, it is concluded that in high mobility ratios, due to low imbibition rates, effect of considering dynamic capillary pressure curves is not significant.",18,19,5
Fracture,Natural Fractures,"Meng, Shangzhi; Li, Yong; Wang, Lei; Wang, Kai; Pan, Zhejun",A mathematical model for gas and water production from overlapping fractured coalbed methane and tight gas reservoirs,Coproduction; Coalbed methane; Tight gas; Interference phenomenon; Unconventional natural gas coproduction,RELATIVE PERMEABILITY; NATURAL-GAS; ORDOS BASIN; WELL TEST; CHINA; ACCUMULATIONS; ADSORPTION; SIMULATION; GEOLOGY; STRATA,"With the continuous expansion, exploration and development of unconventional natural gas resources, mainly coalbed methane, shale gas and tight gas, some areas overlapped by two or three types of unconventional natural gas reservoirs are explored, e.g., the Linxing, Shilou and Linfen blocks located in the east margin of the Ordos Basin, China. Gas extraction from an individual reservoir becomes not economic as gas resources are not fully recovered; thus, gas coproduction from two or multiple layers is an effective method for improving gas production. In this work, a mathematical model of gas and water two-phase flow for the coproduction of coalbed methane and tight gas is developed. The adsorption characteristics, stress-sensitive and matrix shrinkage effects on coal permeability, and the stress-sensitive effect of tight sandstone are all considered in the model. The gas production related parameters, such as bottom hole flowing pressure, reservoir pressure differences, reservoir properties (e.g., permeability, cleat compressibility of coal, and Langmuir isotherm parameters) are discussed and compared with different geological conditions. The results show that the gas and water flow from the coalbed and sandstone reservoirs show no interference between each other under a constant pressure drainage system; the sandstone reservoirs show a fast pressure drawdown with a high gas production rate decline, while the coalbed reservoir is slow in pressure drawdown and the gas production rate increases gradually. The properties of a specific reservoir have a great influence on its own gas production performance, but with no influence on the other reservoirs. It was found that a lower constant drainage pressure should be adopted in the case of stress-sensitive effects, and coal with a lower cleat compression coefficient and Poisson's ratio value is better for higher gas production. The production contribution from each layer can be acquired if a specific production rate is set. If the reservoir pressure difference between the two reservoirs is too high (for instance at least > 3 MPa in the cases studied in this work), gas and water intrusion may happen, but the reservoirs would be balanced quickly. Thus, the coproduction of coalbed methane and tight gas from one well bore is feasible, and more work should be conducted on proposing a proper drainage strategy to improve the gas resource recovery efficiency in coal-bearing strata.",18,19,5
Fracture,Natural Fractures,"Song, Zhaojie; Hou, Jirui; Liu, Xiaochun; Wei, Qi; Hao, Hongda; Zhang, Liya",Conformance control for CO2-EOR in naturally fractured low permeability oil reservoirs,CO2 flooding; Low permeability oil reservoir; Gas channeling; CO2 production control,CARBON-DIOXIDE; CO2 STORAGE; TIGHT OIL; RECOVERY; GAS; PERFORMANCE; IMPROVEMENT,"Poor sweep efficiency seriously limits field applications of CO2-EOR, especially in fractured reservoirs. The investigation of CO2 production performance and the method to control CO2 production becomes a key to successfully run a CO2-EOR project. In this study, artificial sandstone cores were used to perform a series of CO2 flooding experiments at reservoir conditions of pressure, temperature and formation water salinity. Injection pressure and rock heterogeneity were taken into account to study their effect on CO2 production performance. Two-stage gas channeling control with three different scenarios, including PLS gel and ethylenediamine, starch gel and ethylenediamine, and starch gel and CO2 foam, was presented to improve the conformance in 3-D fractured-core models. Based on production performance and experimental observation, three production stages were clearly stated, including gas-free production stage, oil/gas co-production stage, and gas channeling stage. Oil/ gas co-production stage contributed the most to oil recovery. This finding was very consistent with the practical production performance of CO2 flooding in oil fields. The conformance improvement and the increase in injection pressure (within permissible range bearing in mind of fracturing pressure) could remarkably enhance the oil recovery at oil/gas co-production stage. In 3-D radial flow experiments, the two-stage gas channeling control presented great potential in delaying gas production and improving CO2 flooding efficiency. The combination of starch gel and ethylenediamine achieved the best result. The starch gel could effectively block the fracture, while the viscous reactant of ethylenediamine and in-situ CO2 within high permeability layer could successfully tune injected CO2 to flood low permeability layer. This study could help field engineers determine the optimal timing of CO2 production control, and also offered an optimal method to improve the conformance for CO2-EOR.",17,17,8
Fracture,Natural Fractures,"Kong, Bing; Chen, Shengnan",Numerical simulation of fluid flow and sensitivity analysis in rough-wall fractures,Numerical simulation; Hydraulic fracturing; Rough-wall fracture; Fracture conductivity,SURFACE-ROUGHNESS; FRACTAL DIMENSION; CUBIC LAW; ROCK; PERMEABILITY; SINGLE; CONDUCTIVITY; TRANSPORT; GEOMETRY; NETWORK,"Activated natural fractures, poorly-propped and un-propped secondary hydraulic fractures may serve as the connection between reservoir fluids and the main hydraulic fractures (i.e., well-propped fractures). These branched fractures also contribute considerably to well after-fracturing productivity in unconventional fight/ shale reservoirs. Rough fracture surface and its effects on fluid flow behavior in such fractures with very limited width is very important in understanding total mass transport in fractured rocks. In this paper, the effect of rough surface properties on fracture conductivity is studied through 3D numerical simulation of fluid flow behavior within the fractures. First, a tensile fracture was created on a core sample retrieved from the Montney formation, and the rough fracture surface topography was scanned via a high-resolution optical profilometer. The surface roughness characterizations were then used as reference to numerically reconstruct multiple three-dimensional fracture models. A finite element method was adopted to simulate fluid flow in the rough-wall fractures, using Navier-Stokes equation, for various fracture surface properties such as mean aperture, root mean square (RMS) asperity height, correlation length, anisotropy and shear displacement distance. Results showed that cubic law tends to overestimate the conductivity of the fractures with rough-wall surfaces, especially when the fracture aperture is small. Other surface properties, including correlation length, anisotropy and Hurst exponent also exert considerable impacts on fracture hydraulic properties. As the shear displacement distance increases, deviation of the fracture conductivity from cubic law first increases and then maintains at a constant level. The results of this paper have advanced the understanding of fracture conductivity and its dependence on fracture surface properties and will aid in improving production prediction and optimization in fractured tight reservoirs.",17,17,6
Fracture,Natural Fractures,"Zhang, Luqing; Zhou, Jian; Braun, Anika; Han, Zhenhua",Sensitivity analysis on the interaction between hydraulic and natural fractures based on an explicitly coupled hydro-geomechanical model in PFC2D,Hydraulic fracturing; Sensitivity analysis; Explicitly coupled hydro-geomechanical model; Numerical simulation; Two-dimensional particle flow code (PFC2D),FLUID VISCOSITY; FINITE-ELEMENT; PROPAGATION; SHALE; ROCK; SIMULATION; INITIATION; INJECTION; BOREHOLE; BRITTLE,"Fluid-induced fracture nucleation, propagation and interaction with natural fractures are the crucial issues for well understanding the process of hydraulic fracturing in unconventional reservoirs. In this paper, an explicitly coupled hydro-geomechanical model in two-dimensional Particle Flow Code (PFC2D) is employed to investigate the interaction between hydraulic fractures (HFs) and natural fractures (NFs), and the numerical scheme is validated by using analytical results. Several factors affecting the interactions between induced-fractures and NFs are being investigated and discussed. The simulation results show that three fundamental crossing scenarios can be well reproduced: (I) Direct Crossing, (II) Offset Crossing and (III) No Crossing (Arrested), and the crossing types agree well in the evaluation by Blanton's criterion. A sensitivity analysis shows that hydraulic fracture (HF) tend to be arrested by a natural fracture (HF) under low approach angles and prefer to cross the NF under higher in-situ differential stress states. Crossing is likely to be impeded for NFs with lower frictional coefficient and higher permeability. Additionally, lower fracturing fluid injection rates and lower fluid viscosities both are advantageous conditions for NF reactivation, and tend to arrest the HF. Moreover, the mechanism of the interaction of HFs and NFs influenced by the aforementioned factors can be well explained by the evolution of normal stress on the pre-existing interface, which is the key issue for correct simulation of hydraulic fracturing. Compared with the analytical model, the model in this study can reflect the dynamic stress evolution process, which will be a useful tool for optimizing the design of hydraulic fracturing in fractured reservoirs.",17,19,2
Fracture,Natural Fractures,"Wu, Jingjing; Zhang, Shaohe; Cao, Han; Zheng, Mingming; Sun, Pinghe; Luo, Xu","Fracability evaluation of shale gas reservoir-A case study in the Lower Cambrian Niutitang formation, northwestern Hunan, China",Fracability evaluation; Northwestern Hunan; Shale gas reservoir; Lower Cambrian Niutitang; Combination weight method; Acoustic emission (AE) event,FRACTURES; BASIN,"Four main fracability-related factors, brittleness, quartz content, diagenesis and natural fracture, are analyzed for the shale in Lower Cambrian Niutitang formation, Northwestern Hunan. The quantitative evaluation of fissure ratio of shale was achieved by combining SEM technique and Image J. It shows that the Lower Cambrian Niutitang formation shale in the study area has large content of brittle minerals, high brittleness index, high degree of thermal evolution, and well developed fractures, which therefore indicate advantageous conditions for the fracturing of shale gas reservoir. In addition, a mathematical model integrates the four factors is proposed based on the combination weight method to quantitatively evaluate the fracability of the shale in the study area. It was found that the optimum area for fracturing in the study area is Xianfeng, Longshan, Sangzhi and Cili due to their relatively high fracability indexes. Also the shale fracability in this area can be divided into three levels according to the characteristics of reservoir parameters and it is suggested to select shale with fracability index above 0.4354 to be fractured. The lab hydraulic fracturing tests of the shale samples are conducted to verify the accuracy of the quantification model. The experiment results agree with the fracablity index predicted by the proposed quantification model.",16,19,6
Fracture,Natural Fractures,"Sun, Qian; Zhang, Na; Fadlelmula, Mohamed; Wang, Yuhe",Structural regeneration of fracture-vug network in naturally fractured vuggy reservoirs,Fracture-vug network; Improved simulated annealing method; Multiple point statistics; Digital rock; Superimposing method,PORE-SPACE RECONSTRUCTION; FINITE-ELEMENT; FLOW; SIMULATION; MICROSTRUCTURE; PERMEABILITY; PREDICTION; ALGORITHM; PHASE; MODEL,"Naturally fractured vuggy carbonate reservoirs play an important role in the world's oil and gas production. Porescale modeling is treated as an important approach for unveiling the flow mechanism in carbonate reservoirs. The realistic regeneration of fractured vuggy reservoirs needs to preserve the geological structures and complex pores morphologies. Nevertheless, regeneration of such reservoirs is a great challenge because of the co-existence of fractures and vugs over a wide range of scales. In this paper, the reference fracture-vug network will be divided into two systems: matrix-fracture and matrix-vug. The two systems are reconstructed in two ways: (I), the matrixvug and matrix-fracture systems are generated by improved simulated annealing method (ISAM) and multiple point statistics algorithm (MPS), respectively; (II), both of the matrix-vug and matrix-fracture systems are generated by MPS. When applying for ISAM, the multipoint histogram mainly depends on the N-point template. The template is a unit configuration, which is considered as the characteristic of the geometric features. Based on this, we introduce the correlation coefficient matrix to determine an optimal template, and the accuracy of template selection algorithm is also discussed. The optimal template represents essential geological features of the training image, and its size is much smaller than the template size selected by entropy. Therefore, it can improve the computing efficiency while preserving the key properties of the network. Then, a superimposing method is proposed to create the fracture-vug network by combining the matrix-vug with matrix-fracture models. The superimposing method using ISAM (for matrix-vug model generation) and MPS (for matrix-fracture model generation) is called SMIM, while superimposing method using MPS (for both of matrix-vug and matrix-fracture models generation) is called SMM. Finally, the spatial connectivity, local percolation probability and patterns reproduction of the generated models are used to compare with those of the reference model. The results show that the 7-point template selected by the correlation coefficient matrix is enough to get the spatial features of the matrix-vug system. The generated fracture-vug network using the selected template is able to retrieve the patterns of training image (reference model) more accurately than other used templates. The fracture-vug network generated by superimposing method produces better results than the other methods (all named as ""direct method""). The network simulated with SMIM algorithm matches the reference model better than SMM algorithm. The probable reason maybe exist in the different generation methods used for matrix-vug systems. The local percolation probability (LPP), treated as a general geometric characterization method, is used to characterize the connectivity of measured units at a given local porosity. The results of the probability analysis show that SMIM is better in depicting the expected patterns of geological heterogeneities and in producing higher degree of connectivity of pore space than the SMM. The pattern reproduction of SMIM model is assessed by scanning the generated model, and the ratio of pattern reproduction number to that of reference model (i.e. the similarity) is around 97.28%. These results may guide the further application of the proposed method to field-scale modeling of naturally fractured vuggy reservoirs.",15,19,4
Fracture,Natural Fractures,"Ranjith, P. G.; Wanniarachchi, W. A. M.; Perera, M. S. A.; Rathnaweera, T. D.",Investigation of the effect of foam flow rate on foam-based hydraulic fracturing of shale reservoir rocks with natural fractures: An experimental study,Foam; Fracturing; Breakdown pressure; Flow rate; Fracture permeability; CT scanning,PERMEABILITY; PRESSURE; ENERGY; GAS; PROPAGATION,"Foam-based hydraulic fracturing has been identified as a good solution for the extraction of natural gas from deep shale reservoirs, due to its unique advantages such as low water consumption and high proppant carrying capacity. However, lack of knowledge of foam-based shale fracturing and complex nature of two-phase foam, make it challenging to use in field conditions, and one unclear area is the effect of the foam flow rate on fracturing and fracture characteristics. Therefore, the aim of this study was to investigate the effect of foam flow rate on breakdown pressure, fracture permeability and generated fracture characteristics. In order to achieve this, a series of hydraulic fracturing experiments was conducted for shale rocks with existing natural fractures, using nitrogen-based foam. Fracture permeability was also evaluated for intact and fractured rock samples. Micro-CT scanning technology was adopted to characterise the geometrical properties of fractures, in order to investigate the effect of foam flow rate within the fracture. Experimental results show that the breakdown pressure increases by 30% while energy release decreases by 78% when the foam flow rate increases from 10 to 70 ml/min. In addition, the results suggest that the permeability of a fractured sample at 10 ml/min injection rate is about 15 times higher than that of a fractured sample at 70 ml/min injection rate. The findings of this study reveal that low foam-flow rates can create a better inter-connected fracture network than higher flow rates.",15,15,4
Fracture,Natural Fractures,Liu Qingling; Tian Shouceng; Li Gensheng; Sheng Mao; Li Xiaojiang; Wang Tianyu; Shen Zhonghou,An analytical model for fracture initiation from radial lateral borehole,Analytical model; Radial drilling; Hydraulic fracturing; Fracture initiation pressure; Location of failure zone; Initial fracture direction,HYDRAULIC FRACTURE; INTEGRATED WORKFLOW; DIRECTIONAL WELL; MECHANISMS; STRESS; PROPAGATION; SIMULATION; ROCKS; TESTS; SIZE,"Radial drilling-fracturing, the integration of radial drilling and hydraulic fracturing, is an innovative approach to develop low permeability, thin target layer and naturally fractured reservoirs, etc. Understanding the fracture initiation process is required in the practical application to avoid high fracture initiation pressure (FIP) and complex fracture geometries near the wellbore. In this paper, we develop an analytical model to determine FIP, location of rock failure zones and initial fracture direction from the radial lateral borehole. This model is based on the stress superposition induced by cased main wellbore and radial borehole, and the maximum tensile stress criterion is adopted. Then, we perform a series of sensitivity analysis by examining different effects of in-situ stress regime, lateral orientation (the included angle between borehole axis and maximum horizontal in-situ stress), lateral length, and lateral diameter. Besides, the effect of pre-existing weakness plane, across which the tensile strength is much lower than that of the intact rock, is also investigated, when the plane is drilled through by the radial borehole. Results show that for intact rock with no weakness plane, the in-situ stress regime and lateral orientation are main factors influencing FIP, location of rock failure zones, and initial fracture direction. Under the in-situ stress regime of normal fault, fracture initiates vertically, and FIP enlarges as lateral orientation increasing; under the in-situ stress regime of strike slip, fracture initiates vertically with small lateral orientation, while fracture initiates horizontally with large lateral orientation; and under the in-situ stress regime of reverse fault, fracture initiates horizontally with any lateral orientation, and FIP decreases as the lateral orientation increasing. It is also found that when the fracture initiates vertically, the location of rock failure zones is at the base of radial borehole on its top and bottom sides; and when the fracture initiates horizontally, the location of rock failure zone is at the remote region of radial borehole on its right and left sides. The lateral length has a minor effect on fracture initiation, and the influence of lateral diameter is negligible. When the weakness plane is drilled through by the radial borehole, fracture initiation pressure from weakness plane is affected by its occurrence, i.e., azimuth and inclination. FIP is determined by taking the minimum between fracture initiation pressure from rock matrix and the weakness plane. The key findings of this work could provide critical insights into understanding radial drilling-fracturing initiation characteristics.",15,15,3
Fracture,Natural Fractures,"Ding, Yi; Liu, Xiangjun; Luo, Pingya",The analytical model of hydraulic fracture initiation for perforated borehole in fractured formation,Fractured formation; Fracture operation; Multiple fracture planes; Fracture initiation,PROPAGATION; RESERVOIRS; WELLBORE; STABILITY; WELLS; SHALE,"Hydraulic fracturing has been the common method of stimulation treatment. Effective fracture network needs to be formed for having efficient hydraulic fracturing. The forming process of fracture network can be divided into 2 parts, i.e., initiation and propagation. In particular, the initiation part is the foundation of forming fracture network, and also basic parameter for analyzing fracture propagation. However, in fractured formation, it is very tricky to obtain initial fracture pressure due to the influence of rich natural fractures. Therefore, based on the rock mechanics and spatial geometry theory, this paper presents a mechanical model for predicting fracture initiation in fractured formation. Unlike conventional model, this new model considers multiple fractures conditions and the intersection method between natural fractures and perforated borehole. The model has been used to investigate influence factors of initial fracture pressure. These computed results reveal that the initial fracture pressure has complex distribution, and changes with variable occurrence of natural fracture. There are different kinds of intersections between natural fracture and perforated borehole. When fracture plane intersects through perforated borehole, influence of fracture plane on fracture initiation is relatively larger. Furthermore, with increasing number of natural fractures, initial fracture pressure decreases and the initiation mode tends to be tensile failure along natural fracture plane. Additionally, engineering parameters, like well trajectory and perforation azimuth, are related to fracture initiation pressure. Their optimizations can contribute to perform optimization of reservoir stimulation. Results from this model used in this paper aim at offering reference for field fracturing practice in fractured formation.",15,16,2
Fracture,Natural Fractures,"Wan, Yi-Zhao; Liu, Yue-Wu; Chen, Fang-Fang; Wu, Neng-You; Hu, Gao-Wei","Numerical well test model for caved carbonate reservoirs and its application in Tarim Basin, China",Caved carbonate reservoir; Type curves; Numerical well test; Finite element method,NATURALLY FRACTURED RESERVOIRS; PRESSURE TRANSIENT ANALYSIS; COMPOSITE RESERVOIR; EXPLORATION; CAVITY,"The caved carbonate reservoir is a special and complex reservoir with different size cavities, which implies a strong heterogeneity. It is a big challenge to characterize such reservoirs. The dual-porosity model and radial composite model are the two most commonly used models for the interpretation of well test in caved carbonate reservoirs. However, more studies are needed to determine whether these models can be applied to this special and complex type of reservoir. In this paper, first we classify the log-log plots of test pressure into four types and analyze the characteristics of each type. The results show that the cavity controls the pressure response and that the above-mentioned models are not appropriate for the well test interpretation of caved carbonate reservoirs. We also developed a numerical well test model for caved carbonate reservoirs. The model includes two cases: a well drilled outside a cavity and a well drilled inside a cavity. The model's equations were solved by the finite-element method. We analyzed the pressure response of the developed model and found that the log-log plots for the model of a well outside a cavity are similar to that of the dual-porosity model, but the physical mechanisms of these two models are different. The model of a well inside a cavity is similar to the radial composite model except for a deviation in the distance of the well from the center of the cavity. Sensitivity studies show the size of the cavity, its permeability, and the distance from the well to the cavity are the main factors influencing the pressure response behavior. Two field examples of build-up pressure tests are provided to show how the proposed model can be used to understand the properties of caved carbonate reservoirs and characterize them.",15,16,1
Fracture,Natural Fractures,"Taheri-Shakib, Jaber; Ghaderi, Amir; Kanani, Vahid; Rajabi-Kochi, Mahyar; Hosseini, Seyed Ahmad",Numerical analysis of production rate based on interaction between induced and natural fractures in porous media,Hydraulic fracture; Natural fracture; Production; XFEM; UDEC,PRODUCTION PERFORMANCE; HORIZONTAL WELL; PERMEABILITY; ELEMENTS; FLOW,"Hydraulic fracturing in reservoirs with low or high fracture density could have a significant impact on the reservoirs' production rate. In the present study, having determined the fracture direction through the finite difference method according to the induced-stress distributions, this operation simulated fracturing in two reservoirs with high or low levels of natural fracturing, using the distinct-element method. The goal was to investigate the effect of hydraulic fracture length and aperture on the production rate from both reservoirs. Sensitivity analysis indicated that in a reservoir with more natural fractures, hydraulic fracture length plays a more significant role, and in a reservoir with fewer natural fractures, both hydraulic fracture length and opening are highly influential. Also, factors such as fracture coalescence and intersected fractures, which influence the production rate, were examined. Moreover, the results revealed that when the fracture length and aperture increase, the production rate fluctuates.",14,16,4
Fracture,Natural Fractures,"Zhao, Xianyu; Wang, Tao; Elsworth, Derek; He, Yunlong; Zhou, Wei; Zhuang, Li; Zeng, Jun; Wang, Suifeng",Controls of natural fractures on the texture of hydraulic fractures in rock,Hydraulic fracturing; Jointed rock mass; DEM; Crack propagation,SIMULATION; MODEL,"Hydraulic fracturing plays an important role in the exploitation of oil, shale gas and coal seam gas resources-all of which contain natural fractures. We systematically explore the role of the pre-existing texture of such natural fractures on the form of the resulting stimulated reservoir volume (SRV). A blocky discrete element model (DEM) coupled with fluid flow is used to explore this response. Numerical predictions for the evolution of fluid pressure and fracture width at the well are compared with first-order analytical approximations of the zero-toughness solution (FMO). We then construct four typical joint system models separately comprising orthogonal, staggered, diagonal and randomly oriented joints and conduct the virtual hydraulic fracturing simulations via DEM. This defines the influence of structure on breakdown pressure and fracture propagation and allows the analysis of the main factors that influence behavior and resulting SRV. Results for the four forms of jointed rock mass show that: (1) the aggregate/mean extension direction of the fractures is always along the direction of the maximum principal stress but significant deviations may result from the pre-existing fractures; (2) there are negative correlations between the maximum fracture aperture with both Poisson ratio and elastic modulus, but the breakdown pressure is only weakly correlated with Poisson ratio and elastic modulus; (3) an increase in injection rate results in a broader fracture process zone extending orthogonal to the principal fracture, and the breakdown pressure and interior fracture aperture also increase; (4) an increase in fluid viscosity makes the fractures more difficult to extend, and the breakdown pressure and interior fracture aperture both increase accordingly.",14,14,3
Fracture,Natural Fractures,"Liu, Jingshou; Ding, Wenlong; Wang, Ruyue; Yang, Haimeng; Wang, Xinghua; Li, Ang",Methodology for quantitative prediction of fracture sealing with a case study of the lower Cambrian Niutitang Formation in the Cen'gong block in South China,Fracture sealing; Shale reservoir; Paleotectonic stress field; Lower Cambrian; Cen'gong block,PALEOTECTONIC STRESS-FIELDS; SHALE-GAS; PRESERVATION CONDITIONS; CRUSTAL DEFORMATION; NATURAL FRACTURES; NORTHERN GUIZHOU; BASIN; RESERVOIRS; SIMULATION; DEPRESSION,"Industrial levels of shale gas have been produced from the Niutitang Formation in the lower Cambrian of the Cen'gong block, South China. The practice of exploration and development of shale gas in the Cen'gong block shows that the abundance of gas in different layers and wells is closely related to the degree of development of fractures. In this study, data obtained from outcrops, cores, and thin sections from the Cen'gong block were used to determine the development characteristics of such natural fractures. Combined with the analysis of burial history and fluid inclusions, the stress fields during three periods (the Yanshanian period, Himalayan period and neotectonic period) are suspected to play a critical role in fracture sealing. The paleotectonic stress tensor is determined using fault activity analysis, acoustic emission tests, and burial history. The magnitude and direction of current in situ stresses are determined by drilling-induced fractures, deviated well information, and cross multipole array acoustic (XMAC) logging. Under the constraints of XMAC logging interpretation and mechanical experiments, the spatial distribution of mechanical parameters is obtained by seismic inversion, and 3D heterogeneous geomechanical models are established using a finite element method (FEM). Then, the fracture density, reactivity, and aperture are identified. The results show that the magnitudes of the maximum horizontal principal stress during the Yanshanian period, the Himalayan period, and the neotectonic period are 150-170 MPa, 110-130 MPa, and 35-45 MPa, respectively. Using the fracture sealing calculation model, the fracture sealing that developed in the Himalayan period is the worst, the fracture sealing that developed in the Yanshanian period is intermediate, and the fracture sealing that developed in the neotectonic period is the best. Based on three-dimensional heterogeneous geomechanical modeling and tectonic stress evolution estimates, the fracture sealing calculation model proposed in this paper can be widely used in the evaluation of the preservation conditions of shale reservoirs, tight sandstone reservoirs and low-permeability reservoirs in complex tectonic areas.",14,15,2
Fracture,Natural Fractures,"Abbasi, Mahdi; Madani, Mohammad; Sharifi, Mohammad; Kazemi, Alireza",Fluid flow in fractured reservoirs: Exact analytical solution for transient dual porosity model with variable rock matrix block size,Fractured reservoir; Transient dual-porosity model; Shape factor; Rock matrix block size distribution,INJECTION; BEHAVIOR; CURVE; TESTS; WELL,"Dual porosity reservoirs consist of two comparatively independent systems of fractures and matrix blocks with high and low permeability values, respectively. Semi-analytical and numerical studies on naturally fractured reservoirs have been already cited in the literature. The present study focuses on investigation of a linear double porosity model of a semi-infinite-acting naturally fractured reservoir using an exact analytical method. Different matrix block size distributions are embedded into a transient model to consider the effects of heterogeneity in fractured formations. In order to take into account transient fracture-matrix exchange, an analytical method is proposed to solve the coupled fracture and matrix equations. Gauss Legendre quadrature is employed to evaluate the double integral of general transient solution. Moreover, the corresponding shape factor was evaluated in a double porosity transient model coupled with variable matrix block size distribution. Results demonstrated that matrix block size distributions strongly affect the fluid transfer during the early time region. Also, the presented model was employed to generate interference test curves which in turn were studied to investigate the impacts of storativity ratio and matrix block size distributions on the fracture-matrix fluid transfer. Results illustrated that a series of obtained pressure data from an observational well along with the proposed model may be considered a robust method in fracture intensity assessment. Fast sensitivity analysis and very efficient computational cost are the benefit of the derived analytical solutions with respect to previous numerical solutions.",14,14,1
Fracture,Fracture Propagation,"Rui, Zhenhua; Guo, Tiankui; Feng, Qiang; Qu, Zhanqing; Qi, Ning; Gong, Facheng",Influence of gravel on the propagation pattern of hydraulic fracture in the glutenite reservoir,Glutenite; Gravel; Fracture propagation; Numerical simulation; Rock mechanics,HYDROFRACTURING CRACKS; SHALE; MODEL; OIL; GROWTH; SIMULATION; HETEROGENEITY; NETWORKS,"The clear mechanism of hydraulic fracture propagation in glutenite reservoirs with high heterogeneity is still not obtained, thus it is difficult to carry out the design of fracturing plan effectively. Based on the characteristics of the glutenite reservoirs, a coupled flow-stress-damage (FSD) model of hydraulic fracture propagation with gravels is established. This model is experimentally verified and the research on the influence of rock physical parameters and gravel property on the hydraulic fracture propagation is conducted. It is shown that as the gravel tensile strength increases, the hydraulic fracture is prone to propagate around the gravel, where the fracture deflection always occurs; as the gravel Young's modulus increases, there is high probability that hydraulic fracture propagates around the gravel, with more obvious fracture deflection; the matrix permeability influences fracture propagating morphology when encountering gravel and total fracture length; the horizontal geostress difference seriously impacts the fracture deflection; as the fracturing fluids injection displacement increases, the fracture is prone to deflect when encountering gravel; the low viscosity fracturing fluids result in the shorter fracture; the larger gravel increases the possibility of fracture deflection; in case of smaller gravel sizes, the increasing gravel content has a big influence on fracture deflection, and the increasing content of large gravel complicates the fracture morphology, resulting in the fine branched fractures; for the well rounded gravel, the fracture propagation around the gravel is prone to occur, and the fracture is not prone to deflect. Compared with the conventional sandstone reservoir, the glutenite reservoirs have higher breakdown and extension pressures, which fluctuate due to the gravel; the larger gravel size results in higher extension pressure. In this paper, a simulation method of hydraulic fracture propagation in the glutenite reservoirs is introduced, and the result provides the theoretical support for prediction of fracture propagation morphology and plan design of hydraulic fracturing in the glutenite reservoirs.",96,98,17
Fracture,Fracture Propagation,"Taleghani, Arash Dahi; Gonzalez-Chavez, Miguel; Yu, Hao; Asala, Hope",Numerical simulation of hydraulic fracture propagation in naturally fractured formations using the cohesive zone model,Hydraulic fracturing; Cohesive zone model; Fracture intersections; Natural fractures; Complex fracture network; Traction separation law,BARNETT SHALE; STRESS; PRODUCTIVITY; RESERVOIRS; SYSTEMS; IMPACT; JOINTS,"This paper presents an integrated methodology that utilizes the cohesive zone model (CZM) to simulate propagation of hydraulic fractures, and their interactions with pre-existing natural fractures. CZM has the advantage of capturing the non-elastic behavior of shales; usually induced by total organic carbon (TOC) as well as dissimilar mechanical properties of cemented natural fractures. At the intersection of an advancing hydraulic fracture and a stationary natural fracture, the hydraulic fracture may arrest, cross, or divert into a pre-existing natural fracture depending on the rock mechanical properties, magnitude and direction of rock principal stresses, and fracture intersection angle. The activation of natural fractures during hydraulic fracture treatments improves fracture complexity and expands reservoir drainage area, making stimulation treatments more effective. In this work, triaxiality effects are incorporated into the cohesive zone model. Utilizing triaxiality makes the traction separation law (TSL) tied to confining pressure and this ensures a more reliable transition from laboratory test environment to bottomhole conditions. We present a methodology to determine the cohesive properties or TSL characteristics of rock, after performing semicircular bending tests (SCBT). Finite element analysis (FEA) is then used to calibrate the cohesive properties of both rock and natural fractures. The calibrated parameters were utilized in a field-scale FEA to simulate the growth of complex fracture networks. The results show how fracture intersection angle and the nature of cemented materials inside the natural fractures might divert a hydraulic fracture initially propagating in a direction perpendicular to the minimum horizontal stress. The sensitivity analysis of primary parameters such as fluid viscosity, natural fracture distribution, fracture intersection angle, and differential stresses is implemented to provide a better insight into the performance of hydraulic fracturing jobs in naturally fractured reservoirs. Results indicate the importance of nonlinear fracture tip effects as in-situ stress differences increase.",77,79,8
Fracture,Fracture Propagation,"Jia, Yunzhong; Lu, Yiyu; Elsworth, Derek; Fang, Yi; Tang, Jiren",Surface characteristics and permeability enhancement of shale fractures due to water and supercritical carbon dioxide fracturing,Surface characteristics; Permeability enhancement; Hydraulic fracturing; Supercritical carbon dioxide (Sc-CO2),HYDRAULIC FRACTURE; GRAVITY CURRENTS; TIP REGION; FLUID-FLOW; GAS-FLOW; PROPAGATION; INITIATION; ROUGHNESS; RHEOLOGY; WELLS,"Carbon dioxide (CO2) is an alternative working fluid to water for hydraulic fracturing in shale reservoirs. It offers advantages as a substitute for the use of large quantities of potable water and for the concurrent sequestration of CO2, however sorption and swelling effects, and their impact on permeability may be detrimental and are undefined. Hence, it is of great importance to understand the mechanism of supercritical carbon dioxide fracturing in shale and its effect on shale permeability enhancement. We conduct hydraulic fracturing experiments on shale samples using both water (H2O) and supercritical carbon dioxide (Sc-CO2) as fracturing fluids to explore the surface characteristics and permeability evolution of fluid-driven fractures. We use profilometry to measure the roughness and complexity of the resulting fracture surfaces and measure the permeability of the fractures. Results indicate that: (1) Sc-CO2 fracturing creates fractures with larger tortuosity relative to H2O fracturing (macroscale); (2) the topography of Sc-CO2 fracture surfaces is more rough and complex compared to that of H2O fractured surfaces; (3) larger mineral grains are removed and relocated from induced fracture surfaces by Sc-CO2 fracturing-these acting as micro proppants that result in a larger fracture aperture; (4) correspondingly, the permeability of shale fractures increases by similar to 5 orders of magnitude with Sc-CO2 fracturing and this enhancement is similar to 3 orders of magnitude higher than that by traditional hydraulic fracturing. This observation potentially validates the feasibility of Sc-CO2 as a fracturing fluid for the stimulation of shale reservoirs.",64,66,6
Fracture,Fracture Propagation,"Kumari, W. G. P.; Ranjith, P. G.; Perera, M. S. A.; Chen, B. K.","Experimental investigation of quenching effect on mechanical, microstructural and flow characteristics of reservoir rocks: Thermal stimulation method for geothermal energy extraction",Geothermal; Granite; Permeability; Quenching; Thermal cracks; Thermal stimulation,AUSTRALIAN STRATHBOGIE GRANITE; FRACTURE PERMEABILITY; HEAT-TRANSFER; BEHAVIOR; STRESS; TEMPERATURES; EVOLUTION; TRANSPORT; POROSITY; CRACKING,"Thermal stimulation method can be effectively utilized to enhance the flow performance in the tight porous media with an induced thermal shock. This approach can be applied to many deep geo-engineering applications including geothermal energy extraction. In this regard, understanding the flow-mechanical behaviour of reservoir rock during and after thermal stimulation is necessary for safe and effective stimulation process. The aim of this study is, therefore to investigate the quenching effect on mechanical and flow behaviour of Australian Strathbogie granite by conducting a series of micro and macro-experiments. Experiments were conducted by profiling the micro-structure of rock with CT scanning, microscopic imaging and, quantifying the thermally induced damage due to quenching treatment. In order to understand mechanical response of rock due to quenching, strength tests were conducted under the unconfined condition, and the corresponding fracture propagation patterns were investigated using an acoustic emission (AE) system. In addition, flow performance of thermally treated rock was studied under a wide range of coupled high temperature and high-pressure conditions (temperatures 20-300 degrees C, confining pressure up to 45 MPa and injection pressure up to 40 MPa), simulating different geothermal temperatures and depths. According to the findings, thermal treatment resulted in around 70% of reduction of strength and elastic properties respectively due to the thermally induced damage caused by induction of both inter and intra-crystalline cracks. Further, increased porosity and crack density significantly enhanced the permeability of the rock compared to the intact rock (from approximately 1 x 10(-19)m(2) to 6 x 10(-15)m(2) under 10 MPa confining pressure). However with the increasing of normal stresses, permeability decreased non-linearly and further, increasing temperature resulted in significant reductions in permeability of granite (approximately 95% of reduction from room temperature to 300 degrees C) due to the thermally induced volumetric expansion which leads to enhancement of interlock effect.",60,68,12
Fracture,Fracture Propagation,"Hou, Bing; Zhang, Ruxin; Zeng, Yijin; Fu, Weineng; Muhadasi, Yeerfulati; Chen, Mian",Analysis of hydraulic fracture initiation and propagation in deep shale formation with high horizontal stress difference,Hydraulic fracture; Complex fracture network; Discontinuities; Pump rate; AE monitoring,GAS-RESERVOIRS; BEHAVIOR; ROCK,"Deeply buried shale formations (vertical depth > 3500 m) that are rich in shale gas are abundant in south China. The primary problems in the exploitation of these formations are the relatively small stimulated reservoir volume (SRV) and low production rates in comparison with their shallower counterparts. These issues are attributed to the high fracturing pressure, limited fracture extension because of sand plugging, significant horizontal stress contrast, and discontinuities produced during hydraulic fracturing. To accurately evaluate and improve the SRV in deep shale formations, the mechanism of fracture propagation must be understood and described. In this regard, a series of large-scale true tri-axial experiments with acoustic emission (AE) monitoring were conducted to characterize the fracture initiation and propagation in a selected deep shale formation. It was found that the difficulty in the complex fracture network formation was because the high stress contrast controls the fracture propagation path to generate large main fractures instead of activating discontinuities. The hydraulic fractures initiated either from open-hole positions or stress concentration locations on a wellbore wall that displayed two types of intersection in terms of crossing and deflection. In general, four types of fracture morphologies were identified: transverse fracture, transverse fracture with bedding planes, natural fracture with bedding planes, and transverse fracture with bedding planes and natural fractures. In addition, the horizontal stress contrast, fluid viscosity, pump rate and fracturing procedure on fracture propagation were evaluated for their effect on the resulting SRV. A low-viscosity fluid can activate discontinuities to form a complex fracture network, whereas a high-viscosity fluid is likely to produce large fractures under a high contrast in the horizontal stresses. On the basis of the above-mentioned analyses, a fracturing procedure applying a periodically varying pump rate and shut-in using a low-viscosity fluid was suggested to be an effective approach to enhance the interaction between the hydraulic fractures and discontinuities as well as to increase the fracture length.",58,65,4
Fracture,Fracture Propagation,"Zeng, Qing-Dong; Yao, Jun; Shao, Jianfu",Numerical study of hydraulic fracture propagation accounting for rock anisotropy,Hydraulic fracturing; Crack propagation; Rock anisotropy; XFEM; Numerical modeling,FINITE-ELEMENT-METHOD; CRACK-PROPAGATION; ORTHOTROPIC MEDIA; SIMULATION; GROWTH,"The objective of this study is to investigate the effect of rock anisotropy on hydraulic fracture propagation. The coupled model of rock deformation and fluid flow is established to study hydraulic fracturing of orthotropic formation. Stress field is solved by using the extended finite element method with special tip enrichment functions for orthotropic formation. The coupling between stress field and pressure field is treated by Picard iterative procedure. The modified circumferential tensile stress criterion is used to determine fracture propagation, in which stress intensity factors are determined by an interaction integral method. Numerical results show that when fracture doesn't initiate from the direction of material axis with larger modulus, the fracture propagation direction would change and divert to the direction of material axis with larger modulus. And as Young's modulus ratio between two material axes increases, the phenomenon becomes more obvious. Moreover, shear modulus also enhances the diversion phenomenon of fracture propagation direction. However, the in-situ stress difference could weaken the effect of rock anisotropy. The results indicate that the propagation process of hydraulic fracture is influenced by comprehensive factors including material axis angle, Young' modulus ratio, shear modulus and in-situ stress difference.",51,52,2
Fracture,Fracture Propagation,"Li, Yuwei; Yang, Shuai; Zhao, Wanchun; Li, Wei; Zhang, Jun",Experimental of hydraulic fracture propagation using fixed-point multistage fracturing in a vertical well in tight sandstone reservoir,Tight sandstone reservoir; Fixed-point multistage fracturing; Fracture propagation; Fracture geometry,HIGHLY DEVIATED WELL; SHALE GAS-RESERVOIRS; LABORATORY EXPERIMENTS; ORIENTED PERFORATION; INITIATION PRESSURE; BEHAVIOR; NETWORKS; VOLUME; ROCK,"Fixed-point multistage fracturing can effectively increase the stimulated reservoir volume (SRV) in tight sand-stone reservoir. In different geological and engineering conditions, how to explain the geometric form of fracture propagation in fixed-point multistage fracturing has not been reported yet, and the propagation mechanism of hydraulic fracture is ambiguous. To clarify this mechanism, fourteen large-scale triaxial tests were deployed in this study to investigate the fracture propagation behavior in fixed-point multistage fracturing, and the influences of various factors on fracture geometries were studied. The results show that there are six types of fractures in the horizontal plane when the fixed-point multistage fracturing are carried out in a vertical well in tight sandstone reservoir: bi-wing planar fracture; bi-wing non-planar fracture; L-type fracture; X-type fracture; biwing turning fracture and re-orientation turning fracture. Fixed-point multistage fracturing can increase the SRV mainly because it is equivalent to carry out refracturing in the reservoir, so it can form a complex fracture system similar to refracturing. The research proves that it is difficult to form a complex fracture system through the fixed-point of multistage fracturing when the stress difference is more than 6 MPa in the horizontal direction. The fracturing fluid injection rate has an obvious effect on the formation of multi-fractures, and the multi-fracture can not form when the injection rate is too large. The enhancement of rock heterogeneity will lead to more energy consumption in fracturing process, which is not conducive to the initiation and propagation of fractures. Therefore, the in-situ stress, rock heterogeneity, injection rate and other factors should be comprehensive considered when designing the fixed-point multistage fracturing scheme for vertical well in tight sandstone reservoir.",47,51,5
Fracture,Fracture Propagation,"Tang, Jizhou; Wu, Kan; Zeng, Bo; Huang, Haoyong; Hu, Xiaodong; Guo, Xuyang; Zuo, Lihua",Investigate effects of weak bedding interfaces on fracture geometry in unconventional reservoirs,3D DDM; Weak interface; Height containment; Multiple fractures,DISPLACEMENT DISCONTINUITY METHOD; LAYERED FORMATIONS; PROPAGATION; CONTAINMENT; MECHANICS; ROCK,"Shale formations often consist of multiple weak interfaces between layers, which is easily opened during hydraulic fracturing treatment and affect growth of fracture height. Fracture propagation in such formations usually induced complex fracture geometry with primary vertical fractures and horizontal fracture segments between layers. Although numerous numerical models have been developed to simulate fracture propagation in unconventional reservoirs, relatively few physical three-dimensional models exist to quantitatively simulate opening of fractures affected by weak interfaces. In this paper, we analyze width profile of fractures and interaction of vertical and horizontal fracture segments with predetermined fracture path under the assumption of neglecting the flow effect. A fully three-dimensional displacement discontinuity method (3D DDM) is introduced to model multiple fractures in a stage in three dimensions. The fracture geometry is prescribed, which combined with vertical and horizontal fractures. In each case, the horizontal fracture is regarded as opening of the bedding interface and vertical fracture would either be arrested or directly cross the interface. Interfacial sliding distance, defined as width jump of the vertical fracture at the interface, is regarded as a primary impact of fracture height containment. Analysis of fracture opening, shear displacements and interfacial sliding distance is given for both vertical and horizontal fracture segments. When multiple vertical fractures intersect with a horizontal interface, shear displacements are induced on the interface and vertical fractures have smaller width compared with the case without the horizontal interface, as a result of the interaction with the interface. We observed that both widths of fracture segments and interfacial sliding distance are positively correlated with the distance between the center of the vertical fracture and the horizontal interface, half-length of horizontal fracture segment, the net pressure within fracture segments. Conversely, Young's Modulus has a negative relationship with both width of fracture segments and interfacial sliding distance. This paper analyzes the effects of opening of weak interfaces and provides critical insights of fracture width distribution and its impacts on proppant transport.",46,47,2
Fracture,Fracture Propagation,"Liu, Liyuan; Zhu, Wancheng; Wei, Chenhui; Elsworth, Derek; Wang, Jiehao",Microcrack-based geomechanical modeling of rock-gas interaction during supercritical CO2 fracturing,Supercritical CO2 fracturing; Gas adsorption; Internal swelling stress; Rock damage; Numerical simulation,SHALE GAS; CARBON-DIOXIDE; HORIZONTAL WELLS; COAL; PERMEABILITY; PROPAGATION; ADSORPTION; CHALLENGES; CAPTURE; SCALE,"Relative to water-based fluids, non-aqueous fracturing fluids have the potential to increase production, reduce water requirements, and to minimize environmental impacts. Since the viscosity of supercritical CO2 is one-tenth that of water, its density is close to that of water, and is capable of promoting sorptive rejection of methane, it is an attractive substitute for water in the extraction of shale gas and coalbed methane. The following defines a geomechanical model accommodating the interaction of fluid flow, adsorption-induced swelling stress, solid deformation and damage to quantify rock-gas interactions during supercritical CO2 fracturing for shale gas production. The architecture of the shale is accommodated that includes both pore-and micro-crack-based porosity. According to the microcrack model representing shales with low porosity, both analytical and numerical results show that the effective stress coefficient is much smaller than unity. We analyze the potential advantages of fracturing using supercritical CO2 including enhanced fracturing and fracture propagation, increased desorption of methane adsorbed in organic-rich portions of the shale and the potential for partial carbon sequestration. Rock-gas interactions include both the linear poroelastic response and the chemo-mechanical interaction due to sorption. Simulation results demonstrate that supercritical CO2 fracturing indeed has a lower fracture initiation pressure and a significantly lower breakdown pressure, as observed in experiments, and that fractures with greater complexity than those developed with liquid CO2 and water fracturing result. With increasing dynamic viscosity of the fracturing fluids, the predicted breakdown pressure also increases, consistent with experimental observations.",40,43,8
Fracture,Fracture Propagation,"Zhang, Yushuai; Zhang, Jincai; Yuan, Bin; Yin, Shangxian",In-situ stresses controlling hydraulic fracture propagation and fracture breakdown pressure,Hydraulic fracture; In-situ stresses; Horizontal stress; Breakdown pressure; Depletion; Fracture curving,INSITU STRESSES; WELLS; PREDICTION; BOREHOLE; RESERVOIRS; MAGNITUDE; ROCKS; FLOW,"In-situ stress impact on hydraulic fracturing is investigated to enhance hydraulic fracturing performance. Lithology-controlled lower and upper bounds of the horizontal stresses are proposed, and an improved stress polygon method is presented. This improved method can narrow the area of the conventional stress polygon, particularly in shales; therefore, constrain the in-situ stress estimate. The lithology-controlled stresses indicate that a shale has a higher minimum horizontal stress and can be used as a barrier of the hydraulic fracture propagation when hydraulic fracturing is performed in adjacent sandstones. However, when hydraulic fracturing is performed in a shale oil or gas formation, a stress-barrier formation may not exist on the top or the bottom of the shale reservoir, and this will cause the hydraulic fractures to propagate out of the reservoir zone. We also examine the effects of the maximum and minimum horizontal stresses, shear stresses and depletion on the fracture initiation, breakdown, propagation and containment. Shear stresses cause hydraulic fractures kinking; from this evidence, we find that a horizontal well can be drilled with a certain angle to the minimum stress direction because in most cases the hydraulic fractures eventually curve to the maximum stress direction. In addition, we propose a new method to calculate the fracture breakdown pressure based on fracture mechanics. The proposed method predicts a higher breakdown pressure than the conventional one, which may better estimate the breakdown pressure.",38,40,3
Fracture,Fracture Propagation,"Zhou, Dawei; Zhang, Guangqing; Zhao, Pengyun; Wang, Yuanyuan; Xu, Shengfan",Effects of post-instability induced by supercritical CO2 phase change on fracture dynamic propagation,Supercritical CO2 fracturing; Phase change; Post-instability; Equilibrium energy model; Fracture propagation coefficient,CARBON-DIOXIDE; GAS; FLUID; SHALE; WATER; STIMULATION; PRESSURE,"The effects of non-aqueous fracturing on unconventional reservoir stimulation have been investigated by laboratory and field work. Supercritical carbon dioxide (SC-CO2) is a notable non-aqueous fracturing fluid due to its potential to increase production, to reduce water requirements, and to minimize environmental impacts. In this paper, laboratory experiments conducted on polymethyl methacrylate (PMMA) are used to study the post-instability induced by SC-CO2 phase change on fracture dynamic propagation. Experimental results show that the fracture propagating speed of SC-CO2 fracturing is two order greater than that of hydraulic fracturing, and extensive hackle fractures occur in SC-CO2 fracturing. SC-CO2 phase change are mainly responsible for fracture post-instability, which dominates fracture propagation in SC-CO2 fracturing. Meanwhile, an equilibrium energy model of fracture dynamic propagation is proposed to describe the energy variation and transformation in porous medium. The concept of fracture propagation coefficient, i.e., the ratio of energy supplied by injection to fracture energy, is defined. SC-CO2 fracture propagation coefficient is much larger compared to hydraulic fracturing, suggesting that enough kinetic energy can accelerate fracture growth. This research may contribute to field application that SC-CO2 fracturing is likely to be an effective stimulation treatment, even in reservoir of undeveloped natural fractures.",34,35,4
Fracture,Fracture Propagation,"Wang, Y.; Li, C. H.; Hao, J.; Zhou, R. Q.",X-ray micro-tomography for investigation of meso-structural changes and crack evolution in Longmaxi formation shale during compressive deformation,Shale fracturing; Micro-tomography CT; X-ray imaging; Fracture evolution; Longmaxi shale,HIGH-RESOLUTION; MECHANICAL-PROPERTIES; TRIAXIAL COMPRESSION; COMPUTED-TOMOGRAPHY; CREEP; ROCK; MICROTOMOGRAPHY; VISUALIZATION; PROPAGATION; SIMULATION,"Shale is a typical heterogeneous geomaterial and investigation of the meso-structural changes and crack evolution is beneficial to shale gas development. Understanding the microscopic failure mechanism is undoubtedly crucial to hydraulic fracturing treatment. In this paper, real-time high-resolution X-ray Computed (micro-) Tomography (X-ray CT) with was used for the first time to deform shale sample experimentally under unconfined axial compression. Organic matter, pyrite, and micro-fractures were volumetrically rendered with a resolution of 11.27 mu m, and 2D/3D image investigations enabled us to explore the structure and fracture evolution of the sample due to in-situ compression. This work reveals that the stress-induced deformation of shale is found to be dependent on organic matter compaction, pyrite spatial evolution, and micro-fracture initiation, propagation, and coalescence. The volume of organic matter decreases with the increase of axial stress; and the spatial distribution of pyrite changes at different loading stages, but the effective volume is almost the same. The formation of macroscopic fractures similar to 20 degrees oblique to the loading direction was observed. The cracks initiate in the tensile cracks between the bedding plane at the bottom of the sample and shear fractures are composed of tensile cracks connected by an ""X"" shape. The layered deposited structure and weak cementation between layers are the main factors controlling the failure mechanism.",33,36,4
Fracture,Fracture Propagation,"Chen, Zhiqiang; Yang, Zhengming; Wang, Moran",Hydro-mechanical coupled mechanisms of hydraulic fracture propagation in rocks with cemented natural fractures,Hydraulic fracture; Cemented fracture; Natural fracture; LBM-DEM,LATTICE-BOLTZMANN METHOD; GENERAL SHAPES; BARNETT SHALE; FLUID-FLOW; PERMEABILITY; MODEL; DISCONTINUITIES; CRITERION,"Natural fractures commonly exist in unconventional reservoirs such as shale and tight gas sandstone, which are mostly cemented (or sealed) with minerals and not able to contribute to reservoir storage or rock permeability. However, during hydraulic fracture stimulation, these cemented natural fractures will be encountered and influence hydraulic fracture geometry greatly and, thereby, gas production. In this work, hydraulic fracture propagation in rock with cemented natural fracture is investigated using our recently developed and validated hydromechanical coupled LBM-DEM model. The numerical results show that both the strength ratio (between cemented natural fracture and host rock) and the approach angle (between hydraulic and cemented natural fracture) significantly affect the hydraulic fracture propagation. A larger strength contrast or a smaller approach angle will be more conducive to deflection, which is consistent with experimental observation. For rocks with weakly cemented natural fractures, deflection is mainly caused by shear failure in weakly cemented fracture. However, for rocks with strongly cemented natural fractures, deflection happens accompanying with tensile failure in host rock along the cement wall, which cannot be captured by the previous numerical models where the cemented natural fracture is treated as a bonded interface. In addition, complex fracture network is more easily formed if multiple weakly cemented natural fractures are orthogonal to the hydraulic fracture propagation direction.",31,32,3
Fracture,Fracture Propagation,"Wang, Weiwei; Olson, Jon E.; Prodanovic, Masa; Schultz, Richard A.",Interaction between cemented natural fractures and hydraulic fractures assessed by experiments and numerical simulations,Hydraulic fracturing; Cemented natural fractures; Fracture; Fracture interaction; Semi-circular bend experiment,ROCK; PROPAGATION; SHALE; INTERFACES; SPECIMEN; MODE; DISCONTINUITIES; BRITTLE; BASIN; VEINS,"Microseismic events suggest that a complicated fracture network develops during hydraulic fracturing treatment in many naturally fractured unconventional reservoirs. One reason for the complexity is the deformation along weak planes such as faults and cemented natural fractures. The interaction of cemented natural fractures with hydraulic fractures generated as part of reservoir stimulation may impede or terminate hydraulic fracture propagation, which depends on several factors such as interfacial bond strength between the cemented natural fractures and the reservoir rock. Most previous studies treat natural fractures as interfaces without considering their thickness. In this study, the semi-circular bend (SCB) tests for specimens with heterogeneity are used to study the fracture-fracture interactions, because the tensile fracture in the SCB test is analogous to the induced hydraulic fracture. With simple experimental setup and good repeatability, the SCB test results provide insights into real hydraulic fracture propagation behavior in naturally fractured reservoirs. We analyze the effects of natural fracture thickness and rock-cement interfacial bond strength, which are not commonly considered. Results show that hydraulic fracture crossing/diverting behavior depends on the approach angle, the rock-cement interfacial bond strength, and the thickness of natural fracture. Results also imply that as hydraulic fractures approach cemented natural fractures, the hydraulic fracture near. tip stress state is influenced by the tensile and shear strength of the rock-cement interface. In the SCB test, the sample geometry induces shearing along the cemented natural fracture-rock interface, analogous to a frictionally slipping interface in the subsurface. Depending on the frictional strength and the approach angle, the interface may crack apart, and attract a propagating fracture.",30,31,12
Fracture,Fracture Propagation,"Ren, Lan; Lin, Ran; Zhao, Jinzhou; Rasouli, Vamegh; Zhao, Jiangyu; Yang, Hao",Stimulated reservoir volume estimation for shale gas fracturing: Mechanism and modeling approach,Hydraulic fracturing; Stimulated reservoir volume; Fractures propagation; Shale gas; Mathematical model,HYDRAULIC FRACTURE; HORIZONTAL WELL; PROPAGATION; PERMEABILITY,"Multi-stage fracturing, following horizontal well drilling, is the key technology in shale gas reservoir development to enhance the recovery from such tight formations for economic production. The stimulated reservoir volume (SRV), which correlates closely to fracturing performance, is a quantitative measure for both pre-fracturing design and post-fracturing evaluation. However, an accurate estimation of the SRV is a long-standing challenge, because it requires a great knowledge of various parameters and complex mechanisms. In this study, we developed a mathematical model to estimate the SRV through simulating the main process during shale fracturing-multiple simultaneous hydraulic fractures propagate, perturbing the formation stress and raising the reservoir pressure; meanwhile, the stress change and pressure rise may jointly make natural fractures occur failure, and the SRV is estimated based on the volume of the naturally fractured zone that experiences tensile or shear failure. Hybrid numerical methods have been employed in this study. It applies displacement discontinuity method (DDM) to simulate non-planar hydraulic fractures propagation and represent the induced stress triggered by hydraulic fractures. The reservoir pressure is calculated by finite difference method (FDM). The failure state of natural fractures is predicted by the tensor equations deduced from Warpinski's failure theory. The model considers complex but important physical mechanisms that involved in the shale fracturing, including unequal flowrate distribution among each hydraulic fracture, non-planar hydraulic fractures propagation under stress interference, reservoir permeability increase with SRV extending (pressure & stress-depend), different failure states of natural fractures, etc. We validated our model by comparing its simulation results with analytical solution, published papers and onsite microseismic monitoring data. A field case study was performed to show the dynamic processes of hydraulic fractures propagation, reservoir permeability increase, and the SRV expansion during shale gas fracturing. Sensitivity analysis was conducted to investigate the influence of geological condition and fracturing parameters on SRV.",29,30,3
Fracture,Fracture Propagation,"Zhao, Zhiheng; Li, Xiao; He, Jianming; Mao, Tianqiao; Zheng, Bo; Li, Guanfang",A laboratory investigation of fracture propagation induced by supercritical carbon dioxide fracturing in continental shale with interbeds,Continental shale; Supercritical carbon dioxide fracturing; Stress; Interbed; Fracture propagation; Fracture quantification,,"Supercritical carbon dioxide (SC-CO2) used as a fracturing fluid in the shale fracturing stimulation is a promising technology as it can save much water and have some particular properties, such as low surface tension, large diffusion coefficient, strong permeable ability and adsorption capacity in shale. In previous studies, SC-CO2 fracturing presents great advantages in marine shale, granite and tuff. In this work, continental shale with interbeds from the Ordos Basin, China was used to conduct SC-CO2 fracturing experiments under the different stress conditions. Based on the observation of visible fractures before and after experiments, the fractures on the surface mainly propagate along natural fractures, bedding planes and interbeds, where crossing beddings and interbeds can also be observed. Besides, according to visualization and quantification of the main fractures and the main fracture surfaces by electronic microscope and three-dimensional scanner, with the increase in the stress difference, the main fracture can easily cross shale beddings and interbeds, and partial vertical fractures are formed, so tortuosity of the main fracture and roughness of the main fracture surface tend to increase. Furthermore, four main types of interactions between the main fracture and the fracture branch are obtained and the number of the fracture branches induced by the SC-CO2 fracturing is generally larger than that induced by the water fracturing. Meanwhile, compared with the water fracturing, it is implied that the breakdown pressure of SC-CO2 is generally lower, and its tortuosity of the main fracture and roughness of the main fracture surface tend to be higher under the same experimental conditions. Therefore, more curved and wavelike fractures with more branches can be generated in the continental shale SC-CO2 fracturing.",28,30,6
Fracture,Fracture Propagation,"Liu, Jun; Yao, Yanbin; Liu, Dameng; Xu, Lulu; Elsworth, Derek; Huang, Saipeng; Luo, Wanjing","Experimental simulation of the hydraulic fracture propagation in an anthracite coal reservoir in the southern Qinshui basin, China",Coalbed methane; Anthracite coal; Hydraulic fracture propagation; Reservoir stimulation; Qinshui basin,ROCK STRESS ESTIMATION; NUMERICAL-SIMULATION; METHANE RESERVOIR; SHALE RESERVOIRS; STIMULATION; PREDICTION; BEHAVIOR; VOLUME,"As coalbed methane (CBM) reservoirs have extremely low permeability, hydraulic fracturing is a common stimulation process for enhancing the CBM production. An in-depth understanding about the propagation mechanism of hydraulic fractures in coal is important for designing a hydraulic fracturing process and thus for improving the CBM production. This study performed a set of true tri-axial fracturing experiments on six block samples (300 mm x 300 mm x 300 mm, including raw coal and artificial roof/floor) with consideration of in situ conditions, aiming at simulating the propagation of hydraulic fractures in the CBM reservoir in the Changzhi field, southern Qinshui basin. Four groups of experiments were organized to evaluate the influences from the pre-existing natural fracture, in situ stresses and injection flow rates on the hydraulic fracture propagation. Meanwhile, five series of numerical simulations were constructed to model the relationship between in situ horizontal stresses and hydraulic fracture propagation. The results show that the hydraulic fracture propagates only along the pre-existing natural fracture direction under a small approaching angle, while it propagates along both the directions of the pre-existing natural fracture and the maximum horizontal principal stress (sigma < SUB > H < /SUB >) under a large approaching angle. Whether pre-existing natural fractures exist or not can result in a distinct influence on hydraulic fracture propagation. Hydraulic fractures straightly propagate along the sigma < SUB > H < /SUB > direction under a high value of horizontal stresses difference coefficient (K-h), while they tend to deviate from the sigma < SUB > H < /SUB > direction under a low K-h value. The influence of K-h is greater than that of the horizontal stresses difference (Delta sigma) in determining fracture propagation to extend along the sigma < SUB > H < /SUB > direction in the coal seam. Large approaching angle, high in situ stresses and a high injection flow rate are three major factors to cause the roof/floor broken by hydraulic fluids.",28,30,5
Fracture,Fracture Propagation,"Sheng, Mao; Li, Gensheng; Sutula, Danas; Tian, Shouceng; Bordas, Stephane P. A.",XFEM modeling of multistage hydraulic fracturing in anisotropic shale formations,Hydraulic fracturing; Crack propagation; Shale; Extended finite element method,EXTENDED FINITE-ELEMENT; DEFORMABLE POROUS-MEDIA; CRACK-GROWTH; FLUID-FLOW; PROPAGATION; ENRICHMENT; SIMULATION; SCHEMES; SOLIDS,"The aim of the present study is to help understand hydraulic fracture propagation in shale formations through numerical simulations. The hydraulic fracture propagation regime in shale is analyzed considering the anisotropic nature of the shale rock formation and slick-water fracturing fluid. It is determined that the dominant mechanism of hydraulic fracture propagation is the so-called transitional regime that is characterized by a negligibly small fluid lag region and zero fluid front pressure. For the modeling of the hydraulic fracture evolution over time, we assume orthotropic linear-elastic rock media and that the flow of the fracturing fluid is governed by the Reynold's lubrication equation. For the discretization of the coupled solid-fluid equations within the 2D plane-strain context we use the extended finite element method for the rock media and the finite volume method for the lubrication equation. The problem of the hydraulic fracture evolution over time is modeled as stable quasi-static crack growth where time is the result of upholding the mass conservation principle between the fluid inflow and the crack volume. The Picard iterative approach is used to solve the discrete non-linearly coupled solid-fluid equations. Our model is verified against several analytical solutions. Subsequently, a five-stage hydraulic fracturing problem is simulated to study the interactions between the different fractures. Results show that the on-going hydraulic fractures are attracted by the pre-existing hydraulic fractures as a result of the change of the local stress field relative to the initial in-situ stress field. For the cases considered, fracture deflections are found to be most extensive with decreasing fracture spacing and in-situ stress difference, but insensitive with the increasing the ratio of Young's moduli.",27,27,4
Fracture,Fracture Propagation,"Guo, Tiankui; Rui, Zhenhua; Qu, Zhanqing; Qi, Ning",Experimental study of directional propagation of hydraulic fracture guided by multi-radial slim holes,Radial slim hole; Hydraulic fracturing; Fracture propagation; Horizontal stress difference; Azimuth,NUMERICAL-SIMULATION; GLUTENITE RESERVOIR; INTEGRATED WORKFLOW; GAS-RESERVOIRS; SHALE; INITIATION; OIL; BOREHOLES; MODEL; PERFORATION,"The conventional hydraulic fracturing fails in the target oil/gas zone (remaining oil, closed reservoir, etc.) which is not located in the azimuth of maximum horizontal stress of available wellbores. The technology of directional propagation of hydraulic fracture guided by vertical multi-radial slim holes is innovatively developed. In order to verify this technology, lots of true triaxial hydraulic fracturing simulation experiments were carried out with artificial cores, aiming at investigating the influence of in-situ stress, fracturing fluid displacement, and azimuth, diameter, number, and spacing of radial slim holes on fracture propagation. The results show that directional propagation of hydraulic fractures guided by vertical multi-radial slim holes is feasible. Regardless of varied radial slim hole and in-situ stress parameters, hydraulic fracture always initiates in the heel of radial slim hole. For hydraulic fracturing assisted by single radial slim hole, smaller horizontal stress difference (3 MPa, sigma(H)/sigma(h) = 1.25) and smaller radial slim hole azimuth (15 degrees) may guide propagation of hydraulic fractures along radial slim hole, and larger horizontal stress difference (6 MPa, sigma(H)/sigma(h)= 1.67) can sharply reduce guidance of radial slim hole. Affected by mutual interference from guidance of radial slim holes and controlling of horizontal in-situ stress, fractures tend to distort along fracture length and fracture height. For hydraulic fracturing assisted by vertical multi-radial slim holes, horizontal stress difference is one of key factors influencing the directional propagation effect of hydraulic fracture. Larger horizontal in-situ stress difference (> 6 MPa, sigma(H)/sigma(h) > 1.67) hardly results in directional propagation of hydraulic fracture along radial slim hole row, and creates bigger diversion angle of fracture, and larger azimuth (> 45 degrees) of radial slim hole row reduces the guidance strength, resulting small fracture diversion radius. In conditions of larger angle between target zone and maximum horizontal stress, and requirement of large azimuth of radial slim hole row, the effective hydraulic fracture propagation along radial slim holes and ideal fracture height will be achieved through human intervention, e. g. increment of the number and diameter of radial slim holes, reduction of radial slim holes spacing, increment of fracturing fluid displacement, etc. The simulation results provide methods for designing directional propagation of hydraulic fractures guided by vertical multi-radial slim holes.",26,26,6
Fracture,Fracture Propagation,"Ghaderi, Amir; Taheri-Shakib, Jaber; Nik, Mohammad Amin Sharif",The distinct element method (DEM) and the extended finite element method (XFEM) application for analysis of interaction between hydraulic and natural fractures,Hydraulic fracture; Natural fractures; Production; Debonding; Shear failure; Tensile failure,MECHANICS MODEL; FLUID-FLOW; SIMULATION; PROPAGATION; JOINTS; ROCKS,"Hydraulic fracturing can be considered one of the most effective stimulation methods for fractured network formation. The interaction between induced and natural fractures greatly affects the success of the treatment. In this paper, the extended finite element method (XFEM) and distinct element method (DEM) have been combined to identify the propagation of hydraulic fractures in a porous medium with naturally fractured blocks. DEM is used to investigate hydraulic fractures in a natural-fracture network and evaluate the production flow rate under different apertures and lengths of hydraulic fracture. XFEM is used to simulate the deformation of the natural-fracture interface during the approaching phase of induced fractures as a no-remeshing tool. The results of DEM reveal that length of hydraulic fracturing has a significantly greater effect on production than aperture. Results from XFEM show that tensile and shear debonding of natural fractures change as a function of angle and distance from an induced fracture.",26,27,3
Fracture,Fracture Propagation,"He, Wenhao; Hayatdavoudi, Asadollah",A comprehensive analysis of fracture initiation and propagation in sandstones based on micro-level observation and digital imaging correlation,Fracture; Initiation and propagation; Displacement; Brazilian test; Scanning electron microscopy (SEM); Digital imaging correlation (DIC),TOUGHNESS DETERMINATION; TENSILE-STRENGTH; ROCK; SPECIMEN,"Along with the development of the oil & gas industry, the word ""fracture"" is now a quite familiar subject to well stability and integrity over the drilling process. However, the fracturing mechanisms are still less convincing though a large amount of literature have addressed the subject matter. In this paper, a new comprehensive experimental method is proposed herein to analyze the fracturing mechanisms through a micro-level observation to a macro explanation. To assess the tensile resistance of rock, Brazilian Test was applied to disc-shaped specimens of isotropic sandstones. Meanwhile, a high-speed photography system was keeping snapping images for the digital imaging correlation (DIC) to get a dynamic fracturing process. After the specimen failed and was split, the cuttings were analyzed using scanning electron microscope (SEM) and electron-dispersive system (EDS) for a micro-level observation. Two kinds of fracturing mechanisms were identified as: (1) grain fracturing, and (2) pore-fillings fracturing. Three basic fracture modes (Mode I/II/III) can also be distinguished through (1) the grain size, and (2) the grain shape and uniformity using a new parameter named angularity factor. The DIC technique proved to be a powerful analysis tool, especially showing the sequence of fracture initiation, propagation and termination. Though the cracks can be initiated from the center or near the loading points, the main direction of fracturing propagation was still along the diametric loading plane. In addition, a displacement along the thickness was also identified through a 3-D investigation, which should be of interest due to the scarcity of relevant literature in 3-D effect on standard 2-D Brazilian Test.",26,26,2
Fracture,Fracture Propagation,"Kamali-Asl, Arash; Ghazanfari, Ehsan; Newell, Pania; Stevens, Mathew","Elastic, viscoelastic, and strength properties of Marcellus Shale specimens",Shale gas; Failure strength; Ultrasonic velocity; Creep models; Elastic moduli; Viscoelastic; Cyclic,FRACTURE INITIATION; DEFORMATION; ROCK; PROPAGATION; ANISOTROPY; FAILURE,"Shale gas rocks are characterized as clastic sedimentary rocks, with features such as obvious bedding planes, presence of micro-cracks, and high clay and organic content. These rocks are anisotropic and inhomogeneous, exhibiting a nonlinear response under loading. In order to optimize the required energy for hydraulic fracturing operation and production in shale gas reservoirs, and for constitutive and numerical modeling, it is important to characterize these shale gas rocks. In this study, the hysteresis, elastic-plastic, viscoelastic, and strength properties of Marcellus Shale specimens, retrieved from a deep well located in West Virginia, were evaluated through performing a series of creep, cyclic, and triaxial multi-stage failure tests on these specimens. Both elastic moduli and plastic deformations show significant levels of pressure dependency. Moreover, higher creep compliance and lower Young's modulus values were observed for clay-rich specimens. Both Power-Law and Burgers' models were found to capture the creep response of these specimens reasonably well. The dynamic moduli estimated from the ultrasonic velocity measurements at different stress levels were found to be higher than static moduli estimations. In addition, the changes in the internal micro-structure of the specimens resulted from variations in the stress condition, were found to affect the ultrasonic velocity measurements. The strength properties of the calcite/quartz-rich specimen, using multi-stage triaxial failure test, were estimated through both Mohr-Coulomb and Hoek-Brown failure criteria.",25,25,9
Fracture,Fracture Propagation,"Wang, HanYi; Sharma, Mukul M.",Modeling of hydraulic fracture closure on proppants with proppant settling,Hydraulic fracture; Fracture closure; Proppant transport; Proppants settlement; Proppant dune; Stress amplification,SHALE-GAS-PRODUCTION; CONDUCTIVITY; PROPAGATION; SYSTEMS; EMBEDMENT; TRANSPORT; DESIGN; ROCKS; WIDTH,"The placement of proppants in a hydraulic fracture is governed by slurry flow, proppant transport and settlement. The proppant distribution can significantly affect the conductivity of the hydraulic fracture, and hence will impact the productivity of hydraulic fractured wells. Past studies have investigated fracture closure on proppants by envisioning hydraulic fractures as two parallel plates with uniformly distributed proppants. However, in reality, hydraulically induced fractures are wider in the middle and narrower near the fracture edges. In addition, a proppant dune is likely to be accumulated at the bottom of the fracture because of proppant settling. As a result, fracture closure on proppants is controlled by both fracture geometry and the distribution of proppant in the fracture. This is a dynamic process where fracture geometry and the proppant pack will evolve as a function of pressure, and the associated surface contact problem is notoriously challenging to solve because of its non-linear and nonlocal nature. In this study, we proposed a general approach to model hydraulic fracture closure. The residual fracture width profile for both propped and un-propped sections can be obtained at different drawdown pressures for rocks with different clay content. The maximum stress acting on proppants can be calculated to guide the selection of proppants with appropriate strength. Most importantly, the effect of stress concentration and stress amplification can be quantified when a proppant dune or bank is formed. We also show that the traditional method of estimating the maximum stress on a proppant pack is an underestimation.",23,23,2
Fracture,Fracture Propagation,"Luo, Zhifeng; Zhang, Nanlin; Zhao, Liqiang; Yao, Liming; Liu, Fei",Seepage-stress coupling mechanism for intersections between hydraulic fractures and natural fractures,Hydraulic fracturing; Natural fracture; Seepage-stress coupling; Staged fracturing; Extended finite element method; Stress shadow effect,PROPAGATION; CRITERION,"Most unconventional oil and gas reservoirs contain some natural fractures, which play an essential role during reservoir reconstruction. Given the strong discontinuities in the displacement on both sides of the fracture as well as weak discontinuities in the pore fluid pressure, a novel three-dimensional seepage-stress coupling model using extended finite element method is proposed for fractured reservoirs. This directly coupled scheme for displacement field and stress field avoids the cumbersome process during calculating the fluid pressure in complicated fracture networks and translating into equivalent nodal force. Numerical examples are presented to simulate the fracture propagation pathway during the laboratory experiment on the staged synchronous fracturing of a horizontal well, revealing the deformation response and interaction mechanism between hydraulic fractures and natural fractures at orthotropic and non-orthotropic angles. The results show that due to the stress shadow effects, a non-planar fracture deflecting to wellbore would be formed during the progress of staged synchronous fracturing for a horizontal well. Moreover, the adjacent section to the intersection is opened and the others are closed for orthogonal natural fracture. In contrast, the non-orthogonal natural fracture is activated near the intersection at first and then fully opens as time increases; eventually, it is in the tensile-shear and composite state. In other words, the hydraulic fracture tends to traverse the orthogonal natural fracture and continue to propagate, as it is more easily arrested by the oblique natural fracture and transferred to propagation.",22,23,2
Fracture,Fracture Propagation,"Nath, Fatick; Mokhtari, Mehdi",Optical visualization of strain development and fracture propagation in laminated rocks,Laminated formations; Fracture propagation; Full-field strain development; Fracture pattern; Indirect tensile test; Digital image correlation,ANISOTROPY; FAILURE; VELOCITY,"Shales are commonly anisotropic in nature due to layering and natural fractures which consequently impact the m0echanical behavior of shale in terms of stress-strain distribution, fracture initiation, propagation and fracture pattern. The classical method of strain measurement with strain gauges can not reveal the complex process of strain accumulation and fracture propagation in such anisotropic rocks. Therefore, we applied optical techniques along with image processing to measure strain on the surface of laminated Green River shale samples with various lamination angles under indirect tensile testing conditions. Full-field strain development was monitored over time and fracture patterns were identified utilizing digital image correlation (DIC) technique. A load-strain nature were established as a function of lamination angles incorporated with DIC generated horizontal, vertical and shear strain maps which results in better understanding of sequences in strain development and fracture pattern due to laminations. Variation in indirect tensile strengths are evaluated and reported with applied energy which shows that sample with higher tensile strength required higher applied energy to fail it. Fracture pattern obtained from DIC visualization are characterized which show that shear failure is dominant when failure occurred through laminations and tension for central failure samples. Finally, the measured axial strain from load frame is compared with DIC and achieved a considerable agreement in both measurement. The knowledge of this study can help in evaluating fracture behavior of laminated formations which can be important for energy-related activities including fracturing, fluid injection and extraction.",22,24,1
Fracture,Fracture Propagation,"Shimizu, Hiroyuki; Ito, Takatoshi; Tamagawa, Tetsuya; Tezuka, Kazuhiko",A study of the effect of brittleness on hydraulic fracture complexity using a flow-coupled discrete element method,Tight reservoir; Hydraulic fracturing; Brittleness; Discrete element method; Pre-existing fracture,PARTICLE-SIZE; MODEL; ROCK; STRESS; MECHANICS; SHALE,"In recent years, hydraulic fracturing has emerged as an important technique for the development of unconventional tight gas and oil reservoirs, particularly shale reservoirs. Production from a tight reservoir requires hydraulic creation of a highly fractured network for significantly improving the hydraulic conductivity of the reservoir. Field observations have empirically indicated that fracture complexity tends to be higher in the case of higher rock brittleness which is defined as the combination of the Young's modulus and Poisson's ratio of a rock. The brittleness is considered as one of the most important mechanical rock properties of unconventional tight reservoirs. However, the physical relationship between fracture complexity and the brittleness remains unclear. In this study, a series of hydraulic fracturing simulations were performed using a flow-coupled discrete element method to gain insights into the effect of the brittleness on fracture propagation. The brittleness was adjusted under different combinations of Young's modulus and Poisson's ratio for four rock models. Considering mechanical rock properties and pre-existing fractures, the effective stress in the case of lower brittleness reduced to the tension only around the tip of the hydraulic and pre-existing fractures. On the contrary, the tensile region was more widely distributed along the pre-existing fracture in the case of higher brittleness. The effective tensile stress in a wider region should induce more microcracks, thereby enhancing the possibility of the hydraulic fracture branching off from the pre-existing fracture. These considerations indicate a positive correlation between the brittleness and the complexity of a hydraulically induced fracture system.",21,23,2
Fracture,Fracture Propagation,"Yang, Zhao-Zhong; Yi, Liang-Ping; Li, Xiao-Gang; He, Wei",Pseudo-three-dimensional numerical model and investigation of multi-cluster fracturing within a stage in a horizontal well,Displacement discontinuity method; Multi-cluster fracturing; Horizontal well; Three-dimensional fracture,HYDRAULIC FRACTURES; PROPAGATION,"Multi-cluster fracturing and horizontal drilling are the key techniques used to exploit unconventional reservoirs. However, field production has revealed that certain perforation clusters are invalid. In order to find the most effective approaches to improve the uniformity of multiple-fracture growth, a pseudo-3D multi-cluster fracturing model is established in this study. In our model, complex in-situ stress distributions are considered and the stress interactions between fractures are calculated using the displacement discontinuity method (DDM). Fluid dynamic flow distributions into different clusters are calculated using Kirchhoff's second law. Fracture height and length extension velocities are determined based on the fracture edge energy release rate. The effectiveness of our model is verified by comparing the single fracture extension results obtained by our model to those obtained by a semi-analytical model. Based on our numerical model, possible approaches to promoting the uniform growth of multiple fractures are discussed. The results indicate that adjusting spacing is an inefficient method to promote multiple-fracture uniform growth under the condition of four clusters fracturing within a stage. However, regulating perforation friction, reducing fracturing fluid viscosity, and increasing injection rate are useful ways to improve the uniformity of multiple-fracture propagation.",20,24,4
Fracture,Fracture Propagation,"Ren, Guangwei; Nguyen, Quoc P.; Hon Chung Lau",Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants,CO2 soluble surfactants; Partition coefficient; CO2 foam; Fractured carbonate reservoir; EOR,INTERFACIAL-TENSION; GRAVITY DRAINAGE; MOBILITY CONTROL; CRUDE-OIL; DISPLACEMENT; EOR; MICROEMULSIONS; WETTABILITY; SOLUBILITY; REDUCTION,"Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions. A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 degrees C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water. RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam. These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.",19,20,2
Fracture,Fracture Propagation,"Weijermars, Ruud; Alves, Ibere Nascentes","High-resolution visualization of flow velocities near frac-tips and flow interference of multi-fracked Eagle Ford wells, Brazos County, Texas",Drained rock volume; Multi-staged fractured wells; Eagle Ford Formation,PRESSURE,"This study outlines a workflow that combines reservoir characterization and decline curve-based production analysis with a physics-based drainage model that quantifies where fluid is drained from, based on the fracture treatment architecture. Decline curve analysis, applied to production data from four multi-fracked wells in the Eagle Ford formation (Brazos County, East Texas), provides forecasts for the estimated ultimate recovery (EUR). About 50% of EUR is realized in the first 1000 days (similar to 3 years) of the well-life. The drainage model shows where in the reservoir the produced fluid is actually drained from, based on the estimated reservoir parameters. This study includes several fundamental assessments of factors that may impact any drainage model, such as (1) the pressure front propagation time responsible for the depth of investigation, (2) pressure effects due to up-scaling of fracture patterns into a reduced number of fractures, and (3) interaction of fluid velocity patterns with pressure depletion zones. The drainage model for the Eagle Ford wells in our case study suggests that the first generation of hydraulic fractures recovers less than 1% of the original oil in place. With recovery factors so low, a repetitive schedule of periodic refracking the wells - provided the first refracks prove successful - is highly recommended.",19,19,0
Fracture,Fracture Propagation,"Zhong, Ruizhi; Miska, Stefan; Yu, Mengjiao; Ozbayoglu, Evren; Takach, Nicholas",An integrated fluid flow and fracture mechanics model for wellbore strengthening,Wellbore strengthening; Near-wellbore fracturing; Integrated model; Lost circulation; Fracture mechanics; Parametric study,LOST-CIRCULATION,"Fracture-based wellbore strengthening techniques are preventive methods that can reduce the cost of lost circulation and non-productive time. The mud weight window can be extended by plugging fractures with wellbore strengthening materials (WSM) in the near-wellbore region. To maximize the strengthening effect, accurate fracture geometry prediction is of critical importance to the design of WSM. This paper presents a novel, coupled fluid flow and fracture mechanics model for wellbore strengthening applications that accounts for near-wellboreinduced fracture behavior. For fluid flow, mass conservation is considered and momentum conservation is examined; the latter shows that pressure loss with near-wellbore fracturing is low. Thus, we can neglect the pressure drop in the fractures and assume the fluid pressure inside the fractures is equal to the wellbore pressure. The pressure-width relationship (rock elastic deformation) and stress intensity factor are obtained by a dislocation- based approach. For the fracture propagation criterion, the calculated stress intensity factor is compared with fracture toughness at each time step. The stress intensity factor and fracture reopening pressure (FROP) are verified with Tada's model and Feng's model, respectively. Then, simulation results are compared with the large leak-off solutions of the Perkins-KernNordgren (PKN) fracture model. The simulation results reveal that the PKN model overestimates the fracture mouth width, fracture length, and wellbore pressure. Furthermore, the simulation results of wellbore pressure show a different trend. Therefore, we cannot directly use the PKN model to design wellbore strengthening applications. The main reason is the presence of wellbore can generate near-wellbore effects that cannot be disregarded. Finally, we conduct a comprehensive parametric study (i.e., fracture toughness, Young's modulus, Poisson's ratio, horizontal stress ratio, and permeability) on wellbore strengthening fracturing. The proposed model is useful for wellbore strengthening applications using the intentionally induced fractures (i.e., near-wellbore fracturing). Particle size distribution (PSD) of WSM can be designed based on the simulated fracture geometry. No complex model mesh generation or assignment of boundary conditions are needed, which are commonly used in finite element simulation or other numerical methods. The proposed model can also be used to optimize wellbore strengthening operations by performing sensitivity analysis.",19,19,0
Fracture,Fracture Propagation,"Zhao, Haifeng; Wang, Xiaohua; Liu, Zhiyuan; Yan, Yujie; Yang, Haixing",Investigation on the hydraulic fracture propagation of multilayers-commingled fracturing in coal measures,Coal strata; Commingled fracturing; Crack propagation; Geological factors; Engineering factors; Cohesive element,STRESS SENSITIVITY; LAYERED FORMATIONS; MODEL; CONTAINMENT; PERMEABILITY; DEFORMATION; SIMULATION; INTERFACE; WELL,"Multilayers-commingled fracturing is the vital step to achieve gas co-exploration in coal measures. Hydraulic fracture is required to penetrate vertically through multilayers in Multilayers-commingled fracturing. However, investigation on the propagation of commingled crack in coal measures which is soft-hard interlaced strata is less studied and not well understood. Therefore, based on the rock seepage-stress coupling effect, a three-dimensional (3D) hydraulic fracture model of multilayers-commingled fracturing in coal strata was established in combination with ABAQUS finite element software. The influence of geological factors and construction factors on the hydraulic cracks expansion in sandstone-coal interbedded reservoirs of X well in Linxing area in China was investigated. We found that the minimum horizontal stress difference is an essential geological factor to contain the vertical extension of commingled fractures; The high elastic modulus of neighboring reservoirs promotes the longitudinal penetration of fractures in the multilayers; The low tensile strength contrast between multiple layers increases the possibility of vertical expansion of combined fractures, while the high permeability of adjacent layers restrains the longitudinal propagation of fractures. The critical displacement of fracturing fluid exists in the combined fracturing process. The commingled cracks breakthrough the stratigraphic interface and penetrate into the adjoining layers when reaching the critical displacement; The high-viscosity of fracturing fluid facilitates the extending behaviors of hydraulic cracks in the vertical direction. The research results provide theoretical guidance for optimization of commingled fracturing layers and design of construction parameters in coal strata.",18,18,8
Fracture,Fracture Propagation,"Zhang, Luqing; Zhou, Jian; Braun, Anika; Han, Zhenhua",Sensitivity analysis on the interaction between hydraulic and natural fractures based on an explicitly coupled hydro-geomechanical model in PFC2D,Hydraulic fracturing; Sensitivity analysis; Explicitly coupled hydro-geomechanical model; Numerical simulation; Two-dimensional particle flow code (PFC2D),FLUID VISCOSITY; FINITE-ELEMENT; PROPAGATION; SHALE; ROCK; SIMULATION; INITIATION; INJECTION; BOREHOLE; BRITTLE,"Fluid-induced fracture nucleation, propagation and interaction with natural fractures are the crucial issues for well understanding the process of hydraulic fracturing in unconventional reservoirs. In this paper, an explicitly coupled hydro-geomechanical model in two-dimensional Particle Flow Code (PFC2D) is employed to investigate the interaction between hydraulic fractures (HFs) and natural fractures (NFs), and the numerical scheme is validated by using analytical results. Several factors affecting the interactions between induced-fractures and NFs are being investigated and discussed. The simulation results show that three fundamental crossing scenarios can be well reproduced: (I) Direct Crossing, (II) Offset Crossing and (III) No Crossing (Arrested), and the crossing types agree well in the evaluation by Blanton's criterion. A sensitivity analysis shows that hydraulic fracture (HF) tend to be arrested by a natural fracture (HF) under low approach angles and prefer to cross the NF under higher in-situ differential stress states. Crossing is likely to be impeded for NFs with lower frictional coefficient and higher permeability. Additionally, lower fracturing fluid injection rates and lower fluid viscosities both are advantageous conditions for NF reactivation, and tend to arrest the HF. Moreover, the mechanism of the interaction of HFs and NFs influenced by the aforementioned factors can be well explained by the evolution of normal stress on the pre-existing interface, which is the key issue for correct simulation of hydraulic fracturing. Compared with the analytical model, the model in this study can reflect the dynamic stress evolution process, which will be a useful tool for optimizing the design of hydraulic fracturing in fractured reservoirs.",17,19,2
Fracture,Fracture Propagation,"Ranjith, P. G.; Wanniarachchi, W. A. M.; Perera, M. S. A.; Rathnaweera, T. D.",Investigation of the effect of foam flow rate on foam-based hydraulic fracturing of shale reservoir rocks with natural fractures: An experimental study,Foam; Fracturing; Breakdown pressure; Flow rate; Fracture permeability; CT scanning,PERMEABILITY; PRESSURE; ENERGY; GAS; PROPAGATION,"Foam-based hydraulic fracturing has been identified as a good solution for the extraction of natural gas from deep shale reservoirs, due to its unique advantages such as low water consumption and high proppant carrying capacity. However, lack of knowledge of foam-based shale fracturing and complex nature of two-phase foam, make it challenging to use in field conditions, and one unclear area is the effect of the foam flow rate on fracturing and fracture characteristics. Therefore, the aim of this study was to investigate the effect of foam flow rate on breakdown pressure, fracture permeability and generated fracture characteristics. In order to achieve this, a series of hydraulic fracturing experiments was conducted for shale rocks with existing natural fractures, using nitrogen-based foam. Fracture permeability was also evaluated for intact and fractured rock samples. Micro-CT scanning technology was adopted to characterise the geometrical properties of fractures, in order to investigate the effect of foam flow rate within the fracture. Experimental results show that the breakdown pressure increases by 30% while energy release decreases by 78% when the foam flow rate increases from 10 to 70 ml/min. In addition, the results suggest that the permeability of a fractured sample at 10 ml/min injection rate is about 15 times higher than that of a fractured sample at 70 ml/min injection rate. The findings of this study reveal that low foam-flow rates can create a better inter-connected fracture network than higher flow rates.",15,15,4
Fracture,Fracture Propagation,Liu Qingling; Tian Shouceng; Li Gensheng; Sheng Mao; Li Xiaojiang; Wang Tianyu; Shen Zhonghou,An analytical model for fracture initiation from radial lateral borehole,Analytical model; Radial drilling; Hydraulic fracturing; Fracture initiation pressure; Location of failure zone; Initial fracture direction,HYDRAULIC FRACTURE; INTEGRATED WORKFLOW; DIRECTIONAL WELL; MECHANISMS; STRESS; PROPAGATION; SIMULATION; ROCKS; TESTS; SIZE,"Radial drilling-fracturing, the integration of radial drilling and hydraulic fracturing, is an innovative approach to develop low permeability, thin target layer and naturally fractured reservoirs, etc. Understanding the fracture initiation process is required in the practical application to avoid high fracture initiation pressure (FIP) and complex fracture geometries near the wellbore. In this paper, we develop an analytical model to determine FIP, location of rock failure zones and initial fracture direction from the radial lateral borehole. This model is based on the stress superposition induced by cased main wellbore and radial borehole, and the maximum tensile stress criterion is adopted. Then, we perform a series of sensitivity analysis by examining different effects of in-situ stress regime, lateral orientation (the included angle between borehole axis and maximum horizontal in-situ stress), lateral length, and lateral diameter. Besides, the effect of pre-existing weakness plane, across which the tensile strength is much lower than that of the intact rock, is also investigated, when the plane is drilled through by the radial borehole. Results show that for intact rock with no weakness plane, the in-situ stress regime and lateral orientation are main factors influencing FIP, location of rock failure zones, and initial fracture direction. Under the in-situ stress regime of normal fault, fracture initiates vertically, and FIP enlarges as lateral orientation increasing; under the in-situ stress regime of strike slip, fracture initiates vertically with small lateral orientation, while fracture initiates horizontally with large lateral orientation; and under the in-situ stress regime of reverse fault, fracture initiates horizontally with any lateral orientation, and FIP decreases as the lateral orientation increasing. It is also found that when the fracture initiates vertically, the location of rock failure zones is at the base of radial borehole on its top and bottom sides; and when the fracture initiates horizontally, the location of rock failure zone is at the remote region of radial borehole on its right and left sides. The lateral length has a minor effect on fracture initiation, and the influence of lateral diameter is negligible. When the weakness plane is drilled through by the radial borehole, fracture initiation pressure from weakness plane is affected by its occurrence, i.e., azimuth and inclination. FIP is determined by taking the minimum between fracture initiation pressure from rock matrix and the weakness plane. The key findings of this work could provide critical insights into understanding radial drilling-fracturing initiation characteristics.",15,15,3
Fracture,Fracture Propagation,"Ding, Yi; Liu, Xiangjun; Luo, Pingya",The analytical model of hydraulic fracture initiation for perforated borehole in fractured formation,Fractured formation; Fracture operation; Multiple fracture planes; Fracture initiation,PROPAGATION; RESERVOIRS; WELLBORE; STABILITY; WELLS; SHALE,"Hydraulic fracturing has been the common method of stimulation treatment. Effective fracture network needs to be formed for having efficient hydraulic fracturing. The forming process of fracture network can be divided into 2 parts, i.e., initiation and propagation. In particular, the initiation part is the foundation of forming fracture network, and also basic parameter for analyzing fracture propagation. However, in fractured formation, it is very tricky to obtain initial fracture pressure due to the influence of rich natural fractures. Therefore, based on the rock mechanics and spatial geometry theory, this paper presents a mechanical model for predicting fracture initiation in fractured formation. Unlike conventional model, this new model considers multiple fractures conditions and the intersection method between natural fractures and perforated borehole. The model has been used to investigate influence factors of initial fracture pressure. These computed results reveal that the initial fracture pressure has complex distribution, and changes with variable occurrence of natural fracture. There are different kinds of intersections between natural fracture and perforated borehole. When fracture plane intersects through perforated borehole, influence of fracture plane on fracture initiation is relatively larger. Furthermore, with increasing number of natural fractures, initial fracture pressure decreases and the initiation mode tends to be tensile failure along natural fracture plane. Additionally, engineering parameters, like well trajectory and perforation azimuth, are related to fracture initiation pressure. Their optimizations can contribute to perform optimization of reservoir stimulation. Results from this model used in this paper aim at offering reference for field fracturing practice in fractured formation.",15,16,2
Fracture,Fracture Propagation,"Zeng, Qingdong; Liu, Wenzheng; Yao, Jun",Hydro-mechanical modeling of hydraulic fracture propagation based on embedded discrete fracture model and extended finite element method,Numerical modeling; Hydro-mechanical coupling; Hydraulic fracturing; EDFM; XFEM,NUMERICAL-SIMULATION; POROUS-MEDIA; CRACK-GROWTH; COUPLED FLOW; FLUID-FLOW; RESERVOIR; CONVERGENCE; INITIATION; SCHEMES; STRESS,"In this study, an efficient hydro-mechanical model of hydraulic fracture propagation is proposed using the embedded discrete fracture model in conjunction with the extended finite element method. Fracture is embedded into a common computational grid for both stress and pressure fields. A hybrid scheme of fixed stress split and Picard iterative method is presented to deal with the hydro-mechanical coupling and fracture propagation. The model is verified against other numerical solution of hydro-mechanical coupling problem and analytical solution of fracture propagation available from literature. Numerical results show that as matrix permeability increases, more fracturing fluid is required to get a desired length of fracture. The effect of Biot's coefficient is similar to that of matrix permeability. Finally, the model is extended to simulate simultaneous propagation of multiple hydraulic fractures. It's interesting to find that the effect of stress shadowing could be weakened by the poroelastic stress when accounting for hydro-mechanical coupling. The study indicates that the hydro-mechanical coupling could have significant influence on hydraulic fracturing, especially for multi-cluster fracturing of horizontal wells.",14,14,4
Fracture,Fracture Propagation,"Zhang, Hua; Yin, Shunde; Aadnoy, Bernt",Poroelastic modeling of borehole breakouts for in-situ stress determination by finite element method,Borehole breakouts; Finite element method; Inverse analysis; In-situ stress; Poroelasticity,PRINCIPAL STRESS; CAJON PASS; FAILURE; WELL; FRACTURE; ROCK; CRITERION; STRENGTH; MOGI,"Borehole breakouts are changes in borehole geometry in a cross section perpendicular to the borehole axis when rock subjected to in-situ stress experiences shear failure. By finite element modeling of borehole breakouts considering poroelasticity, the authors simulate the process of borehole breakouts in terms of initiation, propagation and stability in the condition of Mogi-Coulomb criteria, and can get the shape of borehole breakouts. It's desirable that this information of borehole breakouts can be used to determine in-situ stress by inverse analysis. Artificial neural network provides such a tool to establish the relationship between in-situ stress and shape on borehole breakouts, by which in-situ stress can be obtain according to different shape of borehole breakouts. In this paper, there are two steps to determinate in-situ stress by inverse analysis. First, Sets of finite element modeling provides sets of data on in-situ stress and borehole breakout measures, which will be used to train an artificial neural network that can eventually represent the relationship between the in-situ stress and borehole breakout measures. Second, for a given measure of borehole breakouts, the trained artificial neural network will be used to predict the corresponding in-situ stress. Results show that the inverse analysis based on finite element modeling of borehole breakouts and artificial neural network can effectively determine in-situ stress.",14,14,4
Fracture,Fracture Propagation,"Zhao, Xianyu; Wang, Tao; Elsworth, Derek; He, Yunlong; Zhou, Wei; Zhuang, Li; Zeng, Jun; Wang, Suifeng",Controls of natural fractures on the texture of hydraulic fractures in rock,Hydraulic fracturing; Jointed rock mass; DEM; Crack propagation,SIMULATION; MODEL,"Hydraulic fracturing plays an important role in the exploitation of oil, shale gas and coal seam gas resources-all of which contain natural fractures. We systematically explore the role of the pre-existing texture of such natural fractures on the form of the resulting stimulated reservoir volume (SRV). A blocky discrete element model (DEM) coupled with fluid flow is used to explore this response. Numerical predictions for the evolution of fluid pressure and fracture width at the well are compared with first-order analytical approximations of the zero-toughness solution (FMO). We then construct four typical joint system models separately comprising orthogonal, staggered, diagonal and randomly oriented joints and conduct the virtual hydraulic fracturing simulations via DEM. This defines the influence of structure on breakdown pressure and fracture propagation and allows the analysis of the main factors that influence behavior and resulting SRV. Results for the four forms of jointed rock mass show that: (1) the aggregate/mean extension direction of the fractures is always along the direction of the maximum principal stress but significant deviations may result from the pre-existing fractures; (2) there are negative correlations between the maximum fracture aperture with both Poisson ratio and elastic modulus, but the breakdown pressure is only weakly correlated with Poisson ratio and elastic modulus; (3) an increase in injection rate results in a broader fracture process zone extending orthogonal to the principal fracture, and the breakdown pressure and interior fracture aperture also increase; (4) an increase in fluid viscosity makes the fractures more difficult to extend, and the breakdown pressure and interior fracture aperture both increase accordingly.",14,14,3
Fracture,Fracture Propagation,"Nath, F.; Kimanzi, R. J.; Mokhtari, M.; Salehi, S.",A novel method to investigate cement-casing bonding using digital image correlation,Casing/cement bonding; Water-cement ratio; Deformation; Strain development; Digital image correlation; Fracture,CAKE-SOLIDIFICATION-AGENTS; MUD; OIL,"The main focus of current industry practices on the cementing of oil and gas wells is short-term cement-design goals such as high strength, adequate pumpability and proper placement of cement in the wellbore. However, the bond between cement and casing is a major factor for long-term integrity of wellbore which requires more attention with the current increasing trend in horizontal drilling and hydraulic fracturing operations in unconventional resources. These wells experience various kinds of forces throughout their life in which the casing and cement bond can play a critical role in the integrity or failure of these wells. In this paper, we apply digital image correlation (DIC) technique to monitor strain development over the surface of a casing filled with cement while it is diametrically compressed. In this technique, the casing/cement sample is painted with random white and black speckles and the surface of sample is recorded by camera. Finally, strain development with time is calculated using image processing technique. This visualization helps to find out the points of weakness for strain accumulation which eventually end up for fracture initiation and propagation. In this laboratory setup, the tensile strain accumulation is the highest on the casing/cement interface 90-degree away from casing/loading point and the strain gradually increases at the casing/cement interface toward the casing/loading point. Then there is fracture generation at the center of cement sample propagating toward casing/loading point. We also review the impact of cement contamination, barite and water-cement ratios on cement/casing bonding and their associated DIC results.",14,14,0
Fracture,Finite Element,"Taleghani, Arash Dahi; Gonzalez-Chavez, Miguel; Yu, Hao; Asala, Hope",Numerical simulation of hydraulic fracture propagation in naturally fractured formations using the cohesive zone model,Hydraulic fracturing; Cohesive zone model; Fracture intersections; Natural fractures; Complex fracture network; Traction separation law,BARNETT SHALE; STRESS; PRODUCTIVITY; RESERVOIRS; SYSTEMS; IMPACT; JOINTS,"This paper presents an integrated methodology that utilizes the cohesive zone model (CZM) to simulate propagation of hydraulic fractures, and their interactions with pre-existing natural fractures. CZM has the advantage of capturing the non-elastic behavior of shales; usually induced by total organic carbon (TOC) as well as dissimilar mechanical properties of cemented natural fractures. At the intersection of an advancing hydraulic fracture and a stationary natural fracture, the hydraulic fracture may arrest, cross, or divert into a pre-existing natural fracture depending on the rock mechanical properties, magnitude and direction of rock principal stresses, and fracture intersection angle. The activation of natural fractures during hydraulic fracture treatments improves fracture complexity and expands reservoir drainage area, making stimulation treatments more effective. In this work, triaxiality effects are incorporated into the cohesive zone model. Utilizing triaxiality makes the traction separation law (TSL) tied to confining pressure and this ensures a more reliable transition from laboratory test environment to bottomhole conditions. We present a methodology to determine the cohesive properties or TSL characteristics of rock, after performing semicircular bending tests (SCBT). Finite element analysis (FEA) is then used to calibrate the cohesive properties of both rock and natural fractures. The calibrated parameters were utilized in a field-scale FEA to simulate the growth of complex fracture networks. The results show how fracture intersection angle and the nature of cemented materials inside the natural fractures might divert a hydraulic fracture initially propagating in a direction perpendicular to the minimum horizontal stress. The sensitivity analysis of primary parameters such as fluid viscosity, natural fracture distribution, fracture intersection angle, and differential stresses is implemented to provide a better insight into the performance of hydraulic fracturing jobs in naturally fractured reservoirs. Results indicate the importance of nonlinear fracture tip effects as in-situ stress differences increase.",77,79,8
Fracture,Finite Element,"Zeng, Qing-Dong; Yao, Jun; Shao, Jianfu",Numerical study of hydraulic fracture propagation accounting for rock anisotropy,Hydraulic fracturing; Crack propagation; Rock anisotropy; XFEM; Numerical modeling,FINITE-ELEMENT-METHOD; CRACK-PROPAGATION; ORTHOTROPIC MEDIA; SIMULATION; GROWTH,"The objective of this study is to investigate the effect of rock anisotropy on hydraulic fracture propagation. The coupled model of rock deformation and fluid flow is established to study hydraulic fracturing of orthotropic formation. Stress field is solved by using the extended finite element method with special tip enrichment functions for orthotropic formation. The coupling between stress field and pressure field is treated by Picard iterative procedure. The modified circumferential tensile stress criterion is used to determine fracture propagation, in which stress intensity factors are determined by an interaction integral method. Numerical results show that when fracture doesn't initiate from the direction of material axis with larger modulus, the fracture propagation direction would change and divert to the direction of material axis with larger modulus. And as Young's modulus ratio between two material axes increases, the phenomenon becomes more obvious. Moreover, shear modulus also enhances the diversion phenomenon of fracture propagation direction. However, the in-situ stress difference could weaken the effect of rock anisotropy. The results indicate that the propagation process of hydraulic fracture is influenced by comprehensive factors including material axis angle, Young' modulus ratio, shear modulus and in-situ stress difference.",51,52,2
Fracture,Finite Element,"Xi, Yan; Li, Jun; Liu, Gonghui; Cha, Chunqing; Fu, Yongqiang",Numerical investigation for different casing deformation reasons in Weiyuan-Changning shale gas field during multistage hydraulic fracturing,Volume fracturing; Casing deformation; Numerical calculation; Lithologic interface; Cement void; Formation slipping,UNCONVENTIONAL RESERVOIRS; HORIZONTAL WELLS; FINITE-ELEMENT; DESIGN; VOLUME; PRESSURE; WEAR,"Casing deformation has been found to be a very significant issue in the development process of shale gas in China. The rate of casing deformation is 34.34% (34 wells of 101), and statistical data show that it decreased the test output of wells by approximately 30%. Based on investigation and analysis of the engineering and geological conditions of 25 wells, 12 of which have casing deformations, both physical models and finite element models were established. Furthermore, the effects of fracturing pressure, geostress, anisotropy, lithologic interface, temperature variation, and cement void were analyzed. The results show the following. a) When the casing deformation points appear far away from point A (the landing point, which is the starting point of the horizontal segment), the influence of the lithologic interface on casing stress plays a decisive role under the combined effect of internal and external pressures when the cement sheath is completed. b) Under the same conditions, but when the casing is in contact with the borehole wall near the bottom because of gravity, a narrow fluid retention space was formed, leading to cementing sheath voids. The effect of cement void pressure reduction is the main reason behind the casing deformation. c) When casing deformation points appear near point A, the activation of the weak plane in the beddings during fracturing causes the casing deformation. The stress of 14 casing deformation points was calculated according to actual engineering and geological conditions, and 78.6% of the results were consistent with field measurements.",35,41,3
Fracture,Finite Element,"Sheng, Mao; Li, Gensheng; Sutula, Danas; Tian, Shouceng; Bordas, Stephane P. A.",XFEM modeling of multistage hydraulic fracturing in anisotropic shale formations,Hydraulic fracturing; Crack propagation; Shale; Extended finite element method,EXTENDED FINITE-ELEMENT; DEFORMABLE POROUS-MEDIA; CRACK-GROWTH; FLUID-FLOW; PROPAGATION; ENRICHMENT; SIMULATION; SCHEMES; SOLIDS,"The aim of the present study is to help understand hydraulic fracture propagation in shale formations through numerical simulations. The hydraulic fracture propagation regime in shale is analyzed considering the anisotropic nature of the shale rock formation and slick-water fracturing fluid. It is determined that the dominant mechanism of hydraulic fracture propagation is the so-called transitional regime that is characterized by a negligibly small fluid lag region and zero fluid front pressure. For the modeling of the hydraulic fracture evolution over time, we assume orthotropic linear-elastic rock media and that the flow of the fracturing fluid is governed by the Reynold's lubrication equation. For the discretization of the coupled solid-fluid equations within the 2D plane-strain context we use the extended finite element method for the rock media and the finite volume method for the lubrication equation. The problem of the hydraulic fracture evolution over time is modeled as stable quasi-static crack growth where time is the result of upholding the mass conservation principle between the fluid inflow and the crack volume. The Picard iterative approach is used to solve the discrete non-linearly coupled solid-fluid equations. Our model is verified against several analytical solutions. Subsequently, a five-stage hydraulic fracturing problem is simulated to study the interactions between the different fractures. Results show that the on-going hydraulic fractures are attracted by the pre-existing hydraulic fractures as a result of the change of the local stress field relative to the initial in-situ stress field. For the cases considered, fracture deflections are found to be most extensive with decreasing fracture spacing and in-situ stress difference, but insensitive with the increasing the ratio of Young's moduli.",27,27,4
Fracture,Finite Element,"Ghaderi, Amir; Taheri-Shakib, Jaber; Nik, Mohammad Amin Sharif",The distinct element method (DEM) and the extended finite element method (XFEM) application for analysis of interaction between hydraulic and natural fractures,Hydraulic fracture; Natural fractures; Production; Debonding; Shear failure; Tensile failure,MECHANICS MODEL; FLUID-FLOW; SIMULATION; PROPAGATION; JOINTS; ROCKS,"Hydraulic fracturing can be considered one of the most effective stimulation methods for fractured network formation. The interaction between induced and natural fractures greatly affects the success of the treatment. In this paper, the extended finite element method (XFEM) and distinct element method (DEM) have been combined to identify the propagation of hydraulic fractures in a porous medium with naturally fractured blocks. DEM is used to investigate hydraulic fractures in a natural-fracture network and evaluate the production flow rate under different apertures and lengths of hydraulic fracture. XFEM is used to simulate the deformation of the natural-fracture interface during the approaching phase of induced fractures as a no-remeshing tool. The results of DEM reveal that length of hydraulic fracturing has a significantly greater effect on production than aperture. Results from XFEM show that tensile and shear debonding of natural fractures change as a function of angle and distance from an induced fracture.",26,27,3
Fracture,Finite Element,"Asadollahpour, E.; Baghbanan, A.; Hashemolhosseini, H.; Mohtarami, E.",The etching and hydraulic conductivity of acidized rough fractures,Acid fracturing; Fracture hydraulic conductivity; Numerical modeling; Normal deformation; Rock embedment strength,FLUID-FLOW; ROCK; APERTURE; SURFACES; PERMEABILITY; BEHAVIOR; STRESS; JOINTS,"Acid fracturing is one of the eligible techniques for increasing productivity of hydrocarbon reservoirs. Laboratory tests are performed on reservoir rock samples to improve understanding of acid fracture performance. Fractures formed by hydraulic fracturing or acid fracturing before acid etching are rough, therefore in this study, an acid injection cell was developed to study surface etching in rough fracture acidizing on Asmari limestone samples (one of Iran's reservoir rocks). In this research, the effects of acidizing at different times on roughness evolution and also conductivity of fractures with rough surfaces were investigated experimentally and numerically. Conductivity of fractures in low stresses was determined using permeability test. In the case of high stresses, conductivity was determined using a penetration model and local aperture (derived from surface scan) and a numerical finite element code developed in MATLAB. Results showed that increase in the initial roughness coefficient and the linear roughness of fracture surface resulted in higher surface etching and higher dissolved rock equivalent conductivity (DREC). With increase in fracture surfaces mismatch, fracture aperture and eventually initial fracture conductivity also increase. In this study, for the first time, mismatch in acidized fracture has been defined as linear roughness difference and roughness coefficient difference of lower and upper fracture surfaces. Increase in acidizing time resulted in higher difference in roughness coefficient, linear roughness of the two surfaces of fractures, and higher initial conductivity. Also, increase in rock embedment strength clearly increased final conductivity for samples with 20 min acidizing time. However, for samples with 10 min of acidizing time, final conductivity of fractures depends on roughness distribution. Measuring normal deformation of fracture emergent from applied normal stress showed that longer durations of acid injection exhibit more normal deformation and lower final conductivity. Final conductivity increases with decrease in kurtosis of roughness distribution and maximum fracture closure. Eventually, a logarithmic relation for decreasing rate of conductivity with closure stress (C-2 in Nierode and Kruk's equation) was approximated using rock embedment strength for Asmari limestone.",25,25,1
Fracture,Finite Element,"Ju, Wei; Yang, Zhaobiao; Qin, Yong; Yi, Tongsheng; Zhang, Zhengguang","Characteristics of in-situ stress state and prediction of the permeability in the Upper Permian coalbed methane reservoir, western Guizhou region, SW China",Coal permeability; In-situ stress state; Coalbed methane reservoir; Numerical simulation; Upper permian; Western Guizhou region,EASTERN ORDOS BASIN; TECTONIC STRESS; PORE PRESSURE; FIELD; EXPLORATION; AREA; SEQUESTRATION; ORIENTATION; MAGNITUDE; POROSITY,"Coal permeability and in-situ stress state are important parameters for coalbed methane (CBM) exploration and development; however, the distribution pattern of the Upper Permian CBM reservoir permeability is poorly understood in the western Guizhou region, SW China. In the present study, based on measured injection/falloff and in-situ stress data in the Upper Permian coal seams of western Guizhou region, the present-day in-situ stress field, and its correlation with coal permeability were investigated. The orientation of the horizontal maximum principal stress (S-Hmax) indicated a dominant similar to NW-SE-trending. In addition, the present-day in-situ stress field showed an important control on coal permeability. The permeability in the Upper Permian coal seams decreased exponentially with the increased effective in-situ stress magnitude. By utilizing the finite element method (FEM), the present-day in-situ stress field in the western Guizhou was numerically analyzed based on a geomechanical two-dimensional (2D) model. Distribution of coal permeability in the Upper Permian CBM reservoir was predicted based on the relationship between coal permeability and effective in-situ stress magnitude. The results indicated that, in the western Guizhou region, vertically, coal permeability was relatively high and widely distributed shallower than approximately 780m below ground level (bgl), whereas, it was extremely low and regularly varied with burial depth deeper than approximately 780m bgl. Laterally, the distribution pattern of coal permeability was characterized by strong heterogeneity due to well-developed faults and folds. High values of the Upper Permian coal permeability were located in regions around Nayong-Zhijin, Panxian-Anlong and along Shuicheng-Liuzhi- Ziyun. The present study may provide geological references for the CBM reservoir productivity and subsequent analysis (e.g., wellbore stability, hydraulic fracturing design, and fault reactivation studies, etc.) in the western Guizhou region.",24,29,4
Fracture,Finite Element,"Feng, Jianwei; Ren, Qiqiang; Xu, Ke","Quantitative prediction of fracture distribution using geomechanical method within Kuqa Depression, Tarim Basin, NW China",3D tectonic stress field; Tectonic fractures prediction; Geomechanical model; Super-deep tight sandstone; Top-popup fold,TECTONIC STRESS-FIELD; FAULT-BEND FOLDS; NUMERICAL-SIMULATION; PORE PRESSURE; MODELS; EVOLUTION; PROVINCE; ZONES; ACCUMULATION; RESERVOIRS,"Understanding and predicting the development and distribution of tectonic fractures in the super-deep tight sandstone reservoir are important for both gas exploration and exploitation activities in Kuqa Depression. We analyzed the characteristics of regional structural evolution and paleotectonic stress field setting. A reasonable geological model of the research area was built based on an interpretation of the geological structure, a test for rock mechanics, and experiment on acoustic emission. Thereafter, a three-dimensional paleotectonic stress field during the Late Himalayan movement was simulated by the finite element method. Composite rock failure criterion and geomechanical models between fracture density, aperture, strike and strain energy density were used to determine the quantitative development of fractures and predict zones that are prone to fracture development. Areas with well-developed tectonic fractures are mainly controlled by the tectonic stress field and elastic strain energy density, typically located in the fold limbs, fault zones and locations of changes in the orientation of fault. In turn, factors of faults, the lithology, depth and curvature control the development and distribution of tectonic fractures in the tight sandstone. The overall simulated results match well with core observation and FMI (Formation MicroScanner Image) results both in the whole geometry and fracture distribution. This evolutionary model of the structures present to us is a distinct and intuitive top-popup fold with low amplitude and relatively low-density fractures in the top, has only experienced pre-folding stage and strong folding stage, and has not yet been developed to vertical uplift stage.",23,26,6
Fracture,Finite Element,"Luo, Zhifeng; Zhang, Nanlin; Zhao, Liqiang; Yao, Liming; Liu, Fei",Seepage-stress coupling mechanism for intersections between hydraulic fractures and natural fractures,Hydraulic fracturing; Natural fracture; Seepage-stress coupling; Staged fracturing; Extended finite element method; Stress shadow effect,PROPAGATION; CRITERION,"Most unconventional oil and gas reservoirs contain some natural fractures, which play an essential role during reservoir reconstruction. Given the strong discontinuities in the displacement on both sides of the fracture as well as weak discontinuities in the pore fluid pressure, a novel three-dimensional seepage-stress coupling model using extended finite element method is proposed for fractured reservoirs. This directly coupled scheme for displacement field and stress field avoids the cumbersome process during calculating the fluid pressure in complicated fracture networks and translating into equivalent nodal force. Numerical examples are presented to simulate the fracture propagation pathway during the laboratory experiment on the staged synchronous fracturing of a horizontal well, revealing the deformation response and interaction mechanism between hydraulic fractures and natural fractures at orthotropic and non-orthotropic angles. The results show that due to the stress shadow effects, a non-planar fracture deflecting to wellbore would be formed during the progress of staged synchronous fracturing for a horizontal well. Moreover, the adjacent section to the intersection is opened and the others are closed for orthogonal natural fracture. In contrast, the non-orthogonal natural fracture is activated near the intersection at first and then fully opens as time increases; eventually, it is in the tensile-shear and composite state. In other words, the hydraulic fracture tends to traverse the orthogonal natural fracture and continue to propagate, as it is more easily arrested by the oblique natural fracture and transferred to propagation.",22,23,2
Fracture,Finite Element,"Zhong, Ruizhi; Miska, Stefan; Yu, Mengjiao; Ozbayoglu, Evren; Takach, Nicholas",An integrated fluid flow and fracture mechanics model for wellbore strengthening,Wellbore strengthening; Near-wellbore fracturing; Integrated model; Lost circulation; Fracture mechanics; Parametric study,LOST-CIRCULATION,"Fracture-based wellbore strengthening techniques are preventive methods that can reduce the cost of lost circulation and non-productive time. The mud weight window can be extended by plugging fractures with wellbore strengthening materials (WSM) in the near-wellbore region. To maximize the strengthening effect, accurate fracture geometry prediction is of critical importance to the design of WSM. This paper presents a novel, coupled fluid flow and fracture mechanics model for wellbore strengthening applications that accounts for near-wellboreinduced fracture behavior. For fluid flow, mass conservation is considered and momentum conservation is examined; the latter shows that pressure loss with near-wellbore fracturing is low. Thus, we can neglect the pressure drop in the fractures and assume the fluid pressure inside the fractures is equal to the wellbore pressure. The pressure-width relationship (rock elastic deformation) and stress intensity factor are obtained by a dislocation- based approach. For the fracture propagation criterion, the calculated stress intensity factor is compared with fracture toughness at each time step. The stress intensity factor and fracture reopening pressure (FROP) are verified with Tada's model and Feng's model, respectively. Then, simulation results are compared with the large leak-off solutions of the Perkins-KernNordgren (PKN) fracture model. The simulation results reveal that the PKN model overestimates the fracture mouth width, fracture length, and wellbore pressure. Furthermore, the simulation results of wellbore pressure show a different trend. Therefore, we cannot directly use the PKN model to design wellbore strengthening applications. The main reason is the presence of wellbore can generate near-wellbore effects that cannot be disregarded. Finally, we conduct a comprehensive parametric study (i.e., fracture toughness, Young's modulus, Poisson's ratio, horizontal stress ratio, and permeability) on wellbore strengthening fracturing. The proposed model is useful for wellbore strengthening applications using the intentionally induced fractures (i.e., near-wellbore fracturing). Particle size distribution (PSD) of WSM can be designed based on the simulated fracture geometry. No complex model mesh generation or assignment of boundary conditions are needed, which are commonly used in finite element simulation or other numerical methods. The proposed model can also be used to optimize wellbore strengthening operations by performing sensitivity analysis.",19,19,0
Fracture,Finite Element,"Zhao, Haifeng; Wang, Xiaohua; Liu, Zhiyuan; Yan, Yujie; Yang, Haixing",Investigation on the hydraulic fracture propagation of multilayers-commingled fracturing in coal measures,Coal strata; Commingled fracturing; Crack propagation; Geological factors; Engineering factors; Cohesive element,STRESS SENSITIVITY; LAYERED FORMATIONS; MODEL; CONTAINMENT; PERMEABILITY; DEFORMATION; SIMULATION; INTERFACE; WELL,"Multilayers-commingled fracturing is the vital step to achieve gas co-exploration in coal measures. Hydraulic fracture is required to penetrate vertically through multilayers in Multilayers-commingled fracturing. However, investigation on the propagation of commingled crack in coal measures which is soft-hard interlaced strata is less studied and not well understood. Therefore, based on the rock seepage-stress coupling effect, a three-dimensional (3D) hydraulic fracture model of multilayers-commingled fracturing in coal strata was established in combination with ABAQUS finite element software. The influence of geological factors and construction factors on the hydraulic cracks expansion in sandstone-coal interbedded reservoirs of X well in Linxing area in China was investigated. We found that the minimum horizontal stress difference is an essential geological factor to contain the vertical extension of commingled fractures; The high elastic modulus of neighboring reservoirs promotes the longitudinal penetration of fractures in the multilayers; The low tensile strength contrast between multiple layers increases the possibility of vertical expansion of combined fractures, while the high permeability of adjacent layers restrains the longitudinal propagation of fractures. The critical displacement of fracturing fluid exists in the combined fracturing process. The commingled cracks breakthrough the stratigraphic interface and penetrate into the adjoining layers when reaching the critical displacement; The high-viscosity of fracturing fluid facilitates the extending behaviors of hydraulic cracks in the vertical direction. The research results provide theoretical guidance for optimization of commingled fracturing layers and design of construction parameters in coal strata.",18,18,8
Fracture,Finite Element,"Wang, Lu; Yang, Shenglai; Meng, Zhan; Chen, Yanzhao; Qian, Kun; Han, Wei; Wang, Danfeng",Time-dependent shape factors for fractured reservoir simulation: Effect of stress sensitivity in matrix system,Time-dependent shape factor; Unsteady transfer flow; Stress sensitivity; Fractured reservoir; Dual-porosity numerical reservoir simulation,CARBONATE GAS-RESERVOIR; DUAL-POROSITY; BOUNDARY-CONDITIONS; MULTIPHASE-FLOW; SINGLE-PHASE; POROUS-MEDIA; MODELS,"Matrix-fracture transfer functions are the backbone of any dual-porosity or dual-permeability formulation in the modeling of fluid flow in fractured porous media. The chief feature within them is the accurate definition of shape factors. To date, there is no commonly accepted formulation of a matrix-fracture transfer function and shape factor. Many unsteady transfer formulations of shape factors for incompressible reservoirs have been presented and used. However, the assumption of incompressible reservoirs for these formulations is not consistent with the in-situ reservoir conditions, and a few have been reported on the application of time-dependent shape factor on dual-porosity numerical reservoir simulation. The focus of this study is, therefore, to find the time-dependent shape factor for the single-phase flow of stress-sensitive reservoirs. In this paper, the stress sensitive curves and corresponding fitting equations of a fractured reservoir are obtained based on the laboratory physical simulation; and, a model for the determination of the time-dependent shape factors that considers the stress sensitivity is presented; then the solution of nonlinear pressure diffusivity equation is used to derive the shape factor; finally, the shape factor obtained in this paper is segmented by time and applied to the dual-porosity numerical reservoir simulation. The Boltzmann transform, the separation variable method and the method of power series are used to solve the nonlinear governing equation by considering the stress sensitivity in matrix system. The approximate analytical model for the shape factor presented in this paper is verified using fine-grid, finite element numerical simulation. The dependency of the shape factor on the matrix stress sensitivity is also investigated. The theoretical analysis presented improved our understanding of transfer flow in fractured porous media, and provides a new method for dual-porosity numerical reservoir simulation of fractured reservoirs.",18,20,1
Fracture,Finite Element,"Kong, Bing; Chen, Shengnan",Numerical simulation of fluid flow and sensitivity analysis in rough-wall fractures,Numerical simulation; Hydraulic fracturing; Rough-wall fracture; Fracture conductivity,SURFACE-ROUGHNESS; FRACTAL DIMENSION; CUBIC LAW; ROCK; PERMEABILITY; SINGLE; CONDUCTIVITY; TRANSPORT; GEOMETRY; NETWORK,"Activated natural fractures, poorly-propped and un-propped secondary hydraulic fractures may serve as the connection between reservoir fluids and the main hydraulic fractures (i.e., well-propped fractures). These branched fractures also contribute considerably to well after-fracturing productivity in unconventional fight/ shale reservoirs. Rough fracture surface and its effects on fluid flow behavior in such fractures with very limited width is very important in understanding total mass transport in fractured rocks. In this paper, the effect of rough surface properties on fracture conductivity is studied through 3D numerical simulation of fluid flow behavior within the fractures. First, a tensile fracture was created on a core sample retrieved from the Montney formation, and the rough fracture surface topography was scanned via a high-resolution optical profilometer. The surface roughness characterizations were then used as reference to numerically reconstruct multiple three-dimensional fracture models. A finite element method was adopted to simulate fluid flow in the rough-wall fractures, using Navier-Stokes equation, for various fracture surface properties such as mean aperture, root mean square (RMS) asperity height, correlation length, anisotropy and shear displacement distance. Results showed that cubic law tends to overestimate the conductivity of the fractures with rough-wall surfaces, especially when the fracture aperture is small. Other surface properties, including correlation length, anisotropy and Hurst exponent also exert considerable impacts on fracture hydraulic properties. As the shear displacement distance increases, deviation of the fracture conductivity from cubic law first increases and then maintains at a constant level. The results of this paper have advanced the understanding of fracture conductivity and its dependence on fracture surface properties and will aid in improving production prediction and optimization in fractured tight reservoirs.",17,17,6
Fracture,Finite Element,"Zhang, Luqing; Zhou, Jian; Braun, Anika; Han, Zhenhua",Sensitivity analysis on the interaction between hydraulic and natural fractures based on an explicitly coupled hydro-geomechanical model in PFC2D,Hydraulic fracturing; Sensitivity analysis; Explicitly coupled hydro-geomechanical model; Numerical simulation; Two-dimensional particle flow code (PFC2D),FLUID VISCOSITY; FINITE-ELEMENT; PROPAGATION; SHALE; ROCK; SIMULATION; INITIATION; INJECTION; BOREHOLE; BRITTLE,"Fluid-induced fracture nucleation, propagation and interaction with natural fractures are the crucial issues for well understanding the process of hydraulic fracturing in unconventional reservoirs. In this paper, an explicitly coupled hydro-geomechanical model in two-dimensional Particle Flow Code (PFC2D) is employed to investigate the interaction between hydraulic fractures (HFs) and natural fractures (NFs), and the numerical scheme is validated by using analytical results. Several factors affecting the interactions between induced-fractures and NFs are being investigated and discussed. The simulation results show that three fundamental crossing scenarios can be well reproduced: (I) Direct Crossing, (II) Offset Crossing and (III) No Crossing (Arrested), and the crossing types agree well in the evaluation by Blanton's criterion. A sensitivity analysis shows that hydraulic fracture (HF) tend to be arrested by a natural fracture (HF) under low approach angles and prefer to cross the NF under higher in-situ differential stress states. Crossing is likely to be impeded for NFs with lower frictional coefficient and higher permeability. Additionally, lower fracturing fluid injection rates and lower fluid viscosities both are advantageous conditions for NF reactivation, and tend to arrest the HF. Moreover, the mechanism of the interaction of HFs and NFs influenced by the aforementioned factors can be well explained by the evolution of normal stress on the pre-existing interface, which is the key issue for correct simulation of hydraulic fracturing. Compared with the analytical model, the model in this study can reflect the dynamic stress evolution process, which will be a useful tool for optimizing the design of hydraulic fracturing in fractured reservoirs.",17,19,2
Fracture,Finite Element,"Sun, Qian; Zhang, Na; Fadlelmula, Mohamed; Wang, Yuhe",Structural regeneration of fracture-vug network in naturally fractured vuggy reservoirs,Fracture-vug network; Improved simulated annealing method; Multiple point statistics; Digital rock; Superimposing method,PORE-SPACE RECONSTRUCTION; FINITE-ELEMENT; FLOW; SIMULATION; MICROSTRUCTURE; PERMEABILITY; PREDICTION; ALGORITHM; PHASE; MODEL,"Naturally fractured vuggy carbonate reservoirs play an important role in the world's oil and gas production. Porescale modeling is treated as an important approach for unveiling the flow mechanism in carbonate reservoirs. The realistic regeneration of fractured vuggy reservoirs needs to preserve the geological structures and complex pores morphologies. Nevertheless, regeneration of such reservoirs is a great challenge because of the co-existence of fractures and vugs over a wide range of scales. In this paper, the reference fracture-vug network will be divided into two systems: matrix-fracture and matrix-vug. The two systems are reconstructed in two ways: (I), the matrixvug and matrix-fracture systems are generated by improved simulated annealing method (ISAM) and multiple point statistics algorithm (MPS), respectively; (II), both of the matrix-vug and matrix-fracture systems are generated by MPS. When applying for ISAM, the multipoint histogram mainly depends on the N-point template. The template is a unit configuration, which is considered as the characteristic of the geometric features. Based on this, we introduce the correlation coefficient matrix to determine an optimal template, and the accuracy of template selection algorithm is also discussed. The optimal template represents essential geological features of the training image, and its size is much smaller than the template size selected by entropy. Therefore, it can improve the computing efficiency while preserving the key properties of the network. Then, a superimposing method is proposed to create the fracture-vug network by combining the matrix-vug with matrix-fracture models. The superimposing method using ISAM (for matrix-vug model generation) and MPS (for matrix-fracture model generation) is called SMIM, while superimposing method using MPS (for both of matrix-vug and matrix-fracture models generation) is called SMM. Finally, the spatial connectivity, local percolation probability and patterns reproduction of the generated models are used to compare with those of the reference model. The results show that the 7-point template selected by the correlation coefficient matrix is enough to get the spatial features of the matrix-vug system. The generated fracture-vug network using the selected template is able to retrieve the patterns of training image (reference model) more accurately than other used templates. The fracture-vug network generated by superimposing method produces better results than the other methods (all named as ""direct method""). The network simulated with SMIM algorithm matches the reference model better than SMM algorithm. The probable reason maybe exist in the different generation methods used for matrix-vug systems. The local percolation probability (LPP), treated as a general geometric characterization method, is used to characterize the connectivity of measured units at a given local porosity. The results of the probability analysis show that SMIM is better in depicting the expected patterns of geological heterogeneities and in producing higher degree of connectivity of pore space than the SMM. The pattern reproduction of SMIM model is assessed by scanning the generated model, and the ratio of pattern reproduction number to that of reference model (i.e. the similarity) is around 97.28%. These results may guide the further application of the proposed method to field-scale modeling of naturally fractured vuggy reservoirs.",15,19,4
Fracture,Finite Element,"Wan, Yi-Zhao; Liu, Yue-Wu; Chen, Fang-Fang; Wu, Neng-You; Hu, Gao-Wei","Numerical well test model for caved carbonate reservoirs and its application in Tarim Basin, China",Caved carbonate reservoir; Type curves; Numerical well test; Finite element method,NATURALLY FRACTURED RESERVOIRS; PRESSURE TRANSIENT ANALYSIS; COMPOSITE RESERVOIR; EXPLORATION; CAVITY,"The caved carbonate reservoir is a special and complex reservoir with different size cavities, which implies a strong heterogeneity. It is a big challenge to characterize such reservoirs. The dual-porosity model and radial composite model are the two most commonly used models for the interpretation of well test in caved carbonate reservoirs. However, more studies are needed to determine whether these models can be applied to this special and complex type of reservoir. In this paper, first we classify the log-log plots of test pressure into four types and analyze the characteristics of each type. The results show that the cavity controls the pressure response and that the above-mentioned models are not appropriate for the well test interpretation of caved carbonate reservoirs. We also developed a numerical well test model for caved carbonate reservoirs. The model includes two cases: a well drilled outside a cavity and a well drilled inside a cavity. The model's equations were solved by the finite-element method. We analyzed the pressure response of the developed model and found that the log-log plots for the model of a well outside a cavity are similar to that of the dual-porosity model, but the physical mechanisms of these two models are different. The model of a well inside a cavity is similar to the radial composite model except for a deviation in the distance of the well from the center of the cavity. Sensitivity studies show the size of the cavity, its permeability, and the distance from the well to the cavity are the main factors influencing the pressure response behavior. Two field examples of build-up pressure tests are provided to show how the proposed model can be used to understand the properties of caved carbonate reservoirs and characterize them.",15,16,1
Fracture,Finite Element,"Zeng, Qingdong; Liu, Wenzheng; Yao, Jun",Hydro-mechanical modeling of hydraulic fracture propagation based on embedded discrete fracture model and extended finite element method,Numerical modeling; Hydro-mechanical coupling; Hydraulic fracturing; EDFM; XFEM,NUMERICAL-SIMULATION; POROUS-MEDIA; CRACK-GROWTH; COUPLED FLOW; FLUID-FLOW; RESERVOIR; CONVERGENCE; INITIATION; SCHEMES; STRESS,"In this study, an efficient hydro-mechanical model of hydraulic fracture propagation is proposed using the embedded discrete fracture model in conjunction with the extended finite element method. Fracture is embedded into a common computational grid for both stress and pressure fields. A hybrid scheme of fixed stress split and Picard iterative method is presented to deal with the hydro-mechanical coupling and fracture propagation. The model is verified against other numerical solution of hydro-mechanical coupling problem and analytical solution of fracture propagation available from literature. Numerical results show that as matrix permeability increases, more fracturing fluid is required to get a desired length of fracture. The effect of Biot's coefficient is similar to that of matrix permeability. Finally, the model is extended to simulate simultaneous propagation of multiple hydraulic fractures. It's interesting to find that the effect of stress shadowing could be weakened by the poroelastic stress when accounting for hydro-mechanical coupling. The study indicates that the hydro-mechanical coupling could have significant influence on hydraulic fracturing, especially for multi-cluster fracturing of horizontal wells.",14,14,4
Fracture,Finite Element,"Taheri-Shakib, Jaber; Ghaderi, Amir; Kanani, Vahid; Rajabi-Kochi, Mahyar; Hosseini, Seyed Ahmad",Numerical analysis of production rate based on interaction between induced and natural fractures in porous media,Hydraulic fracture; Natural fracture; Production; XFEM; UDEC,PRODUCTION PERFORMANCE; HORIZONTAL WELL; PERMEABILITY; ELEMENTS; FLOW,"Hydraulic fracturing in reservoirs with low or high fracture density could have a significant impact on the reservoirs' production rate. In the present study, having determined the fracture direction through the finite difference method according to the induced-stress distributions, this operation simulated fracturing in two reservoirs with high or low levels of natural fracturing, using the distinct-element method. The goal was to investigate the effect of hydraulic fracture length and aperture on the production rate from both reservoirs. Sensitivity analysis indicated that in a reservoir with more natural fractures, hydraulic fracture length plays a more significant role, and in a reservoir with fewer natural fractures, both hydraulic fracture length and opening are highly influential. Also, factors such as fracture coalescence and intersected fractures, which influence the production rate, were examined. Moreover, the results revealed that when the fracture length and aperture increase, the production rate fluctuates.",14,16,4
Fracture,Finite Element,"Zhang, Hua; Yin, Shunde; Aadnoy, Bernt",Poroelastic modeling of borehole breakouts for in-situ stress determination by finite element method,Borehole breakouts; Finite element method; Inverse analysis; In-situ stress; Poroelasticity,PRINCIPAL STRESS; CAJON PASS; FAILURE; WELL; FRACTURE; ROCK; CRITERION; STRENGTH; MOGI,"Borehole breakouts are changes in borehole geometry in a cross section perpendicular to the borehole axis when rock subjected to in-situ stress experiences shear failure. By finite element modeling of borehole breakouts considering poroelasticity, the authors simulate the process of borehole breakouts in terms of initiation, propagation and stability in the condition of Mogi-Coulomb criteria, and can get the shape of borehole breakouts. It's desirable that this information of borehole breakouts can be used to determine in-situ stress by inverse analysis. Artificial neural network provides such a tool to establish the relationship between in-situ stress and shape on borehole breakouts, by which in-situ stress can be obtain according to different shape of borehole breakouts. In this paper, there are two steps to determinate in-situ stress by inverse analysis. First, Sets of finite element modeling provides sets of data on in-situ stress and borehole breakout measures, which will be used to train an artificial neural network that can eventually represent the relationship between the in-situ stress and borehole breakout measures. Second, for a given measure of borehole breakouts, the trained artificial neural network will be used to predict the corresponding in-situ stress. Results show that the inverse analysis based on finite element modeling of borehole breakouts and artificial neural network can effectively determine in-situ stress.",14,14,4
Fracture,Finite Element,"Liu, Jingshou; Ding, Wenlong; Wang, Ruyue; Yang, Haimeng; Wang, Xinghua; Li, Ang",Methodology for quantitative prediction of fracture sealing with a case study of the lower Cambrian Niutitang Formation in the Cen'gong block in South China,Fracture sealing; Shale reservoir; Paleotectonic stress field; Lower Cambrian; Cen'gong block,PALEOTECTONIC STRESS-FIELDS; SHALE-GAS; PRESERVATION CONDITIONS; CRUSTAL DEFORMATION; NATURAL FRACTURES; NORTHERN GUIZHOU; BASIN; RESERVOIRS; SIMULATION; DEPRESSION,"Industrial levels of shale gas have been produced from the Niutitang Formation in the lower Cambrian of the Cen'gong block, South China. The practice of exploration and development of shale gas in the Cen'gong block shows that the abundance of gas in different layers and wells is closely related to the degree of development of fractures. In this study, data obtained from outcrops, cores, and thin sections from the Cen'gong block were used to determine the development characteristics of such natural fractures. Combined with the analysis of burial history and fluid inclusions, the stress fields during three periods (the Yanshanian period, Himalayan period and neotectonic period) are suspected to play a critical role in fracture sealing. The paleotectonic stress tensor is determined using fault activity analysis, acoustic emission tests, and burial history. The magnitude and direction of current in situ stresses are determined by drilling-induced fractures, deviated well information, and cross multipole array acoustic (XMAC) logging. Under the constraints of XMAC logging interpretation and mechanical experiments, the spatial distribution of mechanical parameters is obtained by seismic inversion, and 3D heterogeneous geomechanical models are established using a finite element method (FEM). Then, the fracture density, reactivity, and aperture are identified. The results show that the magnitudes of the maximum horizontal principal stress during the Yanshanian period, the Himalayan period, and the neotectonic period are 150-170 MPa, 110-130 MPa, and 35-45 MPa, respectively. Using the fracture sealing calculation model, the fracture sealing that developed in the Himalayan period is the worst, the fracture sealing that developed in the Yanshanian period is intermediate, and the fracture sealing that developed in the neotectonic period is the best. Based on three-dimensional heterogeneous geomechanical modeling and tectonic stress evolution estimates, the fracture sealing calculation model proposed in this paper can be widely used in the evaluation of the preservation conditions of shale reservoirs, tight sandstone reservoirs and low-permeability reservoirs in complex tectonic areas.",14,15,2
Fracture,In-situ Stress,"Taleghani, Arash Dahi; Gonzalez-Chavez, Miguel; Yu, Hao; Asala, Hope",Numerical simulation of hydraulic fracture propagation in naturally fractured formations using the cohesive zone model,Hydraulic fracturing; Cohesive zone model; Fracture intersections; Natural fractures; Complex fracture network; Traction separation law,BARNETT SHALE; STRESS; PRODUCTIVITY; RESERVOIRS; SYSTEMS; IMPACT; JOINTS,"This paper presents an integrated methodology that utilizes the cohesive zone model (CZM) to simulate propagation of hydraulic fractures, and their interactions with pre-existing natural fractures. CZM has the advantage of capturing the non-elastic behavior of shales; usually induced by total organic carbon (TOC) as well as dissimilar mechanical properties of cemented natural fractures. At the intersection of an advancing hydraulic fracture and a stationary natural fracture, the hydraulic fracture may arrest, cross, or divert into a pre-existing natural fracture depending on the rock mechanical properties, magnitude and direction of rock principal stresses, and fracture intersection angle. The activation of natural fractures during hydraulic fracture treatments improves fracture complexity and expands reservoir drainage area, making stimulation treatments more effective. In this work, triaxiality effects are incorporated into the cohesive zone model. Utilizing triaxiality makes the traction separation law (TSL) tied to confining pressure and this ensures a more reliable transition from laboratory test environment to bottomhole conditions. We present a methodology to determine the cohesive properties or TSL characteristics of rock, after performing semicircular bending tests (SCBT). Finite element analysis (FEA) is then used to calibrate the cohesive properties of both rock and natural fractures. The calibrated parameters were utilized in a field-scale FEA to simulate the growth of complex fracture networks. The results show how fracture intersection angle and the nature of cemented materials inside the natural fractures might divert a hydraulic fracture initially propagating in a direction perpendicular to the minimum horizontal stress. The sensitivity analysis of primary parameters such as fluid viscosity, natural fracture distribution, fracture intersection angle, and differential stresses is implemented to provide a better insight into the performance of hydraulic fracturing jobs in naturally fractured reservoirs. Results indicate the importance of nonlinear fracture tip effects as in-situ stress differences increase.",77,79,8
Fracture,In-situ Stress,"Yin, Shuai; Zhao, Jingzhou; Wu, Zhonghu; Ding, Wenlong",Strain energy density distribution of a tight gas sandstone reservoir in a low-amplitude tectonic zone and its effect on gas well productivity: A 3D FEM study,Strain energy density; Tight gas sandstone; Paleotectonic stress field; Productivity,IN-SITU STRESS; ORDOS BASIN; TARIM BASIN; NUMERICAL-SIMULATION; FRACTURE SYSTEM; PERMIAN STRATA; HANCHENG BLOCK; EASTERN MARGIN; TAZHONG AREA; COAL-BED,"The tight gas sandstone reservoirs in the Paleozoic of the Sulige gas field in China are highly heterogeneous, and fractures are key factors for stable reservoir production. Low-amplitude folds or nose-like structures are widely developed in the Upper Paleozoic strata in this area. To effectively predict gas well productivity, in this paper, a 3D FEM numerical simulation based on the deformation and energy variation of the rock mass was used to predict the "" sweet spots"" of gas well productivity in a tight gas sandstone reservoir using the He8 segment of the Middle Permian Xiashihezi Formation in the Central Sulige block as an example. The paleotectonic stress field of the study area during the maximum episode of compression in the Yanshanian movement was restored, and the two rupture parameters of the integrated rupture rate (IF) and strain energy density (U) were constructed. The strain energy density distribution has a high correlation with gas well productivity, indicating that it can better predict the rock rupture degree in low-amplitude tectonic zones. A complex relationship exists between the strain energy density distribution and low-amplitude folds. The high strain energy density zones are mainly distributed among the high positions and wing areas of the low-amplitude fold zone, but the top area of the low-amplitude fold does not necessarily have a high strain energy density. Portions of the high strain energy density zones are located in the gentle tectonic zone, located near but outside the low-amplitude fold zone. The strain energy in these gentle tectonic zones with a high strain energy density value is relatively high, and the rock mass is prone to rupture. This study is of great value in enriching the prediction of "" sweet spots"" in tight gas sandstone reservoirs in low-amplitude tectonic zones worldwide.",54,54,1
Fracture,In-situ Stress,"Zeng, Qing-Dong; Yao, Jun; Shao, Jianfu",Numerical study of hydraulic fracture propagation accounting for rock anisotropy,Hydraulic fracturing; Crack propagation; Rock anisotropy; XFEM; Numerical modeling,FINITE-ELEMENT-METHOD; CRACK-PROPAGATION; ORTHOTROPIC MEDIA; SIMULATION; GROWTH,"The objective of this study is to investigate the effect of rock anisotropy on hydraulic fracture propagation. The coupled model of rock deformation and fluid flow is established to study hydraulic fracturing of orthotropic formation. Stress field is solved by using the extended finite element method with special tip enrichment functions for orthotropic formation. The coupling between stress field and pressure field is treated by Picard iterative procedure. The modified circumferential tensile stress criterion is used to determine fracture propagation, in which stress intensity factors are determined by an interaction integral method. Numerical results show that when fracture doesn't initiate from the direction of material axis with larger modulus, the fracture propagation direction would change and divert to the direction of material axis with larger modulus. And as Young's modulus ratio between two material axes increases, the phenomenon becomes more obvious. Moreover, shear modulus also enhances the diversion phenomenon of fracture propagation direction. However, the in-situ stress difference could weaken the effect of rock anisotropy. The results indicate that the propagation process of hydraulic fracture is influenced by comprehensive factors including material axis angle, Young' modulus ratio, shear modulus and in-situ stress difference.",51,52,2
Fracture,In-situ Stress,"Li, Yuwei; Yang, Shuai; Zhao, Wanchun; Li, Wei; Zhang, Jun",Experimental of hydraulic fracture propagation using fixed-point multistage fracturing in a vertical well in tight sandstone reservoir,Tight sandstone reservoir; Fixed-point multistage fracturing; Fracture propagation; Fracture geometry,HIGHLY DEVIATED WELL; SHALE GAS-RESERVOIRS; LABORATORY EXPERIMENTS; ORIENTED PERFORATION; INITIATION PRESSURE; BEHAVIOR; NETWORKS; VOLUME; ROCK,"Fixed-point multistage fracturing can effectively increase the stimulated reservoir volume (SRV) in tight sand-stone reservoir. In different geological and engineering conditions, how to explain the geometric form of fracture propagation in fixed-point multistage fracturing has not been reported yet, and the propagation mechanism of hydraulic fracture is ambiguous. To clarify this mechanism, fourteen large-scale triaxial tests were deployed in this study to investigate the fracture propagation behavior in fixed-point multistage fracturing, and the influences of various factors on fracture geometries were studied. The results show that there are six types of fractures in the horizontal plane when the fixed-point multistage fracturing are carried out in a vertical well in tight sandstone reservoir: bi-wing planar fracture; bi-wing non-planar fracture; L-type fracture; X-type fracture; biwing turning fracture and re-orientation turning fracture. Fixed-point multistage fracturing can increase the SRV mainly because it is equivalent to carry out refracturing in the reservoir, so it can form a complex fracture system similar to refracturing. The research proves that it is difficult to form a complex fracture system through the fixed-point of multistage fracturing when the stress difference is more than 6 MPa in the horizontal direction. The fracturing fluid injection rate has an obvious effect on the formation of multi-fractures, and the multi-fracture can not form when the injection rate is too large. The enhancement of rock heterogeneity will lead to more energy consumption in fracturing process, which is not conducive to the initiation and propagation of fractures. Therefore, the in-situ stress, rock heterogeneity, injection rate and other factors should be comprehensive considered when designing the fixed-point multistage fracturing scheme for vertical well in tight sandstone reservoir.",47,51,5
Fracture,In-situ Stress,"Zhang, Yushuai; Zhang, Jincai; Yuan, Bin; Yin, Shangxian",In-situ stresses controlling hydraulic fracture propagation and fracture breakdown pressure,Hydraulic fracture; In-situ stresses; Horizontal stress; Breakdown pressure; Depletion; Fracture curving,INSITU STRESSES; WELLS; PREDICTION; BOREHOLE; RESERVOIRS; MAGNITUDE; ROCKS; FLOW,"In-situ stress impact on hydraulic fracturing is investigated to enhance hydraulic fracturing performance. Lithology-controlled lower and upper bounds of the horizontal stresses are proposed, and an improved stress polygon method is presented. This improved method can narrow the area of the conventional stress polygon, particularly in shales; therefore, constrain the in-situ stress estimate. The lithology-controlled stresses indicate that a shale has a higher minimum horizontal stress and can be used as a barrier of the hydraulic fracture propagation when hydraulic fracturing is performed in adjacent sandstones. However, when hydraulic fracturing is performed in a shale oil or gas formation, a stress-barrier formation may not exist on the top or the bottom of the shale reservoir, and this will cause the hydraulic fractures to propagate out of the reservoir zone. We also examine the effects of the maximum and minimum horizontal stresses, shear stresses and depletion on the fracture initiation, breakdown, propagation and containment. Shear stresses cause hydraulic fractures kinking; from this evidence, we find that a horizontal well can be drilled with a certain angle to the minimum stress direction because in most cases the hydraulic fractures eventually curve to the maximum stress direction. In addition, we propose a new method to calculate the fracture breakdown pressure based on fracture mechanics. The proposed method predicts a higher breakdown pressure than the conventional one, which may better estimate the breakdown pressure.",38,40,3
Fracture,In-situ Stress,"Wang, Y.; Li, C. H.; Hao, J.; Zhou, R. Q.",X-ray micro-tomography for investigation of meso-structural changes and crack evolution in Longmaxi formation shale during compressive deformation,Shale fracturing; Micro-tomography CT; X-ray imaging; Fracture evolution; Longmaxi shale,HIGH-RESOLUTION; MECHANICAL-PROPERTIES; TRIAXIAL COMPRESSION; COMPUTED-TOMOGRAPHY; CREEP; ROCK; MICROTOMOGRAPHY; VISUALIZATION; PROPAGATION; SIMULATION,"Shale is a typical heterogeneous geomaterial and investigation of the meso-structural changes and crack evolution is beneficial to shale gas development. Understanding the microscopic failure mechanism is undoubtedly crucial to hydraulic fracturing treatment. In this paper, real-time high-resolution X-ray Computed (micro-) Tomography (X-ray CT) with was used for the first time to deform shale sample experimentally under unconfined axial compression. Organic matter, pyrite, and micro-fractures were volumetrically rendered with a resolution of 11.27 mu m, and 2D/3D image investigations enabled us to explore the structure and fracture evolution of the sample due to in-situ compression. This work reveals that the stress-induced deformation of shale is found to be dependent on organic matter compaction, pyrite spatial evolution, and micro-fracture initiation, propagation, and coalescence. The volume of organic matter decreases with the increase of axial stress; and the spatial distribution of pyrite changes at different loading stages, but the effective volume is almost the same. The formation of macroscopic fractures similar to 20 degrees oblique to the loading direction was observed. The cracks initiate in the tensile cracks between the bedding plane at the bottom of the sample and shear fractures are composed of tensile cracks connected by an ""X"" shape. The layered deposited structure and weak cementation between layers are the main factors controlling the failure mechanism.",33,36,4
Fracture,In-situ Stress,"Sheng, Mao; Li, Gensheng; Sutula, Danas; Tian, Shouceng; Bordas, Stephane P. A.",XFEM modeling of multistage hydraulic fracturing in anisotropic shale formations,Hydraulic fracturing; Crack propagation; Shale; Extended finite element method,EXTENDED FINITE-ELEMENT; DEFORMABLE POROUS-MEDIA; CRACK-GROWTH; FLUID-FLOW; PROPAGATION; ENRICHMENT; SIMULATION; SCHEMES; SOLIDS,"The aim of the present study is to help understand hydraulic fracture propagation in shale formations through numerical simulations. The hydraulic fracture propagation regime in shale is analyzed considering the anisotropic nature of the shale rock formation and slick-water fracturing fluid. It is determined that the dominant mechanism of hydraulic fracture propagation is the so-called transitional regime that is characterized by a negligibly small fluid lag region and zero fluid front pressure. For the modeling of the hydraulic fracture evolution over time, we assume orthotropic linear-elastic rock media and that the flow of the fracturing fluid is governed by the Reynold's lubrication equation. For the discretization of the coupled solid-fluid equations within the 2D plane-strain context we use the extended finite element method for the rock media and the finite volume method for the lubrication equation. The problem of the hydraulic fracture evolution over time is modeled as stable quasi-static crack growth where time is the result of upholding the mass conservation principle between the fluid inflow and the crack volume. The Picard iterative approach is used to solve the discrete non-linearly coupled solid-fluid equations. Our model is verified against several analytical solutions. Subsequently, a five-stage hydraulic fracturing problem is simulated to study the interactions between the different fractures. Results show that the on-going hydraulic fractures are attracted by the pre-existing hydraulic fractures as a result of the change of the local stress field relative to the initial in-situ stress field. For the cases considered, fracture deflections are found to be most extensive with decreasing fracture spacing and in-situ stress difference, but insensitive with the increasing the ratio of Young's moduli.",27,27,4
Fracture,In-situ Stress,"Guo, Tiankui; Rui, Zhenhua; Qu, Zhanqing; Qi, Ning",Experimental study of directional propagation of hydraulic fracture guided by multi-radial slim holes,Radial slim hole; Hydraulic fracturing; Fracture propagation; Horizontal stress difference; Azimuth,NUMERICAL-SIMULATION; GLUTENITE RESERVOIR; INTEGRATED WORKFLOW; GAS-RESERVOIRS; SHALE; INITIATION; OIL; BOREHOLES; MODEL; PERFORATION,"The conventional hydraulic fracturing fails in the target oil/gas zone (remaining oil, closed reservoir, etc.) which is not located in the azimuth of maximum horizontal stress of available wellbores. The technology of directional propagation of hydraulic fracture guided by vertical multi-radial slim holes is innovatively developed. In order to verify this technology, lots of true triaxial hydraulic fracturing simulation experiments were carried out with artificial cores, aiming at investigating the influence of in-situ stress, fracturing fluid displacement, and azimuth, diameter, number, and spacing of radial slim holes on fracture propagation. The results show that directional propagation of hydraulic fractures guided by vertical multi-radial slim holes is feasible. Regardless of varied radial slim hole and in-situ stress parameters, hydraulic fracture always initiates in the heel of radial slim hole. For hydraulic fracturing assisted by single radial slim hole, smaller horizontal stress difference (3 MPa, sigma(H)/sigma(h) = 1.25) and smaller radial slim hole azimuth (15 degrees) may guide propagation of hydraulic fractures along radial slim hole, and larger horizontal stress difference (6 MPa, sigma(H)/sigma(h)= 1.67) can sharply reduce guidance of radial slim hole. Affected by mutual interference from guidance of radial slim holes and controlling of horizontal in-situ stress, fractures tend to distort along fracture length and fracture height. For hydraulic fracturing assisted by vertical multi-radial slim holes, horizontal stress difference is one of key factors influencing the directional propagation effect of hydraulic fracture. Larger horizontal in-situ stress difference (> 6 MPa, sigma(H)/sigma(h) > 1.67) hardly results in directional propagation of hydraulic fracture along radial slim hole row, and creates bigger diversion angle of fracture, and larger azimuth (> 45 degrees) of radial slim hole row reduces the guidance strength, resulting small fracture diversion radius. In conditions of larger angle between target zone and maximum horizontal stress, and requirement of large azimuth of radial slim hole row, the effective hydraulic fracture propagation along radial slim holes and ideal fracture height will be achieved through human intervention, e. g. increment of the number and diameter of radial slim holes, reduction of radial slim holes spacing, increment of fracturing fluid displacement, etc. The simulation results provide methods for designing directional propagation of hydraulic fractures guided by vertical multi-radial slim holes.",26,26,6
Fracture,In-situ Stress,"Chen, Shida; Tang, Dazhen; Tao, Shu; Xu, Hao; Li, Song; Zhao, Junlong; Cui, Yi; Li, Zhao","Characteristics of in-situ stress distribution and its significance on the coalbed methane (CBM) development in Fanzhuang-Zhengzhuang Block, Southern Qinshui Basin, China",In-situ stress; Permeability; Gas resource; Gas recovery; Deep coalbed methane,RESERVOIR PERMEABILITY; DEPENDENT PERMEABILITY; GEOLOGICAL CONTROLS; WESTERN GUIZHOU; PORE PRESSURE; ORDOS BASIN; NORTH CHINA; GAS; PREDICTION; SYSTEM,"In-situ stress is a vital index on the coal reservoir permeability and coalbed methane (CBM) development. Based on 41 sets of well test data at depths (h) of 353-1273 m in Fanzhuang-Zhengzhuang Block, the distribution of in-situ stress was analyzed systematically and its effect on coal permeability was also addressed. Results show that stress fields could convert in the vertical and four ranges corresponding to the certain depth can be characterized: the sigma(H) > sigma(v) > sigma(h) type mainly occurs in the shallow and deep coal seams (< 600 m and > 825 m); From 600 to 725 m, a stress transition zone can be observed (sigma(H) approximate to sigma(v) > sigma(h)); The sigma(v) > sigma(H) > sigma(h) type is dominant within depth from 725 to 825 m. With the increase of depth, well testing permeability (k) exhibits a trend of decrease (h < 600 m, 0.055 < k < 0.91mD) - increase (600 < h < 825 m, 0.02 < k < 1.13 mD) - decrease (h > 825 m, k < 0.1 mD), the essence of which is the open and closure of pores and fractures under the control of stress regime and vertical belting. Meanwhile, the correlation between gas content and depth was also illustrated, which shows two trends at the depth of 200-825 m (increase) and 825-1400 m (decrease), respectively. Generally, the coal reservoir deeper than 825 m is characterized by high in situ stress, low permeability and low gas resource, meaning that the geological conditions for CBM development deteriorate. The gas/water production of 500 CBM wells also indicates that the gas recovery rate in deeper coal seams is poorer than that in shallower coal seams. Therefore, a series of corresponding methods for these deep CBM (> 825 m) should be taken in the future CBM development strategy.",26,26,6
Fracture,In-situ Stress,"Liu, Kui; Gao, Deli; Taleghani, Arash Dahi",Analysis on integrity of cement sheath in the vertical section of wells during hydraulic fracturing,Sustained casing pressure; Cement sheath; Shale gas; Well integrity; Hydraulic fracturing,WELLBORE,"The sustained casing pressure (SCP) problems occur mainly in intermediate casing that might affect the safety and efficiency of shale gas production. Cement sheath is the main barrier against leakage and migration of gas from the pay zone to the shallow zones. Since the production casing is cemented all the way up to the intermediate casing in the vertical section of the well, the in-situ stress can only act on the intermediate casing and not directly on production casing. Based on this situation, an analytical model considering the well completion steps is established to study the integrity of cement sheath as a two-layer casing-cement system. The effect of mechanical and geometrical parameters of casing and cement are further investigated through a sensitivity analysis. The results show that the tensile failure more likely occurs at the inner face of the cement sheath in the intermediate casing. The casing thickness is in favor of decreasing the tensile stress in the cement sheath. But on the contrary, increasing the thickness and elastic modulus of the cement sheath may increase the risk of tensile failure in the cement sheath while reducing the costs. However, an appropriate increase of back pressure in the annulus during cementing is beneficial to reduce the tensile stress in the cement sheath.",26,30,2
Fracture,In-situ Stress,"Ju, Wei; Yang, Zhaobiao; Qin, Yong; Yi, Tongsheng; Zhang, Zhengguang","Characteristics of in-situ stress state and prediction of the permeability in the Upper Permian coalbed methane reservoir, western Guizhou region, SW China",Coal permeability; In-situ stress state; Coalbed methane reservoir; Numerical simulation; Upper permian; Western Guizhou region,EASTERN ORDOS BASIN; TECTONIC STRESS; PORE PRESSURE; FIELD; EXPLORATION; AREA; SEQUESTRATION; ORIENTATION; MAGNITUDE; POROSITY,"Coal permeability and in-situ stress state are important parameters for coalbed methane (CBM) exploration and development; however, the distribution pattern of the Upper Permian CBM reservoir permeability is poorly understood in the western Guizhou region, SW China. In the present study, based on measured injection/falloff and in-situ stress data in the Upper Permian coal seams of western Guizhou region, the present-day in-situ stress field, and its correlation with coal permeability were investigated. The orientation of the horizontal maximum principal stress (S-Hmax) indicated a dominant similar to NW-SE-trending. In addition, the present-day in-situ stress field showed an important control on coal permeability. The permeability in the Upper Permian coal seams decreased exponentially with the increased effective in-situ stress magnitude. By utilizing the finite element method (FEM), the present-day in-situ stress field in the western Guizhou was numerically analyzed based on a geomechanical two-dimensional (2D) model. Distribution of coal permeability in the Upper Permian CBM reservoir was predicted based on the relationship between coal permeability and effective in-situ stress magnitude. The results indicated that, in the western Guizhou region, vertically, coal permeability was relatively high and widely distributed shallower than approximately 780m below ground level (bgl), whereas, it was extremely low and regularly varied with burial depth deeper than approximately 780m bgl. Laterally, the distribution pattern of coal permeability was characterized by strong heterogeneity due to well-developed faults and folds. High values of the Upper Permian coal permeability were located in regions around Nayong-Zhijin, Panxian-Anlong and along Shuicheng-Liuzhi- Ziyun. The present study may provide geological references for the CBM reservoir productivity and subsequent analysis (e.g., wellbore stability, hydraulic fracturing design, and fault reactivation studies, etc.) in the western Guizhou region.",24,29,4
Fracture,In-situ Stress,"Yang, Zhao-Zhong; Yi, Liang-Ping; Li, Xiao-Gang; He, Wei",Pseudo-three-dimensional numerical model and investigation of multi-cluster fracturing within a stage in a horizontal well,Displacement discontinuity method; Multi-cluster fracturing; Horizontal well; Three-dimensional fracture,HYDRAULIC FRACTURES; PROPAGATION,"Multi-cluster fracturing and horizontal drilling are the key techniques used to exploit unconventional reservoirs. However, field production has revealed that certain perforation clusters are invalid. In order to find the most effective approaches to improve the uniformity of multiple-fracture growth, a pseudo-3D multi-cluster fracturing model is established in this study. In our model, complex in-situ stress distributions are considered and the stress interactions between fractures are calculated using the displacement discontinuity method (DDM). Fluid dynamic flow distributions into different clusters are calculated using Kirchhoff's second law. Fracture height and length extension velocities are determined based on the fracture edge energy release rate. The effectiveness of our model is verified by comparing the single fracture extension results obtained by our model to those obtained by a semi-analytical model. Based on our numerical model, possible approaches to promoting the uniform growth of multiple fractures are discussed. The results indicate that adjusting spacing is an inefficient method to promote multiple-fracture uniform growth under the condition of four clusters fracturing within a stage. However, regulating perforation friction, reducing fracturing fluid viscosity, and increasing injection rate are useful ways to improve the uniformity of multiple-fracture propagation.",20,24,4
Fracture,In-situ Stress,"Wang, Lu; Yang, Shenglai; Meng, Zhan; Chen, Yanzhao; Qian, Kun; Han, Wei; Wang, Danfeng",Time-dependent shape factors for fractured reservoir simulation: Effect of stress sensitivity in matrix system,Time-dependent shape factor; Unsteady transfer flow; Stress sensitivity; Fractured reservoir; Dual-porosity numerical reservoir simulation,CARBONATE GAS-RESERVOIR; DUAL-POROSITY; BOUNDARY-CONDITIONS; MULTIPHASE-FLOW; SINGLE-PHASE; POROUS-MEDIA; MODELS,"Matrix-fracture transfer functions are the backbone of any dual-porosity or dual-permeability formulation in the modeling of fluid flow in fractured porous media. The chief feature within them is the accurate definition of shape factors. To date, there is no commonly accepted formulation of a matrix-fracture transfer function and shape factor. Many unsteady transfer formulations of shape factors for incompressible reservoirs have been presented and used. However, the assumption of incompressible reservoirs for these formulations is not consistent with the in-situ reservoir conditions, and a few have been reported on the application of time-dependent shape factor on dual-porosity numerical reservoir simulation. The focus of this study is, therefore, to find the time-dependent shape factor for the single-phase flow of stress-sensitive reservoirs. In this paper, the stress sensitive curves and corresponding fitting equations of a fractured reservoir are obtained based on the laboratory physical simulation; and, a model for the determination of the time-dependent shape factors that considers the stress sensitivity is presented; then the solution of nonlinear pressure diffusivity equation is used to derive the shape factor; finally, the shape factor obtained in this paper is segmented by time and applied to the dual-porosity numerical reservoir simulation. The Boltzmann transform, the separation variable method and the method of power series are used to solve the nonlinear governing equation by considering the stress sensitivity in matrix system. The approximate analytical model for the shape factor presented in this paper is verified using fine-grid, finite element numerical simulation. The dependency of the shape factor on the matrix stress sensitivity is also investigated. The theoretical analysis presented improved our understanding of transfer flow in fractured porous media, and provides a new method for dual-porosity numerical reservoir simulation of fractured reservoirs.",18,20,1
Fracture,In-situ Stress,"Tang, Haoyu; Li, Sanbai; Zhang, Dongxiao",The effect of heterogeneity on hydraulic fracturing in shale,Hydraulic fracturing simulation; Heterogeneity; Geostatistics; Shale gas development,MECHANICAL-PROPERTIES; SEISMIC EXPLORATION; STRENGTH; ROCKS; SIMULATION; SERIES; MODEL,"Modelling hydraulic fracturing processes in shale oil and gas development remains a major challenge for industrial applications. The omission of heterogeneity inherent in the shale matrix may be one of the causes for the divergence between simulated fractures and those in reality. To elucidate the effects of heterogeneity on hydraulic fracturing, a workflow is developed for generating heterogeneous fields of hydraulic and geomechanical properties based on relatively easily available compressional wave velocity and shear wave velocity. After that, the workflow is implemented in our thermo-hydro-mechanical simulator for hydraulic fracturing. With the integrated simulator, the following are investigated: the effect of heterogeneity and the interactive effects of heterogeneity with other factors, i.e., in-situ stress gradient and stress shadow, the significance of different levels of heterogeneity, and the impact of various injection rates. The simulation results showed that these factors could have either synergetic or competitive effects under different circumstances. Also, different levels of heterogeneity result in different patterns of fractures' geometry. According to our study, a heterogeneity field with a large coefficient of variation (CV) and medium correlation length (CL) turns out to develop fractures of the most complex patterns. Moreover, the high injection rate leads to neutralization of the influence of heterogeneity through the averaging effect of intense fracturing. The study leads to better understandings in the mechanism of hydraulic fracturing process under complicated factors such as heterogeneity, interactive effects, fracturing strategies, and both modes of rock failure. This study may shed light on future research on hydraulic fracturing and possible applications in practice as well as some improvements in designing hydraulic fracturing simulator.",17,19,3
Fracture,In-situ Stress,"Zhang, Luqing; Zhou, Jian; Braun, Anika; Han, Zhenhua",Sensitivity analysis on the interaction between hydraulic and natural fractures based on an explicitly coupled hydro-geomechanical model in PFC2D,Hydraulic fracturing; Sensitivity analysis; Explicitly coupled hydro-geomechanical model; Numerical simulation; Two-dimensional particle flow code (PFC2D),FLUID VISCOSITY; FINITE-ELEMENT; PROPAGATION; SHALE; ROCK; SIMULATION; INITIATION; INJECTION; BOREHOLE; BRITTLE,"Fluid-induced fracture nucleation, propagation and interaction with natural fractures are the crucial issues for well understanding the process of hydraulic fracturing in unconventional reservoirs. In this paper, an explicitly coupled hydro-geomechanical model in two-dimensional Particle Flow Code (PFC2D) is employed to investigate the interaction between hydraulic fractures (HFs) and natural fractures (NFs), and the numerical scheme is validated by using analytical results. Several factors affecting the interactions between induced-fractures and NFs are being investigated and discussed. The simulation results show that three fundamental crossing scenarios can be well reproduced: (I) Direct Crossing, (II) Offset Crossing and (III) No Crossing (Arrested), and the crossing types agree well in the evaluation by Blanton's criterion. A sensitivity analysis shows that hydraulic fracture (HF) tend to be arrested by a natural fracture (HF) under low approach angles and prefer to cross the NF under higher in-situ differential stress states. Crossing is likely to be impeded for NFs with lower frictional coefficient and higher permeability. Additionally, lower fracturing fluid injection rates and lower fluid viscosities both are advantageous conditions for NF reactivation, and tend to arrest the HF. Moreover, the mechanism of the interaction of HFs and NFs influenced by the aforementioned factors can be well explained by the evolution of normal stress on the pre-existing interface, which is the key issue for correct simulation of hydraulic fracturing. Compared with the analytical model, the model in this study can reflect the dynamic stress evolution process, which will be a useful tool for optimizing the design of hydraulic fracturing in fractured reservoirs.",17,19,2
Fracture,In-situ Stress,Liu Qingling; Tian Shouceng; Li Gensheng; Sheng Mao; Li Xiaojiang; Wang Tianyu; Shen Zhonghou,An analytical model for fracture initiation from radial lateral borehole,Analytical model; Radial drilling; Hydraulic fracturing; Fracture initiation pressure; Location of failure zone; Initial fracture direction,HYDRAULIC FRACTURE; INTEGRATED WORKFLOW; DIRECTIONAL WELL; MECHANISMS; STRESS; PROPAGATION; SIMULATION; ROCKS; TESTS; SIZE,"Radial drilling-fracturing, the integration of radial drilling and hydraulic fracturing, is an innovative approach to develop low permeability, thin target layer and naturally fractured reservoirs, etc. Understanding the fracture initiation process is required in the practical application to avoid high fracture initiation pressure (FIP) and complex fracture geometries near the wellbore. In this paper, we develop an analytical model to determine FIP, location of rock failure zones and initial fracture direction from the radial lateral borehole. This model is based on the stress superposition induced by cased main wellbore and radial borehole, and the maximum tensile stress criterion is adopted. Then, we perform a series of sensitivity analysis by examining different effects of in-situ stress regime, lateral orientation (the included angle between borehole axis and maximum horizontal in-situ stress), lateral length, and lateral diameter. Besides, the effect of pre-existing weakness plane, across which the tensile strength is much lower than that of the intact rock, is also investigated, when the plane is drilled through by the radial borehole. Results show that for intact rock with no weakness plane, the in-situ stress regime and lateral orientation are main factors influencing FIP, location of rock failure zones, and initial fracture direction. Under the in-situ stress regime of normal fault, fracture initiates vertically, and FIP enlarges as lateral orientation increasing; under the in-situ stress regime of strike slip, fracture initiates vertically with small lateral orientation, while fracture initiates horizontally with large lateral orientation; and under the in-situ stress regime of reverse fault, fracture initiates horizontally with any lateral orientation, and FIP decreases as the lateral orientation increasing. It is also found that when the fracture initiates vertically, the location of rock failure zones is at the base of radial borehole on its top and bottom sides; and when the fracture initiates horizontally, the location of rock failure zone is at the remote region of radial borehole on its right and left sides. The lateral length has a minor effect on fracture initiation, and the influence of lateral diameter is negligible. When the weakness plane is drilled through by the radial borehole, fracture initiation pressure from weakness plane is affected by its occurrence, i.e., azimuth and inclination. FIP is determined by taking the minimum between fracture initiation pressure from rock matrix and the weakness plane. The key findings of this work could provide critical insights into understanding radial drilling-fracturing initiation characteristics.",15,15,3
Fracture,In-situ Stress,"Zhang, Hua; Yin, Shunde; Aadnoy, Bernt",Poroelastic modeling of borehole breakouts for in-situ stress determination by finite element method,Borehole breakouts; Finite element method; Inverse analysis; In-situ stress; Poroelasticity,PRINCIPAL STRESS; CAJON PASS; FAILURE; WELL; FRACTURE; ROCK; CRITERION; STRENGTH; MOGI,"Borehole breakouts are changes in borehole geometry in a cross section perpendicular to the borehole axis when rock subjected to in-situ stress experiences shear failure. By finite element modeling of borehole breakouts considering poroelasticity, the authors simulate the process of borehole breakouts in terms of initiation, propagation and stability in the condition of Mogi-Coulomb criteria, and can get the shape of borehole breakouts. It's desirable that this information of borehole breakouts can be used to determine in-situ stress by inverse analysis. Artificial neural network provides such a tool to establish the relationship between in-situ stress and shape on borehole breakouts, by which in-situ stress can be obtain according to different shape of borehole breakouts. In this paper, there are two steps to determinate in-situ stress by inverse analysis. First, Sets of finite element modeling provides sets of data on in-situ stress and borehole breakout measures, which will be used to train an artificial neural network that can eventually represent the relationship between the in-situ stress and borehole breakout measures. Second, for a given measure of borehole breakouts, the trained artificial neural network will be used to predict the corresponding in-situ stress. Results show that the inverse analysis based on finite element modeling of borehole breakouts and artificial neural network can effectively determine in-situ stress.",14,14,4
Fracture,Proppant,"Hu, Xiaodong; Wu, Kan; Li, Gensheng; Tang, Jizhou; Shen, Zhonghou",Effect of proppant addition schedule on the proppant distribution in a straight fracture for slickwater treatment,Hydraulic fracturing; Pumping schedule; Low-viscosity fluid; Proppant transport; Proppant bed,HYDRAULIC FRACTURE; GRANULAR-MATERIALS; MODEL; TRANSPORT; FLOW; SIMULATION; EQUATIONS; DESIGN,"The slickwater treatment is widely used in the unconventional fracturing. The proppant addition schedule is an important aspect of slickwater treatment. However, the effect of proppant addition schedule on the proppant distribution in a fracture for slickwater treatment is not well understood now. In this paper, we investigated the effect of proppant addition schedule on the proppant distribution in a straight fracture for slickwater treatment. First, we built the proppant model in a straight fracture based on the Eulerian-Lagrangian model, which can accurately simulate the proppant transport in the fluid. We validated this model by published experimental data. After the validation, we presented a base case to give a clear understanding of the proppant distribution in a straight fracture. Next, we designed a series of case studies to investigate the impacts of injection velocity, injection proppant concentration, multi-concentration proppant addition order and multi-size proppant addition order on proppant distribution in a fracture. This work can give a clear insight into the effects of proppant addition schedule on the proppant distribution. The results can help to optimize the pumping schedule in stimulation treatment in the unconventional reservoir.",65,67,10
Fracture,Proppant,"Jia, Yunzhong; Lu, Yiyu; Elsworth, Derek; Fang, Yi; Tang, Jiren",Surface characteristics and permeability enhancement of shale fractures due to water and supercritical carbon dioxide fracturing,Surface characteristics; Permeability enhancement; Hydraulic fracturing; Supercritical carbon dioxide (Sc-CO2),HYDRAULIC FRACTURE; GRAVITY CURRENTS; TIP REGION; FLUID-FLOW; GAS-FLOW; PROPAGATION; INITIATION; ROUGHNESS; RHEOLOGY; WELLS,"Carbon dioxide (CO2) is an alternative working fluid to water for hydraulic fracturing in shale reservoirs. It offers advantages as a substitute for the use of large quantities of potable water and for the concurrent sequestration of CO2, however sorption and swelling effects, and their impact on permeability may be detrimental and are undefined. Hence, it is of great importance to understand the mechanism of supercritical carbon dioxide fracturing in shale and its effect on shale permeability enhancement. We conduct hydraulic fracturing experiments on shale samples using both water (H2O) and supercritical carbon dioxide (Sc-CO2) as fracturing fluids to explore the surface characteristics and permeability evolution of fluid-driven fractures. We use profilometry to measure the roughness and complexity of the resulting fracture surfaces and measure the permeability of the fractures. Results indicate that: (1) Sc-CO2 fracturing creates fractures with larger tortuosity relative to H2O fracturing (macroscale); (2) the topography of Sc-CO2 fracture surfaces is more rough and complex compared to that of H2O fractured surfaces; (3) larger mineral grains are removed and relocated from induced fracture surfaces by Sc-CO2 fracturing-these acting as micro proppants that result in a larger fracture aperture; (4) correspondingly, the permeability of shale fractures increases by similar to 5 orders of magnitude with Sc-CO2 fracturing and this enhancement is similar to 3 orders of magnitude higher than that by traditional hydraulic fracturing. This observation potentially validates the feasibility of Sc-CO2 as a fracturing fluid for the stimulation of shale reservoirs.",64,66,6
Fracture,Proppant,"Tang, Jizhou; Wu, Kan; Zeng, Bo; Huang, Haoyong; Hu, Xiaodong; Guo, Xuyang; Zuo, Lihua",Investigate effects of weak bedding interfaces on fracture geometry in unconventional reservoirs,3D DDM; Weak interface; Height containment; Multiple fractures,DISPLACEMENT DISCONTINUITY METHOD; LAYERED FORMATIONS; PROPAGATION; CONTAINMENT; MECHANICS; ROCK,"Shale formations often consist of multiple weak interfaces between layers, which is easily opened during hydraulic fracturing treatment and affect growth of fracture height. Fracture propagation in such formations usually induced complex fracture geometry with primary vertical fractures and horizontal fracture segments between layers. Although numerous numerical models have been developed to simulate fracture propagation in unconventional reservoirs, relatively few physical three-dimensional models exist to quantitatively simulate opening of fractures affected by weak interfaces. In this paper, we analyze width profile of fractures and interaction of vertical and horizontal fracture segments with predetermined fracture path under the assumption of neglecting the flow effect. A fully three-dimensional displacement discontinuity method (3D DDM) is introduced to model multiple fractures in a stage in three dimensions. The fracture geometry is prescribed, which combined with vertical and horizontal fractures. In each case, the horizontal fracture is regarded as opening of the bedding interface and vertical fracture would either be arrested or directly cross the interface. Interfacial sliding distance, defined as width jump of the vertical fracture at the interface, is regarded as a primary impact of fracture height containment. Analysis of fracture opening, shear displacements and interfacial sliding distance is given for both vertical and horizontal fracture segments. When multiple vertical fractures intersect with a horizontal interface, shear displacements are induced on the interface and vertical fractures have smaller width compared with the case without the horizontal interface, as a result of the interaction with the interface. We observed that both widths of fracture segments and interfacial sliding distance are positively correlated with the distance between the center of the vertical fracture and the horizontal interface, half-length of horizontal fracture segment, the net pressure within fracture segments. Conversely, Young's Modulus has a negative relationship with both width of fracture segments and interfacial sliding distance. This paper analyzes the effects of opening of weak interfaces and provides critical insights of fracture width distribution and its impacts on proppant transport.",46,47,2
Fracture,Proppant,"Wang, Jiehao; Elsworth, Derek",Role of proppant distribution on the evolution of hydraulic fracture conductivity,Hydraulic fracturing; Proppant distribution; Residual opening; Proppant embedment; Fracture conductivity; Channel fracturing,COMPRESSIBLE PROPPANT; TRANSPORT; MODEL; CLOSURE; PERMEABILITY; DEFORMATION; PERFORMANCE; SIMULATION; MECHANICS; EMBEDMENT,"The residual opening of fluid-driven fractures is conditioned by proppant distribution and has a significant impact on fracture conductivity - a key parameter to determine fluid production rate and well performance. A 2D model follows the evolution of the residual aperture profile and conductivity of fractures partially/ fully filled with proppant packs. The model accommodates the mechanical response of proppant packs in response to closure of arbitrarily rough fractures and the evolution of proppant embedment. The numerical model is validated against existing models and an analytic solution. Proppant may accumulate in a bank at the fracture base during slick water fracturing, and as hydraulic pressure is released, an arched zone forms at the top of the proppant bank as a result of partial closure of the overlaying unpropped fracture. The width and height of the arched zone decreases as the fluid pressure declines, and is further reduced where low concentrations of proppant fill the fracture or where the formation is highly compressible. This high-conductivity arch represents a preferential flow channel and significantly influences the distribution of fluid transport and overall fracture transmissivity. However, elevated compacting stresses and evolving proppant embedment at the top of the settled proppant bed reduce the aperture and diminish the effectiveness of this highly-conductive zone, with time. Two-dimensional analyses are performed on the fractures created by channel fracturing, showing that the open channels formed between proppant pillars dramatically improve fracture transmissivity if they are maintained throughout the lifetime of the fracture. However, for a fixed proppant pillar height, a large proppant pillar spacing results in the premature closure of the flow channels, while a small spacing narrows the existing channels. Such a model provides a rational means to design optimal distribution of the proppant pillars using deformation moduli of the host to control pillar deformation and flexural spans of the fracture wall.",41,42,7
Fracture,Proppant,"Zhang, Lufeng; Zhou, Fujian; Mou, Jianye; Xu, Guoqing; Zhang, Shicheng; Li, Zhun",A new method to improve long-term fracture conductivity in acid fracturing under high closure stress,Deep carbonate reservoirs; Acid propped fracturing; SMA treated proppant; Long-term conductivity; Conductivity model,AGENT TREATED PROPPANT; PERMEABILITY; EMBEDMENT; RESERVOIR; PRESSURE; ROCK,"Acid propped fracturing is one of the most effective methods to enhance the stimulation effect, especially in the high-temperature deep carbonate formation. However, the short-term conductivity experimental data used in existing acid fracturing optimal designs may not be directly applicable to the real case. Aiming at this problem, this paper conducted a research on long-term acid conductivity behavior and proposed a new method to raise acid fracture conductivity under high closure stress. Frist, a series of experiments with carbonate core samples were conducted to investigate long-term acid conductivity behavior of carbonate reservoirs with closure stress up to 100 MPa. Gelled and cross-linked acids with different acid-rock contact times were tested to analyze the effects of acid type and acid-rock contact time on the conductivity. Next, acid fracture conductivity by adding proppant was tested to investigate the feasibility of increasing acid fracture conductivity under high closure stress. Long-term conductivity was measured up to 168 h to analyze the impact of deformation and embedment of proppant on conductivity. Finally, proppant size and concentration on conductivity were optimized for maximizing conductivity. The study shows that the conductivity with gelled acid is higher than the case with cross-linked acid for the same contact time. When the contact time is 60 min, gelled acid fracture conductivity has already reached its upper limit. The ideal combination of proppant size and concentration are optimized at different stress level. When the closure pressure is below 50 MPa, the conductivity is the highest at the proppant concentration of 0.75 kg/m(2) using 20/40 mesh proppant. While the closure pressure exceeds 50 MPa, the conductivity is the highest at the proppant concentration of 3 kg/m(2) using 40/70 mesh proppant. The acid propped fracture conductivity decreases rapidly in 48 h and undergoes the gradual drop, remaining steady after 120 h. An analytical model of acid propped fracture conductivity was also developed. This study provided an insight into optimizing acid propped fracturing design and predicting well performance.",26,29,5
Fracture,Proppant,"Wang, HanYi; Sharma, Mukul M.",Modeling of hydraulic fracture closure on proppants with proppant settling,Hydraulic fracture; Fracture closure; Proppant transport; Proppants settlement; Proppant dune; Stress amplification,SHALE-GAS-PRODUCTION; CONDUCTIVITY; PROPAGATION; SYSTEMS; EMBEDMENT; TRANSPORT; DESIGN; ROCKS; WIDTH,"The placement of proppants in a hydraulic fracture is governed by slurry flow, proppant transport and settlement. The proppant distribution can significantly affect the conductivity of the hydraulic fracture, and hence will impact the productivity of hydraulic fractured wells. Past studies have investigated fracture closure on proppants by envisioning hydraulic fractures as two parallel plates with uniformly distributed proppants. However, in reality, hydraulically induced fractures are wider in the middle and narrower near the fracture edges. In addition, a proppant dune is likely to be accumulated at the bottom of the fracture because of proppant settling. As a result, fracture closure on proppants is controlled by both fracture geometry and the distribution of proppant in the fracture. This is a dynamic process where fracture geometry and the proppant pack will evolve as a function of pressure, and the associated surface contact problem is notoriously challenging to solve because of its non-linear and nonlocal nature. In this study, we proposed a general approach to model hydraulic fracture closure. The residual fracture width profile for both propped and un-propped sections can be obtained at different drawdown pressures for rocks with different clay content. The maximum stress acting on proppants can be calculated to guide the selection of proppants with appropriate strength. Most importantly, the effect of stress concentration and stress amplification can be quantified when a proppant dune or bank is formed. We also show that the traditional method of estimating the maximum stress on a proppant pack is an underestimation.",23,23,2
Fracture,Proppant,"Roostaei, Morteza; Nouri, Alireza; Fattahpour, Vahidoddin; Chan, Dave",Numerical simulation of proppant transport in hydraulic fractures,Frac-packing; Hydraulic fracturing; Proppant transport; Shock capturing techniques,ESSENTIALLY NONOSCILLATORY SCHEMES; NEWTONIAN SLURRY; MODEL; SPHERES; WELLS,"A central issue in hydraulic fracturing treatment in petroleum wells is the transport of proppant particles by the injection fluid. In this paper, we present an innovative proppant transport model in a fixed rectangular-and elliptic-shaped slots. The proposed model is an improvement to the current modeling of proppant transport by applying a non-oscillatory numerical scheme which has high accuracy everywhere in solution domain, even close to the steep gradients. In addition, inertia, fracture wall, and concentration effects on proppant settling along with slurry evolution as a function of proppant concentration has been considered. This paper introduces the mathematical equations that govern the proppant transport phenomenon and discusses special front capturing numerical techniques, boundary conditions, coupling between proppant and slurry mass conservation equations and time stepping restrictions required for the solution stability. We incorporated published correlations obtained from proppant transport laboratory experiments in our numerical model to better capture the physics of the problem. 5th-order WENO scheme was used to avoid oscillation and diffusion at the proppant front since traditional finite difference discretization was found to be insufficient in solving the hyperbolic transport partial differential equations. Results show that the technique used in this study can capture the proppant distribution with minimum oscillation and diffusion. A series of sensitivity analysis was conducted to explore the legitimacy of these assumptions and to provide guidelines that allow more accurate predictions of the proppant and fluid transfer. Numerical results are presented to show how proppant distribution is impacted by the injection fluid viscosity, density difference between proppant particles and injection fluid, proppant size, and fluid flow injection rate. Results of the sensitivity analysis illustrate the significance of choosing appropriate viscosity of the injection fluid as small changes in the viscosity may cause noticeable effects on the concentration distribution. In addition, we found that variation of proppant size and density within a reasonable range have a modest effect on proppant concentration distribution. Furthermore, we also investigated the amount of gravity driven vertical motion of proppant which is driven by density differences ( convection) and compare it to a second gravity driven motion which is proppant settlement. Both of these two well recognized mechanisms can occur inside a fracture during proppant placement, however, the importance of each mechanism as a function of proppant injection design parameters is not fully understood.",22,23,5
Fracture,Proppant,"McClure, Mark",Bed load proppant transport during slickwater hydraulic fracturing: Insights from comparisons between published laboratory data and correlations for sediment and pipeline slurry transport,Proppant transport; Bed load transport; Hydraulic fracturing; Slickwater,EQUATION; CURRENTS; FLOW,"Bed load transport is the movement of particles along the top of a bed through rolling, saltation, and suspension created by turbulent lift above the bed surface. Based on experimental work, early investigators suggested that bed load transport may be an important mechanism during field scale hydraulic fracturing. However, later studies suggested that bed load transport is much more important in the laboratory than at field scale because the rate of bed load transport does not scale with fracture height. In recent years, there has been a resurgence of interest in the idea that bed load transport is significant at the field scale. Patankar et al. (2002) and Wang et al. (2003) presented new laboratory scale experiments on bed load proppant transport and proposed correlations to match the data. The correlations have subsequently been applied directly in field scale hydraulic fracturing simulators and have been used to design completion strategies and select proppants. This paper reviews correlations for sediment and slurry transport and provides a reanalysis of the laboratory results from Patankar et al. (2002). The analysis finds that the experiments can be well-described using classical correlations for sediment and slurry flow. The correlations are applied without adjusting any free parameters to fit the data. The analysis suggests that the total amount of proppant that can be transported in bed load transport in laboratory experiments is roughly similar to the amount transported at field scale. Because much greater volumes of proppant are injected at the field scale, the implication is that bed load transport is negligible in the great majority of field scale hydraulic fracturing treatments.",22,24,4
Fracture,Proppant,"Sun, Baojiang; Wang, Jintang; Wang, Zhiyuan; Gao, Yonghai; Xu, Jianchun",Calculation of proppant-carrying flow in supercritical carbon dioxide fracturing fluid,Supercritical carbon dioxide fracturing; Fracture; Proppant-carrying flow; Equilibrium flow rate; Proppant embankment,GAS-RESERVOIRS; CO2; TEMPERATURE; TRANSPORT; STIMULATION; SEDIMENT; EQUATION,"As a new clear and efficient fracturing fluid, supercritical carbon dioxide (SC-CO2) has many advantages in the development of unconventional oil and gas resources, such as no harm to the reservoir, improving the reservoir permeability and fluid flow resistance, quickly completely flowing back after fracturing. Based on the principle of suspension energy balance, an equilibrium flow rate model of proppant-carrying flow of SC-CO2 is derived, and calculation errors are 3.32% and 4.54%, respectively, compared with equilibrium flow rates obtained from experiments under different density and particle sizes. By considering the change of fluid internal energy and flow work, filtration characteristics, physical parameters, and SC-CO2 -rock adsorption in the SC-CO2 fracturing process, a proppant-carrying flow calculation model of the SC-CO2 fracturing fluid is established based on temperature- pressure field coupling, fracture and filtration zone coupling, and SC-CO2 fluid and proppant coupling. In the experiment, the heights of nine groups of proppant embankments were measured, and the average model prediction error value is 3.43%. SC-CO2 has a similar proppant-carrying capacity to that of clear water under the high Reynolds number condition. Based on the proppant-embankment prediction model of SC-CO2 fracturing, through analyzing proppant-carrying characteristics of the SC-CO2 fracturing fluid, the proppant concentration distribution and proppant embankment section are obtained at different fracturing times. According to the calculation, as the fracturing fluid pumping rate increases, proppant density and proppant particle size will decrease, the viscosity of the SC-CO2 fracturing fluid system will increase, and proppant accumulation height can be reduced over a small range, while proppant accumulation length will experience a greater increase along the fracture length direction. During field operation of SC-CO2 fracturing, the proppant pumping process should be optimized according to the proppant embankment section and proppant concentration should be choose increased in small steps to meet fracture propping requirements.",18,19,2
Fracture,Proppant,"Pu, Wan-fen; Du, Dai-jun; Liu, Rui",Preparation and evaluation of supramolecular fracturing fluid of hydrophobically associative polymer and viscoelastic surfactant,Fracturing fluid; Supramolecular self assembly; Low damage capability,GUM; COPOLYMER; SUSPENSION; BEHAVIOR,"A novel fracturing fluid (NAF) comprising of self-synthesized beta-cyclodextrin-functionalized hydrophobically associative polymer (HMPAM) and viscoelastic surfactant (VES) was developed. The apparent viscosity of NAF was several times more than that of HMPAM and VES alone. The supramolecular complex gel was achieved by weak physical attractive forces, including intermolecular hydrophobic association, host-guest inclusion, and self-assembly between hydrophobic chains and wormlike micelles. NAF possessed favorable temperature tolerance, shearing resistance, and proppant suspension ability due to its multiple supramoelcular behaviors and high viscoelasticity. Moreover, the gel could be completely broken with no residue, and the broken fluid was easy to flow back. The results indicated that NAF is an effective fracturing fluid and might have favorable application during hydraulic fracturing.",17,17,5
Fracture,Proppant,"Liang, Tianbo; Zhou, Fujian; Shi, Yang; Liu, Xiongfei; Wang, Rui; Li, Ben; Li, Xiuhui",Evaluation and optimization of degradable-fiber-assisted slurry for fracturing thick and tight formation with high stress,Degradable fiber; Proppant settling; Proppant transport; Thick formation,PROPPANT TRANSPORT; GAS-PRODUCTION; WATER-USE; PERMEABILITY; SHALE; OIL,"Economically producing hydrocarbon from tight formations requires fracturing with a large volume of water and proppants to ensure a highly conductive fracture network. Proppant settling can hinder proppant transportation within fractures, limiting dimensions of the propped fractures and well production rates. This problem is more serious in thick formations that tall fractures are needed. In deep reservoirs with high closure stresses, using high pumping rate or viscous cross-linked gel have their own limitations, while adding degradable fibers can solve the problem. However, no visualized flow experiments have been conducted that can fill the gap between the benchtop measurements and the field tests, thus providing reliable mechanisms to guide the optimization of this technique for a chosen reservoir. In this study, a systematic screening and evaluation procedure is developed to quantify the effectiveness of degradable fibers on suspending proppants and enhancing fracture conductivity, so as to explore the mechanisms behind this technique. Results indicate that a dilute concentration of fibers in proppant slurry can double proppant placement efficiency without blocking perforation holes on the wellbore; fiber degradation leaves no residue that damages fracture conductivity; fiber degradation does not cause the closure of propped fractures even at high closure stresses.",17,18,1
Fracture,Proppant,"Ranjith, P. G.; Wanniarachchi, W. A. M.; Perera, M. S. A.; Rathnaweera, T. D.",Investigation of the effect of foam flow rate on foam-based hydraulic fracturing of shale reservoir rocks with natural fractures: An experimental study,Foam; Fracturing; Breakdown pressure; Flow rate; Fracture permeability; CT scanning,PERMEABILITY; PRESSURE; ENERGY; GAS; PROPAGATION,"Foam-based hydraulic fracturing has been identified as a good solution for the extraction of natural gas from deep shale reservoirs, due to its unique advantages such as low water consumption and high proppant carrying capacity. However, lack of knowledge of foam-based shale fracturing and complex nature of two-phase foam, make it challenging to use in field conditions, and one unclear area is the effect of the foam flow rate on fracturing and fracture characteristics. Therefore, the aim of this study was to investigate the effect of foam flow rate on breakdown pressure, fracture permeability and generated fracture characteristics. In order to achieve this, a series of hydraulic fracturing experiments was conducted for shale rocks with existing natural fractures, using nitrogen-based foam. Fracture permeability was also evaluated for intact and fractured rock samples. Micro-CT scanning technology was adopted to characterise the geometrical properties of fractures, in order to investigate the effect of foam flow rate within the fracture. Experimental results show that the breakdown pressure increases by 30% while energy release decreases by 78% when the foam flow rate increases from 10 to 70 ml/min. In addition, the results suggest that the permeability of a fractured sample at 10 ml/min injection rate is about 15 times higher than that of a fractured sample at 70 ml/min injection rate. The findings of this study reveal that low foam-flow rates can create a better inter-connected fracture network than higher flow rates.",15,15,4
Fracture,Low Salinity,"Da, Chang; Alzobaidi, Shehab; Jian, Guoqing; Zhang, Leilei; Biswal, Sibani L.; Hirasaki, George J.; Johnston, Keith P.",Carbon dioxide/water foams stabilized with a zwitterionic surfactant at temperatures up to 150 degrees C in high salinity brine,CO2-in-water foam; Zwitterionic surfactant; Porous media; EOR,ENHANCED OIL-RECOVERY; WORMLIKE MICELLES; CONCENTRATED EMULSIONS; SUPERCRITICAL FLUIDS; MOBILITY CONTROL; MIXED-SOLUTIONS; AQUEOUS-PHASE; POROUS-MEDIA; YIELD-STRESS; ADSORPTION,"Stabilization of CO2-in-water (C/W) foams with surfactants at high temperature and high salinity conditions is challenging given limitations in the solubility and thermal stability of surfactants, particularly for surfactants other than anionic ones. Here we show that a single zwitterionic surfactant, cetyl betaine (CH3(CH2)(15)N+(CH3)(2)CH2COO-), stabilizes viscous C/W foam (> 15 cP) in crushed limestone (76-Darcy) at a temperature up to 150 degrees C and over a wide range in salinity up to 22% total dissolved solids (TDS) at superficial velocity of 940 ft/day. According to liquid chromatography mass spectrometry (LC/MS), cetyl betaine has high thermal stability with negligible chemical degradation after incubation at 135 degrees C for 30 days. Interfacial tension (IFT) at the C/W interface was reduced significantly from similar to 37 mN/m to < 5 mN/m with the addition of 0.08 mmol/L of cetyl betaine. Relative to ionic surfactants, the relatively weak electrostatic repulsion between the local charges in the headgroup is shown to produce strong adsorption at the C/W interface (similar to 134 angstrom(2)/molecule), resulting in generation of viscous foam (similar to 6 cP) even in pure water without added salt. At a low superficial velocity of 6 ft/day (shear rate 45 s(-1)) in a beadpack, foam was still formed with cetyl betaine. Static adsorption of cetyl betaine on carbonates was on the order of 1 mg/m(2), and core flood test also proved that cetyl betaine could stabilize viscous C/W foam (> 20 cP) within 6 pore volumes of injection at 120 degrees C. The surfactant stabilized viscous C/W foam at low oil fractions and broke in the presence of large fractions of oil, both of which are desirable in CO2 mobility control and oil displacement. The ability to form foams at high temperatures and over a wide range in salinity is important for various practical applications including CO2 enhanced oil recovery, fracturing with energized fluids and CO2 sequestration.",46,48,19
Fracture,Low Salinity,"Fredriksen, Sunniva B.; Rognmo, Arthur U.; Ferno, Martin A.",Pore-scale mechanisms during low salinity waterflooding: Oil mobilization by diffusion and osmosis,Low salinity effect; Pore-scale mechanisms; Osmosis and water diffusion; Oil mobilization; Salinity contrast; Chemical potential,WETTABILITY ALTERATION; FOAM-GENERATION; RECOVERY; MICROMODEL,"Pore-level oil mobilization is studied during low salinity waterflooding by microscopic visualization of water diffusion and osmosis in sandstone silicon-wafer micromodels. The two-dimensional water-wet micromodels apply a controlled, state-of-the-art experimental approach, with a high accuracy pore network, sharp edges and surface roughness to observe transport and displacement processes during low salinity waterflooding. Residual and capillary trapped oil is mobilized when a salinity contrast is established between high-saline connate brine in matrix and low salinity water flowing in an adjacent fracture. The driving force is the difference in chemical potential between the aqueous phases. The focus of this work is on water transport by diffusion and osmosis, mechanisms that are both present in low salinity waterflooding, but less reported in literature. The micromodel system makes it possible to distinguish diffusive and osmotic effects from other well-known mechanisms such as wettability change and fines migration. Transport of water occurs by diffusion through film-flow resulting in film-expansion along water-wet grains. In presence of an osmotic gradient the oil-phase act as a semi-permeable membrane allowing transport of low salinity water into high-saline water-in-oil emulsions.",38,39,5
Fracture,Low Salinity,"Teklu, Tadesse Weldu; Li, Xiaopeng; Zhou, Zhou; Alharthy, Najeeb; Wang, Lei; Abass, Hazim",Low-salinity water and surfactants for hydraulic fracturing and EOR of shales,Low-salinity water; Low-salinity water plus srufactnat; Osmosis; Capillary pressure; Wettability alteration; IFT decrease; Hydraulic fracturing and EOR of shales,OIL-RECOVERY; UNCONVENTIONAL RESERVOIRS; IMBIBITION; WETTABILITY; TRANSPORT,"There are significant recoverable oil and gas resources stored in shale reservoirs throughout the world. Horizontal well with multistage hydraulic fracturing is an enabling technology for economic production of these shale resources. Recovery factors of liquid rich shale reservoirs is typically less than 10%, hence, there is an incentive for implementing enhanced oil recovery (EOR) technologies to improve oil production from these very tight reservoirs. Brine, chemical (surfactant), gas, or combination of these fluids imbibition or injection in huff-n-puff scenario could improve oil recovery of liquid rich shale reservoirs. In this study, low-salinity water and low-salinity water + surfactant imbibition are assessed as both hydraulic fracturing and EOR fluids in liquid rich shale reservoirs. Osmosis, capillary pressure, wettability alteration, and other effects are among the mechanisms by which these fluids can improve oil recovery from shale reservoirs. These favorable effects were investigated through imbibition experiments. Experiments show: (a) low-salinity water huff-n-puff in tight formations can improve oil production from tight formations. This is because wettability alteration, capillary, and osmotic forces; (b) surfactant + low-salinity-water huff-n-puff can further improve oil production due to additional IFT decrease and wettability alteration by surfactants; hence, improve oil production from stimulated ultra-tight formations. Based on experimental observations and literature reviewed, low-salinity water huff-n-puff (until economical), followed by low-salinity water + surfactant huff-n-puff EOR process is recommended to optimize production from liquid rich shale reservoirs, while minimizing cost. These fluids can be used to reduce matrix-fracture skin damage. The effectiveness of these hydraulic fracturing and EOR fluids in shales is highly dependent on the existence and extent of natural fractures or laminations within the stimulated reservoir volume; this is because osmosis and diffusion are very slow processes.",27,29,7
Fracture,Low Salinity,"Brattekas, B.; Seright, R. S.",Implications for improved polymer gel conformance control during low-salinity chase-floods in fractured carbonates,Polymer gel; Low-salinity chase-flooding; Improved blocking capacity; Fractured carbonates; Influence of oil; PET imaging,PREFORMED-PARTICLE-GEL; PERFORMANCE; PLACEMENT; FLOW,"Polymer gel is often used to reduce flow through highly conductive fracture networks, frequently present in naturally fractured carbonate reservoirs. When in place, polymer gel efficiently reduces fracture flow and may improve sweep efficiency and oil recovery during water chase-floods. Polymer gel treatments have in some cases been less efficient than expected in reducing fracture conductivity. This may occur because the polymer gel only partially fills the fracture volume, and allows fracture channeling of injected fluids. Low-salinity waterfloods may improve polymer gel blocking of fractures and remedy less efficient polymer gel treatments. Previous experimental work has shown that low-salinity waterfloods, where the salinity is reduced with respect to the gel solvent, reduces fracture channeling and restores matrix flow. This work further investigates low-salinity waterflooding as a method to improve conformance during polymer gel treatments in fractured, low permeable, carbonate rock. The low flow capacity of carbonate may cause a less efficient gel blocking of fractures, although the gel behaves according to established models during injection. Low-permeable carbonate core plugs with open, highly conductive fractures were used for this study. Water flow paths during high-salinity and low-salinity waterflooding were evaluated by positron emission tomography (PET). We found that gel blocking efficiency during chase waterfloods depends on: 1) the salinity of the chase water. Gel blocking efficiency increases with low-salinity water throughput; opposite to high-salinity waterfloods, where the gel blocking is reduced with water throughput. 2) The core material. As expected, a higher pressure was required to maintain flow through the matrix during water chase-floods in low-permeable carbonates. Water was diverted into the matrix for all ranges of permeability: sandstone and low-permeable carbonates, during low-salinity waterfloods. 3) The presence of oil. Fracture channeling prevailed during low-salinity waterfloods in chalk cores with residual oil present.",19,19,2
Fracture,Low Salinity,"Song, Zhaojie; Hou, Jirui; Liu, Xiaochun; Wei, Qi; Hao, Hongda; Zhang, Liya",Conformance control for CO2-EOR in naturally fractured low permeability oil reservoirs,CO2 flooding; Low permeability oil reservoir; Gas channeling; CO2 production control,CARBON-DIOXIDE; CO2 STORAGE; TIGHT OIL; RECOVERY; GAS; PERFORMANCE; IMPROVEMENT,"Poor sweep efficiency seriously limits field applications of CO2-EOR, especially in fractured reservoirs. The investigation of CO2 production performance and the method to control CO2 production becomes a key to successfully run a CO2-EOR project. In this study, artificial sandstone cores were used to perform a series of CO2 flooding experiments at reservoir conditions of pressure, temperature and formation water salinity. Injection pressure and rock heterogeneity were taken into account to study their effect on CO2 production performance. Two-stage gas channeling control with three different scenarios, including PLS gel and ethylenediamine, starch gel and ethylenediamine, and starch gel and CO2 foam, was presented to improve the conformance in 3-D fractured-core models. Based on production performance and experimental observation, three production stages were clearly stated, including gas-free production stage, oil/gas co-production stage, and gas channeling stage. Oil/ gas co-production stage contributed the most to oil recovery. This finding was very consistent with the practical production performance of CO2 flooding in oil fields. The conformance improvement and the increase in injection pressure (within permissible range bearing in mind of fracturing pressure) could remarkably enhance the oil recovery at oil/gas co-production stage. In 3-D radial flow experiments, the two-stage gas channeling control presented great potential in delaying gas production and improving CO2 flooding efficiency. The combination of starch gel and ethylenediamine achieved the best result. The starch gel could effectively block the fracture, while the viscous reactant of ethylenediamine and in-situ CO2 within high permeability layer could successfully tune injected CO2 to flood low permeability layer. This study could help field engineers determine the optimal timing of CO2 production control, and also offered an optimal method to improve the conformance for CO2-EOR.",17,17,8
Fracture,Spontaneous Imbibition,"You, Qing; Wang, Huan; Zhang, Yan; Liu, Yifei; Fang, Jichao; Dai, Caili",Experimental study on spontaneous imbibition of recycled fracturing flow-back fluid to enhance oil recovery in low permeability sandstone reservoirs,Recycled fracturing flow-back fluid; Spontaneous imbibition; Wettability alteration; Interfacial tension; Synergistic effect,WETTABILITY ALTERATION; SURFACTANT; NANOFLUIDS; CARBONATES; IFT,"In light of the high treatment costs for massive amounts of fracturing flow-back fluid and its harmfulness to the environment, a novel method of recycled fracturing flow-back fluid (RFFF) to enhance oil recovery by spontaneous imbibition is proposed in this study; this method does not allow the flow-back fluid back to the ground, thereby preventing negative impacts. The wettability alteration and interfacial tension (IFT) can effectively strengthen the spontaneous imbibition to enhance oil recovery in low-permeability sandstone reservoirs. This study combines the effects of wettability alteration and IFT with the use of the RFFF, which is composed of viscoelastic surfactants, on the spontaneous imbibition in low-permeability outcrop cores. Contact angle (CA) experiments, IFT experiments, and spontaneous imbibition experiments are conducted. The CA and IFT experimental results showed that the RFFF solutions changed the wettability of the core surface from oil-wet to waterwet and easily reduced the IFT between the crude oil and the RFFF solution to 10(-3)-10(-2) mN/m, which improved the oil recovery by changing the capillary forces. The spontaneous imbibition results showed that the RFFF solutions at concentrations of 0.03 - 0.10 wt% resulted in a higher imbibition recovery due to the synergistic effect of the wettability alteration and the IFT, which was attributed to the wedge film structure and the spreading force. It can be concluded that the use of the RFFF has the potential to further enhance oil recovery after fracturing the formation in low-permeability reservoirs without letting the fluid flow back to the ground. The proposed method is multi-functional and does not only improve the oil recovery by integrating fracturing and displacement methods but also reduces the costs of reservoir development and protects the environment.",100,103,14
Fracture,Spontaneous Imbibition,"Al-Ameri, Aymen; Gamadi, Talal; Ispas, Ion",Evaluation of the near fracture face formation damage caused by the spontaneously imbibed fracturing fluid in unconventional gas reservoirs,Fracturing fluid spontaneous imbibition; Friction reducer pad fluid; Polymer adsorption; Nonionic surfactant; Bedding plane; Imbibition capillary pressure; Imbibition water relative permeability curves,SPONTANEOUS IMBIBITION; POROUS-MEDIA; RELATIVE PERMEABILITY; CAPILLARY RISE; SHALE; GRAVITY,"In the present study, spontaneous imbibition experiments, steady-state permeability measurements, and numerical simulation were integrated to quantify the changes in the effective water permeability, capillary pressure, and water relative permeability curves due to the polymer adsorption of the spontaneously imbibed fracturing fluid. The effect of the nonionic surfactant and core bedding plane on the fluid spontaneous imbibition volumes were also investigated. The researchers considered the impact of the spontaneous imbibition of a friction reducer fluid in tight sand and shale core samples. Three comparative systematic spontaneous imbibition experiments were conducted for each of the core samples using brine, anionic friction reducer fluid, and brine again. The core sample water permeability before and after the imbibition experiment was measured using a constant rate steady-state permeability apparatus. The polymer adsorption from the spontaneously imbibed fracturing fluid significantly reduced the brine spontaneous imbibition volumes in tight sand samples and in shale samples, though to a lesser degree. Moreover, the effective water permeability was decreased because of the polymer adsorption effect. Therefore, the polymer adsorption during hydraulic fracturing reduces the fluid leak-off into the formation and also the fluid flowback. The nonionic surfactant increased the fluid spontaneous imbibition volumes in both tight sand and shale samples. Thus, adding a nonionic surfactant to the friction reducer pad fluid during hydraulic fracturing leads to enhance both of the fluid leak-off and fluid flowback. The results also showed that the effect of polymer adsorption on the imbibition rates is less when the rock-fluid contact surface is parallel to the bedding plane. The imbibition potentials and imbibition capillary pressure curves were calculated before and after polymer adsorption. The polymer adsorption led to a slight increase in the capillary pressure; moreover, the tight sand samples had higher capillary pressure than the shale samples. The imbibition water relative permeability curves were calculated using ECLIPSE commercial simulator. The polymer adsorption significantly reduces the water relative permeability curves for tight sand samples and in less degree for shale samples.",24,24,6
Fracture,Spontaneous Imbibition,"Liang, Tianbo; Li, Qingguang; Liang, Xingyuan; Yao, Erdong; Wang, Yanqing; Li, Yuan; Chen, Mai; Zhou, Fujian; Lu, Jun",Evaluation of liquid nanofluid as fracturing fluid additive on enhanced oil recovery from low-permeability reservoirs,Fracturing fluid additive; EOR; Tight oil; Wettability alteration,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; GRAVITY DRAINAGE; HIGH-TEMPERATURE; WATER BLOCKING; SHALE; SURFACTANTS; WET; CARBONATES; SYSTEM,"Hydraulic fracturing creates a complex fracture network that makes the oil production from low-permeability reservoirs economical. However, significant amount of water is likely lost into the rock matrix during hydraulic fracturing. This can cause formation damage due to multiphase flow, thus hindering the oil production rate. Surfactants can alter rock wettability and/or reduce oil-water interfacial tension (IFT), and it has been proposed to be used to mitigate such water blockage and enhance oil recovery. Among different approaches of using surfactants, forming liquid nanofluid (LNF) can minimize the adsorption of surfactants on rock surface, and it is likely to be one of the best options for low-permeability rocks with extensive surface area. In this study, the key properties of a well-screened LNF are evaluated, and then compared with a commercial flowback surfactant (CFS) that is widely used in the field. Pressure transmission test is further applied, which can determine the change of rock permeability due to different fluids and the potential formation damage due to multiphase flow. A systematic evaluation method is thus established to screen fracturing fluid additives to enhance oil production from low-permeability reservoirs both effectively and efficiently.",24,28,4
Fracture,Spontaneous Imbibition,"Hasham, Aleem A.; Abedini, Ali; Jatukaran, Arnav; Persad, Aaron; Sinton, David",Visualization of fracturing fluid dynamics in a nanofluidic chip,Fracturing fluid; Infiltration; Entrapment; Recovery; Nanofluidic,MICROFLUIDICS-BASED MEASUREMENT; PORE-SCALE ANALYSIS; SPONTANEOUS IMBIBITION; OIL-RECOVERY; GAS SHALES; HEAVY OIL; CO2; TEMPERATURE; PRESSURE,"Hydraulic fracturing is responsible for remarkable production from shale and tight formations, albeit at the cost of significant water usage. The flow dynamics of oil and fracturing fluid in nanopores remains largely uncharacterized, in part due to the challenge of conducting experiments at nanoscales. In this paper, we demonstrate a nanofluidic-based approach to visualize the fluid displacement during hydraulic fracturing. Nanoporous silicon-glass chips with circular and square grain shapes and identical depth of 175 nm were fabricated using reactiveion etching (RIE) and anodic bonding. Leveraging the inherent fluorescence property of the oil, the fluorescence microscopy was used to record the dynamics of the fluid displacement inside the chip. Performance of three different fracturing fluids - deionized water, potassium chloride (KCl) solution, and slick water - were evaluated based on the volumetric infiltration in the nanoporous network, entrapment of fracturing fluid in the porous media, and total production during drawdown. The KCl solution had the highest infiltration rate (fill factor of 0.68) and the lowest entrapment factor (0.39), resulting in the highest fracturing fluid recovery representing 43% in the square grain geometry with similar results for circular grains. With the fast quantification and ease of operation here, the nanofluidic approach enables a rapid screening of different fracturing fluids to inform shale oil operators.",20,21,3
Fracture,Spontaneous Imbibition,"Wang, Jing; Liu, Huiqing; Zhang, Jing; Meng, Qingbang; Liu, Huapu; Ge, Lizhen; Zhu, Zhiqiang; Liu, Chang",Experimental investigation on water flooding and continued EOR techniques in buried-hill metamorphic fractured reservoirs,Buried-hill fractured reservoir; Enhanced oil recovery; Experimental study; Imbibition; Water flooding,OIL-RECOVERY; SPONTANEOUS IMBIBITION; CARBONATE RESERVOIRS; CAPILLARY IMBIBITION; HIGH-TEMPERATURE; SURFACTANT; INJECTION; WET; PERFORMANCE; COCURRENT,"Fractured reservoirs are complicated due to the coexistence of matrix and fracture systems. In particular, the matrix of buried-hill metamorphic fractured reservoirs (BHMFRs) has plenty of micro-fractures and a few dissolution pores rather than common pores in sandstone. The storage and heterogeneity features, such as the storage ratio between matrix and fractures, and the distribution of fractures, significantly affect the performances of waterflooding and EOR techniques. With the objective of finding effective waterflooding mode and EOR techniques in such reservoirs, the BHMFR of JZ25-1S in Bohai Bay in China was taken as an example. First, static imbibition experiments using a novel imbibition cell were conducted. Then, 3D large-scale models of BHMFRs using outcrops were designed based on the similarity criterion and employed to conduct the experiments of waterflooding and followed EOR techniques. The results show that co-current imbibition is principal and gravity is the dominant force of imbibition for BHMFRs. Because imbibition is slow, most of the yield comes from the macro-fractures. Both water-free recovery and waterflooding recovery increase as the decrease of the storage ratio of matrix to fractures. Pulsing cyclic water-injection is better than intermittently cyclic water-injection. In BHMFRs with heterogeneity of fracture density, injection in the area with low fracture density and production in the area with high fracture density can achieve better effects than the reverse scenario for both waterflooding and followed EOR techniques. If gas flooding is selected as the EOR technique, producer should be perforated at the lower layers of the reservoir. Suitable gel particles not only get a good EOR effect by effective plugging, but also can create a more favorable condition for surfactant flooding. In our experiments, another 2-4% of OOIP was produced by PPG flooding. Surfactant can enhance the oil recovery by both removing the adsorbed oil on the fracture surface and promoting imbibition in matrix. 3-5% of OOIP was recovered by surfactant flooding and soaking in our experiments.",15,16,1
Fracture,Heat Transfer,"Kumari, W. G. P.; Ranjith, P. G.; Perera, M. S. A.; Chen, B. K.","Experimental investigation of quenching effect on mechanical, microstructural and flow characteristics of reservoir rocks: Thermal stimulation method for geothermal energy extraction",Geothermal; Granite; Permeability; Quenching; Thermal cracks; Thermal stimulation,AUSTRALIAN STRATHBOGIE GRANITE; FRACTURE PERMEABILITY; HEAT-TRANSFER; BEHAVIOR; STRESS; TEMPERATURES; EVOLUTION; TRANSPORT; POROSITY; CRACKING,"Thermal stimulation method can be effectively utilized to enhance the flow performance in the tight porous media with an induced thermal shock. This approach can be applied to many deep geo-engineering applications including geothermal energy extraction. In this regard, understanding the flow-mechanical behaviour of reservoir rock during and after thermal stimulation is necessary for safe and effective stimulation process. The aim of this study is, therefore to investigate the quenching effect on mechanical and flow behaviour of Australian Strathbogie granite by conducting a series of micro and macro-experiments. Experiments were conducted by profiling the micro-structure of rock with CT scanning, microscopic imaging and, quantifying the thermally induced damage due to quenching treatment. In order to understand mechanical response of rock due to quenching, strength tests were conducted under the unconfined condition, and the corresponding fracture propagation patterns were investigated using an acoustic emission (AE) system. In addition, flow performance of thermally treated rock was studied under a wide range of coupled high temperature and high-pressure conditions (temperatures 20-300 degrees C, confining pressure up to 45 MPa and injection pressure up to 40 MPa), simulating different geothermal temperatures and depths. According to the findings, thermal treatment resulted in around 70% of reduction of strength and elastic properties respectively due to the thermally induced damage caused by induction of both inter and intra-crystalline cracks. Further, increased porosity and crack density significantly enhanced the permeability of the rock compared to the intact rock (from approximately 1 x 10(-19)m(2) to 6 x 10(-15)m(2) under 10 MPa confining pressure). However with the increasing of normal stresses, permeability decreased non-linearly and further, increasing temperature resulted in significant reductions in permeability of granite (approximately 95% of reduction from room temperature to 300 degrees C) due to the thermally induced volumetric expansion which leads to enhancement of interlock effect.",60,68,12
Fracture,Heat Transfer,"Zhang, Shikun; Huang, Zhongwei; Huang, Pengpeng; Wu, Xiaoguang; Xiong, Chao; Zhang, Chengcheng",Numerical and experimental analysis of hot dry rock fracturing stimulation with high-pressure abrasive liquid nitrogen jet,HDR fracturing; Abrasive liquid nitrogen jet; Flow field; Heat transfer; Thermal stress; Fractal,CONJUGATE HEAT-TRANSFER; TECHNOLOGY; MODEL; RESERVOIRS; TRANSPORT; SYSTEMS,"Abrasive liquid nitrogen (L-nitrogen) jet fracturing is a novel technology, which is expected to be suitable for hot dry rock (HDR) fracturing. In this paper, numerical simulation has been presented to analyze the fluid flow, heat transfer and thermal stresses distribution in HRD fracturing with abrasive L-nitrogen jet. The simulation is carried out with a three-dimensional model in transient state. The low Reynolds number.-e model is employed to accurately predict the near wall flow. The heat transfer between L-nitrogen and hot rock on solid-liquid interface is computed by an inverse method of conjugate heat transfer. The thermo-elastic model is used to calculate the thermal stresses distribution in rock. Numerical results indicate that abrasive L-nitrogen jet has a better performance in perforation than abrasive water and supercritical CO2 jet. Great tensile stress distributes in the region near interface, however, its affected depth is limited. This tensile is expected to be favor for fractures generation and growth along perforation direction. Short perforation length can promote the heat transfer on interface. The initial rock temperature has an important influence on values of thermal stresses. Experiments, in which the hot granite specimens with a small hole in center were impacted by L-nitrogen jet, have been conducted to validate the effect of thermal stresses on fracturing. The fractal method is adopt to quantitatively describe the flow and transport capability in rock masses. Experimental results show that numerous thermal cracks were generated on the interface. Rising rock temperature can significantly increase the number and size of thermal cracks and improve the connectivity of fractured rock, which are benefit to fracture initiation during L-nitrogen jet fracturing. The results in this paper would shed light on L-nitrogen jet fracturing for HDR as well as some high-temperature oil reservoirs.",49,50,5
Fracture,Heat Transfer,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Liu, Qing; Han, Song; Zhou, Yunjian",Effect of friction work on key parameters of steam at different state in toe-point injection horizontal wellbores,Heavy oil recovery; Toe-point injection horizontal well; Friction work; Temperature distribution; Steam quality distribution; Steam state,HEAT-TRANSFER CHARACTERISTICS; MULTI-THERMAL FLUID; SUPERHEATED-STEAM; 2-PHASE FLOW; OIL-RECOVERY; PERFORMANCE ANALYSIS; SUPERCRITICAL CO2; MODEL; TEMPERATURE; WELLS,"When modeling of steam flow in wellbores, the effect of friction work on temperature/ steam quality of both fluid in wellbores and reservoir should be considered. A model that can describe the energy re-distribution in the system should be built. In this paper, new energy balance equations for steam flow in inner tubing (IT) and annuli are developed with consideration of the effect of frction work on the energy re-distribution process in the system. The heat energy caused by shear stress has an obvious influence on the increase of steam quality or superheated steam temperature, especially under high injection speed condition. Firstly, a model for steam flow is developed in wellbores based on the energy and momentum balance equations. The energy balance equation controlls the predicted values of steam quality or superheated steam temperature, and the momentum balance equation controlls mainly the steam pressure. Secondly, coupled with the seepage model in oil layer, a comprehensive mathematical model is establiehed for single, two-phase flow of steam in horizontal wells with toe-point injection technique. Results show that: ( a) when the effect of friction work was neglected, the predicted steam quality or superheated steam temperature were obviously smaller than field data. (b) While seam quality decreases with distance when wet steam flows in wellbores, superheated steam temperature in annuli has an increase at the heel-point in annuli. This is because the fluid with lower temperature in annuli absorbs heat from steam with higher temperature in IT. (c). In order to obtain a satisfactory oil recovery ratio, field engineers are suggested to increase the injection pressure to a reasonable level based on the rock fracture pressure experiment.",35,38,0
Fracture,Multi-phase Flow,"Liang, Tianbo; Li, Qingguang; Liang, Xingyuan; Yao, Erdong; Wang, Yanqing; Li, Yuan; Chen, Mai; Zhou, Fujian; Lu, Jun",Evaluation of liquid nanofluid as fracturing fluid additive on enhanced oil recovery from low-permeability reservoirs,Fracturing fluid additive; EOR; Tight oil; Wettability alteration,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; GRAVITY DRAINAGE; HIGH-TEMPERATURE; WATER BLOCKING; SHALE; SURFACTANTS; WET; CARBONATES; SYSTEM,"Hydraulic fracturing creates a complex fracture network that makes the oil production from low-permeability reservoirs economical. However, significant amount of water is likely lost into the rock matrix during hydraulic fracturing. This can cause formation damage due to multiphase flow, thus hindering the oil production rate. Surfactants can alter rock wettability and/or reduce oil-water interfacial tension (IFT), and it has been proposed to be used to mitigate such water blockage and enhance oil recovery. Among different approaches of using surfactants, forming liquid nanofluid (LNF) can minimize the adsorption of surfactants on rock surface, and it is likely to be one of the best options for low-permeability rocks with extensive surface area. In this study, the key properties of a well-screened LNF are evaluated, and then compared with a commercial flowback surfactant (CFS) that is widely used in the field. Pressure transmission test is further applied, which can determine the change of rock permeability due to different fluids and the potential formation damage due to multiphase flow. A systematic evaluation method is thus established to screen fracturing fluid additives to enhance oil production from low-permeability reservoirs both effectively and efficiently.",24,28,4
Fracture,Multi-phase Flow,"Qu, Ming; Hou, Jirui; Qi, Pengpeng; Zhao, Fenglan; Ma, Shixi; Churchwell, Lauren; Wang, Qian; Li, Hui; Yang, Tianyuan",Experimental study of fluid behaviors from water and nitrogen floods on a 3-D visual fractured-vuggy model,Carbonate reservoir; 3-D physical experiment; Fluid flow behavior; Water flooding; Gas flooding; Enhanced oil recovery,3-DIMENSIONAL PHYSICAL SIMULATION; CARBONATE RESERVOIRS; OIL; PERFORMANCE; INJECTION; RECOVERY; UNIT,"Tahe oil field is a fractured-vuggy carbonate oil field in China. The fluid flow behaviors in this type of reservoir are complex due to multiple flow paths through the matrix, fractures and vugs. The main challenges of production include complicated oil-water distributions, rising state of water cone in different flow units, unclear multiphase flow behaviors, and lack of understanding of the fluid flow mechanism. Based on a geological map of the Tahe oil field, a physical 3-D fractured-vuggy model was designed and fabricated. Water and gas flooding experiments were performed, while the multiphase flow behaviors were captured with a high-resolution camera system. The pressure response was also monitored at different oil displacement stages. The results show that the 3-D physical model can be used to systematically and comprehensively investigate the fluid flow behaviors during the oil displacement process. The oil-water interfaces of prolific wells rise more rapidly than that from the stripper wells, leading to an uneven distribution of internal flow fields and cross-well interferences. Water breaks through early and water channeling is more significant in fractured than vuggy wells. The oil-water flow behavior in fractured-vuggy combinations is mainly determined by fractured-vuggy structure, viscous force, wettability, and the ratio of displacement forces to gravity. During nitrogen gas flooding, gas caps occur from gas displacing the remaining oil at the top of the reservoir. The synergistic interaction between nitrogen gas and injected water contributes to additional oil recovery. This study provides a guide for improving production performance in fractured-vuggy carbonate reservoirs.",23,27,2
Fracture,Multi-phase Flow,"Yan, Bicheng; Mi, Lidong; Chai, Zhi; Wang, Yuhe; Killough, John E.",An Enhanced Discrete Fracture Network model for multiphase flow in fractured reservoirs,Multiphase flow; Fractured reservoirs; Reservoir modeling; EDFN,NUMERICAL-SIMULATION; SHALE GAS; BEHAVIOR; BLOCKS,"We present an Enhanced Discrete Fracture Network (EDFN) model for multiphase flow simulation in fractured reservoirs. EDFN can efficiently represent complex fractured porous media and accurately simulate fluid exchange between matrix and fracture. By using EDFN the fracture network is discretized with minimum number of grids based on the fracture intersecting points and fracture extremities. The matrix is also optimally decomposed into coarse blocks with different geometries using a rapid image processing algorithm. Each coarse matrix block is designed to be associated with one fracture grid and then discretized logarithmically to handle 1D flow between matrix and fracture. EDFN can greatly optimize the discretization for fractured porous media to conform interconnected fractures of arbitrary orientations. Via unstructured format, EDFN is successfully linked with an in-house unstructured compositional simulator. We validate the accuracy of EDFN through a number of multiphase flow simulations in fractured porous media with/without considering capillary pressure. Its efficiency is demonstrated to be superior by using a much less grid blocks comparing with other approaches. Ultimately EDFN is applied to predict hydrocarbon production in a shale oil reservoir and it enables to capture multi-scale fluid transfer in such complex system.",15,15,3
Fracture,Marcellus Shale,"Bhattacharya, Shuvajit; Mishra, Srikanta","Applications of machine learning for facies and fracture prediction using Bayesian Network Theory and Random Forest: Case studies from the Appalachian basin, USA",Bayesian network theory; Random forest; Data analytics; Predictive performance; Causality; Petrophysical logs,MARCELLUS SHALE LITHOFACIES; WELL LOGS; MODEL,"Identification and prediction of facies and fractures are critical to subsurface geosystems analysis and hydrocarbon exploration. However, accurate prediction of facies and fractures is hard in the absence of high-resolution advanced geophysical logs (e.g. image logs) and core samples. This study demonstrates the application of machine learning algorithms, such as Bayesian Network Theory and Random Forest to predict the presence of different facies and fractures in sedimentary rocks using common well logs. We build and train supervised machine learning models using Bayesian Network Theory and Random Forest to classify facies and fractures in unconventional shale and conventional sandstone, and carbonate reservoirs. The trained machine-learning models are cross-validated 10-fold to check their robustness. Application of Bayesian Network theory and Random Forest shows that both facies and fractures can be predicted with high accuracy using limited common well logs. In addition, the Bayesian Network shows the complex causal relationship among the input petrophysical parameters and output (facies or fracture), which is its unique feature compared to other machine learning algorithms, such as Random Forest.",46,48,8
Fracture,Marcellus Shale,"Kamali-Asl, Arash; Ghazanfari, Ehsan; Newell, Pania; Stevens, Mathew","Elastic, viscoelastic, and strength properties of Marcellus Shale specimens",Shale gas; Failure strength; Ultrasonic velocity; Creep models; Elastic moduli; Viscoelastic; Cyclic,FRACTURE INITIATION; DEFORMATION; ROCK; PROPAGATION; ANISOTROPY; FAILURE,"Shale gas rocks are characterized as clastic sedimentary rocks, with features such as obvious bedding planes, presence of micro-cracks, and high clay and organic content. These rocks are anisotropic and inhomogeneous, exhibiting a nonlinear response under loading. In order to optimize the required energy for hydraulic fracturing operation and production in shale gas reservoirs, and for constitutive and numerical modeling, it is important to characterize these shale gas rocks. In this study, the hysteresis, elastic-plastic, viscoelastic, and strength properties of Marcellus Shale specimens, retrieved from a deep well located in West Virginia, were evaluated through performing a series of creep, cyclic, and triaxial multi-stage failure tests on these specimens. Both elastic moduli and plastic deformations show significant levels of pressure dependency. Moreover, higher creep compliance and lower Young's modulus values were observed for clay-rich specimens. Both Power-Law and Burgers' models were found to capture the creep response of these specimens reasonably well. The dynamic moduli estimated from the ultrasonic velocity measurements at different stress levels were found to be higher than static moduli estimations. In addition, the changes in the internal micro-structure of the specimens resulted from variations in the stress condition, were found to affect the ultrasonic velocity measurements. The strength properties of the calcite/quartz-rich specimen, using multi-stage triaxial failure test, were estimated through both Mohr-Coulomb and Hoek-Brown failure criteria.",25,25,9
Fracture,Marcellus Shale,"Wang, J. G.; Hu, Bowen; Liu, Hua; Han, Yue; Liu, Jia",Effects of 'soft-hard' compaction and multiscale flow on the shale gas production from a multistage hydraulic fractured horizontal well,Three-zone model; Dual-porosity medium zone; Multiscale flow mechanism; 'Soft - hard' model; Fracture aperture,MISSISSIPPIAN BARNETT SHALE; APPARENT PERMEABILITY; POROUS-MEDIA; MODEL; RESERVOIRS; STRAIN; SIMULATION; DESORPTION; EVOLUTION; DIFFUSION,"In this study, the shale gas production from a multistage hydraulic fractured shale gas reservoir was analyzed. Firstly, the reservoir was divided into single-porosity medium zone, dual-porosity medium zone, and hydraulic fracture zone. Then, a mathematical model was established for the multiscale gas diffusion and adsorption/desorption mechanisms in matrix, the gas flow in fractures and the interaction between gas flow and shale deformation. Thirdly, this mathematical model was numerically solved within the platform of Comsol Multiphysics and verified by the history matching of the gas production data from Barnett and Marcellus shale reservoirs. Finally, sensitivity study was conducted to identify key parameters to the efficiency of gas recovery enhancement. It is found that hydraulic fracture aperture and initial permeability of fractures are positively correlated with gas production rate. The 'soft - hard' compaction of fractures can significantly modify gas production rate but the modification varies with gas production stage. The deformation and flow properties of hydraulic fractures have significant impacts on gas production rate, particularly in the early stage.",18,19,8
Fracture,Nitrogen Jet,"Zhang, Shikun; Huang, Zhongwei; Huang, Pengpeng; Wu, Xiaoguang; Xiong, Chao; Zhang, Chengcheng",Numerical and experimental analysis of hot dry rock fracturing stimulation with high-pressure abrasive liquid nitrogen jet,HDR fracturing; Abrasive liquid nitrogen jet; Flow field; Heat transfer; Thermal stress; Fractal,CONJUGATE HEAT-TRANSFER; TECHNOLOGY; MODEL; RESERVOIRS; TRANSPORT; SYSTEMS,"Abrasive liquid nitrogen (L-nitrogen) jet fracturing is a novel technology, which is expected to be suitable for hot dry rock (HDR) fracturing. In this paper, numerical simulation has been presented to analyze the fluid flow, heat transfer and thermal stresses distribution in HRD fracturing with abrasive L-nitrogen jet. The simulation is carried out with a three-dimensional model in transient state. The low Reynolds number.-e model is employed to accurately predict the near wall flow. The heat transfer between L-nitrogen and hot rock on solid-liquid interface is computed by an inverse method of conjugate heat transfer. The thermo-elastic model is used to calculate the thermal stresses distribution in rock. Numerical results indicate that abrasive L-nitrogen jet has a better performance in perforation than abrasive water and supercritical CO2 jet. Great tensile stress distributes in the region near interface, however, its affected depth is limited. This tensile is expected to be favor for fractures generation and growth along perforation direction. Short perforation length can promote the heat transfer on interface. The initial rock temperature has an important influence on values of thermal stresses. Experiments, in which the hot granite specimens with a small hole in center were impacted by L-nitrogen jet, have been conducted to validate the effect of thermal stresses on fracturing. The fractal method is adopt to quantitatively describe the flow and transport capability in rock masses. Experimental results show that numerous thermal cracks were generated on the interface. Rising rock temperature can significantly increase the number and size of thermal cracks and improve the connectivity of fractured rock, which are benefit to fracture initiation during L-nitrogen jet fracturing. The results in this paper would shed light on L-nitrogen jet fracturing for HDR as well as some high-temperature oil reservoirs.",49,50,5
Fracture,Nitrogen Jet,"Wu, Xiaoguang; Huang, Zhongwei; Li, Gensheng; Li, Ran; Yan, Pengsen; Deng, Xiao; Mu, Kaiwen; Dai, Xianwei",Experiment on coal breaking with cryogenic nitrogen jet,Liquid nitrogen; Jet; Coal breaking; Coal bed methane; Drilling,LIQUID-NITROGEN; METALLIC SURFACES; VELOCITY; STIMULATION; IMPINGEMENT; TECHNOLOGY; IMPACT; ROCKS; WELLS,"Severe leakage of drilling fluid and reservoir damage due to water and solid invasion during well drilling are the key factors that restrict economic exploitation of coal bed methane (CBM) in China. To solve these issues, this paper presents a method of CBM well drilling with the assistance of cryogenic nitrogen jet, in which no aqueous phase and solid phase are contained. To determine the feasibility of coal breaking by cryogenic nitrogen jet and the effects of different parameters, such as nozzle diameter, dimensionless standoff distance, nozzle pressure difference and exposure time, we conducted corresponding rock breaking experiments on artificial and natural coals with the cryogenic nitrogen jet and the water jet. Rock breaking features and the energy consumption by the two jets were compared. The results indicate that the cryogenic nitrogen jet has better rock breaking performances and consumes less energy. Under the same conditions, the average rock erosion volume and the energy consumption with the cryogenic nitrogen jet were 18.34 times larger and 90.8% lower than those with water jet, respectively. Visible netted fractures could be created on the surface of coal samples blasted with the cryogenic nitrogen jet, and thus rock breaking could be facilitated effectively. The outstanding rock breaking performances of cryogenic nitrogen jet are attributed to three mechanisms: high-velocity jet impact, thermal shock and gasification cracking effect. In addition, under our experimental conditions, the erosion volume and depth were proportional to the pressure difference and inversely proportional to the dimensionless standoff distance. When the nozzle diameter changed from 1.5 mm to 3 mm, the increases of erosion volume were 3% at the pressure difference of 5 MPa and 41.7% at the pressure difference of 10 MPa respectively. This indicates that the effect of nozzle diameter is more significant at relatively higher pressure drops. With the increase of exposure time, both of the rock erosion depth and volume rose, while with a smoother trend. The results of this study are expected to promote the application of cryogenic nitrogen jet in CBM well drilling.",27,31,3
Fracture,Molecular Diffusion,"Jia, Bao; Tsau, Jyun-Syung; Barati, Reza","Role of molecular diffusion in heterogeneous, naturally fractured shale reservoirs during CO2 huff-n-puff",Bakken shale reservoirs; Molecular diffusion; Heterogeneity; Correlation length; CO2 huff-n-puff,OIL; INJECTION; RECOVERY,"Shale reservoirs are characterized by high degree of heterogeneity and ultra-low matrix permeability. Natural fracture (both macro and micro) systems are important to increase the performance of shale reservoirs by providing flow path for the hydrocarbon from the nanopores in the matrix to the wellbore. Configurations of natural fractures also have significant implications for the recovery performance of shale gas and oil reservoirs. CO2 huff-n-puff or cyclic injection has been suggested to be a feasible way to recover oil from shales and the flow process is complex. Molecular diffusion is an important transport mechanism of the mixture of CO2 and oil, especially in tight formations. Based on these knowledge, various configurations of the natural fracture system in shale reservoirs with the dual porosity and dual permeability model were constructed, regarding Dykstra-Parsons (DP) coefficient and correlation length. Dykstra-Parson (DP) coefficient ranges from 0.40 to 0.78, and correlation length ranges from 50 ft to 3000 ft. Based on the geological setting of the Middle Bakken formation and the Bakken live oil PVT data, compositional models were performed to simulate the CO2 huff-n-puff process. CO2 injection begins after the primary recovery factor reaches 3% and both multiple-cycle and single-cycle of injection were investigated regarding the oil recovery performance and CO2 injectivity behavior. In the multiple-cycle scheme the period of one cycle is short; the injection, soak and production time are 10 days, 10 days and 100 days, respectively. In the single-cycle scheme, the period of one cycle is long, and gas injection volume is set to be constant with the soak time of 100 days. The impact of molecular diffusion during the huff-n-puff process is compared in different simulation scenarios. Findings in this work reveal the importance of the configuration of the pre-existing natural fracture system for the performance of the huff-n-puff process. Reservoir heterogeneity hampers primary production. However, during the puff production process, the negative impact of heterogeneity is less as the correlation length increases when the molecular diffusion is taken into account. There exists a threshold correlation length value wherein heterogeneity becomes favorable for improved oil recovery instead of hampering oil recovery, after taking into account of the molecular diffusion, which is approximately 1500 ft in this simulation study. The value of correlation length also affects the performance of multiple-cycle and single-cycle huff-n-puff processes differently because CO2 injectivity behavior is different in reservoirs characterized by different DP coefficients and correlation length: there exists a threshold time point when a longer correlation length begins to favor the injectivity, and the threshold time point is delayed for a scenario with a larger DP coefficient.",41,42,2
Fracture,Molecular Diffusion,"Zhang, Yuan; Yu, Wei; Li, Zhiping; Sepehrnoori, Kamy",Simulation study of factors affecting CO2 Huff-n-Puff process in tight oil reservoirs,CO2 Huff-n-Puff; Nanopore confinement; Molecular diffusion; Minimum miscibility pressure; Tight oil,SHALE; RECOVERY; FLUID; GAS; PERMEABILITY,"CO2 injection is one of the effective enhanced oil recovery (EOR) methods in conventional oil reservoirs, which has been widely applied in the tight oil reservoirs. Although there are some efforts on the investigation of engineering parameters such as fracture half-length, fracture conductivity, and fracture height, the effects of CO2 molecular diffusion, nanopore confinement, and stress-dependent deformation on CO2-EOR effectiveness are poorly understood. In this paper, we modified the conventional phase-equilibrium model to accurately compute the phase behavior in shale nanopores. Subsequently, we investigated the minimum miscibility pressure (MMP) of CO2-EOR process under different pore sizes. Afterwards, we evaluated the well performance of CO2 Huff-n-Puff process by fully capturing physics of CO2 molecular diffusion and nanopore confinement. The impacts of matrix permeability, CO2 injection rate and stress-dependent deformation mechanisms on the CO2 Huff-n-Puff process are examined in detail. The results show that CO2 diffusion and nanopore confinement play an important role in improving the oil recovery factor, which should be correctly implemented in reservoir simulation model. Additionally, matrix permeability, CO2 injection rate, and stress-dependent deformation mechanisms significantly influence the CO2 Huff-n-Puff process. This work enables operators to optimize the CO2 Huff-n-Puff process to improve the efficiency of CO2-EOR and CO2 storage in tight oil reservoirs.",40,43,2
Fracture,Tight Sand,"Zeng, Jie; Wang, Xiangzeng; Guo, Jianchun; Zeng, Fanhua; Zhang, Qiushi",Composite linear flow model for multi-fractured horizontal wells in tight sand reservoirs with the threshold pressure gradient,Tight sand reservoir; Hydraulic fracturing; Well testing; Threshold pressure gradient,GAS-RESERVOIRS; HOMOGENEOUS RESERVOIRS; BOUNDARY-CONDITION; SHALE RESERVOIRS; POROUS-MEDIA; ORDOS BASIN; OPTIMIZATION; PERFORMANCE; FLUIDS; CHINA,"Multi-stage fracturing is currently the most effective method to exploit tight sand reservoirs. Various analytical models have been proposed to fast and accurately investigate the post-fracturing pressure-and rate-transient behavior, and hence, estimate the key parameters that affect well performance. However, these analytical models mainly consider the 2D flow, neglecting the fluids' flow from the upper/lower reservoir when the vertical fractures partially penetrate the reservoir. Although for linear flow models, Olarewaju and Lee (1989) and Azari et al. (1990, 1991) have studied the effects of fracture height, they merely used a skin factor. Moreover, the reservoir heterogeneity is seldom included. This paper presents an analytical model for multi-fractured horizontal wells (MFHWs) in tight sand reservoirs, accounting for the upper/lower reservoir contributions, reservoir heterogeneity and threshold-pressure gradient (TPG). The model is extended from the ""five-flow-region"" model and subdivides the reservoir into seven parts including two upper/lower flow regions, two outer flow regions, two inner flow regions and a hydraulic fracture flow region. Reservoir heterogeneity along the horizontal wellbore is considered, thus, the effects of the fracture pattern in a heterogeneous reservoir are documented. Fracture interference is simulated by locating a virtual no-flow boundary between two adjacent fractures. The exact location of a no-flow boundary is determined based on the boundary's pressure. Thus, the no-flow boundary has a minimum pressure difference between its two sides during the well production, making the no-flow assumption reasonable. The experimentally observed TPG and the pressure drop within the horizontal wellbore are included. Modeling results are compared with those from the well-testing software KAPPA Ecrin, obtaining a good match in most flow regimes. Both the constant-rate and constant-pressure conditions are studied. Results suggest that the fracture penetration ratio dominates the early-mid time pressure responses and the start time of the boundary-dominated flow. For production responses, it determines the initial productivity and the production decline rate. The existence of the TPG results in a higher pressure drop and accelerates the production decline during the middle-late times. But this influence is marginal when the TPG is small (TPG<0.4psi/ft). Effects of other relative parameters, such as the formation permeability, fracture length, conductivity, fracture pattern, wellbore storage, flow-capacity ratio and storativity ratio for dual-porosity reservoir blocks are systematically investigated. Besides, some field data are analyzed and compared graphically, using type curve matching, and reliable results are obtained. Low CPU demands and the minimal data requirement of this model enable the operators to predict well-testing results under different fracture patterns in heterogeneous reservoirs with TPGs in a simple but effective way.",40,42,6
Fracture,Tight Sand,"Al-Ameri, Aymen; Gamadi, Talal; Ispas, Ion",Evaluation of the near fracture face formation damage caused by the spontaneously imbibed fracturing fluid in unconventional gas reservoirs,Fracturing fluid spontaneous imbibition; Friction reducer pad fluid; Polymer adsorption; Nonionic surfactant; Bedding plane; Imbibition capillary pressure; Imbibition water relative permeability curves,SPONTANEOUS IMBIBITION; POROUS-MEDIA; RELATIVE PERMEABILITY; CAPILLARY RISE; SHALE; GRAVITY,"In the present study, spontaneous imbibition experiments, steady-state permeability measurements, and numerical simulation were integrated to quantify the changes in the effective water permeability, capillary pressure, and water relative permeability curves due to the polymer adsorption of the spontaneously imbibed fracturing fluid. The effect of the nonionic surfactant and core bedding plane on the fluid spontaneous imbibition volumes were also investigated. The researchers considered the impact of the spontaneous imbibition of a friction reducer fluid in tight sand and shale core samples. Three comparative systematic spontaneous imbibition experiments were conducted for each of the core samples using brine, anionic friction reducer fluid, and brine again. The core sample water permeability before and after the imbibition experiment was measured using a constant rate steady-state permeability apparatus. The polymer adsorption from the spontaneously imbibed fracturing fluid significantly reduced the brine spontaneous imbibition volumes in tight sand samples and in shale samples, though to a lesser degree. Moreover, the effective water permeability was decreased because of the polymer adsorption effect. Therefore, the polymer adsorption during hydraulic fracturing reduces the fluid leak-off into the formation and also the fluid flowback. The nonionic surfactant increased the fluid spontaneous imbibition volumes in both tight sand and shale samples. Thus, adding a nonionic surfactant to the friction reducer pad fluid during hydraulic fracturing leads to enhance both of the fluid leak-off and fluid flowback. The results also showed that the effect of polymer adsorption on the imbibition rates is less when the rock-fluid contact surface is parallel to the bedding plane. The imbibition potentials and imbibition capillary pressure curves were calculated before and after polymer adsorption. The polymer adsorption led to a slight increase in the capillary pressure; moreover, the tight sand samples had higher capillary pressure than the shale samples. The imbibition water relative permeability curves were calculated using ECLIPSE commercial simulator. The polymer adsorption significantly reduces the water relative permeability curves for tight sand samples and in less degree for shale samples.",24,24,6
Fracture,Rock Breaking,"Wu, Xiaoguang; Huang, Zhongwei; Li, Gensheng; Li, Ran; Yan, Pengsen; Deng, Xiao; Mu, Kaiwen; Dai, Xianwei",Experiment on coal breaking with cryogenic nitrogen jet,Liquid nitrogen; Jet; Coal breaking; Coal bed methane; Drilling,LIQUID-NITROGEN; METALLIC SURFACES; VELOCITY; STIMULATION; IMPINGEMENT; TECHNOLOGY; IMPACT; ROCKS; WELLS,"Severe leakage of drilling fluid and reservoir damage due to water and solid invasion during well drilling are the key factors that restrict economic exploitation of coal bed methane (CBM) in China. To solve these issues, this paper presents a method of CBM well drilling with the assistance of cryogenic nitrogen jet, in which no aqueous phase and solid phase are contained. To determine the feasibility of coal breaking by cryogenic nitrogen jet and the effects of different parameters, such as nozzle diameter, dimensionless standoff distance, nozzle pressure difference and exposure time, we conducted corresponding rock breaking experiments on artificial and natural coals with the cryogenic nitrogen jet and the water jet. Rock breaking features and the energy consumption by the two jets were compared. The results indicate that the cryogenic nitrogen jet has better rock breaking performances and consumes less energy. Under the same conditions, the average rock erosion volume and the energy consumption with the cryogenic nitrogen jet were 18.34 times larger and 90.8% lower than those with water jet, respectively. Visible netted fractures could be created on the surface of coal samples blasted with the cryogenic nitrogen jet, and thus rock breaking could be facilitated effectively. The outstanding rock breaking performances of cryogenic nitrogen jet are attributed to three mechanisms: high-velocity jet impact, thermal shock and gasification cracking effect. In addition, under our experimental conditions, the erosion volume and depth were proportional to the pressure difference and inversely proportional to the dimensionless standoff distance. When the nozzle diameter changed from 1.5 mm to 3 mm, the increases of erosion volume were 3% at the pressure difference of 5 MPa and 41.7% at the pressure difference of 10 MPa respectively. This indicates that the effect of nozzle diameter is more significant at relatively higher pressure drops. With the increase of exposure time, both of the rock erosion depth and volume rose, while with a smoother trend. The results of this study are expected to promote the application of cryogenic nitrogen jet in CBM well drilling.",27,31,3
Fracture,Rock Breaking,"Cheng, Zhen; Sheng, Mao; Li, Gensheng; Huang, Zhongwei; Wu, Xiaoguang; Zhu, Zhaopeng; Yang, Jiawei",Imaging the formation process of cuttings: Characteristics of cuttings and mechanical specific energy in single PDC cutter tests,PDC bit; Single cutter test; Cuttings formation; MSE,HARD-ROCK; FRAGMENTATION; BITS,"Polycrystalline Diamond Compact (PDC) bits account for most of the footage drilled in the oil field. Abundant information relating to cutter-rock interactions and rock breaking mechanism are provided by the cuttings and Mechanical Specific Energy (MSE) in single cutter tests, which are crucial for insuring the longevity and rate of penetration (ROP) enhancement of PDC bits. In this paper, a series of linear cutting tests was conducted at different depths of cut, back rake angles and cutting speeds on three kinds of rock. The formation of cuttings was recorded frame by frame with a high-speed camera. Then, the cuttings were collected and divided into five groups by sieving. Finally, the mass fraction change of cuttings in each group was compared with the MSE variation. The results show that a PDC cutter does not move at a constant speed: relatively slower when crushing and faster when chipping, and crushing dominates almost the entire cutting process. The mass fraction of chunklike cuttings generated in chipping is increased with decreasing back rake angle, while increasing depth of cut and cutting speed; and the mass fraction of powderlike cuttings generated in crushing shows an opposite trend. Furthermore, because of the crystalloblastic texture and well-developed cleavages in calcite, far more chunklike cuttings and totally different fracture surfaces are found when cutting marble, compared with sandstone and granite. Finally, a strong correlation between the mass fraction of cuttings and MSE is found. This indicates that the mass fraction of cuttings could be deemed as a simple method to evaluate the efficiency of rock breaking by PDC cutters. The results in this paper are expected to provide guidelines to the selection of drilling practices and PDC bit design.",24,24,3
Oil Recovery,Heavy Oil,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Miao, Yanan; Han, Song; Chen, Zhili",Flow simulation of the mixture system of supercritical CO2 & superheated steam in toe-point injection horizontal wellbores,Toe-point injection; Horizontal wellbore; Supercritical CO2; Superheated steam; Inner heat exchange; Friction loss; Energy balance,HEAT-TRANSFER CHARACTERISTICS; 2-PHASE FLOW; OIL-RECOVERY; PERFORMANCE ANALYSIS; NONCONDENSING GASES; THERMAL FLUID; SHALE GAS; MODEL; TEMPERATURE; PREDICTION,"Conventional heavy oil recovery method of saturated steam injection at heel-point of horizontal wellbores is facing comparatively more serious fingering phenomenon. With this, oil companies are now actively developing new recovery method of supercritical CO2 - superheated steam injection in horizontal wellbores with toe-point injection technique. Firstly, considering the heat exchange between the inner tubing (IT) and annuli, a pipe flow model comprised of energy and momentum conservation equations is developed for the mixture flow in both IT and annuli. Then, coupled with the S-R-K real gas model, variable mass flow model and transient heat transfer model in oil layer, a comprehensive mathematical model is established. Numerical solutions of the mixture flow in toe-point injection wellbores are obtained through straight forward numerical method. Finally, model validation and sensitivity analysis are conducted. The results show that: (1). there exists a good agreement between predicted results and field data. The predicted temperature is higher when the heat exchange between IT and annuli is neglected. The predicted temperature is lower when the friction loss item is considered in the energy balance equation. (2). the temperature of the mixture increases when the mixture flows from toe-point to heel-point in annuli due to heat flow from IT to annuli. (3). While the absorption rate of the mixture in formation increases with increasing of the content of supercritical CO2, it can be offset by the decrease of temperature and enthalpy of the mixture. (4). Both of the mixture temperature and formation mixture absorption rate increase with increasing of injection pressure.",59,61,1
Oil Recovery,Heavy Oil,"Rakhmatullin, I. Z.; Efimov, S. V.; Tyurin, V. A.; Al-Muntaser, A. A.; Klimovitskii, A. E.; Varfolomeev, M. A.; Klochkov, V. V.",Application of high resolution NMR (H-1 and C-13) and FTIR spectroscopy for characterization of light and heavy crude oils,Crude oil; H-1 NMR spectroscopy; C-13 NMR spectroscopy; FTIR spectroscopy; SARA fraction; Functional group,INFRARED-SPECTROSCOPY; PEPTIDE; PARAMETERS; AROMATICS; BITUMEN; ALKANES,"High-resolution nuclear magnetic resonance (NMR) and Fourier transform infrared (FTIR) spectroscopy experiments were applied to obtain detailed information on the hydrocarbon chemistry of three light and three heavy crude oils. Quantitative fractions of aromatic molecules and functional groups constituting oil hydrocarbons were determined by C-13 NMR spectroscopy and comparative analysis of the oil samples with different viscosity, origin and preliminary treatment. SARA composition and some important information about aromaticity, oxidation behavior, branching, aliphaticity and sulfurization of studied oil samples were obtained. Integral characteristics of high-resolution NMR and FTIR spectra have a great potential to study the structure and characterization of light and heavy crude oils, which could substitute present traditional fractionation procedures. Relationships between spectroscopic parameters obtained by high-resolution NMR and FTIR spectroscopy methods and crude oil compositions can be useful for fast prediction of crude oil properties due to different type of treatment, including thermal methods for enhanced oil recovery. Also quantitative proportions of functional groups obtained by NMR and spectral indices obtained by FTIR can be one of the criteria for developing fingerprint approach.",38,38,4
Oil Recovery,Heavy Oil,"Yousefvand, Hojat Alah; Jafari, Arezou",Stability and flooding analysis of nanosilica/ NaCl /HPAM/SDS solution for enhanced heavy oil recovery,Enhanced oil recovery; Wettability alteration; Stability; Micromodel; Nanosilica; Nanosuspension; Hydrolyzed polyacrylamide; Oil-wet medium,POLYMER-SOLUTION; NANOPARTICLES; DISPLACEMENT; WETTABILITY; PERFORMANCE; SUSPENSIONS; RESERVOIRS; CHINA,"Oil and gas are main sources of energy globally. Limitations on these resources and the ability to explore and exploit them has led to the development of new technologies for enhanced oil recovery. The massive amounts of oil remain in reservoirs must be removed using common enhanced oil recovery methods and other complex methods. Nanotechnology can help solve many problems in the oil and gas industry. Nanoparticles can assist production of oil from reservoirs on the nanometer scale. Nanoparticles can increase oil recovery through polymer flooding, but there are few studies on polymer performance in the presence of nanoparticles and salt, especially HPAM. The current study investigated HPAM/nano-silica for enhanced oil recovery and stability of the injected fluid. To prepare a stable solution for injection, different concentrations of HPAM, nanosilica, salt and water were tested and the best combination of materials was obtained. It was found that the addition of a surfactant is needed to control suspension stability. The results of stability tests indicate that salt is main cause of instability of nano-suspensions. At high salinity single-valence ions show effects similar to bivalence ions on the stability of nano-suspensions. SDS can adsorb onto nano-silica particles and supercharge the interface to stabilize the nano-suspensions. Stable fluid was injected into a strongly oil-wet five-spot glass micromodel saturated with heavy oil and image processing was applied to analyze the displacement mechanisms and calculate the efficiency of each flooding test. The viscosity was measured for precise analysis of the experimental data. The oil recovery factor after one pore volume of injected fluid indicates that the ultimate oil recovery improved in the presence of nanosilica particles, which increased the viscosity of the injected fluid and altered the wettability of the pore walls. Nanoparticles appear to have the ability to change the wettability to water-wet in some portions of the micromodel. Measurements showed that nanosilica particles did not change the IFT between the crude oil and injected fluid.",37,39,6
Oil Recovery,Heavy Oil,"Pei, Haihua; Shu, Zhan; Zhang, Guicai; Ge, Jijiang; Jiang, Ping; Qin, Yu; Cao, Xu",Experimental study of nanoparticle and surfactant stabilized emulsion flooding to enhance heavy oil recovery,Emulsion flooding; Nanoparticles; Heavy oil; Sweep efficiency; Injection parameters,,"It is well known that the recovery of water flooding from heavy oil reservoirs is less than 30% or even 20% of the OOIP (original oil in place), due to its very high viscosity and thus extremely low mobility comparing to light oil at reservoir condition. In order to improve residual oil recovery after water flooding in ordinary heavy oil reservoirs, this study presents an experimental study of nanoparticle and surfactant stabilized emulsion flooding to enhance heavy oil recovery. It is indicated in the emulsion stability and rheology studies that the synergistic interaction of nanoparticle with surfactant can significantly improve the emulsion stability and increase the apparent viscosity of emulsion. The results of core flooding tests show that the residual oil recovery after water flooding can be significantly improved by the nanoparticle-surfactant stabilized emulsions flooding. The incremental oil recovery gradually increases with the increase of injected emulsion volume, but there is an optimal economic value of the injected volume. The low injection rate is more effective than high injection rate, and the continuous injection pattern shows higher tertiary oil recovery as compared to cyclic injection pattern. The nanoparticle-surfactant stabilized emulsion flooding has a great potential for enhanced oil recovery in waterflooded heavy oil reservoirs, with the permeability ranging from 500 mD to 2000 mD and the crude oil viscosity being lower than 1000 mPa s. The two-dimensional homogeneous sandpack flooding test indicates that the nanoparticle-surfactant stabilized emulsion flooding can not only improve the sweep efficiency by blocking the high permeable water channels, but also can improve the displacement efficiency by mobilizing the trapped oil.",36,38,14
Oil Recovery,Heavy Oil,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Liu, Qing; Han, Song; Zhou, Yunjian",Effect of friction work on key parameters of steam at different state in toe-point injection horizontal wellbores,Heavy oil recovery; Toe-point injection horizontal well; Friction work; Temperature distribution; Steam quality distribution; Steam state,HEAT-TRANSFER CHARACTERISTICS; MULTI-THERMAL FLUID; SUPERHEATED-STEAM; 2-PHASE FLOW; OIL-RECOVERY; PERFORMANCE ANALYSIS; SUPERCRITICAL CO2; MODEL; TEMPERATURE; WELLS,"When modeling of steam flow in wellbores, the effect of friction work on temperature/ steam quality of both fluid in wellbores and reservoir should be considered. A model that can describe the energy re-distribution in the system should be built. In this paper, new energy balance equations for steam flow in inner tubing (IT) and annuli are developed with consideration of the effect of frction work on the energy re-distribution process in the system. The heat energy caused by shear stress has an obvious influence on the increase of steam quality or superheated steam temperature, especially under high injection speed condition. Firstly, a model for steam flow is developed in wellbores based on the energy and momentum balance equations. The energy balance equation controlls the predicted values of steam quality or superheated steam temperature, and the momentum balance equation controlls mainly the steam pressure. Secondly, coupled with the seepage model in oil layer, a comprehensive mathematical model is establiehed for single, two-phase flow of steam in horizontal wells with toe-point injection technique. Results show that: ( a) when the effect of friction work was neglected, the predicted steam quality or superheated steam temperature were obviously smaller than field data. (b) While seam quality decreases with distance when wet steam flows in wellbores, superheated steam temperature in annuli has an increase at the heel-point in annuli. This is because the fluid with lower temperature in annuli absorbs heat from steam with higher temperature in IT. (c). In order to obtain a satisfactory oil recovery ratio, field engineers are suggested to increase the injection pressure to a reasonable level based on the rock fracture pressure experiment.",35,38,0
Oil Recovery,Heavy Oil,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Han, Song; Liu, Qing; Liu, Wenyuan",Type curve analysis of multi-phase flow of multi-component thermal fluid in toe-point injection horizontal wells considering phase change,Heavy oil recovery; Phase change; Toe-point injection horizontal wells; Non-condensing gases; Superheated state; Saturated state,HEAVY OIL-RECOVERY; SUPERHEATED-STEAM INJECTION; 2-PHASE FLOW; PERFORMANCE ANALYSIS; NONCONDENSING GASES; GRAVITY DRAINAGE; KEY PARAMETERS; HOT-WATER; WELLBORE; MODEL,"Huge amount of works were done on modeling of wet steam flow in the conventional heel-point injection horizontal wellbores. With the rapid development of technology, new technology of superheated steam - non-condensing gases (SNG) injection coupled with toe-point injection wellbores was adopted in oil field. In this paper, a series of works were done on modeling of SNG flow in a horizontal wellbore with toe-point injection technique. The two-phase flow model was embedded in this SNG model for describing the phase change phenomenon. Firstly, a hydraulics model comprised of mass, momentum and energy conservation equations was developed. Then, coupled with the seepage model in oil layer, a wellbore/formation coupled model was established. Thirdly, straight forward numerical method was adopted to solve the model. Finally, model verification and sensitivity analysis were conducted sequentially. Results show that: (1) The SNG temperature in annuli has an increase at the heel-point due to heat conduction from IT to annuli. (2) When the mass injection rate is kept unchanged, the SNG temperature at a certain place in annuli decreases with increasing of the mass content of non-condensing gases. (3) The SNG in IT undergoes phase change into saturated state at the distance of 150 m. Then, from the distance of 150 m-200 m, the gas content in the mixture system gets an increase and the superheat degree is equal to zero. (4) Phase change occurs again in annuli when the SNG reaches the distance of 110 m where the wet fluid turns into superheated state, after which the superheated degree of SNG increases continuously as SNG is flowing to the heel-point.",32,32,1
Oil Recovery,Heavy Oil,"Pal, Nilanjan; Saxena, Neha; Mandal, Ajay",Characterization of alkali-surfactant-polymer slugs using synthesized gemini surfactant for potential application in enhanced oil recovery,Gemini surfactant; Interfacial tension; Thermal stability; Viscosity; Viscoelasticity; ASP flooding,HYDROPHOBICALLY ASSOCIATING POLYACRYLAMIDE; COMBINATION FLOODING SYSTEMS; HEAVY OIL; ORGANIC ALKALI; RHEOLOGICAL PROPERTIES; INTERFACIAL-TENSIONS; SALINITY CONDITIONS; FIELD APPLICATIONS; MIXED SURFACTANT; LIGHT-SCATTERING,"The present study deals with the formulation and characterization of alkali-surfactant-polymer slugs using gemini surfactant (GS) for effective application in enhanced oil recovery (EOR) processes. The hydrolytic stabilities of the synthesized cationic GSs were measured in both acidic and basic media. Surface tensiometry was employed to determine the CMC values of surfactant at different temperatures. An organic alkali, monoethanolamine (MEA) showed the most favourable interfacial properties at the oil-aqueous interfaces among the various experimented alkalis. Though the addition of PHPA polymer to GS/MEA solutions increase the IFT value, the viscosities of the slugs improve drastically, which is desirable to improve the sweep efficiency. The solutions also showed low turbidity values and high thermal stability over a significant time period. The oil-surfactant-aqueous systems showed favourable emulsification properties, showing the ability to effectively displace trapped oil. Viscosity increases with PHPA concentration due to mixed micelle associations among the surfactant, alkali and polymer molecules. At low shear rates, the GS/MEA/PHPA solutions exhibited shear thinning properties. Oscillatory studies show the presence of both viscous and elastic properties, which have been well described using the Maxwell mechanical model. Formulation consisting of 0.02% 14-6-14 GS, 0.80% MEA and 0.20% PHPA showed the most favourable tertiary recovery after conventional secondary water-flooding.",31,32,2
Oil Recovery,Heavy Oil,"Patel, Harshkumar; Shah, Subhash; Ahmed, Ramadan; Ucan, Sezai",Effects of nanoparticles and temperature on heavy oil viscosity,Heavy oil; Nanoparticles; Rheology; Viscosity reduction; Oil recovery; Optimum concentration,RECOVERY; AQUATHERMOLYSIS,"The objective of this research is to investigate the efficacy of nanoparticles in reducing the viscosity of heavy oil. In this study, three types of metal oxide nanoparticles (CuO, Fe2O3, and NiO) are employed, and their effect on heavy oil viscosity is examined at three different concentrations (0.05, 0.1, and 0.5 wt.% of oil). For all test fluids, rheological measurements were obtained at four different temperatures ranging from 27 to 71 degrees C. The experimental work is conducted with two extremely viscous heavy oil samples having viscosity of approximately 77 and 350 Pas at ambient temperature. This study is unprecedented in terms of viscosity of heavy oil samples investigated. The heavy oil samples used in this study are 9-40 times more viscous than those used in previous similar studies. The addition of nanoparticles resulted in a notable reduction in viscosity of both heavy oil samples. For each type of nanoparticles, 50-70% viscosity reduction was observed. The level of viscosity reduction is sensitive to the types of nanoparticles, their concentration, and fluid temperature. Moreover, the results indicate existence of an optimum concentration of nanoparticles at which maximum viscosity reduction occurs. This optimum concentration is a function of the metal type and fluid temperature. To explain observed viscosity alteration behavior, the paper provides a theoretical overview of various molecular-level physical and chemical interactions between nanoparticles and heavy oil. Additionally, the study presents a new heavy oil viscosity data and delineates some of the challenges associated with viscosity measurement of heavy oil. This research provides valuable information for future rheological and core-flooding studies involving nanoparticle stabilized solvent-based emulsions. Besides, remarkable viscosity reduction obtained in this work reinforces the industry's interest in developing an economically feasible nanoparticle-based technique and helps to solve real problems in the field.",30,31,10
Oil Recovery,Heavy Oil,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Chen, Zhili; Chang, Yucui; Cao, Meng; Han, Song; Chaohui, Iv; Feng, Dong; Sun, Zheng",Effect of Flowing Seawater on Supercritical CO2 - Superheated Water Mixture Flow in an Offshore Oil Well Considering the distribution of heat generated by the work of friction,Wellbore hydraulics; Effect of seawater; Supercritical CO2; Superheated water; CO2 sequestration; Heavy oil recovery,RAPID MULTIPHASE FLOW; STEAM INJECTION; HORIZONTAL WELLS; 2-PHASE FLOW; SEMIANALYTICAL MODEL; PERFORMANCE ANALYSIS; NONCONDENSING GASES; PRESSURE; RECOVERY; ADSORPTION,"The modeling of thermal fluid (mostly reported for saturated steam) flow in wells involving steady-state heat transfer inside wellbores and transient heat transfer in sea water or formation is reviewed and inherited. It is a good addition of modeling of supercritical/superheated fluid to the existing body of literature. The flow of supercritical CO2 coupled with superheated water (SHW) in offshore wells is described by means of the differential mass, energy and momentum balance equations along the vertical wellbores. The effect of supercritical CO2 on pressure and temperature of the multi-component thermal fluid is expressed in terms of the real gas model (the S-R-K model). The differential equations are solved with finite difference method on space involving the constant injection parameters at wellhead. It is found out that: (a). while seawater has a significant influence on temperature drop in wellbores, its effect on pressure profiles is weak. (b). both temperature and superheat degree decrease with increasing of the content of supercritical CO2. Besides, study of the effect of injection rate and pressure is conducted.",30,30,1
Oil Recovery,Heavy Oil,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Li, Xiangfang; Chen, Mingqiang; Chen, Gang; Zhang, Tao",Analysis of superheated steam performance in offshore concentric dual-tubing wells,Offshore Wellbore modeling; Energy balance; Superheated steam; Concentric dual-tubing wells; Enthalpy data,HEAT-TRANSFER CHARACTERISTICS; MULTICOMPONENT THERMAL FLUID; 2-PHASE FLOW; OIL-RECOVERY; HORIZONTAL WELLS; NONCONDENSING GASES; SUPERCRITICAL CO2; MULTIPHASE FLOW; INJECTION WELLS; CURVE ANALYSIS,"Superheated steam (SHS) injection in concentric dual-tubing wells (CDTW) is a new technology for offshore heavy oil recovery. Firstly, compared with conventional saturated steam injection in single-tubing wells, the key advantages of SHS injection in CDTW for heavy oil recovery are introduced. Secondly, a novel mathematical model is proposed to analysis the heat transfer characteristics of SHS flow in offshore CDTW. Then, based upon the validated model, type curves of SHS flow in offshore CDTW are analyzed in detail. The results show that: (1). The heat exchange between the integral joint tubing (IJT) and annuli has a significant influence on SHS temperature and superheat degree in each tubing. (2). More heat get lost when the seawater starts to flow, and the heat loss rate in the sea section of the wellbores is larger than that in the formation section of the wellbores. Moreover, in order to flexibly use the model in practice, the key intrinsic flow characteristics of SHS in offshore CDTW are unraveled. It is found that: (1). The SHS temperature increases at first but turns to decrease with the continuous increase of injection rate due to the fact that the drop of SHS pressure gradually replaces heat losses as the dominant factor on temperature change. (2). The superheat degree at well bottom always increases with the increase of injection rate. This paper presents a basic reference for engineers in heat loss evaluations as well as performance estimations of SHS flow in offshore CDTW.",29,29,0
Oil Recovery,Heavy Oil,"Feng, Haishun; Kang, Wanli; Zhang, Liming; Chen, Jun; Li, Zhe; Zhou, Qiong; Wu, Hairong",Experimental study on a fine emulsion flooding system to enhance oil recovery for low permeability reservoirs,Fine emulsion flooding; Low permeability reservoir; Enhanced oil recovery; Micromodel tests,HEAVY-OIL; POROUS-MEDIA; SURFACTANT; EMULSIFICATION; POLYMER; MECHANISM; PRESSURE; ALKALI; TIGHT,"Numerous studies and field application tests have shown that emulsification is an important mechanism to improve oil recovery. Fine emulsion (FE) with small droplets can improve oil recovery by displacing residual oil after water flooding at a low cost. In this work, a series of core displacement experiments were conducted to compare the effectiveness of different chemical flooding for crude oil. Then, the oil-water interfacial tension (IFT), viscosity and rheological properties were studied thoroughly to understand the displacement mechanism by using an interfacial tensiometer, a viscometer or a rheometer. Finally, micromodel flooding tests were performed to demonstrate the suitability and effectiveness of FE flooding for oil recovery for low permeability reservoirs. The displacement results show that the oil recovery efficiency can reach 16.8% after water flooding by the optimum FE flooding system. The FE flooding system has viscoelastic properties, strong emulsifying performance and stability. Such behavior can reduce the IFT value to the magnitude of 10(-1) mN/m and improve the mobility ratio. The displacement mechanism of FE enhanced oil recovery (EOR) is that emulsification can improve the displacement efficiency and increase the swept efficiency. The micromodel tests indicate that the emulsification mechanisms include emulsification carrying-on and the performance control of the O/W emulsion. The FE flooding system has powerful EOR potential for low permeability reservoirs.",27,28,8
Oil Recovery,Heavy Oil,"Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Yuan, Chengdong; Zhang, Jizhou; Han, Xiaoqiang; Yang, Yang; Peng, Xiaoqiang; Wu, Junxue",Comprehensive investigations into low temperature oxidation of heavy crude oil,Low temperature oxidation; Heavy crude oil; Thermal behavior; Kinetics; Coke; Oxidized oil,IN-SITU-COMBUSTION; AIR INJECTION; SARA FRACTIONS; KINETICS; RECOVERY; LIGHT; BEHAVIOR; RESERVOIRS; PYROLYSIS; TGA/DSC,"Due to the significance of low temperature oxidation (LTO) process on the subsequent oxidation reactions and oil recovery for in situ combustion (ISC), this work aimed at conducting a series of comprehensive investigations into LTO of heavy crude oil. The LTO behavior of heavy oil was analyzed by static oxidation experiments. Then the alterations in oil characteristics due to LTO were investigated through coke content measurements, flammability tests and scanning electron microscopic (SEM) observations. Additionally, the effect of LTO on thermal behavior and kinetics of heavy oil was researched using thermogravimetry (TG)/differential scanning calorimetry (DSC) technique. The results showed that the temperature played a crucial role in LTO of heavy oil. Almost no coke was deposited at 80 degrees C. The amount of coke deposition at 160 degrees C averaged 0.346 g coke/g oil, which was roughly 4.2 times higher than that at 120 degrees C. The oxidized oil at 160 degrees C possessed the most superior flammability at ambient temperature and atmospheric pressure in comparison to that at 80 and 120 degrees C. The surface morphologies of oxidized oil at 160 degrees C and its formed coke were quite rough, which boosted the subsequent combustion reactions. The results of TG/DSC unravelled that the oxidized oils were subjected to higher mass loss and exothermic effect at the fuel deposition (FD) and high temperature oxidation (HTO) stages as compared to crude oil. After the static LTO, the activation energy in the LTO and FD stages for heavy oil was increased, while that in the HTO stage was reduced. Compared with crude oil and oxidized oils, the coke deposited during the static LTO presented the highest thermal release and reaction activity in the HTO interval. This paper can provide some new insights regarding LTO mechanisms of heavy oil to rich the ISC technology.",27,32,1
Oil Recovery,Heavy Oil,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Li, Xiangfang; Li, Qian; Yang, Jian; Wu, Jiqiang",A coupled model for CO2 & superheated steam flow in full-length concentric dual-tube horizontal wells to predict the thermophysical properties of CO2 & superheated steam mixture considering condensation,Heavy oil recovery; Concentric dual-tube wells; Multi-point injection technique; CO2 coupled with superheated steam; Wellbore hydraulics,HEAT-TRANSFER CHARACTERISTICS; MASS-TRANSFER CHARACTERISTICS; MULTICOMPONENT THERMAL FLUID; 2-PHASE FLOW; NONCONDENSING GASES; NONISOTHERMAL FLOW; SUPERCRITICAL CO2; CURVE ANALYSIS; OIL-RECOVERY; INJECTION,"The mixture of CO2 and superheated steam (SHS) has been proved effective for heavy oil recovery by field practices. It has been proved that the development effect is closely related to the state parameters (temperature, pressure and superheated degree etc.) of the mixture. As a result, wellbore modeling is an important branch in the study of thermal recovery of heavy oil. In recent years, concentric dual-tube wells (CDTW) coupled with multi-point injection technique (MPIT) is proposed to overcome the fingering phenomenon, induced by serious reservoir heterogeneity, during the steam injection process. In this paper, a wellbore model is developed for simulating CO2 & SHS flow in a full-length CDTW. The model is solved with finite difference method on space. It is found that: (a) An injection pressure, higher than 4.1 MPa, in the integral joint tube (IJT) or an injection pressure, smaller than 4.1 MPa, in annuli are recommended to obtain a uniform steam absorption rate along the horizontal wellbores. (b) The mass injection rate at well-head condition should be close to each other to avoid un-uniform of steam absorption rate along the horizontal wellbores. (c) When phase change occurs in the annuli, the mixture temperature increases with increasing CO2 content. (d) The total length of wet steam flow in the horizontal section of the wellbores increases with increasing CO2 content.",27,28,0
Oil Recovery,Heavy Oil,"Yuan, Zhe; Liu, Pengcheng; Zhang, Shengfei; Li, Xiuluan; Shi, Lanxiang; Jin, Ruifeng",Experimental study and numerical simulation of nitrogen-assisted SAGD in developing heavy oil reservoirs,Heavy oil; Non-condensable gas; Nitrogen; Temperature profile; Enhance oil recovery,GRAVITY DRAINAGE; NONCONDENSABLE GAS; STEAM; SOLVENT; INJECTION; COINJECTION; PERFORMANCE; RECOVERY; BITUMEN; METHANE,"The presence of significant amounts of injected steam and heat loss are unavoidable issues occurred that are observed during the steam-assisted gravity drainage (SAGD) process in developing heavy oil reservoirs. Because of these limitations and concerns, non-condensable gas co-injection has become a potential technique to enhancing oil recovery and reducing energy consumption. However, the oil production mechanism is complicated and has not been totally understood, thereby requiring further discussion. In this work, a two-dimensional physical model was designed to investigate the production mechanisms of nitrogen on SAGD. Two comparative injection schemes, specifically the conventional SAGD and nitrogen assisted SAGD (NA-SAGD), were conducted to investigate the effect of nitrogen co-injection with steam on the SAGD performance. Dynamic temperature profile changes during the two experiment processes were monitored and recorded. The observation results indicate that nitrogen accumulation at the upper part of the model resulted in the effective expansion of the NA-SAGD process steam chamber along the horizontal direction. The swept area of steam increased significantly and the residual oil saturation was reduced. The cumulative oil production of NA-SAGD was higher than that of the conventional SAGD. Moreover, the apparent heat loss reduction, which defines the heat utilization efficiency, exhibited an increase following nitrogen injection. In addition, a numerical simulation was generated to compare and verify the results obtained in the two experiments. Nitrogen co-injection with steam effectively enhanced the oil recovery. Studies indicate that NA-SAGD is a feasible method for improving oil production in developing heavy oil reservoirs.",26,30,4
Oil Recovery,Heavy Oil,"Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Yuan, Chengdong; Pan, Jingjun; Wang, Ruyan; Chen, Long; Kan, Ni",Low-temperature oxidation of light and heavy oils via thermal analysis: Kinetic analysis and temperature zone division,Low-temperature oxidation; Light and heavy oils; Thermal analysis; Kinetic analysis; Temperature zone division,PRESSURE AIR INJECTION; CRUDE-OIL; THERMOGRAVIMETRIC ANALYSIS; COMBUSTION KINETICS; SARA FRACTIONS; PYROLYSIS; BEHAVIORS; RECOVERY; MODEL; DECOMPOSITION,"This research is intended to investigate low-temperature oxidation (LTO) behavior and kinetics of light and heavy oils and to divide their LTO intervals. Ramped thermogravimetry/derivative thermogravimetry (TG/DTG) and differential scanning calorimetry (DSC) experiments and isothermal TG experiments with different temperature intervals were used to characterize LTO behavior and to obtain kinetic parameters determined by Ozawa-Flynn-Wall (OFW) and general reaction rate models. The results indicated that there were three (two) distinct variation trends about the conversion rate versus temperature for light (heavy) oil in the LTO region, manifesting the LTO interval of light (heavy) oil should be controlled by multiple-step mechanisms and divided into at least three (two) reaction subintervals. The LTO interval of both light and heavy oils used could be subdivided into three temperature intervals inferred from the variation trend of activation energy over temperature for ramped experiments. Additionally, the LTO region of both light and heavy oils held three subzones in the aspect of isothermal tests. For light oil, the reaction rate augmented from 50 to 250 degrees C where the activation energy was positive, while it reduced from 250 to 350 degrees C coupled with negative activation energy. As for heavy oil, the reaction rate presented an increasing trend in the first and third subintervals (50-150 degrees C and 250 350 degrees C) with positive activation energy and a declining trend in the second subinterval (150 250 degrees C) with negative activation energy. It is believed that this research can add new insights to the LTO interval division of crude oil regarding to the isothermal and non-isothermal conditions, which are of significance for understanding LTO reaction pathways and mechanisms.",26,27,1
Oil Recovery,Heavy Oil,"Seyyedi, Mojtaba; Mahzari, Pedram; Sohrabi, Mehran",A comparative study of oil compositional variations during CO2 and carbonated water injection scenarios for EOR,Carbonated water injection; CO2; CO2 storage; Compositional variations; New gaseous phase; EOR,CRUDE-OIL; RECOVERY; STORAGE,"With the significant increase in the atmospheric concentration of CO2, the interest for a combination of Enhanced Oil Recovery (EOR) and safe underground storage of CO2 in oil reservoirs has been increased. Two applicable methods that can address these concerns are CO2 flooding and carbonated water injection ( CWI). Mutual interactions taking place between oil and free CO2 or carbonated water (i.e. dissolve CO2 in the aqueous phase) would possess a fundamental difference. For free CO2 and oils, a combination of condensing/ vaporizing type of mass transfer would occur. However, in the case of carbonated water, a one- way mass transfer of CO2 from the aqueous phase to the oil can take place. This would lead to significant differences in the oil properties after dynamic interactions with free CO2 or carbonated water. In this study, for the first time, we are aiming to comprehensively address these concerns. An integrated approach was conducted to perform a series of carefully designed high-pressure and high-temperature direct visualizations (micromodel) as well as contact (PVT) experiments using a representative live oil. The results of pore-scale visualization experiments revealed an adverse strong extraction taking place during CO2 injection. Due to this extraction, the remaining oil after CO2 flooding was heavier than the original oil and its production was even more difficult. Contrary to that, during CWI the resident oil became lighter (lower viscosity) and no evidence of substantial extraction or oil downgrading was observed. To confirm pore-scale observations, PVT experiments were performed that revealed a strong adverse compositional change happening during CO2-oil single contact test. The oil contacted with CO2 was heavier than the original oil and a heavy condensate formed mainly from the medium components of oil was produced. However, during CW-oil multiple contacts test, the oil composition did not change and only after extensive cell volumes of CW comes in contact with the live oil; a slight change in the oil composition was observed. This slight change was due to the small extraction of light components of the oil into the new gaseous phase and it was observed in the form of a condensate. The produced condensate was lighter than the one produced from CO2-oil single contact test that reveals even after significant cell volumes of CW comes in contact with oil, the compositional change in oil is negligible compared to that of CO2 injection. The results of this study will shed some lights on the complex fluid-fluid interactions and oil compositional variations that take place during conventional CO2 and carbonated water injection in oil reservoirs.",23,24,3
Oil Recovery,Heavy Oil,"Sitnov, Sergey A.; Mukhamatdinov, Irek I.; Vakhin, Alexey V.; Ivanova, Anna G.; Voronina, Elena V.",Composition of aquathermolysis catalysts forming in situ from oil-soluble catalyst precursor mixtures,Aquathermolysis; Mixed oxides; Transition metals; Catalyst precursor; Heavy oil; In-situ upgrading,HIGH-TEMPERATURE CHEMISTRY; HIGH-VISCOSITY OIL; HEAVY CRUDE OILS; ORGANIC-MATTER; SUPERCRITICAL WATER; CONVERSION; IRON; HETEROCYCLES; CARBOCYCLES; COMBUSTION,"Increasing efficiency of thermal recovery methods of heavy oil through injection of destructive hydrogenation catalysts precursors is a relevant task. In this paper the composition and properties of the active binary catalysts, which formed from a mixture of oil-soluble iron-, nickel- and copper-based precursors have been studied by XRD, Mossbauer spectroscopy, SEM, EDX-mapping methods. Moreover, the efficiency of a mixture of the corresponding metals in reducing the content of heavy components (SARA) of heavy crude oil from Ashal'cha field (Republic of Tatarstan) have been investigated. Mossbauer spectroscopy and EDX-mapping detected the formation of not only spinel ferrites MFe2O4 (where M = Ni or Cu), but also individual oxides. Moreover, in case of nickel-based catalyst three phases are formed: magnetite FeO center dot Fe2O3, spinel ferrite NiFe2O4 and superparamagnetic finely dispersed phase of iron oxides (and probably nickel oxides). According to XRD results, the oxides formed in the first stage transform into nonstoichiometric spinel ferrites Cu0.86Fe2.14O4 and Ni1.43Fe1.7O4 under hydrothermal influences. It is related with the thermodynamically beneficial processes of conversion of this specific phase composition. Based on the SARA and elemental analysis of the initial and converted oil, it was found that catalytic aquathermolysis decreases the content of asphaltenes and resins (about 45%) in the presence of catalyst nanoparticles, which indicates an improvement in the quality of the heavy oil.",22,23,2
Oil Recovery,Heavy Oil,"Taheri-Shakib, Jaber; Shekarifard, Ali; Naderi, Hassan",Experimental investigation of the asphaltene deposition in porous media: Accounting for the microwave and ultrasonic effects,Asphaltene precipitation; Permeability; Microwaves; Ultrasonic waves; Polar components; Porous media,HEAVY CRUDE-OIL; MODELING FORMATION DAMAGE; PRECIPITATION; PERMEABILITY; IRRADIATION; DESULFURIZATION; FLOCCULATION; CARBONATES; RECOVERY; COAL,"This study examines the effects of ultrasonic waves (US) and microwaves (MW) on the permeability in carbonate cores with different permeabilities of asphaltenes deposited therein. Using US with toluene injection restores permeability in cores with a permeability of less than 20 md, about 18.8% and 29% higher than injection of toluene without US. The US creates turbulence and cavitation, causing a change in the structure of the asphaltene conglomerations deposited in the cores. These structural changes may be due to increased levels of contact between precipitates and better penetration of the injected fluid which facilitate the process of removing them from the cores. MW, in addition to changing the structure of asphaltene clusters within the cores, reduces the amount of their polar elements, including sulfur (S), nitrogen (N), and oxygen (O). Under MW irradiation, the sulfur, nitrogen, and oxygen values were 23.5%, 18.4% and 48%, respectively. This decrease in the amount of asphaltene polar elements, which is due to their high capacity to absorb MW can reduce the negative charges in asphaltene particles. The zeta potential results also indicated that the negative charges of asphaltene particles decreased and became more positive as a result of MW radiation (from -12.31 mV to -7.59 mV). Fourier transform infrared spectroscopy (FTIR) spectra tests also confirmed these results. The polar bands of the asphaltene particles deposited inside the cores (OH, S-H; C=O) had a decreasing trend and escaped from the structure of the asphaltene clusters. Decreasing the polar values, especially those of the compounds with negative electrical charge (SO) actually reduces the adhesive force between asphaltene and limestone that has positive electrical charges. This phenomenon causes the removal of asphaltene particles from the porous rock media. The rate at which permeability is restored also indicates that MW radiation is much higher than the previous one (US thorn Toluene), especially cores with low permeability. The results of this study could be a major step towards removing asphaltene precipitates in oil reservoirs using US and MW technologies.",21,21,5
Oil Recovery,Heavy Oil,"Ma, Zhiwei; Leung, Juliana Y.; Zanon, Stefan",Integration of artificial intelligence and production data analysis for shale heterogeneity characterization in steam-assisted gravity-drainage reservoirs,,NEURAL-NETWORKS; HEAVY OIL; PERFORMANCE; SIMULATION; WAVELETS; SYSTEM; ZONES,"Steam-Assisted Gravity Drainage (SAGD) recovery is strongly impacted by distributions of heterogeneous shale barriers, which impede the vertical growth and lateral spread of a steam chamber and potentially reduce oil production. Conventional reservoir heterogeneities characterization workflows that entail updating static reservoir models with dynamic flow data are quite time-consuming. Furthermore, certain assumptions are often needed to approximate the complex physical processes. This study proposes a workflow integrating artificial intelligence (AI) in a model selection framework that aims to identify associated shale heterogeneities in SAGD reservoir based on extracted features from production time-series data. A series of SAGD models based on typical Athabasca oil reservoir properties and operating conditions is constructed. After constructing the base homogeneous model, the shale barriers are assigned randomly by sampling their location, lateral extent, and thickness from several probability distributions, which are inferred from field data assembled from the public domain. Sensitivity analysis is carried out to identify and analyze features in the production response that are related to shale characteristics: whenever the steam chamber encounters a shale barrier, a drop in the production is observed; this drop continues until the steam chamber has advanced past the shale barrier, and the production would rise again. Several types of input feature extraction methods are introduced in this work: piecewise linear approximation (PLA), cubic spline interpolation (CSI), and discrete wavelet transform (DWT). Next, artificial neural network (ANN) is constructed to calibrate a relationship between the retrieved production pattern parameters (inputs) and the corresponding geologic parameters describing shale heterogeneities (outputs), which include some variables capturing the location, orientation or size of a particular shale barrier encountered by the steam chamber. The final model is implemented in a novel characterization workflow to infer shale heterogeneities from production profiles. A number of realistic applications are presented to illustrate its utility. The ANN models are validated using numerous synthetic models, where the exact shale distributions are known. The trained ANN models can reliably estimate the relevant shale parameters and the associated uncertainties, while accurately predicting the corresponding production responses. It is intended to extend the proposed method to construct the ANN models directly from well logs and production data. This work presents a preliminary attempt in correlating stochastic shale parameters with observable features in production time-series data using AI techniques. The proposed method facilitates the selection of an ensemble of reservoir models that are consistent with the production history; these models can be subjected to further history-matching for a precise final match. The proposed methodology does not intend to replace traditional simulation and history-matching workflows, but it rather offers a complementary tool for extracting additional information from field data and incorporating AI-based models into practical reservoir modeling workflows.",21,22,1
Oil Recovery,Heavy Oil,"Azinfar, Bahareh; Haddadnia, Ali; Zirrahi, Mohsen; Hassanzadeh, Hassan; Abedi, Jalal",A thermodynamic model to predict propane solubility in bitumen and heavy oil based on experimental fractionation and characterization,Phase behaviour; Bitumen fractionation; Propane; Solvent-aided process; Equation of state; Simulated distillation,EQUATION-OF-STATE; HYDROCARBON-PLUS FRACTIONS; ISOTHERMAL FLASH PROBLEM; PHASE-BEHAVIOR; RESERVOIR FLUIDS; PHYSICAL-PROPERTIES; ATHABASCA BITUMEN; MIXTURES; SYSTEMS; PETROLEUM,"Propane has been suggested as suitable solvent for solvent-aided bitumen recovery methods such as Vapour Extraction (VAPEX), N-Solv (hot solvent injection), and Expanding Solvent-Steam Assisted Gravity Drainage (ESSAGD). Characterization of bitumen and phase behaviour study of solvent/bitumen systems are the initial steps towards an optimized and successful solvent-aided bitumen recovery process. In this study, Athabasca bitumen is experimentally fractionated to four cuts using modified vacuum distillation and then each cut is characterized. The phase behaviour data including solubility, density, and viscosity of propane/bitumen cuts are measured in wide ranges of temperature and pressure. Using the measured solubility data of propane/bitumen cuts, the PR-EoS is tuned and a binary interaction parameter correlation between propane and bitumen components is developed. The bitumen is then characterized using the boiling point or carbon number distribution obtained by Simulated Distillation test (ASTM D7169). The generalized model is then implemented to calculate the propane solubility in two bitumen samples from different reservoirs (Athabasca and Cold Lake). Our proposed model in this paper, predicted the propane solubility in Athabasca bitumen sample with an average deviation of 1.8 mol.% without using any experimental data of propane/bitumen system or tuning parameter. The proposed model was also evaluated by predicting the propane solubility in Cold Lake bitumen. The propane solubility in Cold Lake bitumen was calculated with an average deviation of 3.0 mol.%, which shows the generality of the proposed model.",21,21,1
Oil Recovery,Heavy Oil,"Lashkarbolooki, Mostafa; Ayatollahi, Shahab","The effects of pH, acidity, asphaltene and resin fraction on crude oil/water interfacial tension",IFT; EOR; pH; Asphaltene; Resin; Crude oil,OIL-RECOVERY; HEAVY OIL; ACTIVE FRACTIONS; SURFACTANT; STABILITY; ALKALI; EMULSIFICATION; SYNERGY,"A basic understanding of the activities of indigenous surfactants of crude oil at the water/oil interface as a function of aqueous phase pH can give us a better insight into the alkaline enhanced oil recovery processes. The present study aimed to elucidate the effect of salinity and crude oil type, specifically the influence of resin and asphaltene molecules during alkaline flooding through interfacial tension (IFT) measurements via pendant drop and spinning techniques. Several model oils containing asphaltene and resin fractions were prepared and their IFTs were compared with those of the original crude oils. Moreover, the elemental analyses of asphaltene and resin fractions were performed, and the total acid numbers of all oils were measured as well. The IFT results of three studied crude oils and the asphaltenic and resinous model oils with sea water and deionized water underlined the importance of the degree of salinity, and qualitative and quantitative nature of resin and asphaltene fractions. It was also revealed that the amount of asphaltene and resin fractions as well as their structural nitrogen and oxygen contents were the most influential parameters on the IFT of crude oil as a function of pH values. In addition, the variations of IFT crude oils/the ionic solution and deionized water were more noticeable in the basic aqueous solutions.",21,22,1
Oil Recovery,Heavy Oil,"Wang, Chao; Liu, Pengcheng; Wang, Fushun; Atadurdyyev, Bayramberdi; Ovluyagulyyev, Mergen",Experimental study on effects of CO2 and improving oil recovery for CO2 assisted SAGD in super-heavy-oil reservoirs,Super-heavy oil reservoir; Steam assisted gravity drainage (SAGD); Reduce viscosity; Carbon dioxide; Thermal oil recovery,GRAVITY DRAINAGE; STEAM; EOR; PERFORMANCE; INJECTION; SEQUESTRATION; MECHANISM; PRESSURE; BEHAVIOR; SOLVENT,"When developing heavy-oil reservoirs using steam-assisted gravity drainage (SAGD) technology, CO2 is often used to reduce the viscosity of heavy oil and the heat loss of the steam chamber, thereby enhancing oil recovery. The limitation of experimental apparatuses, results in a maximum temperature of the reaction kettle of no more than 150 degrees C. Thus, the solubility of CO2 in super-heavy oil and its impact on decreasing viscosity beyond 150 degrees C requires further discussion. Considering these issues, a high-temperature-resistant heavy-oil mixing apparatus was designed to measure the solubility of CO2 in super-heavy oil and the relative density and viscosity of super-heavy oil under high temperatures and pressures. Core flooding experiments under 200 degrees C were conducted to explore the effects of CO2 on oil displacement efficiency. The results indicated that solubility of CO2 became significantly lower at 200 degrees C, when the viscosity and relative density of super-heavy oil decreased as pressure increased. The viscosity of super-heavy oil saturated with CO2 decreased by 71.2%, and relative density decreased by 10.1% at 200 degrees C compared to those of degassed crude. At temperatures of 120 degrees C, 150 degrees C and 200 degrees C, the ultimate displacement efficiency of super-heavy oil increased by 6.6%, 19.2% and 21.4%, respectively, compared to a temperature of 60 degrees C. At pressures of 1.0 MPa, 2.0 MPa and 4.0 MPa, the ultimate displacement efficiency (46.7%) of super-heavy oil increased by 5.2%, 4.0% and 5.9%, respectively, compared to a pressure of 0.5 MPa. The experiments showed that CO2 injection can effectively reduce the relative density and viscosity of super-heavy oil and improve oil recovery under high temperatures and pressures. CO2 has good potential to improve SAGD efficiency in developing super-heavy-oil reservoirs.",20,21,4
Oil Recovery,Heavy Oil,"Hasham, Aleem A.; Abedini, Ali; Jatukaran, Arnav; Persad, Aaron; Sinton, David",Visualization of fracturing fluid dynamics in a nanofluidic chip,Fracturing fluid; Infiltration; Entrapment; Recovery; Nanofluidic,MICROFLUIDICS-BASED MEASUREMENT; PORE-SCALE ANALYSIS; SPONTANEOUS IMBIBITION; OIL-RECOVERY; GAS SHALES; HEAVY OIL; CO2; TEMPERATURE; PRESSURE,"Hydraulic fracturing is responsible for remarkable production from shale and tight formations, albeit at the cost of significant water usage. The flow dynamics of oil and fracturing fluid in nanopores remains largely uncharacterized, in part due to the challenge of conducting experiments at nanoscales. In this paper, we demonstrate a nanofluidic-based approach to visualize the fluid displacement during hydraulic fracturing. Nanoporous silicon-glass chips with circular and square grain shapes and identical depth of 175 nm were fabricated using reactiveion etching (RIE) and anodic bonding. Leveraging the inherent fluorescence property of the oil, the fluorescence microscopy was used to record the dynamics of the fluid displacement inside the chip. Performance of three different fracturing fluids - deionized water, potassium chloride (KCl) solution, and slick water - were evaluated based on the volumetric infiltration in the nanoporous network, entrapment of fracturing fluid in the porous media, and total production during drawdown. The KCl solution had the highest infiltration rate (fill factor of 0.68) and the lowest entrapment factor (0.39), resulting in the highest fracturing fluid recovery representing 43% in the square grain geometry with similar results for circular grains. With the fast quantification and ease of operation here, the nanofluidic approach enables a rapid screening of different fracturing fluids to inform shale oil operators.",20,21,3
Oil Recovery,Heavy Oil,"Pei, Shufeng; Wang, Yanyong; Zhang, Liang; Huang, Lijuan; Cui, Guodong; Zhang, Panfeng; Ren, Shaoran",An innovative nitrogen injection assisted in-situ conversion process for oil shale recovery: Mechanism and reservoir simulation study,In-situ conversion process; Nitrogen injection; Oil shale; Reservoir numerical simulation; Kerogen pyrolysis,HEAVY OIL; CRACKING; MODEL,"In-situ conversion process (ICP) can be an effective technique for the development of oil shale and ultra heavy oils, in which kerogen or heavy components will be cracked into light oils and gases via underground heating and pyrolysis, and the retorted oil can be recovered via conventional extraction techniques. Heating of targeted formation can be conducted using electrical heaters installed in vertical or horizontal wells, while a slow heating rate and lack of driving energy for oil production are the main issues of the conventional in-situ conversion process. In this study, an innovative nitrogen injection assisted in-situ conversion process (NAICP) was proposed to increase formation heating rate and improve oil production from oil shale. Reaction models of kerogen pyrolysis at elevated temperature were established, along with models for the evolution of porosity and permeability of oil shale formation during the pyrolysis process. The performance of nitrogen injection on the effectiveness of the ICP was then investigated through reservoir numerical simulation. The simulation results show that additional nitrogen injection can improve the heating rate of the oil shale formation, enhance oil production and energy efficiency in comparison with the conventional ICPs, which can be attributed to enhanced heat convection, pressurization effect and gas driving mechanism. Nitrogen injection assisted in-situ conversion process can be a promising technique for the exploitation of oil shale.",19,21,9
Oil Recovery,Heavy Oil,"Lashkarbolooki, Mostafa; Riazi, Masoud; Ayatollahi, Shahab",Effect of CO2 and crude oil type on the dynamic interfacial tension of crude oil/carbonated water at different operational conditions,Dynamic IFT; Carbonated water; CO2; Adsorption time; Temperature; Pressure,CARBONATED WATER; AQUEOUS-SOLUTIONS; INJECTION; RECOVERY; PH; EQUILIBRIUM; TEMPERATURE; PERFORMANCE; ASPHALTENE; ADSORPTION,"Concerns about climate change have persuaded the researchers to examine CO2 injection in the form of carbonated water (CW) into oil reservoir as a safe and effective CO2 storage and enhanced oil recovery process. Although interfacial tension (IFT) between crude oil and injected fluid has a vital role on the displacement of fluids in porous media, the effect of CO2 and crude oil type on the dynamic IFT of crude oil under different operational conditions is not well understood. Accordingly, this study was carried out to assess the effects of temperature, pressure, crude oil type and CO2 on the dynamic IFT of crude oil/CW. To achieve this goal, two types of crude oil were provided from southern Iranian oil reservoirs and dynamic IFTs with CW were measured in a wide range of temperatures and pressures (i.e. temperature range of 30-80 degrees C and pressure range of 500-4000 psi); the obtained results were compared with the system without CO2. In addition, the adsorption time of carbonated aqueous phase/crude oil, obtained based on the mono exponential decay model, was also compared with unadulterated water/crude oil system. The outcome of this study showed that crude oil type has the most significant effect on the IFT of crude oil/CW compared to pressure, temperature and CO2 content. In more details, the IFT of crude oil/CW can be affected by the amount and type of acidic/basic components in the crude oil as well as pH of the aqueous solution. Besides, the obtained results revealed that the effect of temperature was more considerable on the IFT of the heavy crude oil compared with the light crude oil in both studied aqueous solutions (i.e. unadulterated water and CW). Although the inversion phase temperature was obtained for unadulterated water/studied crude oils at all studied pressures, this phenomenon was not observed for crude oil/CW at elevated pressure, due to the high amount of CO2 at this condition.",17,17,3
Oil Recovery,Heavy Oil,"Nasri, Zarrin; Mozafari, Motahareh",Multivariable statistical analysis and optimization of Iranian heavy crude oil upgrading using microwave technology by response surface methodology (RSM),Heavy crude oil; Upgrading; Microwaves; Response surface methodology,ULTRASONIC IRRADIATION; HORIZONTAL WELL; DEMULSIFICATION; EMULSIONS; PERFORMANCE; PYROLYSIS; RECOVERY,"Conventional methods to upgrade heavy oil due to high pressure, low production efficiency, and low product quality have not been recognized as profitable methods. These complications resulted in using innovative technologies in this area. In this paper, the statistical analysis and process conditions optimization of Iranian heavy crude oil upgrading have been performed using microwave technology, for the first time. The heavy crude oil is from Iranian west Paydar field, with specifications including API 18.53, viscosity 78.76 cSt (at 20 degrees C). In order to optimize process conditions for upgrading heavy crude oil, independent variables include power level (40-70-100%), process time (5-12.5-20) (min), activated carbon as sensitizer (0-5-10) (wt%), and Fe as catalyst (0-3-6) (wt%). Surface temperature, API ratio, viscosity ratio, and asphaltene reduction have been considered as response variables. The Box-Behnken design and response surface methodology (RSM) have been applied to determine parameters levels and to model the responses, respectively. The results show that the optimal conditions to maximize surface temperature, API ratio, and asphaltene reduction, and to minimize viscosity ratio involve power level of 100%, process time of 20 min, activated carbon of 10 wt%, Fe catalyst of 4.06 wt% which leads to 23.31API ratio, 31.6% asphaltene reduction, and 43.37% viscosity reduction. The predicted conditions agreed with the experimental values, representing the models accuracy.",16,17,3
Oil Recovery,Heavy Oil,"Ameli, Forough; Mohammadi, Kaveh",A novel optimization technique for Fast-SAGD process in a heterogeneous reservoir using discrete variables and repetition inhibitory algorithm,Fast SAGD; Optimization; Genetic algorithm; Discrete variables; Repetition inhibitory algorithm,ENHANCED OIL-RECOVERY; IMPERIALIST COMPETITIVE ALGORITHM; ASSISTED GRAVITY DRAINAGE; HEAVY OIL; INTERFACIAL-TENSION; GRID GENERATION; TEMPERATURE; STEAM; SIMULATION; IMPLEMENTATION,"One of the most prevalent methods for enhanced oil recovery in heavy oil reservoirs is thermal techniques. Fast-SAGD process is an advance method of enhance oil recovery in which offset wells are drilled for cyclic steam injection and production. This leads to increasing the production efficiency. Optimization of this process was performed using various techniques including genetic algorithm (GA), imperialist competitive algorithm (ICA), and particle swarm optimization (PSO). Combination of recovery factor and cumulative steam to oil ratio was introduced as the objective function. This study represents a novel supplementary technique implemented in optimization algorithms to increase its speed, significantly. In this technique, effective parameters were defined using sensitivity analysis. Then they were converted to discrete variables. To discretize the selected parameters, three different functions including logarithmic, square, and linear were applied using Minitab 18. Moreover, repetition inhibitory algorithm (RIA) was implemented in optimization algorithms for the first time to prevent recalculation of duplicate states in optimization for the next generation, and to speed-up the optimization process. The results of sensitivity analysis indicated that maximum and minimum effective parameters were attributed to Fast-SAGD production well height and soak time, respectively. Results indicated that among various optimization algorithms, GA worked 6% better in comparison to other optimization techniques and linear discretization function resulted in better optimized point in a shorter time. Results indicated that optimization process using discrete variables and repetition inhibitory algorithm led to the optimized point 6.33 times faster than discrete optimization procedure without RIA. This was 16.46 times faster in comparison to continuous optimization algorithm. Moreover using RIA led to termination of optimization algorithm 9.67 times faster than continuous mode.",15,15,2
Oil Recovery,Heavy Oil,"Ado, Muhammad Rabiu; Greaves, Malcolm; Rigby, Sean P.","Effect of pre-ignition heating cycle method, air injection flux, and reservoir viscosity on the THAI heavy oil recovery process",Toe-to-heel air injection (THAI); In-situ combustion; Bitumen/heavy oil; Enhanced oil recovery (EOR); Pre-ignition heating cycle (PIHC),ASSISTED GRAVITY DRAINAGE; COMBUSTION; SAGD; SIMULATION,"Heavy oil and bitumen reserves can potentially bridge the gap in world energy demand during the transition between conventional hydrocarbon fuels and sustainable energy sources, while the latter are developed. However, the development of efficient extraction methods with low emissions is necessary. The in-situ combustion process, toe-to-heel air injection (THAI), is such a method, but some issues remain in improving its performance. In this paper, the performance of the THAI process has been investigated at the laboratory scale using a validated simulation model. We have studied the effect of pre-ignition heating cycle (PIHC) method, reservoir oil viscosity, and air injection flux, on the stability and operability of the THAI process. It was found that the use of steam, instead of electrical heaters, for the PIHC resulted in an increase in oil recovery. However, use of steam also caused a reduction in oxygen utilisation. The use of a horizontal injector (HI) well, in combination with the steaming during the PIHC, causes some of the oxygen to bypass the combustion front during the early stage of air injection. It is concluded that steaming using a staggered line drive, or 2VIHP well arrangement, is recommended to be used at the field scale. It was also found that THAI operates more stably for higher viscosity oil, albeit at higher operating cost, due to increased cumulative air-oil ratio (CAOR), compared to for a low oil viscosity reservoir. In contrast to previous suppositions, it has been found that oil recovery increases non-linearly with an increase in air flux, which needs to be taken into account on scale-up.",15,15,1
Oil Recovery,Heavy Oil,"Taheri-Shakib, Jaber; Shekarifard, Ali; Naderi, Hassan",The study of influence of electromagnetic waves on the wettability alteration of oil-wet calcite: Imprints in surface properties,Wettability; Heavy oil; Microwave; Calcite; Polar,APPEARANCE TEMPERATURE WAT; CONTACT-ANGLE; RECOVERY; MICROWAVE; SALINITY; CARBONATE; ROUGHNESS; IMPACT; TIME; GAS,"The wettability of reservoir rock is one of the fundamental parameters determining the flow of fluid in the porous media. This study has investigated the effect of microwaves on the wettability of calcite reservoir rock from Yaran, Iran, as the time interval of microwave radiation is one of the most important parameters affecting wettability. The reservoir rock samples were placed in a microwave oven filled with helium gas and subjected to microwave radiation at 5-min intervals from 5 to 35 min. Measurements of the contact angle between the oil and the rock indicated that the microwaves brought the angle from about 120 degrees primary state to 93 degrees at 35 min. At intervals of 5-15 min, no change in the wettability of the oil-wet rock was observed. Sulfur components had high absorption coefficients of microwaves, so initially reduced the amount of sulfur (S) on the surface of the oil-wet rock. Next, the nitrogen (N) and oxygen (O) elements were reduced, and eventually the carbon (C) levels began to decrease. This trend was observed in the zeta potential by changing the surface charge of the rock. Indeed, eliminating SNO polar compounds with a high potential for absorbing microwave caused the rock to become water-wet. Microwave radiation initially produced no change in the Fourier-transform infrared spectroscopy (FTIR) spectrum, as it continued, the peak intensity of the corresponding oil, such as the carboxylic acid functional group, declined, and the corresponding peaks of the rock became more intense, indicating a gradual change in the wettability. It can be interpreted that the aromatic compounds exist in oil and act as surface agent components. The results of this study can be used as a representation of the use of microwave radiation in hydrocarbon reservoirs to change the wettability and increase the production rate of reservoirs.",15,15,0
Oil Recovery,Heavy Oil,"Mehrabi-Kalajahi, Seyed Saeed; Varfolomeev, Mikhail A.; Yuan, Chengdong; Emelianov, Dmitrii A.; Khayarov, Khasan R.; Klimovitskii, Alexander I.; Rodionov, Alexander A.; Orlinskii, Sergei B.; Gafurov, Marat R.; Afanasiev, Igor S.; Fedorchenko, Gennadii D.; Lubnina, Elena V.",EPR as a complementary tool for the analysis of low-temperature oxidation reactions of crude oils,Crude oil; In-situ combustion; Air injection; Oxidation; EPR; Free radical concentration,IN-SITU COMBUSTION; VANADYL-PORPHYRIN COMPLEXES; SARA FRACTIONS; PARAMAGNETIC-RESONANCE; KINETIC-ANALYSIS; AIR INJECTION; HEAVY OIL; LIGHT; ASPHALTENES; BEHAVIOR,"Air injection is a promising method for enhanced oil recovery (EOR) in both conventional and unconventional oil sources. It is widely accepted that oxidation reactions between oil and injected air determine the success of an air injection process. In this study, electron paramagnetic resonance (EPR) was introduced as a new route to investigate the occurrence of low-temperature oxidation (LTO) and its behavior by monitoring the signals of free radicals. The EPR experiments were conducted for the different crude oil samples (light, medium and heavy) heated in both static air and flow air (air-bubbling) conditions under different temperatures from 25 degrees C to 180 degrees C. The results showed that the free-radical concentrations exhibited a good correspondence on the heating temperature. Furthermore, nuclear magnetic resonance (NMR), Fourier-transform infrared spectroscopy (FTIR) and differential scanning calorimetry (DSC) experiments were carried out to help to analyze the oxidation process and verify the EPR results. It turned out that the EPR results can be well supported by NMR, FTIR and DSC data, which indicates that proposed EPR monitoring method can be applied as a fast and low-cost technique to investigate LTO under mild reaction conditions. Simultaneously, the combination of EPR, NMR, FTIR and DSC can help to better understand the LTO mechanism and to monitor the application of in-situ combustion technique in the field.",14,14,1
Oil Recovery,Low Salinity,"Sharma, Himanshu; Mohanty, Kishore K.",An experimental and modeling study to investigate brine-rock interactions during low salinity water flooding in carbonates,Low salinity; Wettability alteration; Brine-rock interactions; IPHREEQC; Carbonates; Mechanistic model; Surface complexation,WETTABILITY ALTERATION; OIL-RECOVERY; CHALK,"Injection of brines with carefully designed ionic compositions into oil-wet carbonate rocks at high temperatures has shown to alter their wettability towards a water-wet state and improve oil recovery. Various mechanisms have been postulated for this wettability alteration such as mineral dissolution and interaction of potential determining ions, such as Ca2+, Mg2+ and SO42-, with the carbonate surface. In this study, experimental and modeling work was performed to gain further insights into the geochemical interactions between carbonate rocks and modified brines. Single-phase static (equilibrium) and transport experiments were performed with various brines in limestone cores at 120 degrees C. The ionic compositions of the effluent samples were monitored using ion chromatography. A mechanistic model for the wettability alteration process was developed in UTCHEM-IPHREEQC based on key geochemical interactions. The calcite surface was assumed to consist of positive and negative sites and their interactions with potential determining ions were considered assuming local equilibrium. The model assumed the degree of oil-wetness to depend on the amount of organic acid attached on the surface, which in-turn was dependent on the geochemistry of the system. Results of static experiments performed with crushed limestones and brines showed an increase in calcium concentration and a decrease in magnesium concentration in the supernatant brines. The effluent concentrations from single-phase brine corefloods in limestone cores showed an increase in calcium concentration, a decrease in magnesium concentration and a delay in sulfate concentration. Three key geochemical interactions were identified based on these results: mineral dissolution, surface dolomitization and sulfate adsorption. A good qualitative agreement was observed between single-phase experiments and simulations, suggesting that the model was able to accurately capture the geochemistry. The simulation results showed good agreement with zeta potential and oil recovery results reported in the literature.",55,57,3
Oil Recovery,Low Salinity,"Nasralla, Ramez A.; Mahani, Hassan; van der Linde, Hilbert A.; Marcelis, Fons H. M.; Masalmeh, Shehadeh K.; Sergienko, Ekaterina; Brussee, Niels J.; Pieterse, Sebastiaan G. J.; Basu, Saptarshi",Low salinity waterflooding for a carbonate reservoir: Experimental evaluation and numerical interpretation,,ENHANCED OIL-RECOVERY; DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; IMPACT; TEMPERATURE,"Several laboratory studies and some field trials have already demonstrated the potential of lowering the injected brine salinity and/or manipulating composition to improve oil recovery in carbonate reservoirs. Laboratory SCAL tests such as coreflooding and imbibition are key steps to screen low salinity waterflood (LSF) for a particular field to (i) ensure that there is LSF response in the studied rock/oil/brine system, (ii) find the optimal brine salinity, (iii) extract relative permeability curves to be used in the reservoir simulation model and quantify the benefit of LSF and (iv) examine the compatibility of injected brine with formation brine and rock to derisk any potential scaling or formation damage caused by fines mobilization. This paper presents an extensive LSF SCAL study for a carbonate reservoir and the numerical interpretation of the tests. The SCAL experiments were performed at reservoir conditions using reservoir core plugs, dead crude oil and synthetic brines. The rock was characterized using porosity-permeability measurement semiquantitative, X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury intrusion capillary pressure (MICP) techniques. The characterization work showed that the plugs can be classified into two groups (uni-modal and bi-modal) based on pore throat size distribution which correlated with porosity-permeability cross-plots. The SCAL experiments were divided in two categories. Firstly, spontaneous imbibition and qualitative unsteady-state (USS) experiments were performed to demonstrate the effect of low salinity brines. In addition, these experiments helped to screen different brines (seawater and different dilutions of seawater) in order to choose the one that showed the most promising effect. Secondly, quantitative unsteady-state (USS) experiments were conducted and interpreted using numerical simulation to extract relative permeability curves for high salinity and low salinity brines by history- matching production and pressure data. The main conclusions of the study are: 1- The spontaneous imbibition and qualitative USS experiments showed extra oil production when switching from formation brine to seawater or diluted seawater subsequently, 2- Oil recovery by LSF can be maximized by injection of brine at a certain salinity threshold, at which lowering the brines salinity further did not lead to additional recovery improvement, 3- The LSF effect and optimal brine salinity varied in different layers of the reservoir which indicates that within the same reservoir the LSF effect is quite dependent on the rock type/ property and mineralogy, 4- The quantitative USS showed that LSF can improve the oil recovery factor by up to 7% at core scale compared to formation brine injection.",47,47,2
Oil Recovery,Low Salinity,"Da, Chang; Alzobaidi, Shehab; Jian, Guoqing; Zhang, Leilei; Biswal, Sibani L.; Hirasaki, George J.; Johnston, Keith P.",Carbon dioxide/water foams stabilized with a zwitterionic surfactant at temperatures up to 150 degrees C in high salinity brine,CO2-in-water foam; Zwitterionic surfactant; Porous media; EOR,ENHANCED OIL-RECOVERY; WORMLIKE MICELLES; CONCENTRATED EMULSIONS; SUPERCRITICAL FLUIDS; MOBILITY CONTROL; MIXED-SOLUTIONS; AQUEOUS-PHASE; POROUS-MEDIA; YIELD-STRESS; ADSORPTION,"Stabilization of CO2-in-water (C/W) foams with surfactants at high temperature and high salinity conditions is challenging given limitations in the solubility and thermal stability of surfactants, particularly for surfactants other than anionic ones. Here we show that a single zwitterionic surfactant, cetyl betaine (CH3(CH2)(15)N+(CH3)(2)CH2COO-), stabilizes viscous C/W foam (> 15 cP) in crushed limestone (76-Darcy) at a temperature up to 150 degrees C and over a wide range in salinity up to 22% total dissolved solids (TDS) at superficial velocity of 940 ft/day. According to liquid chromatography mass spectrometry (LC/MS), cetyl betaine has high thermal stability with negligible chemical degradation after incubation at 135 degrees C for 30 days. Interfacial tension (IFT) at the C/W interface was reduced significantly from similar to 37 mN/m to < 5 mN/m with the addition of 0.08 mmol/L of cetyl betaine. Relative to ionic surfactants, the relatively weak electrostatic repulsion between the local charges in the headgroup is shown to produce strong adsorption at the C/W interface (similar to 134 angstrom(2)/molecule), resulting in generation of viscous foam (similar to 6 cP) even in pure water without added salt. At a low superficial velocity of 6 ft/day (shear rate 45 s(-1)) in a beadpack, foam was still formed with cetyl betaine. Static adsorption of cetyl betaine on carbonates was on the order of 1 mg/m(2), and core flood test also proved that cetyl betaine could stabilize viscous C/W foam (> 20 cP) within 6 pore volumes of injection at 120 degrees C. The surfactant stabilized viscous C/W foam at low oil fractions and broke in the presence of large fractions of oil, both of which are desirable in CO2 mobility control and oil displacement. The ability to form foams at high temperatures and over a wide range in salinity is important for various practical applications including CO2 enhanced oil recovery, fracturing with energized fluids and CO2 sequestration.",46,48,19
Oil Recovery,Low Salinity,"Xie, Quan; Sari, Ahmad; Pu, Wanfen; Chen, Yongqiang; Brady, Patrick V.; Al Maskari, Nasser; Saeedi, Ali",pH effect on wettability of oil/brine/carbonate system: Implications for low salinity water flooding,Carbonate reservoirs; Low salinity water; Wettability; Geochemical modelling; pH,SURFACE COMPLEXATION MODEL; IMPROVED OIL-RECOVERY; IMPACT; CHALK; CARBONATES; SANDSTONE; EOR,"Wettability of oil/brine/carbonate system is a critical parameter to govern subsurface multi-phase flow behaviour, thus remaining oil saturation and ultimate oil recovery in carbonate reservoirs. Despite the fact that salinity level, ionic strength, oil composition and rock chemistry (e.g., limestone and dolomite) have been extensively investigated, few work has been done regarding the effect of pH on oil/brine/rock interaction, thus wettability. We thereby measured contact angles at two different pH (pH = 3 and 8) in the presence of either 1 mol/L Na2SO4 or 1 mol/L CaCl2 using a crude oil with acid number of 1.7 and base number of 1.2 mg KOH/g. Moreover, we performed a geochemical modelling study in light of the diffuse double layer to understand how pH controls the number of surface species at interfaces of oil/brine and brine/carbonate. Our results show that pH scales with oil/brine/carbonate wettability, demonstrating that pH is one of the controlling factors to govern the system wettability. Further, our results suggest that pH (6.5-7.5) likely triggers an oil-wet system, which is favourable for low salinity water flooding, but pH < 5 usually exhibits a water-wet system, which explains why low salinity effect is not always observed in carbonate reservoirs. This also confirms that CO2 flooding, carbonated water flooding, and CO2 huff-and-puff FOR very likely renders a strongly water-wet system due to H+ adsorption on the interface of oil/brine and brine/carbonate as a result of CO2 dissolution.",43,43,2
Oil Recovery,Low Salinity,"Mahzari, Pedram; Sohrabi, Mehran; Cooke, Alexander J.; Carnegie, Andrew",Direct pore-scale visualization of interactions between different crude oils and low salinity brine,Micro-dispersion; Low salinity water injection; Crude oil; Pore scale; Enhanced oil recovery,INFRARED-SPECTROSCOPY; FTIR SPECTROSCOPY; RECOVERY; COMPONENTS,"Direct pore-scale visualizations using micromodels for low salinity water injection (LSWI) have revealed that the contact between low salinity water and crude oil can provoke formation of water-in-oil micro-dispersions. This experimental work, using a number of different crude oils, aims to visually study the link between micro-dispersion formation and pore surface wettability alteration by low salinity water injection. The effect of aging time on wettability alteration by LSWI was investigated. It was observed that mixed-wet conditions established with a moderate aging time would increase low salinity ability controlled by the oil characteristics. Moreover, under tertiary LSWI, the trapped oil was mobilized if the crude oils exhibited capabilities of forming micro-dispersions. Interestingly, when a crude oil with little or no propensity to form micro-dispersions was used, low salinity effects such as wettability alteration and improved oil recovery were absent. Also, micromodel experiments could enable the investigation of LSWI for waxy crude oil, which is difficult to do with other approaches. To demonstrate the impact of micro-dispersion formation on polar components of the oils, infrared analyses were performed indicating the importance of oil polar agents enriched in aromatics and sulfoxides on controlling the formation of the micro-dispersions. After using various crude oils, it was concluded that the effectiveness of LSWI as the method to increase oil recovery is predominantly controlled by two factors; (i) initial degree of wettability of pore surfaces and (ii) the propensity of crude oil to form micro-dispersions.",40,40,3
Oil Recovery,Low Salinity,"Fredriksen, Sunniva B.; Rognmo, Arthur U.; Ferno, Martin A.",Pore-scale mechanisms during low salinity waterflooding: Oil mobilization by diffusion and osmosis,Low salinity effect; Pore-scale mechanisms; Osmosis and water diffusion; Oil mobilization; Salinity contrast; Chemical potential,WETTABILITY ALTERATION; FOAM-GENERATION; RECOVERY; MICROMODEL,"Pore-level oil mobilization is studied during low salinity waterflooding by microscopic visualization of water diffusion and osmosis in sandstone silicon-wafer micromodels. The two-dimensional water-wet micromodels apply a controlled, state-of-the-art experimental approach, with a high accuracy pore network, sharp edges and surface roughness to observe transport and displacement processes during low salinity waterflooding. Residual and capillary trapped oil is mobilized when a salinity contrast is established between high-saline connate brine in matrix and low salinity water flowing in an adjacent fracture. The driving force is the difference in chemical potential between the aqueous phases. The focus of this work is on water transport by diffusion and osmosis, mechanisms that are both present in low salinity waterflooding, but less reported in literature. The micromodel system makes it possible to distinguish diffusive and osmotic effects from other well-known mechanisms such as wettability change and fines migration. Transport of water occurs by diffusion through film-flow resulting in film-expansion along water-wet grains. In presence of an osmotic gradient the oil-phase act as a semi-permeable membrane allowing transport of low salinity water into high-saline water-in-oil emulsions.",38,39,5
Oil Recovery,Low Salinity,"Unsal, E.; ten Berge, A. B. G. M.; Wever, D. A. Z.",Low salinity polymer flooding: Lower polymer retention and improved injectivity,Low salinity polymer; Retention; Rheology; Injectivity; Cation exchange,ENHANCED OIL-RECOVERY; POROUS-MEDIA; CATION-EXCHANGE; FLOW; SHEAR; FIELD,"Delayed arrival of the oil bank and reduced injectivity are risks which are commonly associated with low salinity polymer (LSP) flooding. In this study, experimental work was carried out to address these risks; the polymer retention and the cationic exchange in the presence of polymer were the main subjects of investigation. Single phase coreflood experiments were performed, where low and high salinity polymer (HSP) solutions, i.e., conventional polymer flood using formation brine, were injected in reservoir core plugs. The performance of the two polymer solutions were analyzed for polymer retention, injectivity and polymer acceleration. Compared to the HSP coreflood, the LSP coreflood showed considerably lower polymer retention and better long-term injectivity. There was no delay in polymer breakthrough, and the polymer acceleration was comparable to HSP floods. Analysis of produced effluent of the LSP coreflood detected divalent ion concentrations higher than the injected solution, and the solution which was already in equilibrium with the rock. This suggested that the divalent ions were released from the rock into the solution because of cation exchange in the presence of the LSP solution. Such increase in divalent ion concentration increased the polymer solution salinity and resulted in a viscosity loss. The results of the experimental study indicated that LSP flooding can be an attractive alternative to conventional polymer flooding, although viscosity loss due to cation exchange is a subject for further de-risking work. A numerical model which couples the cation exchange in presence of polymer with flow dynamics in core scale has also been developed. The flow field was used to advect the polymer which influenced the equilibrium condition between the rock surface and the solution. We present preliminary results obtained using the model which can be used to gain insights and study sensitivities around different geochemistry coupled flow processes.",33,34,0
Oil Recovery,Low Salinity,"Pal, Nilanjan; Saxena, Neha; Mandal, Ajay",Characterization of alkali-surfactant-polymer slugs using synthesized gemini surfactant for potential application in enhanced oil recovery,Gemini surfactant; Interfacial tension; Thermal stability; Viscosity; Viscoelasticity; ASP flooding,HYDROPHOBICALLY ASSOCIATING POLYACRYLAMIDE; COMBINATION FLOODING SYSTEMS; HEAVY OIL; ORGANIC ALKALI; RHEOLOGICAL PROPERTIES; INTERFACIAL-TENSIONS; SALINITY CONDITIONS; FIELD APPLICATIONS; MIXED SURFACTANT; LIGHT-SCATTERING,"The present study deals with the formulation and characterization of alkali-surfactant-polymer slugs using gemini surfactant (GS) for effective application in enhanced oil recovery (EOR) processes. The hydrolytic stabilities of the synthesized cationic GSs were measured in both acidic and basic media. Surface tensiometry was employed to determine the CMC values of surfactant at different temperatures. An organic alkali, monoethanolamine (MEA) showed the most favourable interfacial properties at the oil-aqueous interfaces among the various experimented alkalis. Though the addition of PHPA polymer to GS/MEA solutions increase the IFT value, the viscosities of the slugs improve drastically, which is desirable to improve the sweep efficiency. The solutions also showed low turbidity values and high thermal stability over a significant time period. The oil-surfactant-aqueous systems showed favourable emulsification properties, showing the ability to effectively displace trapped oil. Viscosity increases with PHPA concentration due to mixed micelle associations among the surfactant, alkali and polymer molecules. At low shear rates, the GS/MEA/PHPA solutions exhibited shear thinning properties. Oscillatory studies show the presence of both viscous and elastic properties, which have been well described using the Maxwell mechanical model. Formulation consisting of 0.02% 14-6-14 GS, 0.80% MEA and 0.20% PHPA showed the most favourable tertiary recovery after conventional secondary water-flooding.",31,32,2
Oil Recovery,Low Salinity,"Yuan, Bin; Moghanloo, Rouzbeh Ghanbarnezhad","Nanofluid pre-treatment, an effective strategy to improve the performance of low-salinity waterflooding",Low-salinity water flooding; Enhanced oil recovery; Nanofluids; Fines migration; Well injectivity,INDUCED FINES MIGRATION; POROUS-MEDIA; ANALYTICAL-MODEL; OIL-RECOVERY; INJECTION; SURFACE; REDUCTION; PARTICLES; TRANSPORT; CORES,"Low-salinity water (LSW) has been confirmed as a promising improved oil recovery technique. Implementing this technique, in some cases, induces fines migration and has posed great challenges on well injectivity. The aim of this work is to establish a mathematical foundation and explain the improved performance (both EOR and well injectivity) through nanofluid pre-treatment in single-layered and multi-layered heterogeneous reservoirs. We modify the fractional flow function while considering for fines straining effects in one-dimensional radial system, where fines migration varies with distance from the injection well owing to different drag forces. The interplay among nanoparticles, fines, and rocks is described through the maximum retention concentration of fine particles that depend upon both fluid quality and velocity. Our modification of the classical Buckley-Leverett theory leads to the characteristic curves along which water saturation varies. As low-salinity waterflooding continues, the induced fines migration delays the breakthrough of injected water, and bring uniform control of injected fluid entering each layer. On the other hand, fines migration may lead to the issue of well injectivity decline. Nanofluid pre-treatment can significantly mitigate fines migration near wellbore while it may occur far from the injection well. We discuss cases with different nanofluid treatment schemes prior to low-salinity waterflooding by comparing water-saturation profile, water-cut history plot, injection pressure, and oil recovery. A good agreement is obtained between semi-analytical solution and finite-difference simulation. It was observed that although nanofluid treatment slightly accelerate breakthrough of the injected water, it can help maintain long-term well injectivity and sweep efficiency. In practice, our work provides valuable insight to design of nanofluid utilization and improve efficiency of low-salinity waterflooding.",29,29,3
Oil Recovery,Low Salinity,"Teklu, Tadesse Weldu; Li, Xiaopeng; Zhou, Zhou; Alharthy, Najeeb; Wang, Lei; Abass, Hazim",Low-salinity water and surfactants for hydraulic fracturing and EOR of shales,Low-salinity water; Low-salinity water plus srufactnat; Osmosis; Capillary pressure; Wettability alteration; IFT decrease; Hydraulic fracturing and EOR of shales,OIL-RECOVERY; UNCONVENTIONAL RESERVOIRS; IMBIBITION; WETTABILITY; TRANSPORT,"There are significant recoverable oil and gas resources stored in shale reservoirs throughout the world. Horizontal well with multistage hydraulic fracturing is an enabling technology for economic production of these shale resources. Recovery factors of liquid rich shale reservoirs is typically less than 10%, hence, there is an incentive for implementing enhanced oil recovery (EOR) technologies to improve oil production from these very tight reservoirs. Brine, chemical (surfactant), gas, or combination of these fluids imbibition or injection in huff-n-puff scenario could improve oil recovery of liquid rich shale reservoirs. In this study, low-salinity water and low-salinity water + surfactant imbibition are assessed as both hydraulic fracturing and EOR fluids in liquid rich shale reservoirs. Osmosis, capillary pressure, wettability alteration, and other effects are among the mechanisms by which these fluids can improve oil recovery from shale reservoirs. These favorable effects were investigated through imbibition experiments. Experiments show: (a) low-salinity water huff-n-puff in tight formations can improve oil production from tight formations. This is because wettability alteration, capillary, and osmotic forces; (b) surfactant + low-salinity-water huff-n-puff can further improve oil production due to additional IFT decrease and wettability alteration by surfactants; hence, improve oil production from stimulated ultra-tight formations. Based on experimental observations and literature reviewed, low-salinity water huff-n-puff (until economical), followed by low-salinity water + surfactant huff-n-puff EOR process is recommended to optimize production from liquid rich shale reservoirs, while minimizing cost. These fluids can be used to reduce matrix-fracture skin damage. The effectiveness of these hydraulic fracturing and EOR fluids in shales is highly dependent on the existence and extent of natural fractures or laminations within the stimulated reservoir volume; this is because osmosis and diffusion are very slow processes.",27,29,7
Oil Recovery,Low Salinity,"Chequer, L.; Vaz, A.; Bedrikovetsky, P.",Injectivity decline during low-salinity waterflooding due to fines migration,Low-salinity waterflooding; Injectivity; Formation damage; Fines migration; Analytical model; Laboratory data,POROUS-MEDIA; WATER INJECTION; FORMATION DAMAGE; PERMEABILITY VARIATION; SANDSTONE RESERVOIRS; COLLOIDAL TRANSPORT; MATHEMATICAL-MODEL; FILTRATION; PARTICLES; DETACHMENT,"Injectivity damage by fines migration during low-salinity water injection can highly affect field-scale waterflooding projects. In this paper, we develop novel analytical models for one-dimensional linear and radial suspension-colloidal flows accounting for detachment, mobilisation, migration, and straining of natural reservoir fines. We also perform laboratory corefloods by water with piecewise constant decreasing salinity, and with monitoring the breakthrough particle concentration and pressure drop across the core. The analytical model for linear flows matches the laboratory data with high accuracy, and tuned model coefficients belong to the common-value intervals for those coefficients. The analytical model for radial flows predicts well behaviour; the experimental-data-tuned coefficients are used for reliable laboratory-based prediction of injectivity index decline. The calculations show a significant decline of injection-well index due to fines migration during low-salinity water injection.",26,27,1
Oil Recovery,Low Salinity,"Suleimanov, Baghir A.; Latifov, Yashar A.; Veliyev, Elchin F.; Frampton, Harry",Comparative analysis of the EOR mechanisms by using low salinity and low hardness alkaline water,EOR; Low hardness alkali water; Sandstone flooding; Bentonite swelling; Low salinity water; Emulsion,IMPROVED OIL-RECOVERY; BRINE ROCK SYSTEMS; WETTABILITY ALTERATION; CRUDE-OIL; SPONTANEOUS IMBIBITION; SANDSTONE; TEMPERATURE; IONS,"This paper discusses the application of low hardness alkali water compositions (LHAW) as a secondary and tertiary displacement agent for EOR. A comparative analysis of the impact of low salinity water (LSW) and LHAW water on interfacial tension, contact angle on rock, adsorption of ions, emulsion stability and clay swelling is presented. LHAW application contributes to the formation of stable water in oil (w/o) emulsions and a decrease in clay swelling compared to LSW. Adsorption values for both fluids are similar. Contact angle measurements show that both LSW and LHAW reduce interfacial tension compared to Synthetic Caspian Sea water (SCSW), by up to 17% and 94% respectively. Similar results were observed for contact angle measurements. Flooding experiments were conducted in secondary and tertiary modes. In secondary flooding the two water compositions LHAW-2 and LHAW-1 increased the oil recovery (%OOIP) in comparison with SCSW at water breakthrough, by 29% and 25% respectively. The final oil recovery increases were 21% and 15% respectively. In tertiary flooding, tests showed that LHAW-2 and LHAW-1 oil recoveries (%OOIP) compared to LSW were 13% and 10% respectively. The oil recovery rate for LHAW solutions was not linear versus lnt as was that for LSW. This was proposed as a consequence of emulsions generation while water-cut is below 50% however, above 50% water cut the rate stabilizes.",25,25,0
Oil Recovery,Low Salinity,"Adegbite, Jamiu Oyekan; Al-Shalabi, Emad Walid; Ghosh, Bisweswar",Geochemical modeling of engineered water injection effect on oil recovery from carbonate cores,Low salinity water injection (LSWI); Engineered water injection (EWI); Wettability alteration; EWI effect on carbonates; Modeling of EWI,LOW-SALINITY; WETTABILITY ALTERATION; IMPACT; CHALK; INSIGHTS,"In the field of enhanced oil recovery, the engineered/low salinity water injection (EWI/LSWI) is one of the promising development in recent years. Several mechanisms describing the EWI/LSWI recovery process have been suggested without a common consensus. Wettability alteration have been considered as the prime reason behind the incremental oil recovery; however, several other possible mechanisms are also suggested. This paper investigates the effect of engineered water injection (EWI) on oil recovery from carbonates cores along with recovery, pH and effluent-ion predictions, which is based on numerical simulations using laboratory coreflood data. An EWI model is proposed based on multi-ion exchange for capturing the incremental oil recovery by EWI in carbonates. The model includes geochemical reactions, homogeneous (aqueous) and heterogeneous (precipitation/dissolution and ionic exchange reactions), as well as the resulting wettability alteration in carbonates. Oil recovery, pressure drop, pH, and effluent-ion were successfully history match and the results showed there is an improvement in oil displacement as EW is injected. Also, the findings of this study were supported by fractional flow analysis. This work provides more insight into the benefits of EWI and hence, supports new field applications.",23,23,1
Oil Recovery,Low Salinity,"Mohamed, Abdelhalim I. A.; Hussein, Ibnelwaleed A.; Sultan, Abdullah S.; Al-Muntasheri, Ghaithan A.",Use of organoclay as a stabilizer for water-in-oil emulsions under high-temperature high-salinity conditions,W/O emulsion; Pickering emulsion; Emulsion stability; Organoclay; High-temperature high-salinity; Chelating agent,INTERFACIAL-TENSIONS; NANOCOMPOSITES; SURFACTANT; FLOW,"Emulsified polymer gels are used in near wellbore applications for water shut-off treatment to control produced water in oil and gas reservoirs. The emulsified gels are expected to separate into oil and water phases at reservoir conditions. The stability of emulsified gels, as measured by the separation time, is influenced by the emulsifier type, salinity of the mixing water, and temperature. Although a range of commercial surfactants is used as emulsifiers, their toxicity and high cost are significant drawbacks. Nowadays, various nanomaterials have been developed for quite a few applications in different fields of endeavors, due to their low cost, availability, high surface area, and most prominently environmental-friendly. The proposed alternative organoclay (OC) has been shown to enhance emulsion stability with increasing OC concentration. The total separated volume reduced by a factor of 4.8, due to the decrease in the interfacial tension, when the OC (Cloisite 15A) concentration was increased from 600 to 1000 ppm. The stability of an emulsion prepared using a 6 vol% polyethylene glycol-2 ether (PEG-2E) enhanced by a factor of similar to 2 when the concentration of Cloisite 15A was increased from 300 to 1000 ppm. The separation time can be controlled by controlling the OC dose, depending on the application. A chelating agent can be used to reduce the effect of salts on emulsion stability. The OC materials have the potential to be used as cost-effective emulsifiers for PAM/PEI at high temperature (>100 degrees C) and high salinity (>200,000 ppm). The OC materials can be used as standalone emulsifiers or co-surfactants to enhance the performance of commercial emulsifiers.",21,22,5
Oil Recovery,Low Salinity,"Mwangi, Paulina; Brady, Patrick V.; Radonjic, Mileva; Thyne, Geoffrey",The effect of organic acids on wettability of sandstone and carbonate rocks,Wettability; Low salinity; Waterflooding; Organic acids,IMPROVED OIL-RECOVERY; LOW-SALINITY WATER; SPONTANEOUS IMBIBITION; MODEL COMPOUNDS; RESERVOIRS; MECHANISMS; CHALK; BASE; IONS,"This paper examines the role of crude oil's organic acid surface active compounds (SAC) in determining the reservoir wettability over a range of salinities and temperatures. To isolate the effects of individual SACs, this project used model oil mixtures of pure decane and single SACs to represent the oleic phase. Due to the large number of experiments in this study, we used wettability measurement method by the modified flotation technique (MFT) to produce fast, reliable, and quantitative results. The results showed that oil wetting by decane increased with temperature for carbonate rocks. Sandstones oil wetting showed little temperature dependency. The presence of long-chained acids in decane increased oil wetting in sandstone and carbonate rocks as salinity was lowered, while the short-chained acid increased water wetting under the same conditions. The effect of organic acids on wettability was slightly enhanced with increasing temperature for all rock types.",21,23,2
Oil Recovery,Low Salinity,"Dang, Cuong; Nghiem, Long; Nguyen, Ngoc; Yang, Chaodong; Chen, Zhangxin; Bae, Wisup",Modeling and optimization of alkaline-surfactant-polymer flooding and hybrid enhanced oil recovery processes,EOR; ASP flooding; Low salinity waterflooding; Optimization; Geological uncertainty,SALINITY; PERFORMANCE; PARAMETERS; RESERVOIR; TOOL,"This paper presents recent advances in the subject of modeling and optimization of ASP (Alkaline, Surfactant and Polymer) flooding. We used an approach that models the behavior of the surfactant-oil-water-microemulsion system based on solubility data. In Type III systems, the emulsion is distributed judiciously between the oil and water phases without the need to introduce a third liquid phase. This model captures the most important physical and chemical phenomena in the ASP process. The model is validated with numerous coreflooding experiments conducted by different research institutes as well as with a specialized chemical flood simulator. Agreements between the model and the experiments in terms of oil recovery and pressure drop were achieved for all core floods. In addition, the model is consistent with both UTCHEM-EQBATCH and UTCHEM-IPHREEQC. We investigated the potential of hybrid low salinity ASP flooding in which Low Salinity Waterflooding (LSW) was implemented in secondary production and followed by ASP flooding. This approach can provide a superior performance compared to the conventional chemical flooding because it provides better oil recovery in the secondary stage and promotes the synergy between a low salinity environment and ASP slugs. Finally, the proposed robust optimization workflow helps to increase a project NPV and significantly reduces the uncertainty range associated with geology.",20,21,3
Oil Recovery,Low Salinity,"Shabaninejad, Mehdi; Middlelton, Jill; Fogden, Andrew",Systematic pore-scale study of low salinity recovery from Berea sandstone analyzed by micro-CT,Low salinity water flooding; Spontaneous imbibition; Micro CT; Image analysis; Wettability,FINES MIGRATION; OIL-RECOVERY; SEGMENTATION,"The low salinity effect in clay-rich outcrop sandstones is probed by micro-CT imaging and analysis. A set of eight Berea sandstone mini-plugs underwent primary drainage and aging in crude oil to a mixed-wet state, followed by spontaneous imbibition of high and low salinity brines and imaging of this sequence of prepared starting and endpoint states. Tomogram registration and analysis were used to determine the salinity-induced changes in oil volume, oil/rock and oil/brine interfacial areas, and oil/brine interfacial mean curvature. Pore-scale statistics were extracted to explore any local correlation between the low salinity effect and pore geometry/topology. The qualitative observations and quantitative analyses demonstrated that the small oil recovery by the low salinity effect corresponded to a slight shift towards water-wet.",20,20,1
Oil Recovery,Low Salinity,"Wang, Zhihao; Wu, Yuanpeng; Luo, Pingya; Tian, Yingpei; Lin, Yuanhua; Guo, Qipeng",Poly (sodium p-styrene sulfonate) modified Fe3O4 nanoparticles as effective additives in water-based drilling fluids,Water-based drilling fluids; Fe3O4 nanoparticles; Poly (sodium p-styrene sulfonate); Rheology; Fluid loss,CONTROLLING FILTRATION PROPERTIES; RHEOLOGICAL PROPERTIES; BENTONITE SUSPENSIONS; HIGH-TEMPERATURES; HIGH-PRESSURE; LOSS AGENT; BEHAVIOR; PERFORMANCE; SHALE; STABILIZATION,"In this work, a series of low solid phase, economic and excellent performance water-based drilling fluids (WBDFs) were obtained by introducing nanoparticles into conventional WBDFs. Fe3O4 nanoparticles which were surface modified by poly (sodium p-styrene sulfonate) (PSSS) through 3-(trimethoxysilyl) proryl methacrylate (TMSPMA) were adopted in low solid WBDFs containing 4 wt % bentonite (BT). The effect of temperature on rheological property and fluid filtration was investigated. When the concentration of Fe3O4/PSSS nanoparticles reached 0.1 wt %, shear thinning of WBDFs will be perfect at different temperatures. When the concentration of Fe3O4/PSSS nanoparticles reached 0.25 wt %, the WBDFs had superior rheological properties, as compared to other concentrations of the particles in salt environment. Rheological curves provide a closely fit for the Bingham model at low temperature, however, the curves fit Herschel-Bulkley model at higher temperature. Rheological tests indicated that higher concentration of Fe3O4/PSSS nanoparticles can effectively improve salt (KCl) tolerance. Under high temperature and high press (HTHP) filtration test, WBDFs with Fe3O4/PSSS nanoparticles exhibited minimum filtration loss volume with the concentration of Fe3O4/PSSS nanoparticles as low as 0.1 wt % at different temperatures. For salt tolerance test, the higher concentration of the Fe3O4/PSSS nanoparticles leads to the lower the amount of fluid loss at the same concentration of KCl. With the concentration of nanoparticles grows to 0.1 wt %, the amount of fluid loss volume was minimum, indicating that Fe3O4/PSSS nanoparticles in WBDFs improve the filtration. The WBDFs with performance improved by Fe3O4/PSSS nanoparticles can be used as effective drilling fluids even under high temperature and high salinity, demonstrating that the modified fluids are potential candidates for drilling in deep and salty formation.",19,20,8
Oil Recovery,Low Salinity,"Brattekas, B.; Seright, R. S.",Implications for improved polymer gel conformance control during low-salinity chase-floods in fractured carbonates,Polymer gel; Low-salinity chase-flooding; Improved blocking capacity; Fractured carbonates; Influence of oil; PET imaging,PREFORMED-PARTICLE-GEL; PERFORMANCE; PLACEMENT; FLOW,"Polymer gel is often used to reduce flow through highly conductive fracture networks, frequently present in naturally fractured carbonate reservoirs. When in place, polymer gel efficiently reduces fracture flow and may improve sweep efficiency and oil recovery during water chase-floods. Polymer gel treatments have in some cases been less efficient than expected in reducing fracture conductivity. This may occur because the polymer gel only partially fills the fracture volume, and allows fracture channeling of injected fluids. Low-salinity waterfloods may improve polymer gel blocking of fractures and remedy less efficient polymer gel treatments. Previous experimental work has shown that low-salinity waterfloods, where the salinity is reduced with respect to the gel solvent, reduces fracture channeling and restores matrix flow. This work further investigates low-salinity waterflooding as a method to improve conformance during polymer gel treatments in fractured, low permeable, carbonate rock. The low flow capacity of carbonate may cause a less efficient gel blocking of fractures, although the gel behaves according to established models during injection. Low-permeable carbonate core plugs with open, highly conductive fractures were used for this study. Water flow paths during high-salinity and low-salinity waterflooding were evaluated by positron emission tomography (PET). We found that gel blocking efficiency during chase waterfloods depends on: 1) the salinity of the chase water. Gel blocking efficiency increases with low-salinity water throughput; opposite to high-salinity waterfloods, where the gel blocking is reduced with water throughput. 2) The core material. As expected, a higher pressure was required to maintain flow through the matrix during water chase-floods in low-permeable carbonates. Water was diverted into the matrix for all ranges of permeability: sandstone and low-permeable carbonates, during low-salinity waterfloods. 3) The presence of oil. Fracture channeling prevailed during low-salinity waterfloods in chalk cores with residual oil present.",19,19,2
Oil Recovery,Low Salinity,"Saikia, Bikash D.; Mahadevan, Jagannathan; Rao, Dandina N.",Exploring mechanisms for wettability alteration in low-salinity waterfloods in carbonate rocks,Wettability; Isoelectric point; Low-salinity; Carbonates; Contact angle; Zeta potential,OIL-RECOVERY,"Low Salinity waterfloods, even in carbonates, have received a great deal of attention because of their potential to significantly increase waterflood recoveries in addition to being cost effective. Wettability alteration has been found to play a major role in affecting higher recoveries from carbonates in low salinity floods. A large volume of research has accumulated for determining the effect of brine chemistry on wettability alteration and consequent recoveries. Both divalent cations (Ca2+, Mg2+) and anions (SO42-) as well as their interactions have been found to affect wettability. Charges on the mineral surface were also linked to observed wettability change. Despite the efforts, a clear understanding of the mechanisms for such wettability changes seems to be still elusive. Here in our work, first we have attempted to find viable alternatives for sulfates which pose fouling risks for reservoirs. Sulfur oxyanions such as bisulfites and metabisulfites have been found to be potential anions capable of affecting the desired wettability change without the risk associated with sulfates. Secondly, an effort has been made to understand the mechanism (s) behind such wettability alteration in carbonates during low salinity waterfloods based on our work and that by various authors. A potential mechanism has been proposed for wettability alteration, which seems to explain the works of many researchers. The mechanism is based on the isoelectric point of the carbonate rock surface, pH and interfacial energy between the aqueous brine solution and the rock surface. It is proposed that carbonates would be strongly oil-wet at the isoelectric point of the carbonate rock crystal, when the aqueous solution-rock interfacial tension is maximum. On the other hand, it would exhibit more water-wet or less oil-wet behavior, the further the pH of the brine solution is away from the isoelectric point of the carbonate rock. The wettability change is as a result of electrostatic attraction between polar water molecules with the charged surface that helps to bring down the brine-rock interfacial energy. This minimization of interfacial energy is manifested as the wettability change at the 3- phase carbonate mineral-oil-water contact line. The shift in the isoelectric point due to changes imposed in brine composition needs to be accounted for in addition to brine pH and salinity in order to optimize recoveries from low-salinity waterfloods.",18,18,0
Oil Recovery,Low Salinity,"Song, Zhaojie; Hou, Jirui; Liu, Xiaochun; Wei, Qi; Hao, Hongda; Zhang, Liya",Conformance control for CO2-EOR in naturally fractured low permeability oil reservoirs,CO2 flooding; Low permeability oil reservoir; Gas channeling; CO2 production control,CARBON-DIOXIDE; CO2 STORAGE; TIGHT OIL; RECOVERY; GAS; PERFORMANCE; IMPROVEMENT,"Poor sweep efficiency seriously limits field applications of CO2-EOR, especially in fractured reservoirs. The investigation of CO2 production performance and the method to control CO2 production becomes a key to successfully run a CO2-EOR project. In this study, artificial sandstone cores were used to perform a series of CO2 flooding experiments at reservoir conditions of pressure, temperature and formation water salinity. Injection pressure and rock heterogeneity were taken into account to study their effect on CO2 production performance. Two-stage gas channeling control with three different scenarios, including PLS gel and ethylenediamine, starch gel and ethylenediamine, and starch gel and CO2 foam, was presented to improve the conformance in 3-D fractured-core models. Based on production performance and experimental observation, three production stages were clearly stated, including gas-free production stage, oil/gas co-production stage, and gas channeling stage. Oil/ gas co-production stage contributed the most to oil recovery. This finding was very consistent with the practical production performance of CO2 flooding in oil fields. The conformance improvement and the increase in injection pressure (within permissible range bearing in mind of fracturing pressure) could remarkably enhance the oil recovery at oil/gas co-production stage. In 3-D radial flow experiments, the two-stage gas channeling control presented great potential in delaying gas production and improving CO2 flooding efficiency. The combination of starch gel and ethylenediamine achieved the best result. The starch gel could effectively block the fracture, while the viscous reactant of ethylenediamine and in-situ CO2 within high permeability layer could successfully tune injected CO2 to flood low permeability layer. This study could help field engineers determine the optimal timing of CO2 production control, and also offered an optimal method to improve the conformance for CO2-EOR.",17,17,8
Oil Recovery,Low Salinity,"Aghaeifar, Zahra; Strand, Skule; Puntervold, Tina; Austad, Tor; Sajjad, Farasdaq Muchibbus",Smart Water injection strategies for optimized EOR in a high temperature offshore oil reservoir,,CRUDE-OIL; SALINITY; RECOVERY; WETTABILITY; ADSORPTION; KAOLINITE,"Smart Water injection is an EOR technique that is both environmentally friendly and easily implementable to a fractional cost compared to other water-based EOR methods. EOR by Smart Water is a wettability alteration process towards more water-wet conditions, which induces increased positive capillary forces and increased microscopic sweep efficiency. The objective of this work was to evaluate the injection strategy for Smart Water in an offshore high temperature sandstone reservoir, and compare the efficiency of seawater-based injection brines with low salinity brines, which can behave as Smart Water in sandstone reservoirs. Oil recovery experiments have been performed at reservoir conditions using preserved reservoir cores and reservoir fluids. Secondary low salinity injection gave an average of 33.5 %OOIP extra oil produced, compared to modified seawater injection. The tertiary low salinity EOR effect after modified seawater flooding gave an average of 11.8 %OOIP extra oil. Significant changes in produced water pH from initially acidic to alkaline conditions during low salinity injection were observed, favoring wettability alteration towards more water-wet conditions. The results confirmed that low salinity brine behaved as a Smart Water, contributing with significant extra oil recovery in a high temperature sandstone reservoir. Introducing Smart Water from day one in a reservoir, i.e. in secondary recovery mode, is significantly more efficient, regarding both response time and ultimate oil recovery, than tertiary mode Smart Water injection.",16,16,1
Oil Recovery,Low Salinity,"Silva, Ivonete P. G.; Aguiar, Amaury A.; Rezende, Viviane P.; Monsores, Andre L. M.; Lucas, Elizabete F.",A polymer flooding mechanism for mature oil fields: Laboratory measurements and field results interpretation,Enhanced oil recovery; Polymer flooding; Mobility; Rheology; Particle size,LIGHT-SCATTERING; MOLECULAR-WEIGHT; POLYACRYLAMIDE; FLOW; DEPENDENCE; RECOVERY; POLYELECTROLYTE; TEMPERATURE; COPOLYMERS; RETENTION,"Although polymer flooding has been widely studied in the literature on oil recovery, many questions remain about the technique's action mechanisms. It is widely accepted that the process is based on increasing viscosity of the aqueous phase (injected fluid). The polymer can also act secondarily by reducing the relative permeability to water. Fields that are markedly heterogeneous, highly depleted or that contain fluids with strong salinity are not good candidates for the process. To overcome these restrictions, the most recent applications have used more resistant polymers, with higher molar masses, injected in larger quantities, to preserve the level of viscosity under these adverse conditions. However, a pilot test in a field under adverse conditions showed surprising results and unexpected pressure abnormality, even with small quantities of partially hydrolyzed polyacrylamide (HPAM) with relatively low molar mass (6 x 10(6) g/mol). This paper reports the investigation of the prevailing mechanism responsible for these unexpected results, by means of laboratory tests of flow in porous media and rheological analysis of fluids and hydrodynamic diameter of polymer molecules. The Salt effect (NaCl) on polymer solutions was researched by rheology and particle size analysis at 25 and 50 degrees C. The results showed that mechanical/hydrodynamic retention prevails over polymer adsorption at the rock, with the former being caused by the increase in the polymeric hydrodynamic volume in fluid dilution processes. Besides this, increased temperature was found to favor greater hydrodynamic volume under tested conditions, while salinity had little influence. The results also shed new light on the flow behavior of polymer solutions in porous media, particularly in polymer injection for enhanced oil recovery from mature fields.",15,15,3
Oil Recovery,Low Salinity,"Chandrasekhar, Sriram; Mohanty, Kishore K.",Effect of brine composition on oil-rock interaction by atomic force microscopy,Adhesion force; Low salinity brine; Calcite surface charge; Wettability alteration; Atomic force microscopy,SELF-ASSEMBLED MONOLAYERS; WETTABILITY ALTERATION; CALCITE SURFACE; CRUDE-OIL; SALINITY; IONS; DISSOLUTION; RECOVERY; SULFATE; MODEL,"Wettability alteration is known to occur in low salinity waterflooding of carbonate rocks. Oil droplets are thought to detach from the rock partially due to changes of the solid surface charge by multi-ion exchange with the brine. These mechanisms have been investigated in the past by measuring zeta potentials of calcite and oil, separately in test brines. In this work, the coupled calcite-brine-oil system was studied by measuring the adhesion force of an organic acid functionalized solid probe with a calcite surface, using an atomic force microscope. Brine compositions were varied in pH and ion concentration, to identify key conditions for minimum oil adhesion to calcite. Our experiments showed the strongest acid-calcite adhesion in formation brine. The adhesion force decreased in decreasing ionic strength NaCl brines, particularly below similar to 0.1 mol/L where the diffuse double layer expanded greatly. The complex composition brines of ultra-dilute seawater and excess sulfate seawater each gave the lowest adhesion due to a combination of double layer expansion, surface charge change and gypsum passivation of the calcite surface. Modifying seawater's Ca2+ and Mg2+ concentrations showed little change in the adhesion force despite being potential determining ions for calcite. Adhesion force responded the most to pH change. Increasing pH substantially decreased the adhesion force in seawater and excess sulfate seawater until a threshold value of pH 10. Above pH 10, the adhesion increased due to brine instability (to mineral precipitation) and material precipitation onto the calcite surface.",15,15,1
Oil Recovery,Low Salinity,"Boujelben, Ahmed; McDougall, Steven; Watson, Michael; Bondino, Igor; Agenet, Nicolas",Pore network modelling of low salinity water injection under unsteady-state flow conditions,Pore network modelling; Low salinity; Secondary water injection; Tertiary water injection; Unsteady-state flow; Contact angle modification,OIL-RECOVERY; WETTABILITY ALTERATION; BRINE COMPOSITION; POROUS-MEDIA,"In this work, we describe a dynamic pore network model that has been developed to investigate the effects of low salinity (LS) water injection on oil recovery under dynamic flow conditions. For the first time, we introduce a formulation whereby the evolving spatial distribution of brine salinity is explicitly tracked during unsteady-state secondary and tertiary LS floods. Phases are updated in capillary elements according to the relative balance between capillary and viscous forces, the former being correlated to salinity through a functional relationship between effective contact angle (i.e. wettability) and local brine concentration. We have investigated the impact of several key parameters on secondary and tertiary LS injection, including: injection rate, viscosity ratio, and salinity-induced wettability modifications. We have implemented a stochastic approach throughout in order to assess statistical variability in recovery outcomes. For the particular network architecture studied, simulations have shown a range of results for different induced wettability changes. When the contact angle variation shifted the system from strongly oil-wet to weakly oil-wet, most cases exhibited a small positive secondary LS effect but negligible tertiary benefit. Greater variation in LS outcome was observed when LS brine modified pores to close to neutral-wet conditions - a generally positive secondary LS effect was seen but there were several exceptions dependent upon frontal advance rate and viscosity ratio, where the displacement regime could switch from capillary-dominated flow to viscous fingering. Salinity modification of wettability to a water-wet configuration resulted in positive secondary LS displacement and a positive tertiary LS effect. The study shows that the impact of LS injection can often be difficult to predict a priori for any given combination of rock/fluid parameters and laboratory protocol, due to the complex way in which the underlying parameters interact. When compared against high salinity (HS) data, both positive and negative LS effects have been observed depending upon the prevailing system properties and the timing of LS initiation. However, by running a series of network modelling simulations, we are able to identify areas of parameter space that are more likely to elicit a positive LS response. In particular, we observe that a change in the dominant flow regime (capillary fingering, viscous fingering, frontal advance) may be induced by the injection of LS brine and this has been found to play an important role in determining LS efficacy.",14,14,2
Oil Recovery,Low Salinity,"Torrijos, Ivan D. Pinerez; Puntervold, Tina; Strand, Skule; Austad, Tor; Bleivik, Tord H.; Abdullah, Hakar I.",An experimental study of the low salinity Smart Water - Polymer hybrid EOR effect in sandstone material,,OIL-RECOVERY; BRINE COMPOSITION; WETTABILITY; TEMPERATURE; RESERVOIRS; ADSORPTION,"Previously reported experimental work has shown positive oil recovery effects by combining low salinity brine with polymer for injection into sandstone cores. The extra oil recovered by the combination of the two EOR methods was termed a ""Hybrid EOR effect"". The experimental work performed in the present study assessed the potential of combining low salinity (LS) Smart Water injection with polymer (P) flooding; LSP flooding. Dramatic improvements in the EOR effect were observed when combining LS in secondary mode with polymer injection in tertiary mode. Secondary LS injection gave 59 % OOIP after 1 PV injected, which is an outstanding result compared to secondary formation water (FW) injection reaching only 35 % OOIP after 1 PV, and an ultimate recovery of 40 % OOIP after 2.5 PV. The ultimate recovery with seawater (SW) in secondary mode was 44% OOIP, showing only a slightly better performance than FW, but poorer efficiency than the ultimate LS brine recovery of 64 % OOIP. In comparison, the ultimate recovery with secondary LSP injection was 66 % OOIP. The displacement front was stable and fast, but it did not give a substantial increase in oil recovery in comparison to the secondary LS injection. Tertiary LSP injection after secondary LS injection gave the highest oil recoveries with a total hybrid EOR effect of 86 % OOIP. All tertiary LSP floods gave improved displacement stability with EOR effects of similar to 20 % OOIP. The positive EOR effects are a result of redistribution of oil within the pore space after wettability alteration with the Smart Water. Oil attached to the mineral surface has low mobility, but at more water-wet conditions a new fraction of mobile oil, which is more easily mobilized with a polymer solution, is created (Wang et al., 2001). The combination of Smart Water with polymer flooding appears to have a huge potential for future EOR applications. Field development strategies for new sandstone reservoirs should include wettability alteration and redistribution of oil within the pores by Smart Water and improved displacement efficiency with polymer for optimized EOR to lowest cost.",14,14,0
Oil Recovery,Degrees C,"Sharma, Himanshu; Mohanty, Kishore K.",An experimental and modeling study to investigate brine-rock interactions during low salinity water flooding in carbonates,Low salinity; Wettability alteration; Brine-rock interactions; IPHREEQC; Carbonates; Mechanistic model; Surface complexation,WETTABILITY ALTERATION; OIL-RECOVERY; CHALK,"Injection of brines with carefully designed ionic compositions into oil-wet carbonate rocks at high temperatures has shown to alter their wettability towards a water-wet state and improve oil recovery. Various mechanisms have been postulated for this wettability alteration such as mineral dissolution and interaction of potential determining ions, such as Ca2+, Mg2+ and SO42-, with the carbonate surface. In this study, experimental and modeling work was performed to gain further insights into the geochemical interactions between carbonate rocks and modified brines. Single-phase static (equilibrium) and transport experiments were performed with various brines in limestone cores at 120 degrees C. The ionic compositions of the effluent samples were monitored using ion chromatography. A mechanistic model for the wettability alteration process was developed in UTCHEM-IPHREEQC based on key geochemical interactions. The calcite surface was assumed to consist of positive and negative sites and their interactions with potential determining ions were considered assuming local equilibrium. The model assumed the degree of oil-wetness to depend on the amount of organic acid attached on the surface, which in-turn was dependent on the geochemistry of the system. Results of static experiments performed with crushed limestones and brines showed an increase in calcium concentration and a decrease in magnesium concentration in the supernatant brines. The effluent concentrations from single-phase brine corefloods in limestone cores showed an increase in calcium concentration, a decrease in magnesium concentration and a delay in sulfate concentration. Three key geochemical interactions were identified based on these results: mineral dissolution, surface dolomitization and sulfate adsorption. A good qualitative agreement was observed between single-phase experiments and simulations, suggesting that the model was able to accurately capture the geochemistry. The simulation results showed good agreement with zeta potential and oil recovery results reported in the literature.",55,57,3
Oil Recovery,Degrees C,"Da, Chang; Alzobaidi, Shehab; Jian, Guoqing; Zhang, Leilei; Biswal, Sibani L.; Hirasaki, George J.; Johnston, Keith P.",Carbon dioxide/water foams stabilized with a zwitterionic surfactant at temperatures up to 150 degrees C in high salinity brine,CO2-in-water foam; Zwitterionic surfactant; Porous media; EOR,ENHANCED OIL-RECOVERY; WORMLIKE MICELLES; CONCENTRATED EMULSIONS; SUPERCRITICAL FLUIDS; MOBILITY CONTROL; MIXED-SOLUTIONS; AQUEOUS-PHASE; POROUS-MEDIA; YIELD-STRESS; ADSORPTION,"Stabilization of CO2-in-water (C/W) foams with surfactants at high temperature and high salinity conditions is challenging given limitations in the solubility and thermal stability of surfactants, particularly for surfactants other than anionic ones. Here we show that a single zwitterionic surfactant, cetyl betaine (CH3(CH2)(15)N+(CH3)(2)CH2COO-), stabilizes viscous C/W foam (> 15 cP) in crushed limestone (76-Darcy) at a temperature up to 150 degrees C and over a wide range in salinity up to 22% total dissolved solids (TDS) at superficial velocity of 940 ft/day. According to liquid chromatography mass spectrometry (LC/MS), cetyl betaine has high thermal stability with negligible chemical degradation after incubation at 135 degrees C for 30 days. Interfacial tension (IFT) at the C/W interface was reduced significantly from similar to 37 mN/m to < 5 mN/m with the addition of 0.08 mmol/L of cetyl betaine. Relative to ionic surfactants, the relatively weak electrostatic repulsion between the local charges in the headgroup is shown to produce strong adsorption at the C/W interface (similar to 134 angstrom(2)/molecule), resulting in generation of viscous foam (similar to 6 cP) even in pure water without added salt. At a low superficial velocity of 6 ft/day (shear rate 45 s(-1)) in a beadpack, foam was still formed with cetyl betaine. Static adsorption of cetyl betaine on carbonates was on the order of 1 mg/m(2), and core flood test also proved that cetyl betaine could stabilize viscous C/W foam (> 20 cP) within 6 pore volumes of injection at 120 degrees C. The surfactant stabilized viscous C/W foam at low oil fractions and broke in the presence of large fractions of oil, both of which are desirable in CO2 mobility control and oil displacement. The ability to form foams at high temperatures and over a wide range in salinity is important for various practical applications including CO2 enhanced oil recovery, fracturing with energized fluids and CO2 sequestration.",46,48,19
Oil Recovery,Degrees C,"Liu, Chuhan; Zhang, Yin; Sun, Shanshan; Huang, Lixin; Yu, Li; Liu, Xiaonan; Lai, Ruiqiu; Luo, Yijing; Zhang, Zhiyong; Zhang, Zhongzhi",Oil recovery from tank bottom sludge using rhamnolipids,Oil sludge; Oil recovery; Pseudomonas aeruginosa; Biosurfactant,CRUDE-OIL; CONTAMINATED SOIL; PETROLEUM; DEMULSIFICATION; BIOSURFACTANTS; PSEUDOMONAS; PYROLYSIS; EMULSIONS,"Oil sludge has become a major impediment to the development of the petroleum and petrochemical industries with the growth of oil production worldwide. In this research, rhamnolipid biosurfactant produced by Pseudomonas aeruginosa was used to recover oil from oil tank bottom sludge. The optimum value of the fermentation broth (with rhamnolipid biosurfactant concentration of 5.4 g/L) addition was a volume fraction of 2% (v/v). Optimal temperature (65 degrees C), liquid/solid ratio (3:1), washing time (3 h), and agitation intensity (300 rpm) for oil recovery were determined. Wastewater from oil recovery was flocculated with 400 mg/L polyaluminum chloride for reuse. The moisture of the recovered oil was (0.42 +/- 0.12) %, which could directly enter into the refinery process. The solid particles in the oil sludge exhibited a porous structure that adsorbed a significant amount of oil and increased the difficulty of oil recovery. Results showed that the fermentation broth of P. aeruginosa can be used to recover oil from oil sludge and has potential industrial applications.",34,38,5
Oil Recovery,Degrees C,"Patel, Harshkumar; Shah, Subhash; Ahmed, Ramadan; Ucan, Sezai",Effects of nanoparticles and temperature on heavy oil viscosity,Heavy oil; Nanoparticles; Rheology; Viscosity reduction; Oil recovery; Optimum concentration,RECOVERY; AQUATHERMOLYSIS,"The objective of this research is to investigate the efficacy of nanoparticles in reducing the viscosity of heavy oil. In this study, three types of metal oxide nanoparticles (CuO, Fe2O3, and NiO) are employed, and their effect on heavy oil viscosity is examined at three different concentrations (0.05, 0.1, and 0.5 wt.% of oil). For all test fluids, rheological measurements were obtained at four different temperatures ranging from 27 to 71 degrees C. The experimental work is conducted with two extremely viscous heavy oil samples having viscosity of approximately 77 and 350 Pas at ambient temperature. This study is unprecedented in terms of viscosity of heavy oil samples investigated. The heavy oil samples used in this study are 9-40 times more viscous than those used in previous similar studies. The addition of nanoparticles resulted in a notable reduction in viscosity of both heavy oil samples. For each type of nanoparticles, 50-70% viscosity reduction was observed. The level of viscosity reduction is sensitive to the types of nanoparticles, their concentration, and fluid temperature. Moreover, the results indicate existence of an optimum concentration of nanoparticles at which maximum viscosity reduction occurs. This optimum concentration is a function of the metal type and fluid temperature. To explain observed viscosity alteration behavior, the paper provides a theoretical overview of various molecular-level physical and chemical interactions between nanoparticles and heavy oil. Additionally, the study presents a new heavy oil viscosity data and delineates some of the challenges associated with viscosity measurement of heavy oil. This research provides valuable information for future rheological and core-flooding studies involving nanoparticle stabilized solvent-based emulsions. Besides, remarkable viscosity reduction obtained in this work reinforces the industry's interest in developing an economically feasible nanoparticle-based technique and helps to solve real problems in the field.",30,31,10
Oil Recovery,Degrees C,"Goswami, Rishiraj; Chaturvedi, Krishna Raghav; Kumar, Ravi Shankar; Chon, Bo Hyun; Sharma, Tushar",Effect of ionic strength on crude emulsification and EOR potential of micellar flood for oil recovery applications in high saline environment,Crude oil; Emulsion; Micellar flood; Rheology; SDS; Salt,NANOPARTICLE-SURFACTANT-POLYMER; IN-WATER EMULSIONS; INTERFACIAL-TENSION; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; HIGH-TEMPERATURE; SYSTEM; BEHAVIOR; CALCIUM; STABILITY,"Micellar flooding is one of the chemical oil recovery techniques in which micelle action emulsifies the crude oil to be mobilized in form of emulsion from a subsurface porous media. However, the subsurface conditions such as high ionic strength and temperature are challenges to the successful use of micellar flood owing to the deterioration of micelle action suggesting no crude emulsification. The ionic compounds dissociate into different ions that may further affect micelle action via loss in viscosity and pressure drop, increased water cut, and mobility contrast between micellar flood and displaced oil. Thus, investigation leading to the successful use of micellar flood, context to crude emulsion, in extreme salinity and temperature is vital to extend the use of chemical methods in new reservoirs. In this work, a typical surfactant sodium dodecyl sulfate (SDS) solution with critical micelle concentration (0.8 wt%) was tested to emulsify a fresh crude oil in the presence of varying ionic strength (0-4 wt%, NaCl/CaCl2 and temperature (40-98 degrees C). The efficacy of SDS micelles to produce crude emulsion significantly reduced with increasing salt concentration as reported through microscopic, rheological, and flooding experiments, particularly for divalent salt (CaCl2) than monovalent salt (NaCl). The increase in temperature (> 40 degrees C) further curtailed the growth of crude emulsion, mainly due to enhanced droplet coalescence; thus the use of micellar flood is critical in a reservoir enriched with high salinity and high temperature. Salinity effect on emulsion viscosity is reported through rheological measurements. The study highlighted important aspects of surfactant flooding and is a forward step towards the use of SDS based micellar flood at complex reservoir conditions.",29,28,1
Oil Recovery,Degrees C,"Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Yuan, Chengdong; Zhang, Jizhou; Han, Xiaoqiang; Yang, Yang; Peng, Xiaoqiang; Wu, Junxue",Comprehensive investigations into low temperature oxidation of heavy crude oil,Low temperature oxidation; Heavy crude oil; Thermal behavior; Kinetics; Coke; Oxidized oil,IN-SITU-COMBUSTION; AIR INJECTION; SARA FRACTIONS; KINETICS; RECOVERY; LIGHT; BEHAVIOR; RESERVOIRS; PYROLYSIS; TGA/DSC,"Due to the significance of low temperature oxidation (LTO) process on the subsequent oxidation reactions and oil recovery for in situ combustion (ISC), this work aimed at conducting a series of comprehensive investigations into LTO of heavy crude oil. The LTO behavior of heavy oil was analyzed by static oxidation experiments. Then the alterations in oil characteristics due to LTO were investigated through coke content measurements, flammability tests and scanning electron microscopic (SEM) observations. Additionally, the effect of LTO on thermal behavior and kinetics of heavy oil was researched using thermogravimetry (TG)/differential scanning calorimetry (DSC) technique. The results showed that the temperature played a crucial role in LTO of heavy oil. Almost no coke was deposited at 80 degrees C. The amount of coke deposition at 160 degrees C averaged 0.346 g coke/g oil, which was roughly 4.2 times higher than that at 120 degrees C. The oxidized oil at 160 degrees C possessed the most superior flammability at ambient temperature and atmospheric pressure in comparison to that at 80 and 120 degrees C. The surface morphologies of oxidized oil at 160 degrees C and its formed coke were quite rough, which boosted the subsequent combustion reactions. The results of TG/DSC unravelled that the oxidized oils were subjected to higher mass loss and exothermic effect at the fuel deposition (FD) and high temperature oxidation (HTO) stages as compared to crude oil. After the static LTO, the activation energy in the LTO and FD stages for heavy oil was increased, while that in the HTO stage was reduced. Compared with crude oil and oxidized oils, the coke deposited during the static LTO presented the highest thermal release and reaction activity in the HTO interval. This paper can provide some new insights regarding LTO mechanisms of heavy oil to rich the ISC technology.",27,32,1
Oil Recovery,Degrees C,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Li, Xiangfang; Li, Qian; Yang, Jian; Wu, Jiqiang",A coupled model for CO2 & superheated steam flow in full-length concentric dual-tube horizontal wells to predict the thermophysical properties of CO2 & superheated steam mixture considering condensation,Heavy oil recovery; Concentric dual-tube wells; Multi-point injection technique; CO2 coupled with superheated steam; Wellbore hydraulics,HEAT-TRANSFER CHARACTERISTICS; MASS-TRANSFER CHARACTERISTICS; MULTICOMPONENT THERMAL FLUID; 2-PHASE FLOW; NONCONDENSING GASES; NONISOTHERMAL FLOW; SUPERCRITICAL CO2; CURVE ANALYSIS; OIL-RECOVERY; INJECTION,"The mixture of CO2 and superheated steam (SHS) has been proved effective for heavy oil recovery by field practices. It has been proved that the development effect is closely related to the state parameters (temperature, pressure and superheated degree etc.) of the mixture. As a result, wellbore modeling is an important branch in the study of thermal recovery of heavy oil. In recent years, concentric dual-tube wells (CDTW) coupled with multi-point injection technique (MPIT) is proposed to overcome the fingering phenomenon, induced by serious reservoir heterogeneity, during the steam injection process. In this paper, a wellbore model is developed for simulating CO2 & SHS flow in a full-length CDTW. The model is solved with finite difference method on space. It is found that: (a) An injection pressure, higher than 4.1 MPa, in the integral joint tube (IJT) or an injection pressure, smaller than 4.1 MPa, in annuli are recommended to obtain a uniform steam absorption rate along the horizontal wellbores. (b) The mass injection rate at well-head condition should be close to each other to avoid un-uniform of steam absorption rate along the horizontal wellbores. (c) When phase change occurs in the annuli, the mixture temperature increases with increasing CO2 content. (d) The total length of wet steam flow in the horizontal section of the wellbores increases with increasing CO2 content.",27,28,0
Oil Recovery,Degrees C,"Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Yuan, Chengdong; Pan, Jingjun; Wang, Ruyan; Chen, Long; Kan, Ni",Low-temperature oxidation of light and heavy oils via thermal analysis: Kinetic analysis and temperature zone division,Low-temperature oxidation; Light and heavy oils; Thermal analysis; Kinetic analysis; Temperature zone division,PRESSURE AIR INJECTION; CRUDE-OIL; THERMOGRAVIMETRIC ANALYSIS; COMBUSTION KINETICS; SARA FRACTIONS; PYROLYSIS; BEHAVIORS; RECOVERY; MODEL; DECOMPOSITION,"This research is intended to investigate low-temperature oxidation (LTO) behavior and kinetics of light and heavy oils and to divide their LTO intervals. Ramped thermogravimetry/derivative thermogravimetry (TG/DTG) and differential scanning calorimetry (DSC) experiments and isothermal TG experiments with different temperature intervals were used to characterize LTO behavior and to obtain kinetic parameters determined by Ozawa-Flynn-Wall (OFW) and general reaction rate models. The results indicated that there were three (two) distinct variation trends about the conversion rate versus temperature for light (heavy) oil in the LTO region, manifesting the LTO interval of light (heavy) oil should be controlled by multiple-step mechanisms and divided into at least three (two) reaction subintervals. The LTO interval of both light and heavy oils used could be subdivided into three temperature intervals inferred from the variation trend of activation energy over temperature for ramped experiments. Additionally, the LTO region of both light and heavy oils held three subzones in the aspect of isothermal tests. For light oil, the reaction rate augmented from 50 to 250 degrees C where the activation energy was positive, while it reduced from 250 to 350 degrees C coupled with negative activation energy. As for heavy oil, the reaction rate presented an increasing trend in the first and third subintervals (50-150 degrees C and 250 350 degrees C) with positive activation energy and a declining trend in the second subinterval (150 250 degrees C) with negative activation energy. It is believed that this research can add new insights to the LTO interval division of crude oil regarding to the isothermal and non-isothermal conditions, which are of significance for understanding LTO reaction pathways and mechanisms.",26,27,1
Oil Recovery,Degrees C,"Xie, Binqiang; Ting, Li; Zhang, Yan; Liu, Chen",Rheological properties of bentonite-free water-based drilling fluids with novel polymer viscosifier,Water-soluble polymers; Viscosifier; Thermo-thickening; Rheology; Bentonite-free drilling fluid,ACRYLAMIDE-BASED TERPOLYMER; ENHANCED OIL-RECOVERY; AQUEOUS-SOLUTION; GRAFT-COPOLYMERS; THERMOASSOCIATIVE COPOLYMERS; CELLULOSE NANOPARTICLES; FORMATION DAMAGE; PERFORMANCE; BEHAVIOR; ADDITIVES,"Water-based drilling fluids with no bentonite content was particularly advantageous in oil and natural gas exploration due to the excellent characteristics including faster rates of penetration, enhanced hole cleaning, less formation damage, etc. However, how to keep the excellent rheological regulation of bentonite-free drilling fluids was still one of the most serious issues for the mud designers. In this study, novel polymer viscosifier (SDKP) was prepared under optimal synthesis conditions through the copolymerization of N-vinylcaprolactam and sodium 2-acrylamido-2-methylpropane sulfonate. The effect of SDKP on rheological behavior of bentonite-free fluids was studied according to American Petroleum Institute standard. Results showed that SDKP could improve the rheological properties of bentonite-free fluids. In addition, the good thermal stability and salt stability in improving rheological behavior of fluids made SDKP more attractive. Rheological behavior of SDKP based bentonite-free fluids at different temperatures was also evaluated. Results showed that SDKP based bentonite-free fluids showed certain thermo-viscosifying behavior in the temperature range of 80-140 degrees C even in high salinity, which was benefit for carrying cuttings. Shear test showed that the magnitude of the thermo-thickening viscosity was very sensitive to shear rate, and SDKP containing fluids became better shear-thinning upon heating, which could be more easily pumped into the well. In addition, the mechanism of SDKP in improving rheological behavior of bentonite-free fluids was revealed based on the investigation of morphology of SDKP through Environmental Scanning Electron Microscopy experiment.",24,25,3
Oil Recovery,Degrees C,"Hanamertani, Alvinda Sri; Pilus, Rashidah M.; Manan, Ninie A.; Mutalib, M. Ibrahim A.",The use of ionic liquids as additive to stabilize surfactant foam for mobility control application,Surfactant; Foam additive; Ionic liquid; Foam stability; Foamscan,DEEP EUTECTIC SOLVENTS; ALKYL CHAIN-LENGTH; INTERFACIAL-TENSION; PHYSICOCHEMICAL PROPERTIES; PHASE-BEHAVIOR; OIL; IMIDAZOLIUM; FILMS; CHLORIDE; AGGREGATION,"Foam application has been introduced in enhanced oil recovery processes for mobility control to overcome some issues occurred during gas injection. The stability of foam has become the main concern as it dictates the effectiveness of foam mobility control. Many attempts at enhancing foam stability under reservoir conditions involve the application of chemical additives which can produce synergistic effect in combination with surfactant. Ionic liquids (ILs), salts melting below 100 degrees C, are considered to be able to alter surface behavior of surfactant molecules, hence supporting the surfactant performance at the interface. Their alteration is expected to be favorable in improving surface properties of foam. This research has introduced ionic liquid based additives for the first time to improve surfactant foam stability. Identification of the effect of ILs was performed by conducting bulk foam experiments at ambient conditions and also at high temperature using Foamscan. The foaming properties of in-house surfactant (MFOMAX) were evaluated in the absence and presence of ILs at different mixture ratios. The results show that imidazolium-and eutectic-based ILs were able to improve surfactant foam stability to different extent at high temperature and their effect on foam stabilization was more pronounced at surfactant/IL mixture ratio of 60:40. The highest foam stability increment exhibited by the best formulation reached 136% of that achieved by the formulation without IL. This study has indicated that ionic liquid has a promising potential for improving surfactant-stabilized foam mobility control during EOR processes.",24,24,3
Oil Recovery,Degrees C,"Lenji, Majid Abedi; Haghshenasfard, Masoud; Sefti, Mohsen Vafaie; Salehi, Mahsa Baghban; Heidari, Aghdas",Experimental study of swelling and rheological behavior of preformed particle gel used in water shutoff treatment,Preformed particle gel; Swelling ratio; PPG strength; Core flooding; Water cut reduction,ENHANCED OIL-RECOVERY; CONFORMANCE CONTROL; NUMERICAL-SIMULATION; PHENOLIC RESIN; HYDROGELS; POLYMER; POLYACRYLAMIDE; PERMEABILITY; PH; TRANSPORT,"Production of water effluents in mature reservoirs subjected to water flooding face many difficulties that might, ultimately, lead to their abandonment. Gel shutoff treatment of such reservoirs using preformed particle gel (PPG) is a technique used to block fracture channels and to insulate highly permeable zones. The technique not only reduces water production but leads also to successful conformance control. The present study introduces a novel type of PPG with an extremely high swelling ratio. The PPG is made up of polyacrylamide and Aluminum nitrate nanohydrate, which acts like a superabsorbent to absorb water equivalent in weight to 1000-2000 times the dry weight of the gel. Tests were conducted in the present experiment to investigate the effects of polymer and crosslinker concentrations, temperature, salinity, and pH on the swelling of PPG. Results showed that increasing polymer and crosslinker concentrations as well as enhanced salinity led to declining PPG swelling ratio. While PPG swelling ratio was not considerable outside the pH range of 5-9, its rate within this range was relatively high. Moreover, PPG swelling ratio increased only slightly with increasing temperature by up to 100 degrees C, beyond which the 3D network structure of PPG collapsed. Rheological tests were performed to determine PPG strength in three samples selected based on least salt sensitivity factor values. In addition, the core flooding test was performed to evaluate the blocking efficiency and the performance of the three samples in reducing water production in sandpacks. The test results revealed that PPG reduced water effluents in the sandpack by 30%-65%.",22,22,3
Oil Recovery,Degrees C,"Mohamed, Abdelhalim I. A.; Hussein, Ibnelwaleed A.; Sultan, Abdullah S.; Al-Muntasheri, Ghaithan A.",Use of organoclay as a stabilizer for water-in-oil emulsions under high-temperature high-salinity conditions,W/O emulsion; Pickering emulsion; Emulsion stability; Organoclay; High-temperature high-salinity; Chelating agent,INTERFACIAL-TENSIONS; NANOCOMPOSITES; SURFACTANT; FLOW,"Emulsified polymer gels are used in near wellbore applications for water shut-off treatment to control produced water in oil and gas reservoirs. The emulsified gels are expected to separate into oil and water phases at reservoir conditions. The stability of emulsified gels, as measured by the separation time, is influenced by the emulsifier type, salinity of the mixing water, and temperature. Although a range of commercial surfactants is used as emulsifiers, their toxicity and high cost are significant drawbacks. Nowadays, various nanomaterials have been developed for quite a few applications in different fields of endeavors, due to their low cost, availability, high surface area, and most prominently environmental-friendly. The proposed alternative organoclay (OC) has been shown to enhance emulsion stability with increasing OC concentration. The total separated volume reduced by a factor of 4.8, due to the decrease in the interfacial tension, when the OC (Cloisite 15A) concentration was increased from 600 to 1000 ppm. The stability of an emulsion prepared using a 6 vol% polyethylene glycol-2 ether (PEG-2E) enhanced by a factor of similar to 2 when the concentration of Cloisite 15A was increased from 300 to 1000 ppm. The separation time can be controlled by controlling the OC dose, depending on the application. A chelating agent can be used to reduce the effect of salts on emulsion stability. The OC materials have the potential to be used as cost-effective emulsifiers for PAM/PEI at high temperature (>100 degrees C) and high salinity (>200,000 ppm). The OC materials can be used as standalone emulsifiers or co-surfactants to enhance the performance of commercial emulsifiers.",21,22,5
Oil Recovery,Degrees C,"Wang, Chao; Liu, Pengcheng; Wang, Fushun; Atadurdyyev, Bayramberdi; Ovluyagulyyev, Mergen",Experimental study on effects of CO2 and improving oil recovery for CO2 assisted SAGD in super-heavy-oil reservoirs,Super-heavy oil reservoir; Steam assisted gravity drainage (SAGD); Reduce viscosity; Carbon dioxide; Thermal oil recovery,GRAVITY DRAINAGE; STEAM; EOR; PERFORMANCE; INJECTION; SEQUESTRATION; MECHANISM; PRESSURE; BEHAVIOR; SOLVENT,"When developing heavy-oil reservoirs using steam-assisted gravity drainage (SAGD) technology, CO2 is often used to reduce the viscosity of heavy oil and the heat loss of the steam chamber, thereby enhancing oil recovery. The limitation of experimental apparatuses, results in a maximum temperature of the reaction kettle of no more than 150 degrees C. Thus, the solubility of CO2 in super-heavy oil and its impact on decreasing viscosity beyond 150 degrees C requires further discussion. Considering these issues, a high-temperature-resistant heavy-oil mixing apparatus was designed to measure the solubility of CO2 in super-heavy oil and the relative density and viscosity of super-heavy oil under high temperatures and pressures. Core flooding experiments under 200 degrees C were conducted to explore the effects of CO2 on oil displacement efficiency. The results indicated that solubility of CO2 became significantly lower at 200 degrees C, when the viscosity and relative density of super-heavy oil decreased as pressure increased. The viscosity of super-heavy oil saturated with CO2 decreased by 71.2%, and relative density decreased by 10.1% at 200 degrees C compared to those of degassed crude. At temperatures of 120 degrees C, 150 degrees C and 200 degrees C, the ultimate displacement efficiency of super-heavy oil increased by 6.6%, 19.2% and 21.4%, respectively, compared to a temperature of 60 degrees C. At pressures of 1.0 MPa, 2.0 MPa and 4.0 MPa, the ultimate displacement efficiency (46.7%) of super-heavy oil increased by 5.2%, 4.0% and 5.9%, respectively, compared to a pressure of 0.5 MPa. The experiments showed that CO2 injection can effectively reduce the relative density and viscosity of super-heavy oil and improve oil recovery under high temperatures and pressures. CO2 has good potential to improve SAGD efficiency in developing super-heavy-oil reservoirs.",20,21,4
Oil Recovery,Degrees C,"Ren, Guangwei; Nguyen, Quoc P.; Hon Chung Lau",Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants,CO2 soluble surfactants; Partition coefficient; CO2 foam; Fractured carbonate reservoir; EOR,INTERFACIAL-TENSION; GRAVITY DRAINAGE; MOBILITY CONTROL; CRUDE-OIL; DISPLACEMENT; EOR; MICROEMULSIONS; WETTABILITY; SOLUBILITY; REDUCTION,"Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions. A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 degrees C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water. RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam. These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.",19,20,2
Oil Recovery,Degrees C,"Li, Xiuluan; Shi, Lanxiang; Li, Haozhe; Liu, Pengcheng; Luo, Jian; Yuan, Zhe",Experimental study on viscosity reducers for SAGD in developing extra-heavy oil reservoirs,Steam assisted gravity drainage (SAGD); Viscosity reducer; Extra-heavy oil; Thermal stability; Displacement efficiency,ASSISTED GRAVITY DRAINAGE; ES-SAGD; PHASE-BEHAVIOR; SOLVENT; STEAM; BITUMEN; WELLS; PERFORMANCE; RECOVERY,"Steam assisted gravity drainage (SAGD) is an effective in situ oil recovery technology in developing extra-heavy oil reservoirs. Large volumes of steam are needed, however, to heat the extra-heavy oil because of its high viscosity. Steam generation consumes large amounts of natural gas, which adversely affects the economics of SAGD, especially when oil prices are low. Moreover, environmental concerns arise because of excessive freshwater use and greenhouse gas emissions from the burning of the fossil fuels to generate steam. Considering these limitations and concerns, this paper evaluates the effectiveness of different viscosity reducers to decrease the steam consumption and improve SAGD performance. We conducted a series of screening experiments, including viscosity-reduction ratio, thermal stability, and core flooding, for nine types of viscosity reducers, based on an extra-heavy oil sample from a commercial SAGD project in China. The results indicate that water-soluble viscosity reducer #8, a nanoemulsion, is suitable for SAGD. It has a viscosity-reduction ratio of 98.0% at 50 degrees C and is still effective after high-temperature and high-pressure (200 degrees C, 4.0 MPa) treatment, with a viscosity-reduction ratio of 92.6%. The displacement efficiency is improved by 29.1%, and the cumulative steam-to-oil-ratio is reduced by 45.3% compared with pure steam flooding. Despite viscosity-reduction, the effect of interfacial tension reduction plays an important role in improving displacement efficiency during the coinjection of steam and viscosity reducer #8 has good potential to improve SAGD performance in developing extra-heavy oil reservoirs.",18,21,4
Oil Recovery,Degrees C,"Lashkarbolooki, Mostafa; Riazi, Masoud; Ayatollahi, Shahab",Effect of CO2 and crude oil type on the dynamic interfacial tension of crude oil/carbonated water at different operational conditions,Dynamic IFT; Carbonated water; CO2; Adsorption time; Temperature; Pressure,CARBONATED WATER; AQUEOUS-SOLUTIONS; INJECTION; RECOVERY; PH; EQUILIBRIUM; TEMPERATURE; PERFORMANCE; ASPHALTENE; ADSORPTION,"Concerns about climate change have persuaded the researchers to examine CO2 injection in the form of carbonated water (CW) into oil reservoir as a safe and effective CO2 storage and enhanced oil recovery process. Although interfacial tension (IFT) between crude oil and injected fluid has a vital role on the displacement of fluids in porous media, the effect of CO2 and crude oil type on the dynamic IFT of crude oil under different operational conditions is not well understood. Accordingly, this study was carried out to assess the effects of temperature, pressure, crude oil type and CO2 on the dynamic IFT of crude oil/CW. To achieve this goal, two types of crude oil were provided from southern Iranian oil reservoirs and dynamic IFTs with CW were measured in a wide range of temperatures and pressures (i.e. temperature range of 30-80 degrees C and pressure range of 500-4000 psi); the obtained results were compared with the system without CO2. In addition, the adsorption time of carbonated aqueous phase/crude oil, obtained based on the mono exponential decay model, was also compared with unadulterated water/crude oil system. The outcome of this study showed that crude oil type has the most significant effect on the IFT of crude oil/CW compared to pressure, temperature and CO2 content. In more details, the IFT of crude oil/CW can be affected by the amount and type of acidic/basic components in the crude oil as well as pH of the aqueous solution. Besides, the obtained results revealed that the effect of temperature was more considerable on the IFT of the heavy crude oil compared with the light crude oil in both studied aqueous solutions (i.e. unadulterated water and CW). Although the inversion phase temperature was obtained for unadulterated water/studied crude oils at all studied pressures, this phenomenon was not observed for crude oil/CW at elevated pressure, due to the high amount of CO2 at this condition.",17,17,3
Oil Recovery,Degrees C,"Nasri, Zarrin; Mozafari, Motahareh",Multivariable statistical analysis and optimization of Iranian heavy crude oil upgrading using microwave technology by response surface methodology (RSM),Heavy crude oil; Upgrading; Microwaves; Response surface methodology,ULTRASONIC IRRADIATION; HORIZONTAL WELL; DEMULSIFICATION; EMULSIONS; PERFORMANCE; PYROLYSIS; RECOVERY,"Conventional methods to upgrade heavy oil due to high pressure, low production efficiency, and low product quality have not been recognized as profitable methods. These complications resulted in using innovative technologies in this area. In this paper, the statistical analysis and process conditions optimization of Iranian heavy crude oil upgrading have been performed using microwave technology, for the first time. The heavy crude oil is from Iranian west Paydar field, with specifications including API 18.53, viscosity 78.76 cSt (at 20 degrees C). In order to optimize process conditions for upgrading heavy crude oil, independent variables include power level (40-70-100%), process time (5-12.5-20) (min), activated carbon as sensitizer (0-5-10) (wt%), and Fe as catalyst (0-3-6) (wt%). Surface temperature, API ratio, viscosity ratio, and asphaltene reduction have been considered as response variables. The Box-Behnken design and response surface methodology (RSM) have been applied to determine parameters levels and to model the responses, respectively. The results show that the optimal conditions to maximize surface temperature, API ratio, and asphaltene reduction, and to minimize viscosity ratio involve power level of 100%, process time of 20 min, activated carbon of 10 wt%, Fe catalyst of 4.06 wt% which leads to 23.31API ratio, 31.6% asphaltene reduction, and 43.37% viscosity reduction. The predicted conditions agreed with the experimental values, representing the models accuracy.",16,17,3
Oil Recovery,Degrees C,"Franco-Aguirre, Maribel; Zabala, Richard D.; Lopera, Sergio H.; Franco, Camilo A.; Cortes, Farid B.",Ca-DTPMP nanoparticles-based nanofluids for the inhibition and remediation of formation damage due to CaCO3 scaling in tight gas-condensate reservoirs,Calcium carbonate; Formation damage; Inhibition; Nanofluid; Phosphonate; Remediation,CALCIUM-CARBONATE PRECIPITATION; PHOSPHONATE; ADSORPTION; MEDIA; OIL,"The oil productivity of tight gas-condensate reservoirs can be affected by the precipitation/deposition of inorganic scales such calcium carbonate (CaCO3), which leads to a reduction mainly in permeability and porosity of the porous media. Therefore, the main objective of this study is to develop for the first time a nanofluid based on the interaction between active nanoparticles such as Ca-diethylenetriamine pentamethylene phosphonic (Ca-DTPMP) and remaining synthesis fluid (RSF) obtained from the synthesis process, to simultaneously inhibit and remove the formation damage due to the precipitation/deposition of CaCO3 scales. The synthesis of the Ca-DTPMP nanoparticles was performed varying the phosphonate concentration between 0.01 and 0.5 M. The obtained nanoparticles were characterized through N-2 physisorption at - 196 degrees C for obtaining the surface area (S-BET), field emission scanning electron microscopy (FESEM), and dynamic light scattering (DLS) measurements. The mean nanoparticles size of the obtained materials ranged between 36 and 69 nm and was lower for the nanoparticles synthesized with a lower concentration of DTPMP. Nanofluids containing the synthesized nanoparticles of Ca-DTPMP were prepared with RSF solutions in deionized water as a carrier fluid for different Ca-DTPMP/RSF ratios of 10, 50, 200 and 500. The ability of the nanoparticles and nanofluids to inhibit the CaCO3 scaling was evaluated in batch-mode experiments at 70 degrees C by measuring changes in the calcium ion (Ca2+) concentration in the solution. The nanofluid with better performance was that prepared with 50 mg/L of Ca-DTPMP/0.3 nanoparticles and a Ca-DTPMP/RSF ratio of 10, with an inhibition efficiency of 67%. Further, coreflooding tests were carried out using the nanofluid with better performance from the batch-mode experiments. Displacement tests were conducted under tight gas-condensate reservoir conditions at a temperature of 110 degrees C (230 degrees F) and confining and pore pressures of 34.47 MPa (5000 Psi) and 6.89 MPa (1000 Psi), respectively. Inhibition and remediation of CaCO3 scaling were evaluated. The nanofluid was soaked in the porous media for 8 h. Based on the results of the relative permeability and oil recovery curves, it is possible to conclude that the synthesized nanofluid promotes the inhibition and removal of the formation damage due to CaCO3 inorganic scales. The nanofluid injection leads to an increase of the oil permeability of 57% in comparison with the base system, suggesting that the nanofluid acts as inhibitor agent, as remediation treatment, and as stimulation product of oil wells. Also, the treatment showed a perdurability of more than 60 pore volumes and increasing of oil recovery of 4 and 24% regarding the base and the damaged systems, respectively.",16,16,1
Oil Recovery,Degrees C,"Silva, Ivonete P. G.; Aguiar, Amaury A.; Rezende, Viviane P.; Monsores, Andre L. M.; Lucas, Elizabete F.",A polymer flooding mechanism for mature oil fields: Laboratory measurements and field results interpretation,Enhanced oil recovery; Polymer flooding; Mobility; Rheology; Particle size,LIGHT-SCATTERING; MOLECULAR-WEIGHT; POLYACRYLAMIDE; FLOW; DEPENDENCE; RECOVERY; POLYELECTROLYTE; TEMPERATURE; COPOLYMERS; RETENTION,"Although polymer flooding has been widely studied in the literature on oil recovery, many questions remain about the technique's action mechanisms. It is widely accepted that the process is based on increasing viscosity of the aqueous phase (injected fluid). The polymer can also act secondarily by reducing the relative permeability to water. Fields that are markedly heterogeneous, highly depleted or that contain fluids with strong salinity are not good candidates for the process. To overcome these restrictions, the most recent applications have used more resistant polymers, with higher molar masses, injected in larger quantities, to preserve the level of viscosity under these adverse conditions. However, a pilot test in a field under adverse conditions showed surprising results and unexpected pressure abnormality, even with small quantities of partially hydrolyzed polyacrylamide (HPAM) with relatively low molar mass (6 x 10(6) g/mol). This paper reports the investigation of the prevailing mechanism responsible for these unexpected results, by means of laboratory tests of flow in porous media and rheological analysis of fluids and hydrodynamic diameter of polymer molecules. The Salt effect (NaCl) on polymer solutions was researched by rheology and particle size analysis at 25 and 50 degrees C. The results showed that mechanical/hydrodynamic retention prevails over polymer adsorption at the rock, with the former being caused by the increase in the polymeric hydrodynamic volume in fluid dilution processes. Besides this, increased temperature was found to favor greater hydrodynamic volume under tested conditions, while salinity had little influence. The results also shed new light on the flow behavior of polymer solutions in porous media, particularly in polymer injection for enhanced oil recovery from mature fields.",15,15,3
Oil Recovery,Degrees C,"Taheri-Shakib, Jaber; Shekarifard, Ali; Naderi, Hassan",The study of influence of electromagnetic waves on the wettability alteration of oil-wet calcite: Imprints in surface properties,Wettability; Heavy oil; Microwave; Calcite; Polar,APPEARANCE TEMPERATURE WAT; CONTACT-ANGLE; RECOVERY; MICROWAVE; SALINITY; CARBONATE; ROUGHNESS; IMPACT; TIME; GAS,"The wettability of reservoir rock is one of the fundamental parameters determining the flow of fluid in the porous media. This study has investigated the effect of microwaves on the wettability of calcite reservoir rock from Yaran, Iran, as the time interval of microwave radiation is one of the most important parameters affecting wettability. The reservoir rock samples were placed in a microwave oven filled with helium gas and subjected to microwave radiation at 5-min intervals from 5 to 35 min. Measurements of the contact angle between the oil and the rock indicated that the microwaves brought the angle from about 120 degrees primary state to 93 degrees at 35 min. At intervals of 5-15 min, no change in the wettability of the oil-wet rock was observed. Sulfur components had high absorption coefficients of microwaves, so initially reduced the amount of sulfur (S) on the surface of the oil-wet rock. Next, the nitrogen (N) and oxygen (O) elements were reduced, and eventually the carbon (C) levels began to decrease. This trend was observed in the zeta potential by changing the surface charge of the rock. Indeed, eliminating SNO polar compounds with a high potential for absorbing microwave caused the rock to become water-wet. Microwave radiation initially produced no change in the Fourier-transform infrared spectroscopy (FTIR) spectrum, as it continued, the peak intensity of the corresponding oil, such as the carboxylic acid functional group, declined, and the corresponding peaks of the rock became more intense, indicating a gradual change in the wettability. It can be interpreted that the aromatic compounds exist in oil and act as surface agent components. The results of this study can be used as a representation of the use of microwave radiation in hydrocarbon reservoirs to change the wettability and increase the production rate of reservoirs.",15,15,0
Oil Recovery,Degrees C,"Derguine-Mecheri, Louiza; Kebbouche-Gana, Salima; Khemili-Talbi, Souad; Djenane, Djamel",Screening and biosurfactant/bioemulsifier production from a high-salt-tolerant halophilic Cryptococcus strain YLF isolated from crude oil,Yeasts; Biosurfactant; Cryptococcus sp YLF; Agro industrial wastes; EOR,BIOSURFACTANT PRODUCTION; LIPOPEPTIDE BIOSURFACTANT; SURFACE-PROPERTIES; WASTE-WATER; CANDIDA; BOMBICOLA; YEAST; SOPHOROLIPIDS; BIOEMULSIFIER; QUANTITATION,"Biosurfactant-producing yeasts were isolated from different biotopes including food samples, waste and sand samples collected from areas contaminated with hydrocarbons in Algeria. Isolates were screened for biosurfactant/bioemulsifier production in mineral salt medium and in high salinity using emulsification index (E24), drop-collapse test, spread oil technique and hemolytic activity. Fifty of one hundred isolates were positive for almost all the qualitative tests, four of them were the best strains for biosurfactants production with emulsions over than 60%. More interestingly, one high-salt-tolerant yeast isolate was the most potent biosurfactants producing yeast with an emulsification index of 69.50 +/- 0.70. It was identified by morphological, physiological and biochemical tests and by 5.8s-rDNA Analysis as Cryptococcus sp. YLF. This strain produced biosurfactant using different carbon and nitrogen sources and when grown in low-cost fermentative media based on agro industrial by-products and wastes like whey, molasses, corn steep liquor, date syrup and olive mill wastewater (OMW) supplemented with NaCl (2.5 M). The biosurfactant produced by Cryptococcus sp. YLF was partially characterized as glycolipid based on the estimation of macromolecules, TLC and IR analysis. The crude biosurfactant demonstrated stability regarding surface tension reduction and emulsification activity in a range of temperatures (5-100 degrees C), pH (2-12) and high salinities (1-10%). The partially purified biosurfactant showed promising potential for application in enhanced oil recovery (EOR).",14,14,4
Oil Recovery,Degrees C,"Aurepatipan, Nathapat; Champreda, Verawat; Kanokratana, Pattanop; Chitov, Thararat; Bovonsombut, Sakunnee",Assessment of bacterial communities and activities of thermotolerant enzymes produced by bacteria indigenous to oil-bearing sandstone cores for potential application in Enhanced Oil Recovery,Enhanced Oil Recovery; Lipase; Esterase; Bacterial communities,BIOSURFACTANT PRODUCTION; PETROLEUM RESERVOIRS; MOLECULAR ANALYSIS; BACILLUS-SUBTILIS; HIGH-TEMPERATURE; ALKALINE LIPASE; WATER; MICROORGANISMS; DIVERSITY; BIODEGRADATION,"Enhanced Oil Recovery (EOR) is a potential approach to improve oil yield in petroleum production. In this research, indigenous bacterial communities residing in oil-bearing sandstone cores, taken from oil wells in Fang oil field in Northern Thailand, were investigated using the Ion Torrent PGM sequencing method. Based on 16rRNA gene sequences, Proteobacteria and Firmicutes were found to be the predominant phyla, and Bacillus, Sinomonas, Paenibacillus and Hydrogenophaga were the major genera. Thermotolerant lipase-esterase and urease producing bacteria were also isolated from the oil-bearing sandstone core samples. One lipase-esterase producing isolate, Bacillus licheniformis L3-2, produced the enzyme with highest activity at 80 degrees C. The enzyme retained up to 50% of its activity after incubation at 60 degrees C for 4 h. The results suggest the possibility of applying an in situ EOR approach using a combination of Enzyme Enhanced Oil Recovery (EEOR) and Microbial Enhanced Oil Recovery (MEOR) methods, with this lipase-esterase producing Bacillus licheniformis isolate, which is indigenous to one of the wells in this oil field.",14,14,3
Oil Recovery,Degrees C,"Mehrabi-Kalajahi, Seyed Saeed; Varfolomeev, Mikhail A.; Yuan, Chengdong; Emelianov, Dmitrii A.; Khayarov, Khasan R.; Klimovitskii, Alexander I.; Rodionov, Alexander A.; Orlinskii, Sergei B.; Gafurov, Marat R.; Afanasiev, Igor S.; Fedorchenko, Gennadii D.; Lubnina, Elena V.",EPR as a complementary tool for the analysis of low-temperature oxidation reactions of crude oils,Crude oil; In-situ combustion; Air injection; Oxidation; EPR; Free radical concentration,IN-SITU COMBUSTION; VANADYL-PORPHYRIN COMPLEXES; SARA FRACTIONS; PARAMAGNETIC-RESONANCE; KINETIC-ANALYSIS; AIR INJECTION; HEAVY OIL; LIGHT; ASPHALTENES; BEHAVIOR,"Air injection is a promising method for enhanced oil recovery (EOR) in both conventional and unconventional oil sources. It is widely accepted that oxidation reactions between oil and injected air determine the success of an air injection process. In this study, electron paramagnetic resonance (EPR) was introduced as a new route to investigate the occurrence of low-temperature oxidation (LTO) and its behavior by monitoring the signals of free radicals. The EPR experiments were conducted for the different crude oil samples (light, medium and heavy) heated in both static air and flow air (air-bubbling) conditions under different temperatures from 25 degrees C to 180 degrees C. The results showed that the free-radical concentrations exhibited a good correspondence on the heating temperature. Furthermore, nuclear magnetic resonance (NMR), Fourier-transform infrared spectroscopy (FTIR) and differential scanning calorimetry (DSC) experiments were carried out to help to analyze the oxidation process and verify the EPR results. It turned out that the EPR results can be well supported by NMR, FTIR and DSC data, which indicates that proposed EPR monitoring method can be applied as a fast and low-cost technique to investigate LTO under mild reaction conditions. Simultaneously, the combination of EPR, NMR, FTIR and DSC can help to better understand the LTO mechanism and to monitor the application of in-situ combustion technique in the field.",14,14,1
Oil Recovery,Degrees C,"Ashish; Debnath (Das), Mira",Application of biosurfactant produced by an adaptive strain of C-tropicalis MTCC230 in microbial enhanced oil recovery (MEOR) and removal of motor oil from contaminated sand and water,Biosurfactant; Candida tropicalis; Surfactin; Critical micelle concentration; MEOR,WASTE-WATER; SURFACTIN; BACTERIA; PURIFICATION; HYDROCARBON; SUBSTRATE; GLYCEROL; SOIL,"Microbial enhanced oil recovery (MEOR) represents the use of microorganisms or their products to recover remaining oil trapped up in oil reservoirs. In this study adaptive strain C. tropicalis MTCC230 was used to determine its suitability in MEOR. Biosurfactant produced from an adaptive strain C. tropicalis MTCC230 was characterized as lipopeptide surfactin by Near IR, FTIR spectrum and HPLC and mass spectroscopy analysis. It can significantly reduce the surface tension 72 mN/m to 32 mN/m, with the critical micelle concentration (CMC) of 32.5 mg/l and B. subtilis MTCC2423 used as a standard surfactin (Biosurfactant) producing strain for comparative study. It shows stable Physiochemical properties under the extreme pH(2-12), temperature(30 degrees C - 90 degrees C) and salinity(2%-10%) that promote its potential use in enhanced oil recovery. Oil spreading method and soil washing analysis confirmed it suitability to remove the hydrocarbon contaminants from water and soil. Laboratory scale sand pack column saturated with four stroke engine oil resulted similar to 39.80% additional oil recovery (AOR), suggesting its suitability for commercial use in microbial enhanced oil recovery (MEOR) in oil reservoirs.",14,15,1
Oil Recovery,CO2,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Miao, Yanan; Han, Song; Chen, Zhili",Flow simulation of the mixture system of supercritical CO2 & superheated steam in toe-point injection horizontal wellbores,Toe-point injection; Horizontal wellbore; Supercritical CO2; Superheated steam; Inner heat exchange; Friction loss; Energy balance,HEAT-TRANSFER CHARACTERISTICS; 2-PHASE FLOW; OIL-RECOVERY; PERFORMANCE ANALYSIS; NONCONDENSING GASES; THERMAL FLUID; SHALE GAS; MODEL; TEMPERATURE; PREDICTION,"Conventional heavy oil recovery method of saturated steam injection at heel-point of horizontal wellbores is facing comparatively more serious fingering phenomenon. With this, oil companies are now actively developing new recovery method of supercritical CO2 - superheated steam injection in horizontal wellbores with toe-point injection technique. Firstly, considering the heat exchange between the inner tubing (IT) and annuli, a pipe flow model comprised of energy and momentum conservation equations is developed for the mixture flow in both IT and annuli. Then, coupled with the S-R-K real gas model, variable mass flow model and transient heat transfer model in oil layer, a comprehensive mathematical model is established. Numerical solutions of the mixture flow in toe-point injection wellbores are obtained through straight forward numerical method. Finally, model validation and sensitivity analysis are conducted. The results show that: (1). there exists a good agreement between predicted results and field data. The predicted temperature is higher when the heat exchange between IT and annuli is neglected. The predicted temperature is lower when the friction loss item is considered in the energy balance equation. (2). the temperature of the mixture increases when the mixture flows from toe-point to heel-point in annuli due to heat flow from IT to annuli. (3). While the absorption rate of the mixture in formation increases with increasing of the content of supercritical CO2, it can be offset by the decrease of temperature and enthalpy of the mixture. (4). Both of the mixture temperature and formation mixture absorption rate increase with increasing of injection pressure.",59,61,1
Oil Recovery,CO2,"Da, Chang; Alzobaidi, Shehab; Jian, Guoqing; Zhang, Leilei; Biswal, Sibani L.; Hirasaki, George J.; Johnston, Keith P.",Carbon dioxide/water foams stabilized with a zwitterionic surfactant at temperatures up to 150 degrees C in high salinity brine,CO2-in-water foam; Zwitterionic surfactant; Porous media; EOR,ENHANCED OIL-RECOVERY; WORMLIKE MICELLES; CONCENTRATED EMULSIONS; SUPERCRITICAL FLUIDS; MOBILITY CONTROL; MIXED-SOLUTIONS; AQUEOUS-PHASE; POROUS-MEDIA; YIELD-STRESS; ADSORPTION,"Stabilization of CO2-in-water (C/W) foams with surfactants at high temperature and high salinity conditions is challenging given limitations in the solubility and thermal stability of surfactants, particularly for surfactants other than anionic ones. Here we show that a single zwitterionic surfactant, cetyl betaine (CH3(CH2)(15)N+(CH3)(2)CH2COO-), stabilizes viscous C/W foam (> 15 cP) in crushed limestone (76-Darcy) at a temperature up to 150 degrees C and over a wide range in salinity up to 22% total dissolved solids (TDS) at superficial velocity of 940 ft/day. According to liquid chromatography mass spectrometry (LC/MS), cetyl betaine has high thermal stability with negligible chemical degradation after incubation at 135 degrees C for 30 days. Interfacial tension (IFT) at the C/W interface was reduced significantly from similar to 37 mN/m to < 5 mN/m with the addition of 0.08 mmol/L of cetyl betaine. Relative to ionic surfactants, the relatively weak electrostatic repulsion between the local charges in the headgroup is shown to produce strong adsorption at the C/W interface (similar to 134 angstrom(2)/molecule), resulting in generation of viscous foam (similar to 6 cP) even in pure water without added salt. At a low superficial velocity of 6 ft/day (shear rate 45 s(-1)) in a beadpack, foam was still formed with cetyl betaine. Static adsorption of cetyl betaine on carbonates was on the order of 1 mg/m(2), and core flood test also proved that cetyl betaine could stabilize viscous C/W foam (> 20 cP) within 6 pore volumes of injection at 120 degrees C. The surfactant stabilized viscous C/W foam at low oil fractions and broke in the presence of large fractions of oil, both of which are desirable in CO2 mobility control and oil displacement. The ability to form foams at high temperatures and over a wide range in salinity is important for various practical applications including CO2 enhanced oil recovery, fracturing with energized fluids and CO2 sequestration.",46,48,19
Oil Recovery,CO2,"Xie, Quan; Sari, Ahmad; Pu, Wanfen; Chen, Yongqiang; Brady, Patrick V.; Al Maskari, Nasser; Saeedi, Ali",pH effect on wettability of oil/brine/carbonate system: Implications for low salinity water flooding,Carbonate reservoirs; Low salinity water; Wettability; Geochemical modelling; pH,SURFACE COMPLEXATION MODEL; IMPROVED OIL-RECOVERY; IMPACT; CHALK; CARBONATES; SANDSTONE; EOR,"Wettability of oil/brine/carbonate system is a critical parameter to govern subsurface multi-phase flow behaviour, thus remaining oil saturation and ultimate oil recovery in carbonate reservoirs. Despite the fact that salinity level, ionic strength, oil composition and rock chemistry (e.g., limestone and dolomite) have been extensively investigated, few work has been done regarding the effect of pH on oil/brine/rock interaction, thus wettability. We thereby measured contact angles at two different pH (pH = 3 and 8) in the presence of either 1 mol/L Na2SO4 or 1 mol/L CaCl2 using a crude oil with acid number of 1.7 and base number of 1.2 mg KOH/g. Moreover, we performed a geochemical modelling study in light of the diffuse double layer to understand how pH controls the number of surface species at interfaces of oil/brine and brine/carbonate. Our results show that pH scales with oil/brine/carbonate wettability, demonstrating that pH is one of the controlling factors to govern the system wettability. Further, our results suggest that pH (6.5-7.5) likely triggers an oil-wet system, which is favourable for low salinity water flooding, but pH < 5 usually exhibits a water-wet system, which explains why low salinity effect is not always observed in carbonate reservoirs. This also confirms that CO2 flooding, carbonated water flooding, and CO2 huff-and-puff FOR very likely renders a strongly water-wet system due to H+ adsorption on the interface of oil/brine and brine/carbonate as a result of CO2 dissolution.",43,43,2
Oil Recovery,CO2,"Jia, Bao; Tsau, Jyun-Syung; Barati, Reza","Role of molecular diffusion in heterogeneous, naturally fractured shale reservoirs during CO2 huff-n-puff",Bakken shale reservoirs; Molecular diffusion; Heterogeneity; Correlation length; CO2 huff-n-puff,OIL; INJECTION; RECOVERY,"Shale reservoirs are characterized by high degree of heterogeneity and ultra-low matrix permeability. Natural fracture (both macro and micro) systems are important to increase the performance of shale reservoirs by providing flow path for the hydrocarbon from the nanopores in the matrix to the wellbore. Configurations of natural fractures also have significant implications for the recovery performance of shale gas and oil reservoirs. CO2 huff-n-puff or cyclic injection has been suggested to be a feasible way to recover oil from shales and the flow process is complex. Molecular diffusion is an important transport mechanism of the mixture of CO2 and oil, especially in tight formations. Based on these knowledge, various configurations of the natural fracture system in shale reservoirs with the dual porosity and dual permeability model were constructed, regarding Dykstra-Parsons (DP) coefficient and correlation length. Dykstra-Parson (DP) coefficient ranges from 0.40 to 0.78, and correlation length ranges from 50 ft to 3000 ft. Based on the geological setting of the Middle Bakken formation and the Bakken live oil PVT data, compositional models were performed to simulate the CO2 huff-n-puff process. CO2 injection begins after the primary recovery factor reaches 3% and both multiple-cycle and single-cycle of injection were investigated regarding the oil recovery performance and CO2 injectivity behavior. In the multiple-cycle scheme the period of one cycle is short; the injection, soak and production time are 10 days, 10 days and 100 days, respectively. In the single-cycle scheme, the period of one cycle is long, and gas injection volume is set to be constant with the soak time of 100 days. The impact of molecular diffusion during the huff-n-puff process is compared in different simulation scenarios. Findings in this work reveal the importance of the configuration of the pre-existing natural fracture system for the performance of the huff-n-puff process. Reservoir heterogeneity hampers primary production. However, during the puff production process, the negative impact of heterogeneity is less as the correlation length increases when the molecular diffusion is taken into account. There exists a threshold correlation length value wherein heterogeneity becomes favorable for improved oil recovery instead of hampering oil recovery, after taking into account of the molecular diffusion, which is approximately 1500 ft in this simulation study. The value of correlation length also affects the performance of multiple-cycle and single-cycle huff-n-puff processes differently because CO2 injectivity behavior is different in reservoirs characterized by different DP coefficients and correlation length: there exists a threshold time point when a longer correlation length begins to favor the injectivity, and the threshold time point is delayed for a scenario with a larger DP coefficient.",41,42,2
Oil Recovery,CO2,"Zhang, Yuan; Yu, Wei; Li, Zhiping; Sepehrnoori, Kamy",Simulation study of factors affecting CO2 Huff-n-Puff process in tight oil reservoirs,CO2 Huff-n-Puff; Nanopore confinement; Molecular diffusion; Minimum miscibility pressure; Tight oil,SHALE; RECOVERY; FLUID; GAS; PERMEABILITY,"CO2 injection is one of the effective enhanced oil recovery (EOR) methods in conventional oil reservoirs, which has been widely applied in the tight oil reservoirs. Although there are some efforts on the investigation of engineering parameters such as fracture half-length, fracture conductivity, and fracture height, the effects of CO2 molecular diffusion, nanopore confinement, and stress-dependent deformation on CO2-EOR effectiveness are poorly understood. In this paper, we modified the conventional phase-equilibrium model to accurately compute the phase behavior in shale nanopores. Subsequently, we investigated the minimum miscibility pressure (MMP) of CO2-EOR process under different pore sizes. Afterwards, we evaluated the well performance of CO2 Huff-n-Puff process by fully capturing physics of CO2 molecular diffusion and nanopore confinement. The impacts of matrix permeability, CO2 injection rate and stress-dependent deformation mechanisms on the CO2 Huff-n-Puff process are examined in detail. The results show that CO2 diffusion and nanopore confinement play an important role in improving the oil recovery factor, which should be correctly implemented in reservoir simulation model. Additionally, matrix permeability, CO2 injection rate, and stress-dependent deformation mechanisms significantly influence the CO2 Huff-n-Puff process. This work enables operators to optimize the CO2 Huff-n-Puff process to improve the efficiency of CO2-EOR and CO2 storage in tight oil reservoirs.",40,43,2
Oil Recovery,CO2,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Liu, Qing; Han, Song; Zhou, Yunjian",Effect of friction work on key parameters of steam at different state in toe-point injection horizontal wellbores,Heavy oil recovery; Toe-point injection horizontal well; Friction work; Temperature distribution; Steam quality distribution; Steam state,HEAT-TRANSFER CHARACTERISTICS; MULTI-THERMAL FLUID; SUPERHEATED-STEAM; 2-PHASE FLOW; OIL-RECOVERY; PERFORMANCE ANALYSIS; SUPERCRITICAL CO2; MODEL; TEMPERATURE; WELLS,"When modeling of steam flow in wellbores, the effect of friction work on temperature/ steam quality of both fluid in wellbores and reservoir should be considered. A model that can describe the energy re-distribution in the system should be built. In this paper, new energy balance equations for steam flow in inner tubing (IT) and annuli are developed with consideration of the effect of frction work on the energy re-distribution process in the system. The heat energy caused by shear stress has an obvious influence on the increase of steam quality or superheated steam temperature, especially under high injection speed condition. Firstly, a model for steam flow is developed in wellbores based on the energy and momentum balance equations. The energy balance equation controlls the predicted values of steam quality or superheated steam temperature, and the momentum balance equation controlls mainly the steam pressure. Secondly, coupled with the seepage model in oil layer, a comprehensive mathematical model is establiehed for single, two-phase flow of steam in horizontal wells with toe-point injection technique. Results show that: ( a) when the effect of friction work was neglected, the predicted steam quality or superheated steam temperature were obviously smaller than field data. (b) While seam quality decreases with distance when wet steam flows in wellbores, superheated steam temperature in annuli has an increase at the heel-point in annuli. This is because the fluid with lower temperature in annuli absorbs heat from steam with higher temperature in IT. (c). In order to obtain a satisfactory oil recovery ratio, field engineers are suggested to increase the injection pressure to a reasonable level based on the rock fracture pressure experiment.",35,38,0
Oil Recovery,CO2,"Wei, Peng; Pu, Wanfen; Sun, Lin; Pu, Yong; Wang, Song; Fang, Zhengkui",Oil recovery enhancement in low permeable and severe heterogeneous oil reservoirs via gas and foam flooding,Low permeability; Heterogeneity; Enhanced oil recovery; Nitrogen and CO2; Foam flooding,MINIMUM MISCIBILITY PRESSURE; MOBILITY CONTROL; NITROGEN FOAM; CO2; STABILITY; DISPLACEMENT; PERFORMANCE; INJECTION,"In view of the co-existence of the low permeability and severe heterogeneity, the effective tertiary technique for the enhanced oil recovery is still in progress. In this study, on the base of the simulation of SH reservoir conditions, we conducted the trinal-core flooding experiments about gas flooding (N-2 and CO2), WAG (N-2 and CO2) injection and foam flooding (N-2 and CO2). Combined with some static investigations, we found that CO2 flooding achieves additional oil recovery due to the development of near-miscibility and CO2 extraction, and the WAG injection can relieve the gas channeling associated with gas flooding. As for the foam flooding, CO2 foam has the advantage of oil displacement in a higher permeability layer and nitrogen foam is capable of diverting the flow to the least permeability zone in the strong heterogeneity formation and sharply increasing the oil recovery. It is also found that, in the pilot test of SH reservoir, nitrogen foam flooding is qualified for flow adjustment, water controlling and oil recovery enhancement in the low permeable and severe heterogeneous reservoir.",31,33,8
Oil Recovery,CO2,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Chen, Zhili; Chang, Yucui; Cao, Meng; Han, Song; Chaohui, Iv; Feng, Dong; Sun, Zheng",Effect of Flowing Seawater on Supercritical CO2 - Superheated Water Mixture Flow in an Offshore Oil Well Considering the distribution of heat generated by the work of friction,Wellbore hydraulics; Effect of seawater; Supercritical CO2; Superheated water; CO2 sequestration; Heavy oil recovery,RAPID MULTIPHASE FLOW; STEAM INJECTION; HORIZONTAL WELLS; 2-PHASE FLOW; SEMIANALYTICAL MODEL; PERFORMANCE ANALYSIS; NONCONDENSING GASES; PRESSURE; RECOVERY; ADSORPTION,"The modeling of thermal fluid (mostly reported for saturated steam) flow in wells involving steady-state heat transfer inside wellbores and transient heat transfer in sea water or formation is reviewed and inherited. It is a good addition of modeling of supercritical/superheated fluid to the existing body of literature. The flow of supercritical CO2 coupled with superheated water (SHW) in offshore wells is described by means of the differential mass, energy and momentum balance equations along the vertical wellbores. The effect of supercritical CO2 on pressure and temperature of the multi-component thermal fluid is expressed in terms of the real gas model (the S-R-K model). The differential equations are solved with finite difference method on space involving the constant injection parameters at wellhead. It is found out that: (a). while seawater has a significant influence on temperature drop in wellbores, its effect on pressure profiles is weak. (b). both temperature and superheat degree decrease with increasing of the content of supercritical CO2. Besides, study of the effect of injection rate and pressure is conducted.",30,30,1
Oil Recovery,CO2,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Li, Xiangfang; Chen, Mingqiang; Chen, Gang; Zhang, Tao",Analysis of superheated steam performance in offshore concentric dual-tubing wells,Offshore Wellbore modeling; Energy balance; Superheated steam; Concentric dual-tubing wells; Enthalpy data,HEAT-TRANSFER CHARACTERISTICS; MULTICOMPONENT THERMAL FLUID; 2-PHASE FLOW; OIL-RECOVERY; HORIZONTAL WELLS; NONCONDENSING GASES; SUPERCRITICAL CO2; MULTIPHASE FLOW; INJECTION WELLS; CURVE ANALYSIS,"Superheated steam (SHS) injection in concentric dual-tubing wells (CDTW) is a new technology for offshore heavy oil recovery. Firstly, compared with conventional saturated steam injection in single-tubing wells, the key advantages of SHS injection in CDTW for heavy oil recovery are introduced. Secondly, a novel mathematical model is proposed to analysis the heat transfer characteristics of SHS flow in offshore CDTW. Then, based upon the validated model, type curves of SHS flow in offshore CDTW are analyzed in detail. The results show that: (1). The heat exchange between the integral joint tubing (IJT) and annuli has a significant influence on SHS temperature and superheat degree in each tubing. (2). More heat get lost when the seawater starts to flow, and the heat loss rate in the sea section of the wellbores is larger than that in the formation section of the wellbores. Moreover, in order to flexibly use the model in practice, the key intrinsic flow characteristics of SHS in offshore CDTW are unraveled. It is found that: (1). The SHS temperature increases at first but turns to decrease with the continuous increase of injection rate due to the fact that the drop of SHS pressure gradually replaces heat losses as the dominant factor on temperature change. (2). The superheat degree at well bottom always increases with the increase of injection rate. This paper presents a basic reference for engineers in heat loss evaluations as well as performance estimations of SHS flow in offshore CDTW.",29,29,0
Oil Recovery,CO2,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Li, Xiangfang; Li, Qian; Yang, Jian; Wu, Jiqiang",A coupled model for CO2 & superheated steam flow in full-length concentric dual-tube horizontal wells to predict the thermophysical properties of CO2 & superheated steam mixture considering condensation,Heavy oil recovery; Concentric dual-tube wells; Multi-point injection technique; CO2 coupled with superheated steam; Wellbore hydraulics,HEAT-TRANSFER CHARACTERISTICS; MASS-TRANSFER CHARACTERISTICS; MULTICOMPONENT THERMAL FLUID; 2-PHASE FLOW; NONCONDENSING GASES; NONISOTHERMAL FLOW; SUPERCRITICAL CO2; CURVE ANALYSIS; OIL-RECOVERY; INJECTION,"The mixture of CO2 and superheated steam (SHS) has been proved effective for heavy oil recovery by field practices. It has been proved that the development effect is closely related to the state parameters (temperature, pressure and superheated degree etc.) of the mixture. As a result, wellbore modeling is an important branch in the study of thermal recovery of heavy oil. In recent years, concentric dual-tube wells (CDTW) coupled with multi-point injection technique (MPIT) is proposed to overcome the fingering phenomenon, induced by serious reservoir heterogeneity, during the steam injection process. In this paper, a wellbore model is developed for simulating CO2 & SHS flow in a full-length CDTW. The model is solved with finite difference method on space. It is found that: (a) An injection pressure, higher than 4.1 MPa, in the integral joint tube (IJT) or an injection pressure, smaller than 4.1 MPa, in annuli are recommended to obtain a uniform steam absorption rate along the horizontal wellbores. (b) The mass injection rate at well-head condition should be close to each other to avoid un-uniform of steam absorption rate along the horizontal wellbores. (c) When phase change occurs in the annuli, the mixture temperature increases with increasing CO2 content. (d) The total length of wet steam flow in the horizontal section of the wellbores increases with increasing CO2 content.",27,28,0
Oil Recovery,CO2,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun",Data analysis for CO2-EOR in shale-oil reservoirs based on a laboratory database,CO2-EOR in unconventional reservoirs; CO2-EOR in shale oil reservoirs; Unconventional EOR methods; Lab data analysis for EOR data screening,,"Unconventional resources have played a significant role in changing oil industry plans recently. Shale formations in North America such as Bakken, Niobrara, and Eagle Ford have huge oil in place, 100-900 Billion barrels of recoverable oil in Bakken only. However, the primary oil recovery is still low as 5-10%. EOR methods are currently considered as a new concept in unconventional reservoirs due to the immature information about these plays. Injecting carbon dioxide (CO2) might be the most potential strategy to improve oil recovery in such complex plays (Alfarge et al., 2017a,b). Jin et al. (2016) conducted an experimental study to investigate improving oil recovery by CO2 injection in 21 natural preserved core samples from Bakken Petroleum System (BPS). Their experimental results indicated that CO2 injection has a significant potential to improve oil transportability in these Nano-pores formations. In this study, data analysis for feasibility of CO2-EOR has been conducted on 95 cases of natural preserved cores collected from different formations including 44 cases from Middle Bakken, 26 cases from Lower Bakken, 17 from Upper Bakken, 4 cases from Three Forks, and 4 cases from unknown formation/formations. The relationship between the improved oil recovery by the injected CO2 and 6 rock properties including porosity, permeability, mean pore throat radius, total organic carbon content (TOC), water saturation, and oil saturation has been separately determined and physically discussed. Furthermore, the relationships between the improved oil recovery obtained by the injected CO2 and 4 operating parameters including CO2 bath pressure, CO2 bath temperature, and core sample bulk size, and exposing time have been also separately investigated. A Proxy model to associate the functionality of the improved oil recovery by CO2 injection and these 10 parameters have been constructed. Moreover, statistical methods for Design of Experiments (DOE) have been used to rank the most important parameters affecting CO2-EOR performance in the microscale level (lab scale) of these unconventional reservoirs. This study provides an important set of lab-based data obtained from natural preserved cores to find out the applicability of CO2-EOR in these unconventional reservoirs. Also, this research demonstrates some key points which could help in understanding CO2-EOR mechanisms in shale plays since they are much complex and very different from conventional formations.",27,28,0
Oil Recovery,CO2,"Seyyedi, Mojtaba; Mahzari, Pedram; Sohrabi, Mehran",A comparative study of oil compositional variations during CO2 and carbonated water injection scenarios for EOR,Carbonated water injection; CO2; CO2 storage; Compositional variations; New gaseous phase; EOR,CRUDE-OIL; RECOVERY; STORAGE,"With the significant increase in the atmospheric concentration of CO2, the interest for a combination of Enhanced Oil Recovery (EOR) and safe underground storage of CO2 in oil reservoirs has been increased. Two applicable methods that can address these concerns are CO2 flooding and carbonated water injection ( CWI). Mutual interactions taking place between oil and free CO2 or carbonated water (i.e. dissolve CO2 in the aqueous phase) would possess a fundamental difference. For free CO2 and oils, a combination of condensing/ vaporizing type of mass transfer would occur. However, in the case of carbonated water, a one- way mass transfer of CO2 from the aqueous phase to the oil can take place. This would lead to significant differences in the oil properties after dynamic interactions with free CO2 or carbonated water. In this study, for the first time, we are aiming to comprehensively address these concerns. An integrated approach was conducted to perform a series of carefully designed high-pressure and high-temperature direct visualizations (micromodel) as well as contact (PVT) experiments using a representative live oil. The results of pore-scale visualization experiments revealed an adverse strong extraction taking place during CO2 injection. Due to this extraction, the remaining oil after CO2 flooding was heavier than the original oil and its production was even more difficult. Contrary to that, during CWI the resident oil became lighter (lower viscosity) and no evidence of substantial extraction or oil downgrading was observed. To confirm pore-scale observations, PVT experiments were performed that revealed a strong adverse compositional change happening during CO2-oil single contact test. The oil contacted with CO2 was heavier than the original oil and a heavy condensate formed mainly from the medium components of oil was produced. However, during CW-oil multiple contacts test, the oil composition did not change and only after extensive cell volumes of CW comes in contact with the live oil; a slight change in the oil composition was observed. This slight change was due to the small extraction of light components of the oil into the new gaseous phase and it was observed in the form of a condensate. The produced condensate was lighter than the one produced from CO2-oil single contact test that reveals even after significant cell volumes of CW comes in contact with oil, the compositional change in oil is negligible compared to that of CO2 injection. The results of this study will shed some lights on the complex fluid-fluid interactions and oil compositional variations that take place during conventional CO2 and carbonated water injection in oil reservoirs.",23,24,3
Oil Recovery,CO2,"Wang, Chao; Liu, Pengcheng; Wang, Fushun; Atadurdyyev, Bayramberdi; Ovluyagulyyev, Mergen",Experimental study on effects of CO2 and improving oil recovery for CO2 assisted SAGD in super-heavy-oil reservoirs,Super-heavy oil reservoir; Steam assisted gravity drainage (SAGD); Reduce viscosity; Carbon dioxide; Thermal oil recovery,GRAVITY DRAINAGE; STEAM; EOR; PERFORMANCE; INJECTION; SEQUESTRATION; MECHANISM; PRESSURE; BEHAVIOR; SOLVENT,"When developing heavy-oil reservoirs using steam-assisted gravity drainage (SAGD) technology, CO2 is often used to reduce the viscosity of heavy oil and the heat loss of the steam chamber, thereby enhancing oil recovery. The limitation of experimental apparatuses, results in a maximum temperature of the reaction kettle of no more than 150 degrees C. Thus, the solubility of CO2 in super-heavy oil and its impact on decreasing viscosity beyond 150 degrees C requires further discussion. Considering these issues, a high-temperature-resistant heavy-oil mixing apparatus was designed to measure the solubility of CO2 in super-heavy oil and the relative density and viscosity of super-heavy oil under high temperatures and pressures. Core flooding experiments under 200 degrees C were conducted to explore the effects of CO2 on oil displacement efficiency. The results indicated that solubility of CO2 became significantly lower at 200 degrees C, when the viscosity and relative density of super-heavy oil decreased as pressure increased. The viscosity of super-heavy oil saturated with CO2 decreased by 71.2%, and relative density decreased by 10.1% at 200 degrees C compared to those of degassed crude. At temperatures of 120 degrees C, 150 degrees C and 200 degrees C, the ultimate displacement efficiency of super-heavy oil increased by 6.6%, 19.2% and 21.4%, respectively, compared to a temperature of 60 degrees C. At pressures of 1.0 MPa, 2.0 MPa and 4.0 MPa, the ultimate displacement efficiency (46.7%) of super-heavy oil increased by 5.2%, 4.0% and 5.9%, respectively, compared to a pressure of 0.5 MPa. The experiments showed that CO2 injection can effectively reduce the relative density and viscosity of super-heavy oil and improve oil recovery under high temperatures and pressures. CO2 has good potential to improve SAGD efficiency in developing super-heavy-oil reservoirs.",20,21,4
Oil Recovery,CO2,"Hasham, Aleem A.; Abedini, Ali; Jatukaran, Arnav; Persad, Aaron; Sinton, David",Visualization of fracturing fluid dynamics in a nanofluidic chip,Fracturing fluid; Infiltration; Entrapment; Recovery; Nanofluidic,MICROFLUIDICS-BASED MEASUREMENT; PORE-SCALE ANALYSIS; SPONTANEOUS IMBIBITION; OIL-RECOVERY; GAS SHALES; HEAVY OIL; CO2; TEMPERATURE; PRESSURE,"Hydraulic fracturing is responsible for remarkable production from shale and tight formations, albeit at the cost of significant water usage. The flow dynamics of oil and fracturing fluid in nanopores remains largely uncharacterized, in part due to the challenge of conducting experiments at nanoscales. In this paper, we demonstrate a nanofluidic-based approach to visualize the fluid displacement during hydraulic fracturing. Nanoporous silicon-glass chips with circular and square grain shapes and identical depth of 175 nm were fabricated using reactiveion etching (RIE) and anodic bonding. Leveraging the inherent fluorescence property of the oil, the fluorescence microscopy was used to record the dynamics of the fluid displacement inside the chip. Performance of three different fracturing fluids - deionized water, potassium chloride (KCl) solution, and slick water - were evaluated based on the volumetric infiltration in the nanoporous network, entrapment of fracturing fluid in the porous media, and total production during drawdown. The KCl solution had the highest infiltration rate (fill factor of 0.68) and the lowest entrapment factor (0.39), resulting in the highest fracturing fluid recovery representing 43% in the square grain geometry with similar results for circular grains. With the fast quantification and ease of operation here, the nanofluidic approach enables a rapid screening of different fracturing fluids to inform shale oil operators.",20,21,3
Oil Recovery,CO2,"Li, Xingxun; Guo, Yunmei; Sun, Qiang; Lan, Wenjie; Liu, Aixian; Guo, Xuqiang",Experimental study for the impacts of flow rate and concentration of asphaltene precipitant on dynamic asphaltene deposition in microcapillary medium,Asphaltene deposition; Visualization; Capillary flow; Microcapillary; Pore scale,ENHANCED OIL-RECOVERY; POROUS-MEDIA; CAPILLARY-FLOW; CO2 INJECTION; CONTACT-ANGLE; CRUDE-OIL; AGGREGATION PHENOMENA; INTERFACIAL-TENSION; PRESSURE DEPLETION; NATURAL DEPLETION,"Asphaltenes have been referred to 'cholesterol of petroleum' and the heaviest and the most complex components in crude oil. Asphaltene aggregation and deposition have always been a challenging issue on fluid transport in porous media for oil recovery and production processes in industries. Many experimental efforts have been done to study asphaltene aggregation and deposition from crude oil. Most of these works were carried out by coreflood tests or in bulk solution. Only several macroscopic parameters, such as pressure variation and permeability reduction caused by asphlatene deposition, were studied. Few experimental studies have been done to make the direct pore-scale visualization of dynamic asphaltene deposition behavior in capillary flow. In this study, we developed a new experimental approach to directly visualize and measure the dynamic asphaltene deposition process in capillary flow. Effects of concentration of asphaltene precipitant and flowrate were examined. The results indicate that the concentration of precipitant has a significant effect on the dynamic asphaltene deposition in capillary flow. The size of asphaltene deposit increases significantly with elapsed time and size distribution becomes wider at higher precipitant concentration. Higher concentration of asphaltene precipitant could lead to higher deposition rate. The results also indicate that higher flowrate causes faster growth of asphaltene deposits in capillary flow. Larger sizes of asphaltene deposits are formed and number of asphaltene deposits decreases with the elapsed time at higher flowrate. The results produced provide new sights into the dynamic asphaltene deposition in capillary flow at a pore scale. They could contribute to predict the growth rate of arterial asphaltene deposition in porous media and develop accurate numerical simulator for enhanced oil recovery purpose in industries.",19,20,5
Oil Recovery,CO2,"Guo, Feng; Aryana, Saman A.",Improved sweep efficiency due to foam flooding in a heterogeneous microfluidic device,Heterogeneous microfluidic device; Foam flood; Trapezoidal cross-section; Capillary entry pressure,ENHANCED OIL-RECOVERY; POROUS-MEDIA; 2-PHASE FLOW; DISPLACEMENT; MICROMODEL; SURFACTANT; NETWORK; MECHANISMS; GENERATION; BEHAVIOR,"In this work, the flow behavior of foam and its impact on mobility control in displacing oil are investigated using a glass microfluidic device comprising a complex heterogeneous porous medium. The medium, fabricated with a centrally located low permeability zone and two high permeability zones on its sides, is initially saturated with crude oil. A blend of surfactants are used to stabilize CO2 foam in the presence of crude oil. Flow behavior in the microfluidic device is captured using a high-resolution camera. Foam is able to mobilize and recover oil trapped in the low permeability zone by increasing the resistance to flow in the high permeability zones and diverting the surfactant solution into the adjacent low-permeability zone. Foam remains gas-rich in the high permeability zones and solvent-rich in the low permeability zone throughout the experiments. The observed displacement dynamics are explained by characterizing channel geometries and calculating capillary entry pressure values for various fluids and zones of the medium.",19,21,4
Oil Recovery,CO2,"Ren, Guangwei; Nguyen, Quoc P.; Hon Chung Lau",Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants,CO2 soluble surfactants; Partition coefficient; CO2 foam; Fractured carbonate reservoir; EOR,INTERFACIAL-TENSION; GRAVITY DRAINAGE; MOBILITY CONTROL; CRUDE-OIL; DISPLACEMENT; EOR; MICROEMULSIONS; WETTABILITY; SOLUBILITY; REDUCTION,"Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions. A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 degrees C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water. RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam. These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.",19,20,2
Oil Recovery,CO2,"Song, Zhaojie; Hou, Jirui; Liu, Xiaochun; Wei, Qi; Hao, Hongda; Zhang, Liya",Conformance control for CO2-EOR in naturally fractured low permeability oil reservoirs,CO2 flooding; Low permeability oil reservoir; Gas channeling; CO2 production control,CARBON-DIOXIDE; CO2 STORAGE; TIGHT OIL; RECOVERY; GAS; PERFORMANCE; IMPROVEMENT,"Poor sweep efficiency seriously limits field applications of CO2-EOR, especially in fractured reservoirs. The investigation of CO2 production performance and the method to control CO2 production becomes a key to successfully run a CO2-EOR project. In this study, artificial sandstone cores were used to perform a series of CO2 flooding experiments at reservoir conditions of pressure, temperature and formation water salinity. Injection pressure and rock heterogeneity were taken into account to study their effect on CO2 production performance. Two-stage gas channeling control with three different scenarios, including PLS gel and ethylenediamine, starch gel and ethylenediamine, and starch gel and CO2 foam, was presented to improve the conformance in 3-D fractured-core models. Based on production performance and experimental observation, three production stages were clearly stated, including gas-free production stage, oil/gas co-production stage, and gas channeling stage. Oil/ gas co-production stage contributed the most to oil recovery. This finding was very consistent with the practical production performance of CO2 flooding in oil fields. The conformance improvement and the increase in injection pressure (within permissible range bearing in mind of fracturing pressure) could remarkably enhance the oil recovery at oil/gas co-production stage. In 3-D radial flow experiments, the two-stage gas channeling control presented great potential in delaying gas production and improving CO2 flooding efficiency. The combination of starch gel and ethylenediamine achieved the best result. The starch gel could effectively block the fracture, while the viscous reactant of ethylenediamine and in-situ CO2 within high permeability layer could successfully tune injected CO2 to flood low permeability layer. This study could help field engineers determine the optimal timing of CO2 production control, and also offered an optimal method to improve the conformance for CO2-EOR.",17,17,8
Oil Recovery,CO2,"Chen, Mingyan; Wang, Hua; Liu, Yucheng; Ma, Lili; Wu, Donghai; Wang, Shanyi",Corrosion behavior study of oil casing steel on alternate injection air and foam liquid in air-foam flooding for enhance oil recovery,Alternating corrosion; Alternating injection frequency; Oil casing steel; Air-foam flooding,CARBON-STEEL; GALVANIZED STEEL; CO2 CORROSION; WET; PH; TEMPERATURE; EFFICIENCY; OXYGEN; WATER; IRON,"The effect of air and foam liquid alternating injection frequency on corrosion of oil casing steel in air-foam flooding process for enhanced oil recovery (EOR) was investigated in an autoclave. The characteristics of alternating corrosion in air-foam flooding were different from the conventional corrosion. The surface microtopography of corrosion scale was observed by scanning electron microscopy (SEM) at various alternating injection frequencies (F = 0, 1, 2, 4 and 6). In addition, energy dispersive spectrometry (EDS) and X-ray diffraction (XRD) were used to analyze the composition of the corrosion product when alternating injection frequency was F = 0, 1 and 6. The results showed that the corrosion rate was increased significantly with the increase of alternating injection frequency. Meanwhile, pitting gradually developed into localized corrosion, which then slowly led to general corrosion. Moreover, the main corrosion products were Fe(OH)(3), FeOOH, and Fe3O4 with alternating injection frequency for F = 0, F = 1 and F = 6, respectively. In this study, the alternating corrosion in air-foam flooding was investigated systematically, which would provide theoretical guidance for further research of air-foam corrosion.",17,20,4
Oil Recovery,CO2,"Lashkarbolooki, Mostafa; Riazi, Masoud; Ayatollahi, Shahab",Effect of CO2 and crude oil type on the dynamic interfacial tension of crude oil/carbonated water at different operational conditions,Dynamic IFT; Carbonated water; CO2; Adsorption time; Temperature; Pressure,CARBONATED WATER; AQUEOUS-SOLUTIONS; INJECTION; RECOVERY; PH; EQUILIBRIUM; TEMPERATURE; PERFORMANCE; ASPHALTENE; ADSORPTION,"Concerns about climate change have persuaded the researchers to examine CO2 injection in the form of carbonated water (CW) into oil reservoir as a safe and effective CO2 storage and enhanced oil recovery process. Although interfacial tension (IFT) between crude oil and injected fluid has a vital role on the displacement of fluids in porous media, the effect of CO2 and crude oil type on the dynamic IFT of crude oil under different operational conditions is not well understood. Accordingly, this study was carried out to assess the effects of temperature, pressure, crude oil type and CO2 on the dynamic IFT of crude oil/CW. To achieve this goal, two types of crude oil were provided from southern Iranian oil reservoirs and dynamic IFTs with CW were measured in a wide range of temperatures and pressures (i.e. temperature range of 30-80 degrees C and pressure range of 500-4000 psi); the obtained results were compared with the system without CO2. In addition, the adsorption time of carbonated aqueous phase/crude oil, obtained based on the mono exponential decay model, was also compared with unadulterated water/crude oil system. The outcome of this study showed that crude oil type has the most significant effect on the IFT of crude oil/CW compared to pressure, temperature and CO2 content. In more details, the IFT of crude oil/CW can be affected by the amount and type of acidic/basic components in the crude oil as well as pH of the aqueous solution. Besides, the obtained results revealed that the effect of temperature was more considerable on the IFT of the heavy crude oil compared with the light crude oil in both studied aqueous solutions (i.e. unadulterated water and CW). Although the inversion phase temperature was obtained for unadulterated water/studied crude oils at all studied pressures, this phenomenon was not observed for crude oil/CW at elevated pressure, due to the high amount of CO2 at this condition.",17,17,3
Oil Recovery,CO2,"Farmani, Zohreh; Azin, Reza; Fatehi, Rouhollah; Escrochi, Mehdi",Analysis of Pre-Darcy flow for different liquids and gases,Pre-Darcy flow; Hydrocarbon; Superficial velocity; Reynolds number; Friction factor,THROUGH POROUS-MEDIA; LAW; REGIMES; SPHERES,"Fluid flow in porous media is extensively associated with Darcy's law. Deviations from Darcy's law and its limitations result in modifications known as non-Darcy flow M high velocity and Pre-Darcy flow M low velocity. In this paper, experiments were conducted to explore significance of departure from linearity M low fluid velocity (Pre-Darcy flow) in porous media. Effect of different liquid and gas types on the onset of Pre-Darcy flow were studied for water, condensate, n-hexane and n-heptane as liquid phase and CH4, CO2 and N-2 as gas phase. Superficial velocity versus pressure gradient was measured and different onset values were reported. The minimum observed Darcy velocity was 0.189 x 10(-05) m/s, below which Pre-Darcy flow prevails. Analysis was performed in terms of friction factor and Reynolds number for different particle size of 0.15, 0.25 and 0.3 mm. Pre-Darcy, Darcy and Non-Darcy flow regimes were observed and characterized in terms of Re-root k , Re-d and Re-p. The range of Reynolds number were reported for different flow regimes, different particle sizes and different types of liquids. For the case of condensate in 0.15 mm sand pack, Pre-Darcy flow was observed in the range of Re-root k < 2.81 x 10(-06), Re-d < 0.0014 and Re-p < 0.0005. In addition to new liquids and gases that are investigated in this study, one of the differences between this study and previous ones, is investigation the relevance of Pre-Darcy flow to fluid properties in addition to rock properties for wide ranges of liquids and gases. The existence of Pre-Darcy flow means that, there is unknown opportunities for improved oil recovery in petroleum reservoirs. Also, accurate emission velocity is effective for reduction of soil pollution by hydrocarbon leakage. This velocity can be corrected by considering Pre-Darcy flow.",14,16,1
Oil Recovery,Porous Media,"Da, Chang; Alzobaidi, Shehab; Jian, Guoqing; Zhang, Leilei; Biswal, Sibani L.; Hirasaki, George J.; Johnston, Keith P.",Carbon dioxide/water foams stabilized with a zwitterionic surfactant at temperatures up to 150 degrees C in high salinity brine,CO2-in-water foam; Zwitterionic surfactant; Porous media; EOR,ENHANCED OIL-RECOVERY; WORMLIKE MICELLES; CONCENTRATED EMULSIONS; SUPERCRITICAL FLUIDS; MOBILITY CONTROL; MIXED-SOLUTIONS; AQUEOUS-PHASE; POROUS-MEDIA; YIELD-STRESS; ADSORPTION,"Stabilization of CO2-in-water (C/W) foams with surfactants at high temperature and high salinity conditions is challenging given limitations in the solubility and thermal stability of surfactants, particularly for surfactants other than anionic ones. Here we show that a single zwitterionic surfactant, cetyl betaine (CH3(CH2)(15)N+(CH3)(2)CH2COO-), stabilizes viscous C/W foam (> 15 cP) in crushed limestone (76-Darcy) at a temperature up to 150 degrees C and over a wide range in salinity up to 22% total dissolved solids (TDS) at superficial velocity of 940 ft/day. According to liquid chromatography mass spectrometry (LC/MS), cetyl betaine has high thermal stability with negligible chemical degradation after incubation at 135 degrees C for 30 days. Interfacial tension (IFT) at the C/W interface was reduced significantly from similar to 37 mN/m to < 5 mN/m with the addition of 0.08 mmol/L of cetyl betaine. Relative to ionic surfactants, the relatively weak electrostatic repulsion between the local charges in the headgroup is shown to produce strong adsorption at the C/W interface (similar to 134 angstrom(2)/molecule), resulting in generation of viscous foam (similar to 6 cP) even in pure water without added salt. At a low superficial velocity of 6 ft/day (shear rate 45 s(-1)) in a beadpack, foam was still formed with cetyl betaine. Static adsorption of cetyl betaine on carbonates was on the order of 1 mg/m(2), and core flood test also proved that cetyl betaine could stabilize viscous C/W foam (> 20 cP) within 6 pore volumes of injection at 120 degrees C. The surfactant stabilized viscous C/W foam at low oil fractions and broke in the presence of large fractions of oil, both of which are desirable in CO2 mobility control and oil displacement. The ability to form foams at high temperatures and over a wide range in salinity is important for various practical applications including CO2 enhanced oil recovery, fracturing with energized fluids and CO2 sequestration.",46,48,19
Oil Recovery,Porous Media,"Hanamertani, Alvinda Sri; Pilus, Rashidah M.; Idris, Ahmad Kamal; Irawan, Sonny; Tan, Isa M.",Ionic liquids as a potential additive for reducing surfactant adsorption onto crushed Berea sandstone,Static adsorption; Surfactant; Ionic liquid; Berea sandstone; Additive; EOR,SODIUM DODECYL-SULFATE; DEEP EUTECTIC SOLVENTS; ENHANCED OIL-RECOVERY; ANIONIC SURFACTANT; NONIONIC SURFACTANT; INTERFACIAL-TENSION; DYNAMIC ADSORPTION; NANOSTRUCTURES; MINERALS; CHLORIDE,"In chemical Enhanced Oil Recovery (EOR) applications, chemical sensitivity has been taken into account as a major challenge due to its interactions under harsh environment of the reservoirs leading to reduced oil recovery efficiency. For instance, surfactant adsorption onto the reservoir rock during chemical flooding processes causes chemical loss and hence degrades its performance in porous media. The addition of chemical which has been known as an environmental benign material could be applied to overcome surfactant adsorption. In this study, static adsorption experiments were conducted for two types of surfactant and three ionic liquid (IL)-based solutions using crushed Berea sandstone. Besides investigating their individual adsorption, the ability of imidazolium-based ILs and deep eutectic solvent (DES) which has been known as a biodegradable IL-based material with good solubility, to reduce surfactant adsorption was evaluated. Results indicate that surfactant adsorption is dependent on the surfactants types and concentrations. It was also indicated that ILs producing specific interactions with rock surface have a comparable possibility to adsorb onto reservoir rock, hence the potential to substitute surfactant as the adsorbate. The presence of certain concentration of IL in surfactant solution was found to be able to decrease surfactant adsorption onto crushed core sample. The addition of imidazolium-based IL and DES was able to decrease the anionic surfactant adsorption by three times. Other finding shows that DES also gives a significant reduction of in-house surfactant adsorption down to the noticeable value compared to other ILs. The different results on adsorption behavior obtained from the combination of various surfactants and ILs impart the high influence of the type of surfactant and IL applied.",43,44,2
Oil Recovery,Porous Media,"Zhou, Yazhou; Yin, Daiyin; Cao, Rui; Zhang, Chengli",The mechanism for pore-throat scale emulsion displacing residual oil after water flooding,Pore-throat scale; Emulsion; Viscoelasticity; Surfactant flooding; Displacement mechanism,POROUS-MEDIA; CRUDE-OIL; SURFACE-TENSION; RECOVERY; PARAMETERS; REDUCTION; VISCOSITY; POLYMER; FLOW,"The reservoir characteristics and fluid property of Daqing Oilfield was taken as the research platform. The emulsion was prepared by core displacement experiment. The stability of emulsion was analyzed by measuring the Zeta potential at different emulsifier concentrations. The emulsion viscoelasticity was also measured in different water cut stage. Displacement experiments of emulsion and surfactant flooding (poor emulsification) at the same interfacial tension were conducted, and the displacement efficiency of pore-throat scale emulsion (particle size greater than throat diameter but less than pore diameter) was studied. Using a visual sand packed model, displacement experiments allowed for the observation of the pore-throat scale emulsion displacing oil drop and columnar residual oil, and the deformation and migration process of residual oil were analyzed. The mechanism of pore-throat scale emulsion displacing residual oil was studied. The results show that with the emulsifier concentration increases, the absolute value of emulsion Zeta potential increases, and the stability of emulsion increases, the stability of pore-throat emulsion is preferably. When the water cut is 63.2%, the emulsion viscoelasticity is most favorably. When the emulsifier concentration is 0.4%, the emulsion flooding can enhance recovery efficiency by 9.84% compared to surfactant flooding with the same interfacial tension. The viscoelastic deformation of the pore-throat scale emulsion can pull the oil drop and columnar residual oil, and the residual oil can migrate.",35,34,5
Oil Recovery,Porous Media,"Unsal, E.; ten Berge, A. B. G. M.; Wever, D. A. Z.",Low salinity polymer flooding: Lower polymer retention and improved injectivity,Low salinity polymer; Retention; Rheology; Injectivity; Cation exchange,ENHANCED OIL-RECOVERY; POROUS-MEDIA; CATION-EXCHANGE; FLOW; SHEAR; FIELD,"Delayed arrival of the oil bank and reduced injectivity are risks which are commonly associated with low salinity polymer (LSP) flooding. In this study, experimental work was carried out to address these risks; the polymer retention and the cationic exchange in the presence of polymer were the main subjects of investigation. Single phase coreflood experiments were performed, where low and high salinity polymer (HSP) solutions, i.e., conventional polymer flood using formation brine, were injected in reservoir core plugs. The performance of the two polymer solutions were analyzed for polymer retention, injectivity and polymer acceleration. Compared to the HSP coreflood, the LSP coreflood showed considerably lower polymer retention and better long-term injectivity. There was no delay in polymer breakthrough, and the polymer acceleration was comparable to HSP floods. Analysis of produced effluent of the LSP coreflood detected divalent ion concentrations higher than the injected solution, and the solution which was already in equilibrium with the rock. This suggested that the divalent ions were released from the rock into the solution because of cation exchange in the presence of the LSP solution. Such increase in divalent ion concentration increased the polymer solution salinity and resulted in a viscosity loss. The results of the experimental study indicated that LSP flooding can be an attractive alternative to conventional polymer flooding, although viscosity loss due to cation exchange is a subject for further de-risking work. A numerical model which couples the cation exchange in presence of polymer with flow dynamics in core scale has also been developed. The flow field was used to advect the polymer which influenced the equilibrium condition between the rock surface and the solution. We present preliminary results obtained using the model which can be used to gain insights and study sensitivities around different geochemistry coupled flow processes.",33,34,0
Oil Recovery,Porous Media,"Xie, Chiyu; Lv, Weifeng; Wang, Moran",Shear-thinning or shear-thickening fluid for better EOR? - A direct pore-scale study,Multiphase flow; Non-Newtonian fluid; Diversion effect; Lattice Boltzmann method; Porous media; Enhanced Oil Recovery (EOR),ENHANCED OIL-RECOVERY; POROUS-MEDIA; FOAM; FLOW; POLYMERS; SWEEP; FIELD,"Non-Newtonian fluids are widely applied in Enhanced Oil Recovery (EOR) techniques, and the good performances have been ascribed to the shear-thinning or shear-thickening characteristics of them. In this paper, we aim at discovering the roles of these rheological properties in non-Newtonian fluid displacement from the pore scale. A recently developed lattice Boltzmann model (LBM) for multiphase viscoplastic fluid flow [ Xie et al. J Non-Newton Fluid, 2016.234: 118-128] is used. Displacements in both homogeneous and heterogeneous porous media are considered. For homogeneous cases, the performances of shear-thinning and shear-thickening fluids are almost the same when compared in favorable displacement regime; while the performance of shear-thinning fluid is poorer than that of shear-thickening fluid in unfavorable displacement regime. For heterogeneous cases, we demonstrate that the shear-thinning property does not contribute too much to the diversion effect, which clarifies the debate of understandings. Our pore-scale modeling results also indicate the significance of low viscosity ratio for diversion and EOR, which can stabilize the displacing front despite of the increased viscous resistance.",31,31,4
Oil Recovery,Porous Media,"Yuan, Bin; Moghanloo, Rouzbeh Ghanbarnezhad","Nanofluid pre-treatment, an effective strategy to improve the performance of low-salinity waterflooding",Low-salinity water flooding; Enhanced oil recovery; Nanofluids; Fines migration; Well injectivity,INDUCED FINES MIGRATION; POROUS-MEDIA; ANALYTICAL-MODEL; OIL-RECOVERY; INJECTION; SURFACE; REDUCTION; PARTICLES; TRANSPORT; CORES,"Low-salinity water (LSW) has been confirmed as a promising improved oil recovery technique. Implementing this technique, in some cases, induces fines migration and has posed great challenges on well injectivity. The aim of this work is to establish a mathematical foundation and explain the improved performance (both EOR and well injectivity) through nanofluid pre-treatment in single-layered and multi-layered heterogeneous reservoirs. We modify the fractional flow function while considering for fines straining effects in one-dimensional radial system, where fines migration varies with distance from the injection well owing to different drag forces. The interplay among nanoparticles, fines, and rocks is described through the maximum retention concentration of fine particles that depend upon both fluid quality and velocity. Our modification of the classical Buckley-Leverett theory leads to the characteristic curves along which water saturation varies. As low-salinity waterflooding continues, the induced fines migration delays the breakthrough of injected water, and bring uniform control of injected fluid entering each layer. On the other hand, fines migration may lead to the issue of well injectivity decline. Nanofluid pre-treatment can significantly mitigate fines migration near wellbore while it may occur far from the injection well. We discuss cases with different nanofluid treatment schemes prior to low-salinity waterflooding by comparing water-saturation profile, water-cut history plot, injection pressure, and oil recovery. A good agreement is obtained between semi-analytical solution and finite-difference simulation. It was observed that although nanofluid treatment slightly accelerate breakthrough of the injected water, it can help maintain long-term well injectivity and sweep efficiency. In practice, our work provides valuable insight to design of nanofluid utilization and improve efficiency of low-salinity waterflooding.",29,29,3
Oil Recovery,Porous Media,"Goswami, Rishiraj; Chaturvedi, Krishna Raghav; Kumar, Ravi Shankar; Chon, Bo Hyun; Sharma, Tushar",Effect of ionic strength on crude emulsification and EOR potential of micellar flood for oil recovery applications in high saline environment,Crude oil; Emulsion; Micellar flood; Rheology; SDS; Salt,NANOPARTICLE-SURFACTANT-POLYMER; IN-WATER EMULSIONS; INTERFACIAL-TENSION; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; HIGH-TEMPERATURE; SYSTEM; BEHAVIOR; CALCIUM; STABILITY,"Micellar flooding is one of the chemical oil recovery techniques in which micelle action emulsifies the crude oil to be mobilized in form of emulsion from a subsurface porous media. However, the subsurface conditions such as high ionic strength and temperature are challenges to the successful use of micellar flood owing to the deterioration of micelle action suggesting no crude emulsification. The ionic compounds dissociate into different ions that may further affect micelle action via loss in viscosity and pressure drop, increased water cut, and mobility contrast between micellar flood and displaced oil. Thus, investigation leading to the successful use of micellar flood, context to crude emulsion, in extreme salinity and temperature is vital to extend the use of chemical methods in new reservoirs. In this work, a typical surfactant sodium dodecyl sulfate (SDS) solution with critical micelle concentration (0.8 wt%) was tested to emulsify a fresh crude oil in the presence of varying ionic strength (0-4 wt%, NaCl/CaCl2 and temperature (40-98 degrees C). The efficacy of SDS micelles to produce crude emulsion significantly reduced with increasing salt concentration as reported through microscopic, rheological, and flooding experiments, particularly for divalent salt (CaCl2) than monovalent salt (NaCl). The increase in temperature (> 40 degrees C) further curtailed the growth of crude emulsion, mainly due to enhanced droplet coalescence; thus the use of micellar flood is critical in a reservoir enriched with high salinity and high temperature. Salinity effect on emulsion viscosity is reported through rheological measurements. The study highlighted important aspects of surfactant flooding and is a forward step towards the use of SDS based micellar flood at complex reservoir conditions.",29,28,1
Oil Recovery,Porous Media,"Feng, Haishun; Kang, Wanli; Zhang, Liming; Chen, Jun; Li, Zhe; Zhou, Qiong; Wu, Hairong",Experimental study on a fine emulsion flooding system to enhance oil recovery for low permeability reservoirs,Fine emulsion flooding; Low permeability reservoir; Enhanced oil recovery; Micromodel tests,HEAVY-OIL; POROUS-MEDIA; SURFACTANT; EMULSIFICATION; POLYMER; MECHANISM; PRESSURE; ALKALI; TIGHT,"Numerous studies and field application tests have shown that emulsification is an important mechanism to improve oil recovery. Fine emulsion (FE) with small droplets can improve oil recovery by displacing residual oil after water flooding at a low cost. In this work, a series of core displacement experiments were conducted to compare the effectiveness of different chemical flooding for crude oil. Then, the oil-water interfacial tension (IFT), viscosity and rheological properties were studied thoroughly to understand the displacement mechanism by using an interfacial tensiometer, a viscometer or a rheometer. Finally, micromodel flooding tests were performed to demonstrate the suitability and effectiveness of FE flooding for oil recovery for low permeability reservoirs. The displacement results show that the oil recovery efficiency can reach 16.8% after water flooding by the optimum FE flooding system. The FE flooding system has viscoelastic properties, strong emulsifying performance and stability. Such behavior can reduce the IFT value to the magnitude of 10(-1) mN/m and improve the mobility ratio. The displacement mechanism of FE enhanced oil recovery (EOR) is that emulsification can improve the displacement efficiency and increase the swept efficiency. The micromodel tests indicate that the emulsification mechanisms include emulsification carrying-on and the performance control of the O/W emulsion. The FE flooding system has powerful EOR potential for low permeability reservoirs.",27,28,8
Oil Recovery,Porous Media,"Chequer, L.; Vaz, A.; Bedrikovetsky, P.",Injectivity decline during low-salinity waterflooding due to fines migration,Low-salinity waterflooding; Injectivity; Formation damage; Fines migration; Analytical model; Laboratory data,POROUS-MEDIA; WATER INJECTION; FORMATION DAMAGE; PERMEABILITY VARIATION; SANDSTONE RESERVOIRS; COLLOIDAL TRANSPORT; MATHEMATICAL-MODEL; FILTRATION; PARTICLES; DETACHMENT,"Injectivity damage by fines migration during low-salinity water injection can highly affect field-scale waterflooding projects. In this paper, we develop novel analytical models for one-dimensional linear and radial suspension-colloidal flows accounting for detachment, mobilisation, migration, and straining of natural reservoir fines. We also perform laboratory corefloods by water with piecewise constant decreasing salinity, and with monitoring the breakthrough particle concentration and pressure drop across the core. The analytical model for linear flows matches the laboratory data with high accuracy, and tuned model coefficients belong to the common-value intervals for those coefficients. The analytical model for radial flows predicts well behaviour; the experimental-data-tuned coefficients are used for reliable laboratory-based prediction of injectivity index decline. The calculations show a significant decline of injection-well index due to fines migration during low-salinity water injection.",26,27,1
Oil Recovery,Porous Media,"Agi, Augustine; Junin, Radzuan; Chong, Aik Shye",Intermittent ultrasonic wave to improve oil recovery,Ultrasound; Intermittent ultrasonic vibration; Micro-model; Viscosity; Dimensionless parameters; Enhanced oil recovery,RESERVOIR CONDITIONS; POISEUILLE FLOW; RADIATION; WATER; MIGRATION; FORCES,"This paper presents the use of intermittent vibration as a cost-effective and environmentally friendly approach to enhance oil recovery (EOR). Previous research work has focused only on continuous ultrasonic vibration, but the continuous vibration has its limitation of the high cost of the production and maintenance of equipment because of the high energy generated. For this purpose, a 2D micro-model placed inside an ultrasonic bath under an ultrasound vibration was used to determine the effect of viscosity, intensity and the distance between the energy source and the micro-model. Dimensionless parameters were used to reduce the number of parameters to be studied by scaling the miscible and immiscible displacement in the porous media and to predict the fluid flow pattern. A stereo microscope with the camera mounted at the top of the micro-model recorded the displacement process. The snapshot of each time interval was used to give the estimate in percent (%) of the residual oil left in the micro-model. The outcome reveals that the use of intermittent vibration can recover more oil compared with the application using continuous vibration. The oil recovery increased with increase in the dimensionless parameters. The Reynold's number indicated that the flow was dominated by a laminar flow. The combination of intermittent vibration, high viscosity, high intensity and a short distance from the energy source gave the best recovery of oil.",22,24,1
Oil Recovery,Porous Media,"Taheri-Shakib, Jaber; Shekarifard, Ali; Naderi, Hassan",Experimental investigation of the asphaltene deposition in porous media: Accounting for the microwave and ultrasonic effects,Asphaltene precipitation; Permeability; Microwaves; Ultrasonic waves; Polar components; Porous media,HEAVY CRUDE-OIL; MODELING FORMATION DAMAGE; PRECIPITATION; PERMEABILITY; IRRADIATION; DESULFURIZATION; FLOCCULATION; CARBONATES; RECOVERY; COAL,"This study examines the effects of ultrasonic waves (US) and microwaves (MW) on the permeability in carbonate cores with different permeabilities of asphaltenes deposited therein. Using US with toluene injection restores permeability in cores with a permeability of less than 20 md, about 18.8% and 29% higher than injection of toluene without US. The US creates turbulence and cavitation, causing a change in the structure of the asphaltene conglomerations deposited in the cores. These structural changes may be due to increased levels of contact between precipitates and better penetration of the injected fluid which facilitate the process of removing them from the cores. MW, in addition to changing the structure of asphaltene clusters within the cores, reduces the amount of their polar elements, including sulfur (S), nitrogen (N), and oxygen (O). Under MW irradiation, the sulfur, nitrogen, and oxygen values were 23.5%, 18.4% and 48%, respectively. This decrease in the amount of asphaltene polar elements, which is due to their high capacity to absorb MW can reduce the negative charges in asphaltene particles. The zeta potential results also indicated that the negative charges of asphaltene particles decreased and became more positive as a result of MW radiation (from -12.31 mV to -7.59 mV). Fourier transform infrared spectroscopy (FTIR) spectra tests also confirmed these results. The polar bands of the asphaltene particles deposited inside the cores (OH, S-H; C=O) had a decreasing trend and escaped from the structure of the asphaltene clusters. Decreasing the polar values, especially those of the compounds with negative electrical charge (SO) actually reduces the adhesive force between asphaltene and limestone that has positive electrical charges. This phenomenon causes the removal of asphaltene particles from the porous rock media. The rate at which permeability is restored also indicates that MW radiation is much higher than the previous one (US thorn Toluene), especially cores with low permeability. The results of this study could be a major step towards removing asphaltene precipitates in oil reservoirs using US and MW technologies.",21,21,5
Oil Recovery,Porous Media,"Hasham, Aleem A.; Abedini, Ali; Jatukaran, Arnav; Persad, Aaron; Sinton, David",Visualization of fracturing fluid dynamics in a nanofluidic chip,Fracturing fluid; Infiltration; Entrapment; Recovery; Nanofluidic,MICROFLUIDICS-BASED MEASUREMENT; PORE-SCALE ANALYSIS; SPONTANEOUS IMBIBITION; OIL-RECOVERY; GAS SHALES; HEAVY OIL; CO2; TEMPERATURE; PRESSURE,"Hydraulic fracturing is responsible for remarkable production from shale and tight formations, albeit at the cost of significant water usage. The flow dynamics of oil and fracturing fluid in nanopores remains largely uncharacterized, in part due to the challenge of conducting experiments at nanoscales. In this paper, we demonstrate a nanofluidic-based approach to visualize the fluid displacement during hydraulic fracturing. Nanoporous silicon-glass chips with circular and square grain shapes and identical depth of 175 nm were fabricated using reactiveion etching (RIE) and anodic bonding. Leveraging the inherent fluorescence property of the oil, the fluorescence microscopy was used to record the dynamics of the fluid displacement inside the chip. Performance of three different fracturing fluids - deionized water, potassium chloride (KCl) solution, and slick water - were evaluated based on the volumetric infiltration in the nanoporous network, entrapment of fracturing fluid in the porous media, and total production during drawdown. The KCl solution had the highest infiltration rate (fill factor of 0.68) and the lowest entrapment factor (0.39), resulting in the highest fracturing fluid recovery representing 43% in the square grain geometry with similar results for circular grains. With the fast quantification and ease of operation here, the nanofluidic approach enables a rapid screening of different fracturing fluids to inform shale oil operators.",20,21,3
Oil Recovery,Porous Media,"Li, Xingxun; Guo, Yunmei; Sun, Qiang; Lan, Wenjie; Liu, Aixian; Guo, Xuqiang",Experimental study for the impacts of flow rate and concentration of asphaltene precipitant on dynamic asphaltene deposition in microcapillary medium,Asphaltene deposition; Visualization; Capillary flow; Microcapillary; Pore scale,ENHANCED OIL-RECOVERY; POROUS-MEDIA; CAPILLARY-FLOW; CO2 INJECTION; CONTACT-ANGLE; CRUDE-OIL; AGGREGATION PHENOMENA; INTERFACIAL-TENSION; PRESSURE DEPLETION; NATURAL DEPLETION,"Asphaltenes have been referred to 'cholesterol of petroleum' and the heaviest and the most complex components in crude oil. Asphaltene aggregation and deposition have always been a challenging issue on fluid transport in porous media for oil recovery and production processes in industries. Many experimental efforts have been done to study asphaltene aggregation and deposition from crude oil. Most of these works were carried out by coreflood tests or in bulk solution. Only several macroscopic parameters, such as pressure variation and permeability reduction caused by asphlatene deposition, were studied. Few experimental studies have been done to make the direct pore-scale visualization of dynamic asphaltene deposition behavior in capillary flow. In this study, we developed a new experimental approach to directly visualize and measure the dynamic asphaltene deposition process in capillary flow. Effects of concentration of asphaltene precipitant and flowrate were examined. The results indicate that the concentration of precipitant has a significant effect on the dynamic asphaltene deposition in capillary flow. The size of asphaltene deposit increases significantly with elapsed time and size distribution becomes wider at higher precipitant concentration. Higher concentration of asphaltene precipitant could lead to higher deposition rate. The results also indicate that higher flowrate causes faster growth of asphaltene deposits in capillary flow. Larger sizes of asphaltene deposits are formed and number of asphaltene deposits decreases with the elapsed time at higher flowrate. The results produced provide new sights into the dynamic asphaltene deposition in capillary flow at a pore scale. They could contribute to predict the growth rate of arterial asphaltene deposition in porous media and develop accurate numerical simulator for enhanced oil recovery purpose in industries.",19,20,5
Oil Recovery,Porous Media,"Guo, Feng; Aryana, Saman A.",Improved sweep efficiency due to foam flooding in a heterogeneous microfluidic device,Heterogeneous microfluidic device; Foam flood; Trapezoidal cross-section; Capillary entry pressure,ENHANCED OIL-RECOVERY; POROUS-MEDIA; 2-PHASE FLOW; DISPLACEMENT; MICROMODEL; SURFACTANT; NETWORK; MECHANISMS; GENERATION; BEHAVIOR,"In this work, the flow behavior of foam and its impact on mobility control in displacing oil are investigated using a glass microfluidic device comprising a complex heterogeneous porous medium. The medium, fabricated with a centrally located low permeability zone and two high permeability zones on its sides, is initially saturated with crude oil. A blend of surfactants are used to stabilize CO2 foam in the presence of crude oil. Flow behavior in the microfluidic device is captured using a high-resolution camera. Foam is able to mobilize and recover oil trapped in the low permeability zone by increasing the resistance to flow in the high permeability zones and diverting the surfactant solution into the adjacent low-permeability zone. Foam remains gas-rich in the high permeability zones and solvent-rich in the low permeability zone throughout the experiments. The observed displacement dynamics are explained by characterizing channel geometries and calculating capillary entry pressure values for various fluids and zones of the medium.",19,21,4
Oil Recovery,Porous Media,"Luo, Haishan; Delshad, Mojdeh; Pope, Gary A.; Mohanty, Kishore K.",Scaling up the interplay of fingering and channeling for unstable water/polymer floods in viscous-oil reservoirs,Fingering; Channeling; Viscous oil; Water/polymer flood; Field simulation,POROUS-MEDIA; PERMEABILITY HETEROGENEITY; DISPLACEMENT; INSTABILITY; STABILITY; SIMULATOR; FLUID; FLOW,"Unstable displacement and the resulting viscous fingers remain a challenge for reservoir simulation as practical gridblock sizes are usually much larger than the viscous finger wavelength. Traditional reservoir simulators do not consider sub-grid viscous fingering effects and tend to overestimate the oil recovery at the field scale. Several previous studies suggested that fingering can be ignored at the field scale because channeling (caused by heterogeneity) is dominant, but they missed the existence of viscous fingering at the small scale, which affects the displacement efficiency. In our work, we consider that fingering and channeling coexist in the field across different scales, based on the fact that the heterogeneity increases with the scale. At the small-scale (e.g., lab-scale) where heterogeneity is small, fingering is dominant and causes oil bypassing. An effective-fingering model was developed to scale up fingering effects. The model divides each gridblock into three dynamic regions: two-phase flow, oil single-phase flow, and bypassed-oil regions. Model parameters represent the maximum fraction of viscous fingering and the growth factors of different regions, and they are used to modify flow functions. Model parameters from history-matches of a set of laboratory experiments show clear power-law correlations with a dimensionless viscous finger number, a function of viscosity ratio, fluid velocity, permeability, interfacial tension, and core cross-sectional area. The correlation was achieved at the lab-scale by considering relatively homogeneous cores. We extended it further to the field scale by performing high-order spatially accurate numerical simulations at the intermediate scale using gridblock sizes that are roughly the same as that of the core. Geostatistical realizations of the permeability field were generated with various variances and correlation lengths. In a statistical way, we were able to quantify the viscous finger number for a gridblock at the field-scale affected by various heterogeneities. It is also observed that channelized permeability distributions increase the viscous finger number drastically, showing the important role of channeling in such cases. This new model was applied to a synthetic field case with high heterogeneity undergoing water/polymer floods. It is observed that the oil recovery was improved by the polymer slug because of the enhancement in both local displacement efficiency and sweep efficiency.",18,19,2
Oil Recovery,Porous Media,"Lashkarbolooki, Mostafa; Riazi, Masoud; Ayatollahi, Shahab",Effect of CO2 and crude oil type on the dynamic interfacial tension of crude oil/carbonated water at different operational conditions,Dynamic IFT; Carbonated water; CO2; Adsorption time; Temperature; Pressure,CARBONATED WATER; AQUEOUS-SOLUTIONS; INJECTION; RECOVERY; PH; EQUILIBRIUM; TEMPERATURE; PERFORMANCE; ASPHALTENE; ADSORPTION,"Concerns about climate change have persuaded the researchers to examine CO2 injection in the form of carbonated water (CW) into oil reservoir as a safe and effective CO2 storage and enhanced oil recovery process. Although interfacial tension (IFT) between crude oil and injected fluid has a vital role on the displacement of fluids in porous media, the effect of CO2 and crude oil type on the dynamic IFT of crude oil under different operational conditions is not well understood. Accordingly, this study was carried out to assess the effects of temperature, pressure, crude oil type and CO2 on the dynamic IFT of crude oil/CW. To achieve this goal, two types of crude oil were provided from southern Iranian oil reservoirs and dynamic IFTs with CW were measured in a wide range of temperatures and pressures (i.e. temperature range of 30-80 degrees C and pressure range of 500-4000 psi); the obtained results were compared with the system without CO2. In addition, the adsorption time of carbonated aqueous phase/crude oil, obtained based on the mono exponential decay model, was also compared with unadulterated water/crude oil system. The outcome of this study showed that crude oil type has the most significant effect on the IFT of crude oil/CW compared to pressure, temperature and CO2 content. In more details, the IFT of crude oil/CW can be affected by the amount and type of acidic/basic components in the crude oil as well as pH of the aqueous solution. Besides, the obtained results revealed that the effect of temperature was more considerable on the IFT of the heavy crude oil compared with the light crude oil in both studied aqueous solutions (i.e. unadulterated water and CW). Although the inversion phase temperature was obtained for unadulterated water/studied crude oils at all studied pressures, this phenomenon was not observed for crude oil/CW at elevated pressure, due to the high amount of CO2 at this condition.",17,17,3
Oil Recovery,Porous Media,"Franco-Aguirre, Maribel; Zabala, Richard D.; Lopera, Sergio H.; Franco, Camilo A.; Cortes, Farid B.",Ca-DTPMP nanoparticles-based nanofluids for the inhibition and remediation of formation damage due to CaCO3 scaling in tight gas-condensate reservoirs,Calcium carbonate; Formation damage; Inhibition; Nanofluid; Phosphonate; Remediation,CALCIUM-CARBONATE PRECIPITATION; PHOSPHONATE; ADSORPTION; MEDIA; OIL,"The oil productivity of tight gas-condensate reservoirs can be affected by the precipitation/deposition of inorganic scales such calcium carbonate (CaCO3), which leads to a reduction mainly in permeability and porosity of the porous media. Therefore, the main objective of this study is to develop for the first time a nanofluid based on the interaction between active nanoparticles such as Ca-diethylenetriamine pentamethylene phosphonic (Ca-DTPMP) and remaining synthesis fluid (RSF) obtained from the synthesis process, to simultaneously inhibit and remove the formation damage due to the precipitation/deposition of CaCO3 scales. The synthesis of the Ca-DTPMP nanoparticles was performed varying the phosphonate concentration between 0.01 and 0.5 M. The obtained nanoparticles were characterized through N-2 physisorption at - 196 degrees C for obtaining the surface area (S-BET), field emission scanning electron microscopy (FESEM), and dynamic light scattering (DLS) measurements. The mean nanoparticles size of the obtained materials ranged between 36 and 69 nm and was lower for the nanoparticles synthesized with a lower concentration of DTPMP. Nanofluids containing the synthesized nanoparticles of Ca-DTPMP were prepared with RSF solutions in deionized water as a carrier fluid for different Ca-DTPMP/RSF ratios of 10, 50, 200 and 500. The ability of the nanoparticles and nanofluids to inhibit the CaCO3 scaling was evaluated in batch-mode experiments at 70 degrees C by measuring changes in the calcium ion (Ca2+) concentration in the solution. The nanofluid with better performance was that prepared with 50 mg/L of Ca-DTPMP/0.3 nanoparticles and a Ca-DTPMP/RSF ratio of 10, with an inhibition efficiency of 67%. Further, coreflooding tests were carried out using the nanofluid with better performance from the batch-mode experiments. Displacement tests were conducted under tight gas-condensate reservoir conditions at a temperature of 110 degrees C (230 degrees F) and confining and pore pressures of 34.47 MPa (5000 Psi) and 6.89 MPa (1000 Psi), respectively. Inhibition and remediation of CaCO3 scaling were evaluated. The nanofluid was soaked in the porous media for 8 h. Based on the results of the relative permeability and oil recovery curves, it is possible to conclude that the synthesized nanofluid promotes the inhibition and removal of the formation damage due to CaCO3 inorganic scales. The nanofluid injection leads to an increase of the oil permeability of 57% in comparison with the base system, suggesting that the nanofluid acts as inhibitor agent, as remediation treatment, and as stimulation product of oil wells. Also, the treatment showed a perdurability of more than 60 pore volumes and increasing of oil recovery of 4 and 24% regarding the base and the damaged systems, respectively.",16,16,1
Oil Recovery,Porous Media,"Silva, Ivonete P. G.; Aguiar, Amaury A.; Rezende, Viviane P.; Monsores, Andre L. M.; Lucas, Elizabete F.",A polymer flooding mechanism for mature oil fields: Laboratory measurements and field results interpretation,Enhanced oil recovery; Polymer flooding; Mobility; Rheology; Particle size,LIGHT-SCATTERING; MOLECULAR-WEIGHT; POLYACRYLAMIDE; FLOW; DEPENDENCE; RECOVERY; POLYELECTROLYTE; TEMPERATURE; COPOLYMERS; RETENTION,"Although polymer flooding has been widely studied in the literature on oil recovery, many questions remain about the technique's action mechanisms. It is widely accepted that the process is based on increasing viscosity of the aqueous phase (injected fluid). The polymer can also act secondarily by reducing the relative permeability to water. Fields that are markedly heterogeneous, highly depleted or that contain fluids with strong salinity are not good candidates for the process. To overcome these restrictions, the most recent applications have used more resistant polymers, with higher molar masses, injected in larger quantities, to preserve the level of viscosity under these adverse conditions. However, a pilot test in a field under adverse conditions showed surprising results and unexpected pressure abnormality, even with small quantities of partially hydrolyzed polyacrylamide (HPAM) with relatively low molar mass (6 x 10(6) g/mol). This paper reports the investigation of the prevailing mechanism responsible for these unexpected results, by means of laboratory tests of flow in porous media and rheological analysis of fluids and hydrodynamic diameter of polymer molecules. The Salt effect (NaCl) on polymer solutions was researched by rheology and particle size analysis at 25 and 50 degrees C. The results showed that mechanical/hydrodynamic retention prevails over polymer adsorption at the rock, with the former being caused by the increase in the polymeric hydrodynamic volume in fluid dilution processes. Besides this, increased temperature was found to favor greater hydrodynamic volume under tested conditions, while salinity had little influence. The results also shed new light on the flow behavior of polymer solutions in porous media, particularly in polymer injection for enhanced oil recovery from mature fields.",15,15,3
Oil Recovery,Porous Media,"Taheri-Shakib, Jaber; Shekarifard, Ali; Naderi, Hassan",The study of influence of electromagnetic waves on the wettability alteration of oil-wet calcite: Imprints in surface properties,Wettability; Heavy oil; Microwave; Calcite; Polar,APPEARANCE TEMPERATURE WAT; CONTACT-ANGLE; RECOVERY; MICROWAVE; SALINITY; CARBONATE; ROUGHNESS; IMPACT; TIME; GAS,"The wettability of reservoir rock is one of the fundamental parameters determining the flow of fluid in the porous media. This study has investigated the effect of microwaves on the wettability of calcite reservoir rock from Yaran, Iran, as the time interval of microwave radiation is one of the most important parameters affecting wettability. The reservoir rock samples were placed in a microwave oven filled with helium gas and subjected to microwave radiation at 5-min intervals from 5 to 35 min. Measurements of the contact angle between the oil and the rock indicated that the microwaves brought the angle from about 120 degrees primary state to 93 degrees at 35 min. At intervals of 5-15 min, no change in the wettability of the oil-wet rock was observed. Sulfur components had high absorption coefficients of microwaves, so initially reduced the amount of sulfur (S) on the surface of the oil-wet rock. Next, the nitrogen (N) and oxygen (O) elements were reduced, and eventually the carbon (C) levels began to decrease. This trend was observed in the zeta potential by changing the surface charge of the rock. Indeed, eliminating SNO polar compounds with a high potential for absorbing microwave caused the rock to become water-wet. Microwave radiation initially produced no change in the Fourier-transform infrared spectroscopy (FTIR) spectrum, as it continued, the peak intensity of the corresponding oil, such as the carboxylic acid functional group, declined, and the corresponding peaks of the rock became more intense, indicating a gradual change in the wettability. It can be interpreted that the aromatic compounds exist in oil and act as surface agent components. The results of this study can be used as a representation of the use of microwave radiation in hydrocarbon reservoirs to change the wettability and increase the production rate of reservoirs.",15,15,0
Oil Recovery,Porous Media,"Boujelben, Ahmed; McDougall, Steven; Watson, Michael; Bondino, Igor; Agenet, Nicolas",Pore network modelling of low salinity water injection under unsteady-state flow conditions,Pore network modelling; Low salinity; Secondary water injection; Tertiary water injection; Unsteady-state flow; Contact angle modification,OIL-RECOVERY; WETTABILITY ALTERATION; BRINE COMPOSITION; POROUS-MEDIA,"In this work, we describe a dynamic pore network model that has been developed to investigate the effects of low salinity (LS) water injection on oil recovery under dynamic flow conditions. For the first time, we introduce a formulation whereby the evolving spatial distribution of brine salinity is explicitly tracked during unsteady-state secondary and tertiary LS floods. Phases are updated in capillary elements according to the relative balance between capillary and viscous forces, the former being correlated to salinity through a functional relationship between effective contact angle (i.e. wettability) and local brine concentration. We have investigated the impact of several key parameters on secondary and tertiary LS injection, including: injection rate, viscosity ratio, and salinity-induced wettability modifications. We have implemented a stochastic approach throughout in order to assess statistical variability in recovery outcomes. For the particular network architecture studied, simulations have shown a range of results for different induced wettability changes. When the contact angle variation shifted the system from strongly oil-wet to weakly oil-wet, most cases exhibited a small positive secondary LS effect but negligible tertiary benefit. Greater variation in LS outcome was observed when LS brine modified pores to close to neutral-wet conditions - a generally positive secondary LS effect was seen but there were several exceptions dependent upon frontal advance rate and viscosity ratio, where the displacement regime could switch from capillary-dominated flow to viscous fingering. Salinity modification of wettability to a water-wet configuration resulted in positive secondary LS displacement and a positive tertiary LS effect. The study shows that the impact of LS injection can often be difficult to predict a priori for any given combination of rock/fluid parameters and laboratory protocol, due to the complex way in which the underlying parameters interact. When compared against high salinity (HS) data, both positive and negative LS effects have been observed depending upon the prevailing system properties and the timing of LS initiation. However, by running a series of network modelling simulations, we are able to identify areas of parameter space that are more likely to elicit a positive LS response. In particular, we observe that a change in the dominant flow regime (capillary fingering, viscous fingering, frontal advance) may be induced by the injection of LS brine and this has been found to play an important role in determining LS efficacy.",14,14,2
Oil Recovery,Porous Media,"Farmani, Zohreh; Azin, Reza; Fatehi, Rouhollah; Escrochi, Mehdi",Analysis of Pre-Darcy flow for different liquids and gases,Pre-Darcy flow; Hydrocarbon; Superficial velocity; Reynolds number; Friction factor,THROUGH POROUS-MEDIA; LAW; REGIMES; SPHERES,"Fluid flow in porous media is extensively associated with Darcy's law. Deviations from Darcy's law and its limitations result in modifications known as non-Darcy flow M high velocity and Pre-Darcy flow M low velocity. In this paper, experiments were conducted to explore significance of departure from linearity M low fluid velocity (Pre-Darcy flow) in porous media. Effect of different liquid and gas types on the onset of Pre-Darcy flow were studied for water, condensate, n-hexane and n-heptane as liquid phase and CH4, CO2 and N-2 as gas phase. Superficial velocity versus pressure gradient was measured and different onset values were reported. The minimum observed Darcy velocity was 0.189 x 10(-05) m/s, below which Pre-Darcy flow prevails. Analysis was performed in terms of friction factor and Reynolds number for different particle size of 0.15, 0.25 and 0.3 mm. Pre-Darcy, Darcy and Non-Darcy flow regimes were observed and characterized in terms of Re-root k , Re-d and Re-p. The range of Reynolds number were reported for different flow regimes, different particle sizes and different types of liquids. For the case of condensate in 0.15 mm sand pack, Pre-Darcy flow was observed in the range of Re-root k < 2.81 x 10(-06), Re-d < 0.0014 and Re-p < 0.0005. In addition to new liquids and gases that are investigated in this study, one of the differences between this study and previous ones, is investigation the relevance of Pre-Darcy flow to fluid properties in addition to rock properties for wide ranges of liquids and gases. The existence of Pre-Darcy flow means that, there is unknown opportunities for improved oil recovery in petroleum reservoirs. Also, accurate emission velocity is effective for reduction of soil pollution by hydrocarbon leakage. This velocity can be corrected by considering Pre-Darcy flow.",14,16,1
Oil Recovery,Interfacial Tension,"You, Qing; Wang, Huan; Zhang, Yan; Liu, Yifei; Fang, Jichao; Dai, Caili",Experimental study on spontaneous imbibition of recycled fracturing flow-back fluid to enhance oil recovery in low permeability sandstone reservoirs,Recycled fracturing flow-back fluid; Spontaneous imbibition; Wettability alteration; Interfacial tension; Synergistic effect,WETTABILITY ALTERATION; SURFACTANT; NANOFLUIDS; CARBONATES; IFT,"In light of the high treatment costs for massive amounts of fracturing flow-back fluid and its harmfulness to the environment, a novel method of recycled fracturing flow-back fluid (RFFF) to enhance oil recovery by spontaneous imbibition is proposed in this study; this method does not allow the flow-back fluid back to the ground, thereby preventing negative impacts. The wettability alteration and interfacial tension (IFT) can effectively strengthen the spontaneous imbibition to enhance oil recovery in low-permeability sandstone reservoirs. This study combines the effects of wettability alteration and IFT with the use of the RFFF, which is composed of viscoelastic surfactants, on the spontaneous imbibition in low-permeability outcrop cores. Contact angle (CA) experiments, IFT experiments, and spontaneous imbibition experiments are conducted. The CA and IFT experimental results showed that the RFFF solutions changed the wettability of the core surface from oil-wet to waterwet and easily reduced the IFT between the crude oil and the RFFF solution to 10(-3)-10(-2) mN/m, which improved the oil recovery by changing the capillary forces. The spontaneous imbibition results showed that the RFFF solutions at concentrations of 0.03 - 0.10 wt% resulted in a higher imbibition recovery due to the synergistic effect of the wettability alteration and the IFT, which was attributed to the wedge film structure and the spreading force. It can be concluded that the use of the RFFF has the potential to further enhance oil recovery after fracturing the formation in low-permeability reservoirs without letting the fluid flow back to the ground. The proposed method is multi-functional and does not only improve the oil recovery by integrating fracturing and displacement methods but also reduces the costs of reservoir development and protects the environment.",100,103,14
Oil Recovery,Interfacial Tension,"Da, Chang; Alzobaidi, Shehab; Jian, Guoqing; Zhang, Leilei; Biswal, Sibani L.; Hirasaki, George J.; Johnston, Keith P.",Carbon dioxide/water foams stabilized with a zwitterionic surfactant at temperatures up to 150 degrees C in high salinity brine,CO2-in-water foam; Zwitterionic surfactant; Porous media; EOR,ENHANCED OIL-RECOVERY; WORMLIKE MICELLES; CONCENTRATED EMULSIONS; SUPERCRITICAL FLUIDS; MOBILITY CONTROL; MIXED-SOLUTIONS; AQUEOUS-PHASE; POROUS-MEDIA; YIELD-STRESS; ADSORPTION,"Stabilization of CO2-in-water (C/W) foams with surfactants at high temperature and high salinity conditions is challenging given limitations in the solubility and thermal stability of surfactants, particularly for surfactants other than anionic ones. Here we show that a single zwitterionic surfactant, cetyl betaine (CH3(CH2)(15)N+(CH3)(2)CH2COO-), stabilizes viscous C/W foam (> 15 cP) in crushed limestone (76-Darcy) at a temperature up to 150 degrees C and over a wide range in salinity up to 22% total dissolved solids (TDS) at superficial velocity of 940 ft/day. According to liquid chromatography mass spectrometry (LC/MS), cetyl betaine has high thermal stability with negligible chemical degradation after incubation at 135 degrees C for 30 days. Interfacial tension (IFT) at the C/W interface was reduced significantly from similar to 37 mN/m to < 5 mN/m with the addition of 0.08 mmol/L of cetyl betaine. Relative to ionic surfactants, the relatively weak electrostatic repulsion between the local charges in the headgroup is shown to produce strong adsorption at the C/W interface (similar to 134 angstrom(2)/molecule), resulting in generation of viscous foam (similar to 6 cP) even in pure water without added salt. At a low superficial velocity of 6 ft/day (shear rate 45 s(-1)) in a beadpack, foam was still formed with cetyl betaine. Static adsorption of cetyl betaine on carbonates was on the order of 1 mg/m(2), and core flood test also proved that cetyl betaine could stabilize viscous C/W foam (> 20 cP) within 6 pore volumes of injection at 120 degrees C. The surfactant stabilized viscous C/W foam at low oil fractions and broke in the presence of large fractions of oil, both of which are desirable in CO2 mobility control and oil displacement. The ability to form foams at high temperatures and over a wide range in salinity is important for various practical applications including CO2 enhanced oil recovery, fracturing with energized fluids and CO2 sequestration.",46,48,19
Oil Recovery,Interfacial Tension,"Hanamertani, Alvinda Sri; Pilus, Rashidah M.; Idris, Ahmad Kamal; Irawan, Sonny; Tan, Isa M.",Ionic liquids as a potential additive for reducing surfactant adsorption onto crushed Berea sandstone,Static adsorption; Surfactant; Ionic liquid; Berea sandstone; Additive; EOR,SODIUM DODECYL-SULFATE; DEEP EUTECTIC SOLVENTS; ENHANCED OIL-RECOVERY; ANIONIC SURFACTANT; NONIONIC SURFACTANT; INTERFACIAL-TENSION; DYNAMIC ADSORPTION; NANOSTRUCTURES; MINERALS; CHLORIDE,"In chemical Enhanced Oil Recovery (EOR) applications, chemical sensitivity has been taken into account as a major challenge due to its interactions under harsh environment of the reservoirs leading to reduced oil recovery efficiency. For instance, surfactant adsorption onto the reservoir rock during chemical flooding processes causes chemical loss and hence degrades its performance in porous media. The addition of chemical which has been known as an environmental benign material could be applied to overcome surfactant adsorption. In this study, static adsorption experiments were conducted for two types of surfactant and three ionic liquid (IL)-based solutions using crushed Berea sandstone. Besides investigating their individual adsorption, the ability of imidazolium-based ILs and deep eutectic solvent (DES) which has been known as a biodegradable IL-based material with good solubility, to reduce surfactant adsorption was evaluated. Results indicate that surfactant adsorption is dependent on the surfactants types and concentrations. It was also indicated that ILs producing specific interactions with rock surface have a comparable possibility to adsorb onto reservoir rock, hence the potential to substitute surfactant as the adsorbate. The presence of certain concentration of IL in surfactant solution was found to be able to decrease surfactant adsorption onto crushed core sample. The addition of imidazolium-based IL and DES was able to decrease the anionic surfactant adsorption by three times. Other finding shows that DES also gives a significant reduction of in-house surfactant adsorption down to the noticeable value compared to other ILs. The different results on adsorption behavior obtained from the combination of various surfactants and ILs impart the high influence of the type of surfactant and IL applied.",43,44,2
Oil Recovery,Interfacial Tension,"Zhou, Yazhou; Yin, Daiyin; Cao, Rui; Zhang, Chengli",The mechanism for pore-throat scale emulsion displacing residual oil after water flooding,Pore-throat scale; Emulsion; Viscoelasticity; Surfactant flooding; Displacement mechanism,POROUS-MEDIA; CRUDE-OIL; SURFACE-TENSION; RECOVERY; PARAMETERS; REDUCTION; VISCOSITY; POLYMER; FLOW,"The reservoir characteristics and fluid property of Daqing Oilfield was taken as the research platform. The emulsion was prepared by core displacement experiment. The stability of emulsion was analyzed by measuring the Zeta potential at different emulsifier concentrations. The emulsion viscoelasticity was also measured in different water cut stage. Displacement experiments of emulsion and surfactant flooding (poor emulsification) at the same interfacial tension were conducted, and the displacement efficiency of pore-throat scale emulsion (particle size greater than throat diameter but less than pore diameter) was studied. Using a visual sand packed model, displacement experiments allowed for the observation of the pore-throat scale emulsion displacing oil drop and columnar residual oil, and the deformation and migration process of residual oil were analyzed. The mechanism of pore-throat scale emulsion displacing residual oil was studied. The results show that with the emulsifier concentration increases, the absolute value of emulsion Zeta potential increases, and the stability of emulsion increases, the stability of pore-throat emulsion is preferably. When the water cut is 63.2%, the emulsion viscoelasticity is most favorably. When the emulsifier concentration is 0.4%, the emulsion flooding can enhance recovery efficiency by 9.84% compared to surfactant flooding with the same interfacial tension. The viscoelastic deformation of the pore-throat scale emulsion can pull the oil drop and columnar residual oil, and the residual oil can migrate.",35,34,5
Oil Recovery,Interfacial Tension,"Pal, Nilanjan; Saxena, Neha; Mandal, Ajay",Characterization of alkali-surfactant-polymer slugs using synthesized gemini surfactant for potential application in enhanced oil recovery,Gemini surfactant; Interfacial tension; Thermal stability; Viscosity; Viscoelasticity; ASP flooding,HYDROPHOBICALLY ASSOCIATING POLYACRYLAMIDE; COMBINATION FLOODING SYSTEMS; HEAVY OIL; ORGANIC ALKALI; RHEOLOGICAL PROPERTIES; INTERFACIAL-TENSIONS; SALINITY CONDITIONS; FIELD APPLICATIONS; MIXED SURFACTANT; LIGHT-SCATTERING,"The present study deals with the formulation and characterization of alkali-surfactant-polymer slugs using gemini surfactant (GS) for effective application in enhanced oil recovery (EOR) processes. The hydrolytic stabilities of the synthesized cationic GSs were measured in both acidic and basic media. Surface tensiometry was employed to determine the CMC values of surfactant at different temperatures. An organic alkali, monoethanolamine (MEA) showed the most favourable interfacial properties at the oil-aqueous interfaces among the various experimented alkalis. Though the addition of PHPA polymer to GS/MEA solutions increase the IFT value, the viscosities of the slugs improve drastically, which is desirable to improve the sweep efficiency. The solutions also showed low turbidity values and high thermal stability over a significant time period. The oil-surfactant-aqueous systems showed favourable emulsification properties, showing the ability to effectively displace trapped oil. Viscosity increases with PHPA concentration due to mixed micelle associations among the surfactant, alkali and polymer molecules. At low shear rates, the GS/MEA/PHPA solutions exhibited shear thinning properties. Oscillatory studies show the presence of both viscous and elastic properties, which have been well described using the Maxwell mechanical model. Formulation consisting of 0.02% 14-6-14 GS, 0.80% MEA and 0.20% PHPA showed the most favourable tertiary recovery after conventional secondary water-flooding.",31,32,2
Oil Recovery,Interfacial Tension,"Goswami, Rishiraj; Chaturvedi, Krishna Raghav; Kumar, Ravi Shankar; Chon, Bo Hyun; Sharma, Tushar",Effect of ionic strength on crude emulsification and EOR potential of micellar flood for oil recovery applications in high saline environment,Crude oil; Emulsion; Micellar flood; Rheology; SDS; Salt,NANOPARTICLE-SURFACTANT-POLYMER; IN-WATER EMULSIONS; INTERFACIAL-TENSION; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; HIGH-TEMPERATURE; SYSTEM; BEHAVIOR; CALCIUM; STABILITY,"Micellar flooding is one of the chemical oil recovery techniques in which micelle action emulsifies the crude oil to be mobilized in form of emulsion from a subsurface porous media. However, the subsurface conditions such as high ionic strength and temperature are challenges to the successful use of micellar flood owing to the deterioration of micelle action suggesting no crude emulsification. The ionic compounds dissociate into different ions that may further affect micelle action via loss in viscosity and pressure drop, increased water cut, and mobility contrast between micellar flood and displaced oil. Thus, investigation leading to the successful use of micellar flood, context to crude emulsion, in extreme salinity and temperature is vital to extend the use of chemical methods in new reservoirs. In this work, a typical surfactant sodium dodecyl sulfate (SDS) solution with critical micelle concentration (0.8 wt%) was tested to emulsify a fresh crude oil in the presence of varying ionic strength (0-4 wt%, NaCl/CaCl2 and temperature (40-98 degrees C). The efficacy of SDS micelles to produce crude emulsion significantly reduced with increasing salt concentration as reported through microscopic, rheological, and flooding experiments, particularly for divalent salt (CaCl2) than monovalent salt (NaCl). The increase in temperature (> 40 degrees C) further curtailed the growth of crude emulsion, mainly due to enhanced droplet coalescence; thus the use of micellar flood is critical in a reservoir enriched with high salinity and high temperature. Salinity effect on emulsion viscosity is reported through rheological measurements. The study highlighted important aspects of surfactant flooding and is a forward step towards the use of SDS based micellar flood at complex reservoir conditions.",29,28,1
Oil Recovery,Interfacial Tension,"Feng, Haishun; Kang, Wanli; Zhang, Liming; Chen, Jun; Li, Zhe; Zhou, Qiong; Wu, Hairong",Experimental study on a fine emulsion flooding system to enhance oil recovery for low permeability reservoirs,Fine emulsion flooding; Low permeability reservoir; Enhanced oil recovery; Micromodel tests,HEAVY-OIL; POROUS-MEDIA; SURFACTANT; EMULSIFICATION; POLYMER; MECHANISM; PRESSURE; ALKALI; TIGHT,"Numerous studies and field application tests have shown that emulsification is an important mechanism to improve oil recovery. Fine emulsion (FE) with small droplets can improve oil recovery by displacing residual oil after water flooding at a low cost. In this work, a series of core displacement experiments were conducted to compare the effectiveness of different chemical flooding for crude oil. Then, the oil-water interfacial tension (IFT), viscosity and rheological properties were studied thoroughly to understand the displacement mechanism by using an interfacial tensiometer, a viscometer or a rheometer. Finally, micromodel flooding tests were performed to demonstrate the suitability and effectiveness of FE flooding for oil recovery for low permeability reservoirs. The displacement results show that the oil recovery efficiency can reach 16.8% after water flooding by the optimum FE flooding system. The FE flooding system has viscoelastic properties, strong emulsifying performance and stability. Such behavior can reduce the IFT value to the magnitude of 10(-1) mN/m and improve the mobility ratio. The displacement mechanism of FE enhanced oil recovery (EOR) is that emulsification can improve the displacement efficiency and increase the swept efficiency. The micromodel tests indicate that the emulsification mechanisms include emulsification carrying-on and the performance control of the O/W emulsion. The FE flooding system has powerful EOR potential for low permeability reservoirs.",27,28,8
Oil Recovery,Interfacial Tension,"Suleimanov, Baghir A.; Latifov, Yashar A.; Veliyev, Elchin F.; Frampton, Harry",Comparative analysis of the EOR mechanisms by using low salinity and low hardness alkaline water,EOR; Low hardness alkali water; Sandstone flooding; Bentonite swelling; Low salinity water; Emulsion,IMPROVED OIL-RECOVERY; BRINE ROCK SYSTEMS; WETTABILITY ALTERATION; CRUDE-OIL; SPONTANEOUS IMBIBITION; SANDSTONE; TEMPERATURE; IONS,"This paper discusses the application of low hardness alkali water compositions (LHAW) as a secondary and tertiary displacement agent for EOR. A comparative analysis of the impact of low salinity water (LSW) and LHAW water on interfacial tension, contact angle on rock, adsorption of ions, emulsion stability and clay swelling is presented. LHAW application contributes to the formation of stable water in oil (w/o) emulsions and a decrease in clay swelling compared to LSW. Adsorption values for both fluids are similar. Contact angle measurements show that both LSW and LHAW reduce interfacial tension compared to Synthetic Caspian Sea water (SCSW), by up to 17% and 94% respectively. Similar results were observed for contact angle measurements. Flooding experiments were conducted in secondary and tertiary modes. In secondary flooding the two water compositions LHAW-2 and LHAW-1 increased the oil recovery (%OOIP) in comparison with SCSW at water breakthrough, by 29% and 25% respectively. The final oil recovery increases were 21% and 15% respectively. In tertiary flooding, tests showed that LHAW-2 and LHAW-1 oil recoveries (%OOIP) compared to LSW were 13% and 10% respectively. The oil recovery rate for LHAW solutions was not linear versus lnt as was that for LSW. This was proposed as a consequence of emulsions generation while water-cut is below 50% however, above 50% water cut the rate stabilizes.",25,25,0
Oil Recovery,Interfacial Tension,"Liang, Tianbo; Li, Qingguang; Liang, Xingyuan; Yao, Erdong; Wang, Yanqing; Li, Yuan; Chen, Mai; Zhou, Fujian; Lu, Jun",Evaluation of liquid nanofluid as fracturing fluid additive on enhanced oil recovery from low-permeability reservoirs,Fracturing fluid additive; EOR; Tight oil; Wettability alteration,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; GRAVITY DRAINAGE; HIGH-TEMPERATURE; WATER BLOCKING; SHALE; SURFACTANTS; WET; CARBONATES; SYSTEM,"Hydraulic fracturing creates a complex fracture network that makes the oil production from low-permeability reservoirs economical. However, significant amount of water is likely lost into the rock matrix during hydraulic fracturing. This can cause formation damage due to multiphase flow, thus hindering the oil production rate. Surfactants can alter rock wettability and/or reduce oil-water interfacial tension (IFT), and it has been proposed to be used to mitigate such water blockage and enhance oil recovery. Among different approaches of using surfactants, forming liquid nanofluid (LNF) can minimize the adsorption of surfactants on rock surface, and it is likely to be one of the best options for low-permeability rocks with extensive surface area. In this study, the key properties of a well-screened LNF are evaluated, and then compared with a commercial flowback surfactant (CFS) that is widely used in the field. Pressure transmission test is further applied, which can determine the change of rock permeability due to different fluids and the potential formation damage due to multiphase flow. A systematic evaluation method is thus established to screen fracturing fluid additives to enhance oil production from low-permeability reservoirs both effectively and efficiently.",24,28,4
Oil Recovery,Interfacial Tension,"Hanamertani, Alvinda Sri; Pilus, Rashidah M.; Manan, Ninie A.; Mutalib, M. Ibrahim A.",The use of ionic liquids as additive to stabilize surfactant foam for mobility control application,Surfactant; Foam additive; Ionic liquid; Foam stability; Foamscan,DEEP EUTECTIC SOLVENTS; ALKYL CHAIN-LENGTH; INTERFACIAL-TENSION; PHYSICOCHEMICAL PROPERTIES; PHASE-BEHAVIOR; OIL; IMIDAZOLIUM; FILMS; CHLORIDE; AGGREGATION,"Foam application has been introduced in enhanced oil recovery processes for mobility control to overcome some issues occurred during gas injection. The stability of foam has become the main concern as it dictates the effectiveness of foam mobility control. Many attempts at enhancing foam stability under reservoir conditions involve the application of chemical additives which can produce synergistic effect in combination with surfactant. Ionic liquids (ILs), salts melting below 100 degrees C, are considered to be able to alter surface behavior of surfactant molecules, hence supporting the surfactant performance at the interface. Their alteration is expected to be favorable in improving surface properties of foam. This research has introduced ionic liquid based additives for the first time to improve surfactant foam stability. Identification of the effect of ILs was performed by conducting bulk foam experiments at ambient conditions and also at high temperature using Foamscan. The foaming properties of in-house surfactant (MFOMAX) were evaluated in the absence and presence of ILs at different mixture ratios. The results show that imidazolium-and eutectic-based ILs were able to improve surfactant foam stability to different extent at high temperature and their effect on foam stabilization was more pronounced at surfactant/IL mixture ratio of 60:40. The highest foam stability increment exhibited by the best formulation reached 136% of that achieved by the formulation without IL. This study has indicated that ionic liquid has a promising potential for improving surfactant-stabilized foam mobility control during EOR processes.",24,24,3
Oil Recovery,Interfacial Tension,"Mohamed, Abdelhalim I. A.; Hussein, Ibnelwaleed A.; Sultan, Abdullah S.; Al-Muntasheri, Ghaithan A.",Use of organoclay as a stabilizer for water-in-oil emulsions under high-temperature high-salinity conditions,W/O emulsion; Pickering emulsion; Emulsion stability; Organoclay; High-temperature high-salinity; Chelating agent,INTERFACIAL-TENSIONS; NANOCOMPOSITES; SURFACTANT; FLOW,"Emulsified polymer gels are used in near wellbore applications for water shut-off treatment to control produced water in oil and gas reservoirs. The emulsified gels are expected to separate into oil and water phases at reservoir conditions. The stability of emulsified gels, as measured by the separation time, is influenced by the emulsifier type, salinity of the mixing water, and temperature. Although a range of commercial surfactants is used as emulsifiers, their toxicity and high cost are significant drawbacks. Nowadays, various nanomaterials have been developed for quite a few applications in different fields of endeavors, due to their low cost, availability, high surface area, and most prominently environmental-friendly. The proposed alternative organoclay (OC) has been shown to enhance emulsion stability with increasing OC concentration. The total separated volume reduced by a factor of 4.8, due to the decrease in the interfacial tension, when the OC (Cloisite 15A) concentration was increased from 600 to 1000 ppm. The stability of an emulsion prepared using a 6 vol% polyethylene glycol-2 ether (PEG-2E) enhanced by a factor of similar to 2 when the concentration of Cloisite 15A was increased from 300 to 1000 ppm. The separation time can be controlled by controlling the OC dose, depending on the application. A chelating agent can be used to reduce the effect of salts on emulsion stability. The OC materials have the potential to be used as cost-effective emulsifiers for PAM/PEI at high temperature (>100 degrees C) and high salinity (>200,000 ppm). The OC materials can be used as standalone emulsifiers or co-surfactants to enhance the performance of commercial emulsifiers.",21,22,5
Oil Recovery,Interfacial Tension,"Lashkarbolooki, Mostafa; Ayatollahi, Shahab","The effects of pH, acidity, asphaltene and resin fraction on crude oil/water interfacial tension",IFT; EOR; pH; Asphaltene; Resin; Crude oil,OIL-RECOVERY; HEAVY OIL; ACTIVE FRACTIONS; SURFACTANT; STABILITY; ALKALI; EMULSIFICATION; SYNERGY,"A basic understanding of the activities of indigenous surfactants of crude oil at the water/oil interface as a function of aqueous phase pH can give us a better insight into the alkaline enhanced oil recovery processes. The present study aimed to elucidate the effect of salinity and crude oil type, specifically the influence of resin and asphaltene molecules during alkaline flooding through interfacial tension (IFT) measurements via pendant drop and spinning techniques. Several model oils containing asphaltene and resin fractions were prepared and their IFTs were compared with those of the original crude oils. Moreover, the elemental analyses of asphaltene and resin fractions were performed, and the total acid numbers of all oils were measured as well. The IFT results of three studied crude oils and the asphaltenic and resinous model oils with sea water and deionized water underlined the importance of the degree of salinity, and qualitative and quantitative nature of resin and asphaltene fractions. It was also revealed that the amount of asphaltene and resin fractions as well as their structural nitrogen and oxygen contents were the most influential parameters on the IFT of crude oil as a function of pH values. In addition, the variations of IFT crude oils/the ionic solution and deionized water were more noticeable in the basic aqueous solutions.",21,22,1
Oil Recovery,Interfacial Tension,"Saien, Javad; Hashemi, Sajjad",Long chain imidazolium ionic liquid and magnetite nanoparticle interactions at the oil/water interface,Interfacial tension; Interface adsorption; Imidazolium ionic liquids; Magnetite nanoparticle; Mixed diffusion-kinetic-control,ENHANCED OIL-RECOVERY; PLUS WATER; SILICA NANOPARTICLES; DIFFUSION-COEFFICIENTS; ADSORPTION BEHAVIOR; ZNO NANOPARTICLES; SURFACTANT; TENSION; EMULSIONS; CHLORIDE,"The influence of the long chain ionic liquid 1-hexadecyl-3-methyl imidazolium chloride on equilibrium and dynamic interfacial tensions of n-heptane/water, as a representative system of oil/water, was investigated. Interfacial tension was drastically decreased by the ionic liquid and presence of magnetite nanoparticles as low as 0.01 wt%. Alkaline pH intensifies this effect. It was while nanoparticles alone had no sensible effect. The equilibrium interfacial tension data were nicely reproduced by the Szyszkowski model. Accordingly, the saturated surface excess for the systems with nanoparticles was decreased compared to the particles free case, but the adsorption equilibrium constant was increased. The dynamic interfacial tension data, on the other hand, showed a good agreement with the mixed diffusion-kinetic control theory for the both cases. Further, the stability of different emulsions was investigated. The results showed that the used nanoparticles were poor emulsifying agent, but the emulsion stability was increased when accompanied with the ionic liquid. Finally, the contact angle of aqueous phase drops surrounded by n-heptane on quartz surface was consistently decreased with the ionic liquid concentration and was more in the presence of nanoparticles.",20,21,2
Oil Recovery,Interfacial Tension,"Li, Xingxun; Guo, Yunmei; Sun, Qiang; Lan, Wenjie; Liu, Aixian; Guo, Xuqiang",Experimental study for the impacts of flow rate and concentration of asphaltene precipitant on dynamic asphaltene deposition in microcapillary medium,Asphaltene deposition; Visualization; Capillary flow; Microcapillary; Pore scale,ENHANCED OIL-RECOVERY; POROUS-MEDIA; CAPILLARY-FLOW; CO2 INJECTION; CONTACT-ANGLE; CRUDE-OIL; AGGREGATION PHENOMENA; INTERFACIAL-TENSION; PRESSURE DEPLETION; NATURAL DEPLETION,"Asphaltenes have been referred to 'cholesterol of petroleum' and the heaviest and the most complex components in crude oil. Asphaltene aggregation and deposition have always been a challenging issue on fluid transport in porous media for oil recovery and production processes in industries. Many experimental efforts have been done to study asphaltene aggregation and deposition from crude oil. Most of these works were carried out by coreflood tests or in bulk solution. Only several macroscopic parameters, such as pressure variation and permeability reduction caused by asphlatene deposition, were studied. Few experimental studies have been done to make the direct pore-scale visualization of dynamic asphaltene deposition behavior in capillary flow. In this study, we developed a new experimental approach to directly visualize and measure the dynamic asphaltene deposition process in capillary flow. Effects of concentration of asphaltene precipitant and flowrate were examined. The results indicate that the concentration of precipitant has a significant effect on the dynamic asphaltene deposition in capillary flow. The size of asphaltene deposit increases significantly with elapsed time and size distribution becomes wider at higher precipitant concentration. Higher concentration of asphaltene precipitant could lead to higher deposition rate. The results also indicate that higher flowrate causes faster growth of asphaltene deposits in capillary flow. Larger sizes of asphaltene deposits are formed and number of asphaltene deposits decreases with the elapsed time at higher flowrate. The results produced provide new sights into the dynamic asphaltene deposition in capillary flow at a pore scale. They could contribute to predict the growth rate of arterial asphaltene deposition in porous media and develop accurate numerical simulator for enhanced oil recovery purpose in industries.",19,20,5
Oil Recovery,Interfacial Tension,"Ayirala, Subhash C.; Al-Saleh, Salah H.; Al-Yousef, Ali A.",Microscopic scale interactions of water ions at crude oil/water interface and their impact on oil mobilization in advanced water flooding,Enhanced oil recovery; Advanced water flood; Interfacial tension; Interfacial rheology; Surface potential; Coalescence times,POTENTIAL DETERMINING IONS; WETTABILITY ALTERATION; RECOVERY; SALINITY; CARBONATES; TEMPERATURE; RESERVOIRS; INJECTION; DROPLETS; SO42,"In this study, we performed interfacial shear rheology, surface potential and oil droplets coalescence time measurements to investigate microscopic scale interactions of various individual water ions at both air-water and crude oil-water interfaces. The measured interfacial rheology data indicated completely different interfacial behavior at crude oil-water interface when compared to air-water interface due to the presence of crude oil functional groups. Viscous dominated response was observed at crude oil-water interface for all brine compositions. Lower interfacial viscous modulus was observed for certain key ions such as calcium, and magnesium. The interfacial viscous modulus was found to be substantially much higher for sulfates, besides exhibiting some elasticity. The surface potential was gradually decreased by replacing seawater with calcium only brine. The better surface activity with seawater can be attributed to adsorption of more key water ions at the surface. These interesting results observed with calcium and magnesium ions at crude oil-water interface are expected to favorably impact oil mobilization in advanced water flooding processes. Such favorable interactions can quickly destabilize the interfacial film between oil and water (due to less viscous interfaces) to promote the coalescence between released oil droplets and enable faster oil mobilization. This coalescence process is also sequential and it would continue until the formation of small oil bank. The coalescence times measured between oil droplets confirmed the adverse impact of sulfate ions, to hinder the coalescence and delay oil mobilization, in consistent with interfacial shear rheology results. The new fundamental knowledge gained in this study would provide an important guidance on how to synergize water ion interactions at fluid-fluid interfaces with those at rock-fluids interfaces and optimize advanced water flooding processes in carbonate reservoirs.",19,19,3
Oil Recovery,Interfacial Tension,"Ren, Guangwei; Nguyen, Quoc P.; Hon Chung Lau",Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants,CO2 soluble surfactants; Partition coefficient; CO2 foam; Fractured carbonate reservoir; EOR,INTERFACIAL-TENSION; GRAVITY DRAINAGE; MOBILITY CONTROL; CRUDE-OIL; DISPLACEMENT; EOR; MICROEMULSIONS; WETTABILITY; SOLUBILITY; REDUCTION,"Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions. A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 degrees C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water. RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam. These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.",19,20,2
Oil Recovery,Interfacial Tension,"Li, Xiuluan; Shi, Lanxiang; Li, Haozhe; Liu, Pengcheng; Luo, Jian; Yuan, Zhe",Experimental study on viscosity reducers for SAGD in developing extra-heavy oil reservoirs,Steam assisted gravity drainage (SAGD); Viscosity reducer; Extra-heavy oil; Thermal stability; Displacement efficiency,ASSISTED GRAVITY DRAINAGE; ES-SAGD; PHASE-BEHAVIOR; SOLVENT; STEAM; BITUMEN; WELLS; PERFORMANCE; RECOVERY,"Steam assisted gravity drainage (SAGD) is an effective in situ oil recovery technology in developing extra-heavy oil reservoirs. Large volumes of steam are needed, however, to heat the extra-heavy oil because of its high viscosity. Steam generation consumes large amounts of natural gas, which adversely affects the economics of SAGD, especially when oil prices are low. Moreover, environmental concerns arise because of excessive freshwater use and greenhouse gas emissions from the burning of the fossil fuels to generate steam. Considering these limitations and concerns, this paper evaluates the effectiveness of different viscosity reducers to decrease the steam consumption and improve SAGD performance. We conducted a series of screening experiments, including viscosity-reduction ratio, thermal stability, and core flooding, for nine types of viscosity reducers, based on an extra-heavy oil sample from a commercial SAGD project in China. The results indicate that water-soluble viscosity reducer #8, a nanoemulsion, is suitable for SAGD. It has a viscosity-reduction ratio of 98.0% at 50 degrees C and is still effective after high-temperature and high-pressure (200 degrees C, 4.0 MPa) treatment, with a viscosity-reduction ratio of 92.6%. The displacement efficiency is improved by 29.1%, and the cumulative steam-to-oil-ratio is reduced by 45.3% compared with pure steam flooding. Despite viscosity-reduction, the effect of interfacial tension reduction plays an important role in improving displacement efficiency during the coinjection of steam and viscosity reducer #8 has good potential to improve SAGD performance in developing extra-heavy oil reservoirs.",18,21,4
Oil Recovery,Interfacial Tension,"Luo, Haishan; Delshad, Mojdeh; Pope, Gary A.; Mohanty, Kishore K.",Scaling up the interplay of fingering and channeling for unstable water/polymer floods in viscous-oil reservoirs,Fingering; Channeling; Viscous oil; Water/polymer flood; Field simulation,POROUS-MEDIA; PERMEABILITY HETEROGENEITY; DISPLACEMENT; INSTABILITY; STABILITY; SIMULATOR; FLUID; FLOW,"Unstable displacement and the resulting viscous fingers remain a challenge for reservoir simulation as practical gridblock sizes are usually much larger than the viscous finger wavelength. Traditional reservoir simulators do not consider sub-grid viscous fingering effects and tend to overestimate the oil recovery at the field scale. Several previous studies suggested that fingering can be ignored at the field scale because channeling (caused by heterogeneity) is dominant, but they missed the existence of viscous fingering at the small scale, which affects the displacement efficiency. In our work, we consider that fingering and channeling coexist in the field across different scales, based on the fact that the heterogeneity increases with the scale. At the small-scale (e.g., lab-scale) where heterogeneity is small, fingering is dominant and causes oil bypassing. An effective-fingering model was developed to scale up fingering effects. The model divides each gridblock into three dynamic regions: two-phase flow, oil single-phase flow, and bypassed-oil regions. Model parameters represent the maximum fraction of viscous fingering and the growth factors of different regions, and they are used to modify flow functions. Model parameters from history-matches of a set of laboratory experiments show clear power-law correlations with a dimensionless viscous finger number, a function of viscosity ratio, fluid velocity, permeability, interfacial tension, and core cross-sectional area. The correlation was achieved at the lab-scale by considering relatively homogeneous cores. We extended it further to the field scale by performing high-order spatially accurate numerical simulations at the intermediate scale using gridblock sizes that are roughly the same as that of the core. Geostatistical realizations of the permeability field were generated with various variances and correlation lengths. In a statistical way, we were able to quantify the viscous finger number for a gridblock at the field-scale affected by various heterogeneities. It is also observed that channelized permeability distributions increase the viscous finger number drastically, showing the important role of channeling in such cases. This new model was applied to a synthetic field case with high heterogeneity undergoing water/polymer floods. It is observed that the oil recovery was improved by the polymer slug because of the enhancement in both local displacement efficiency and sweep efficiency.",18,19,2
Oil Recovery,Interfacial Tension,"Saikia, Bikash D.; Mahadevan, Jagannathan; Rao, Dandina N.",Exploring mechanisms for wettability alteration in low-salinity waterfloods in carbonate rocks,Wettability; Isoelectric point; Low-salinity; Carbonates; Contact angle; Zeta potential,OIL-RECOVERY,"Low Salinity waterfloods, even in carbonates, have received a great deal of attention because of their potential to significantly increase waterflood recoveries in addition to being cost effective. Wettability alteration has been found to play a major role in affecting higher recoveries from carbonates in low salinity floods. A large volume of research has accumulated for determining the effect of brine chemistry on wettability alteration and consequent recoveries. Both divalent cations (Ca2+, Mg2+) and anions (SO42-) as well as their interactions have been found to affect wettability. Charges on the mineral surface were also linked to observed wettability change. Despite the efforts, a clear understanding of the mechanisms for such wettability changes seems to be still elusive. Here in our work, first we have attempted to find viable alternatives for sulfates which pose fouling risks for reservoirs. Sulfur oxyanions such as bisulfites and metabisulfites have been found to be potential anions capable of affecting the desired wettability change without the risk associated with sulfates. Secondly, an effort has been made to understand the mechanism (s) behind such wettability alteration in carbonates during low salinity waterfloods based on our work and that by various authors. A potential mechanism has been proposed for wettability alteration, which seems to explain the works of many researchers. The mechanism is based on the isoelectric point of the carbonate rock surface, pH and interfacial energy between the aqueous brine solution and the rock surface. It is proposed that carbonates would be strongly oil-wet at the isoelectric point of the carbonate rock crystal, when the aqueous solution-rock interfacial tension is maximum. On the other hand, it would exhibit more water-wet or less oil-wet behavior, the further the pH of the brine solution is away from the isoelectric point of the carbonate rock. The wettability change is as a result of electrostatic attraction between polar water molecules with the charged surface that helps to bring down the brine-rock interfacial energy. This minimization of interfacial energy is manifested as the wettability change at the 3- phase carbonate mineral-oil-water contact line. The shift in the isoelectric point due to changes imposed in brine composition needs to be accounted for in addition to brine pH and salinity in order to optimize recoveries from low-salinity waterfloods.",18,18,0
Oil Recovery,Interfacial Tension,"Lashkarbolooki, Mostafa; Riazi, Masoud; Ayatollahi, Shahab",Effect of CO2 and crude oil type on the dynamic interfacial tension of crude oil/carbonated water at different operational conditions,Dynamic IFT; Carbonated water; CO2; Adsorption time; Temperature; Pressure,CARBONATED WATER; AQUEOUS-SOLUTIONS; INJECTION; RECOVERY; PH; EQUILIBRIUM; TEMPERATURE; PERFORMANCE; ASPHALTENE; ADSORPTION,"Concerns about climate change have persuaded the researchers to examine CO2 injection in the form of carbonated water (CW) into oil reservoir as a safe and effective CO2 storage and enhanced oil recovery process. Although interfacial tension (IFT) between crude oil and injected fluid has a vital role on the displacement of fluids in porous media, the effect of CO2 and crude oil type on the dynamic IFT of crude oil under different operational conditions is not well understood. Accordingly, this study was carried out to assess the effects of temperature, pressure, crude oil type and CO2 on the dynamic IFT of crude oil/CW. To achieve this goal, two types of crude oil were provided from southern Iranian oil reservoirs and dynamic IFTs with CW were measured in a wide range of temperatures and pressures (i.e. temperature range of 30-80 degrees C and pressure range of 500-4000 psi); the obtained results were compared with the system without CO2. In addition, the adsorption time of carbonated aqueous phase/crude oil, obtained based on the mono exponential decay model, was also compared with unadulterated water/crude oil system. The outcome of this study showed that crude oil type has the most significant effect on the IFT of crude oil/CW compared to pressure, temperature and CO2 content. In more details, the IFT of crude oil/CW can be affected by the amount and type of acidic/basic components in the crude oil as well as pH of the aqueous solution. Besides, the obtained results revealed that the effect of temperature was more considerable on the IFT of the heavy crude oil compared with the light crude oil in both studied aqueous solutions (i.e. unadulterated water and CW). Although the inversion phase temperature was obtained for unadulterated water/studied crude oils at all studied pressures, this phenomenon was not observed for crude oil/CW at elevated pressure, due to the high amount of CO2 at this condition.",17,17,3
Oil Recovery,Interfacial Tension,"Ameli, Forough; Mohammadi, Kaveh",A novel optimization technique for Fast-SAGD process in a heterogeneous reservoir using discrete variables and repetition inhibitory algorithm,Fast SAGD; Optimization; Genetic algorithm; Discrete variables; Repetition inhibitory algorithm,ENHANCED OIL-RECOVERY; IMPERIALIST COMPETITIVE ALGORITHM; ASSISTED GRAVITY DRAINAGE; HEAVY OIL; INTERFACIAL-TENSION; GRID GENERATION; TEMPERATURE; STEAM; SIMULATION; IMPLEMENTATION,"One of the most prevalent methods for enhanced oil recovery in heavy oil reservoirs is thermal techniques. Fast-SAGD process is an advance method of enhance oil recovery in which offset wells are drilled for cyclic steam injection and production. This leads to increasing the production efficiency. Optimization of this process was performed using various techniques including genetic algorithm (GA), imperialist competitive algorithm (ICA), and particle swarm optimization (PSO). Combination of recovery factor and cumulative steam to oil ratio was introduced as the objective function. This study represents a novel supplementary technique implemented in optimization algorithms to increase its speed, significantly. In this technique, effective parameters were defined using sensitivity analysis. Then they were converted to discrete variables. To discretize the selected parameters, three different functions including logarithmic, square, and linear were applied using Minitab 18. Moreover, repetition inhibitory algorithm (RIA) was implemented in optimization algorithms for the first time to prevent recalculation of duplicate states in optimization for the next generation, and to speed-up the optimization process. The results of sensitivity analysis indicated that maximum and minimum effective parameters were attributed to Fast-SAGD production well height and soak time, respectively. Results indicated that among various optimization algorithms, GA worked 6% better in comparison to other optimization techniques and linear discretization function resulted in better optimized point in a shorter time. Results indicated that optimization process using discrete variables and repetition inhibitory algorithm led to the optimized point 6.33 times faster than discrete optimization procedure without RIA. This was 16.46 times faster in comparison to continuous optimization algorithm. Moreover using RIA led to termination of optimization algorithm 9.67 times faster than continuous mode.",15,15,2
Oil Recovery,Spontaneous Imbibition,"You, Qing; Wang, Huan; Zhang, Yan; Liu, Yifei; Fang, Jichao; Dai, Caili",Experimental study on spontaneous imbibition of recycled fracturing flow-back fluid to enhance oil recovery in low permeability sandstone reservoirs,Recycled fracturing flow-back fluid; Spontaneous imbibition; Wettability alteration; Interfacial tension; Synergistic effect,WETTABILITY ALTERATION; SURFACTANT; NANOFLUIDS; CARBONATES; IFT,"In light of the high treatment costs for massive amounts of fracturing flow-back fluid and its harmfulness to the environment, a novel method of recycled fracturing flow-back fluid (RFFF) to enhance oil recovery by spontaneous imbibition is proposed in this study; this method does not allow the flow-back fluid back to the ground, thereby preventing negative impacts. The wettability alteration and interfacial tension (IFT) can effectively strengthen the spontaneous imbibition to enhance oil recovery in low-permeability sandstone reservoirs. This study combines the effects of wettability alteration and IFT with the use of the RFFF, which is composed of viscoelastic surfactants, on the spontaneous imbibition in low-permeability outcrop cores. Contact angle (CA) experiments, IFT experiments, and spontaneous imbibition experiments are conducted. The CA and IFT experimental results showed that the RFFF solutions changed the wettability of the core surface from oil-wet to waterwet and easily reduced the IFT between the crude oil and the RFFF solution to 10(-3)-10(-2) mN/m, which improved the oil recovery by changing the capillary forces. The spontaneous imbibition results showed that the RFFF solutions at concentrations of 0.03 - 0.10 wt% resulted in a higher imbibition recovery due to the synergistic effect of the wettability alteration and the IFT, which was attributed to the wedge film structure and the spreading force. It can be concluded that the use of the RFFF has the potential to further enhance oil recovery after fracturing the formation in low-permeability reservoirs without letting the fluid flow back to the ground. The proposed method is multi-functional and does not only improve the oil recovery by integrating fracturing and displacement methods but also reduces the costs of reservoir development and protects the environment.",100,103,14
Oil Recovery,Spontaneous Imbibition,"Nasralla, Ramez A.; Mahani, Hassan; van der Linde, Hilbert A.; Marcelis, Fons H. M.; Masalmeh, Shehadeh K.; Sergienko, Ekaterina; Brussee, Niels J.; Pieterse, Sebastiaan G. J.; Basu, Saptarshi",Low salinity waterflooding for a carbonate reservoir: Experimental evaluation and numerical interpretation,,ENHANCED OIL-RECOVERY; DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; IMPACT; TEMPERATURE,"Several laboratory studies and some field trials have already demonstrated the potential of lowering the injected brine salinity and/or manipulating composition to improve oil recovery in carbonate reservoirs. Laboratory SCAL tests such as coreflooding and imbibition are key steps to screen low salinity waterflood (LSF) for a particular field to (i) ensure that there is LSF response in the studied rock/oil/brine system, (ii) find the optimal brine salinity, (iii) extract relative permeability curves to be used in the reservoir simulation model and quantify the benefit of LSF and (iv) examine the compatibility of injected brine with formation brine and rock to derisk any potential scaling or formation damage caused by fines mobilization. This paper presents an extensive LSF SCAL study for a carbonate reservoir and the numerical interpretation of the tests. The SCAL experiments were performed at reservoir conditions using reservoir core plugs, dead crude oil and synthetic brines. The rock was characterized using porosity-permeability measurement semiquantitative, X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury intrusion capillary pressure (MICP) techniques. The characterization work showed that the plugs can be classified into two groups (uni-modal and bi-modal) based on pore throat size distribution which correlated with porosity-permeability cross-plots. The SCAL experiments were divided in two categories. Firstly, spontaneous imbibition and qualitative unsteady-state (USS) experiments were performed to demonstrate the effect of low salinity brines. In addition, these experiments helped to screen different brines (seawater and different dilutions of seawater) in order to choose the one that showed the most promising effect. Secondly, quantitative unsteady-state (USS) experiments were conducted and interpreted using numerical simulation to extract relative permeability curves for high salinity and low salinity brines by history- matching production and pressure data. The main conclusions of the study are: 1- The spontaneous imbibition and qualitative USS experiments showed extra oil production when switching from formation brine to seawater or diluted seawater subsequently, 2- Oil recovery by LSF can be maximized by injection of brine at a certain salinity threshold, at which lowering the brines salinity further did not lead to additional recovery improvement, 3- The LSF effect and optimal brine salinity varied in different layers of the reservoir which indicates that within the same reservoir the LSF effect is quite dependent on the rock type/ property and mineralogy, 4- The quantitative USS showed that LSF can improve the oil recovery factor by up to 7% at core scale compared to formation brine injection.",47,47,2
Oil Recovery,Spontaneous Imbibition,"Wang, Xiukun; Sheng, James J.",Spontaneous imbibition analysis in shale reservoirs based on pore network modeling,Spontaneous imbibition; Shale; Pore network modeling; Two-phase flow,NON-DARCY FLOW; 2-PHASE FLOW; RELATIVE PERMEABILITY; WETTING LIQUID; DISPLACEMENT; WETTABILITY; PRESSURE; NANOPORES; BEHAVIOR; FLUID,"Capillary spontaneous imbibition is vital to the successful development of shale reservoirs. The two-phase flow macro-properties of shale are significantly difficult to be measured in the laboratory. A pore network model is proposed in this work. The model is validated in the conventional Bentheimer sandstone and then applied to shale matrix with the consideration of variable wettability. Some representative relative permeability and capillary pressure curves are obtained from this pore network model. Based on an analytical solution of spontaneous imbibition, we propose a computational algorithm to calculate the oil recovery factors using the calculated macro-properties from our pore network model. Combining these two, the effects of wettability and absolute permeability on the spontaneous imbibition are studied. The absolute permeability plays an important role in the oil recovery factor induced by spontaneous imbibition. The recovery factor is proportional to the quartic root of absolute permeability. A relative small portion of oil wet pores (less than 40%) in a mixed wet formation won't prevent water from imbibing into the shale matrix and increasing the oil recovery. However, when the portion of oil wet pores is too large, the imbibition recovery drops dramatically. The attempt of this work is made to investigate the two-phase flow and spontaneous imbibition of shale reservoirs in the perspective of micro-scale.",25,26,7
Oil Recovery,Spontaneous Imbibition,"Suleimanov, Baghir A.; Latifov, Yashar A.; Veliyev, Elchin F.; Frampton, Harry",Comparative analysis of the EOR mechanisms by using low salinity and low hardness alkaline water,EOR; Low hardness alkali water; Sandstone flooding; Bentonite swelling; Low salinity water; Emulsion,IMPROVED OIL-RECOVERY; BRINE ROCK SYSTEMS; WETTABILITY ALTERATION; CRUDE-OIL; SPONTANEOUS IMBIBITION; SANDSTONE; TEMPERATURE; IONS,"This paper discusses the application of low hardness alkali water compositions (LHAW) as a secondary and tertiary displacement agent for EOR. A comparative analysis of the impact of low salinity water (LSW) and LHAW water on interfacial tension, contact angle on rock, adsorption of ions, emulsion stability and clay swelling is presented. LHAW application contributes to the formation of stable water in oil (w/o) emulsions and a decrease in clay swelling compared to LSW. Adsorption values for both fluids are similar. Contact angle measurements show that both LSW and LHAW reduce interfacial tension compared to Synthetic Caspian Sea water (SCSW), by up to 17% and 94% respectively. Similar results were observed for contact angle measurements. Flooding experiments were conducted in secondary and tertiary modes. In secondary flooding the two water compositions LHAW-2 and LHAW-1 increased the oil recovery (%OOIP) in comparison with SCSW at water breakthrough, by 29% and 25% respectively. The final oil recovery increases were 21% and 15% respectively. In tertiary flooding, tests showed that LHAW-2 and LHAW-1 oil recoveries (%OOIP) compared to LSW were 13% and 10% respectively. The oil recovery rate for LHAW solutions was not linear versus lnt as was that for LSW. This was proposed as a consequence of emulsions generation while water-cut is below 50% however, above 50% water cut the rate stabilizes.",25,25,0
Oil Recovery,Spontaneous Imbibition,"Liang, Tianbo; Li, Qingguang; Liang, Xingyuan; Yao, Erdong; Wang, Yanqing; Li, Yuan; Chen, Mai; Zhou, Fujian; Lu, Jun",Evaluation of liquid nanofluid as fracturing fluid additive on enhanced oil recovery from low-permeability reservoirs,Fracturing fluid additive; EOR; Tight oil; Wettability alteration,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; GRAVITY DRAINAGE; HIGH-TEMPERATURE; WATER BLOCKING; SHALE; SURFACTANTS; WET; CARBONATES; SYSTEM,"Hydraulic fracturing creates a complex fracture network that makes the oil production from low-permeability reservoirs economical. However, significant amount of water is likely lost into the rock matrix during hydraulic fracturing. This can cause formation damage due to multiphase flow, thus hindering the oil production rate. Surfactants can alter rock wettability and/or reduce oil-water interfacial tension (IFT), and it has been proposed to be used to mitigate such water blockage and enhance oil recovery. Among different approaches of using surfactants, forming liquid nanofluid (LNF) can minimize the adsorption of surfactants on rock surface, and it is likely to be one of the best options for low-permeability rocks with extensive surface area. In this study, the key properties of a well-screened LNF are evaluated, and then compared with a commercial flowback surfactant (CFS) that is widely used in the field. Pressure transmission test is further applied, which can determine the change of rock permeability due to different fluids and the potential formation damage due to multiphase flow. A systematic evaluation method is thus established to screen fracturing fluid additives to enhance oil production from low-permeability reservoirs both effectively and efficiently.",24,28,4
Oil Recovery,Spontaneous Imbibition,"Mwangi, Paulina; Brady, Patrick V.; Radonjic, Mileva; Thyne, Geoffrey",The effect of organic acids on wettability of sandstone and carbonate rocks,Wettability; Low salinity; Waterflooding; Organic acids,IMPROVED OIL-RECOVERY; LOW-SALINITY WATER; SPONTANEOUS IMBIBITION; MODEL COMPOUNDS; RESERVOIRS; MECHANISMS; CHALK; BASE; IONS,"This paper examines the role of crude oil's organic acid surface active compounds (SAC) in determining the reservoir wettability over a range of salinities and temperatures. To isolate the effects of individual SACs, this project used model oil mixtures of pure decane and single SACs to represent the oleic phase. Due to the large number of experiments in this study, we used wettability measurement method by the modified flotation technique (MFT) to produce fast, reliable, and quantitative results. The results showed that oil wetting by decane increased with temperature for carbonate rocks. Sandstones oil wetting showed little temperature dependency. The presence of long-chained acids in decane increased oil wetting in sandstone and carbonate rocks as salinity was lowered, while the short-chained acid increased water wetting under the same conditions. The effect of organic acids on wettability was slightly enhanced with increasing temperature for all rock types.",21,23,2
Oil Recovery,Spontaneous Imbibition,"Hasham, Aleem A.; Abedini, Ali; Jatukaran, Arnav; Persad, Aaron; Sinton, David",Visualization of fracturing fluid dynamics in a nanofluidic chip,Fracturing fluid; Infiltration; Entrapment; Recovery; Nanofluidic,MICROFLUIDICS-BASED MEASUREMENT; PORE-SCALE ANALYSIS; SPONTANEOUS IMBIBITION; OIL-RECOVERY; GAS SHALES; HEAVY OIL; CO2; TEMPERATURE; PRESSURE,"Hydraulic fracturing is responsible for remarkable production from shale and tight formations, albeit at the cost of significant water usage. The flow dynamics of oil and fracturing fluid in nanopores remains largely uncharacterized, in part due to the challenge of conducting experiments at nanoscales. In this paper, we demonstrate a nanofluidic-based approach to visualize the fluid displacement during hydraulic fracturing. Nanoporous silicon-glass chips with circular and square grain shapes and identical depth of 175 nm were fabricated using reactiveion etching (RIE) and anodic bonding. Leveraging the inherent fluorescence property of the oil, the fluorescence microscopy was used to record the dynamics of the fluid displacement inside the chip. Performance of three different fracturing fluids - deionized water, potassium chloride (KCl) solution, and slick water - were evaluated based on the volumetric infiltration in the nanoporous network, entrapment of fracturing fluid in the porous media, and total production during drawdown. The KCl solution had the highest infiltration rate (fill factor of 0.68) and the lowest entrapment factor (0.39), resulting in the highest fracturing fluid recovery representing 43% in the square grain geometry with similar results for circular grains. With the fast quantification and ease of operation here, the nanofluidic approach enables a rapid screening of different fracturing fluids to inform shale oil operators.",20,21,3
Oil Recovery,Spontaneous Imbibition,"Shabaninejad, Mehdi; Middlelton, Jill; Fogden, Andrew",Systematic pore-scale study of low salinity recovery from Berea sandstone analyzed by micro-CT,Low salinity water flooding; Spontaneous imbibition; Micro CT; Image analysis; Wettability,FINES MIGRATION; OIL-RECOVERY; SEGMENTATION,"The low salinity effect in clay-rich outcrop sandstones is probed by micro-CT imaging and analysis. A set of eight Berea sandstone mini-plugs underwent primary drainage and aging in crude oil to a mixed-wet state, followed by spontaneous imbibition of high and low salinity brines and imaging of this sequence of prepared starting and endpoint states. Tomogram registration and analysis were used to determine the salinity-induced changes in oil volume, oil/rock and oil/brine interfacial areas, and oil/brine interfacial mean curvature. Pore-scale statistics were extracted to explore any local correlation between the low salinity effect and pore geometry/topology. The qualitative observations and quantitative analyses demonstrated that the small oil recovery by the low salinity effect corresponded to a slight shift towards water-wet.",20,20,1
Oil Recovery,Spontaneous Imbibition,"Javaheri, Ali; Habibi, Ali; Dehghanpour, Hassan; Wood, James M.",Imbibition oil recovery from tight rocks with dual-wettability behavior,,SHALE GAS-RESERVOIRS; MERCURY-INTRUSION; WATER-ADSORPTION; PORE STRUCTURE; BRINE; PLAY,"Previous studies demonstrate that the Montney rock samples have a dual-wettability pore network. Recovery of the oil retained in small hydrophobic pores is a unique challenge. In this study, we apply dual-core imbibition (DCI) method on several Montney core plugs and introduce imbibition-recovery (IR) trio to investigate the recovery mechanisms in rocks with dual-wettability pore network. First, we evaluate the wetting affinity of five twin core-plugs from the Montney Formation by measuring spontaneous imbibition of reservoir oil and brine, and by measuring equilibrium contact angle. We place one plug of each pair in the oil and the other in the brine, and measure the weight change periodically. Second, we place the oil-saturated plugs in the brine to visualize the expelled oil droplets and measure volume of the recovered oil. We comparatively analyze the spontaneous imbibition data from the first step and the oil recovery data from the second step in one imbibition-recovery trio (oil imbibition, brine imbibition, and imbibition oil recovery). The results of air-liquid contact angle and spontaneous imbibition tests on dry samples suggest that affinity of the samples to oil is higher than that to brine, in an air-liquid system. However, the results of liquid-liquid contact angle and countercurrent imbibition tests suggest that affinity of the samples to water is higher than that to oil, in a liquid-liquid system. For each twin set, the oil recovery curve follows the trend of brine imbibition curve, and the final oil recovery is always less than the equilibrated water uptake of dry samples. This observation indicates that water can only access the hydrophilic part of the pore network initially saturated with oil.",15,18,4
Oil Recovery,Spontaneous Imbibition,"Wang, Jing; Liu, Huiqing; Zhang, Jing; Meng, Qingbang; Liu, Huapu; Ge, Lizhen; Zhu, Zhiqiang; Liu, Chang",Experimental investigation on water flooding and continued EOR techniques in buried-hill metamorphic fractured reservoirs,Buried-hill fractured reservoir; Enhanced oil recovery; Experimental study; Imbibition; Water flooding,OIL-RECOVERY; SPONTANEOUS IMBIBITION; CARBONATE RESERVOIRS; CAPILLARY IMBIBITION; HIGH-TEMPERATURE; SURFACTANT; INJECTION; WET; PERFORMANCE; COCURRENT,"Fractured reservoirs are complicated due to the coexistence of matrix and fracture systems. In particular, the matrix of buried-hill metamorphic fractured reservoirs (BHMFRs) has plenty of micro-fractures and a few dissolution pores rather than common pores in sandstone. The storage and heterogeneity features, such as the storage ratio between matrix and fractures, and the distribution of fractures, significantly affect the performances of waterflooding and EOR techniques. With the objective of finding effective waterflooding mode and EOR techniques in such reservoirs, the BHMFR of JZ25-1S in Bohai Bay in China was taken as an example. First, static imbibition experiments using a novel imbibition cell were conducted. Then, 3D large-scale models of BHMFRs using outcrops were designed based on the similarity criterion and employed to conduct the experiments of waterflooding and followed EOR techniques. The results show that co-current imbibition is principal and gravity is the dominant force of imbibition for BHMFRs. Because imbibition is slow, most of the yield comes from the macro-fractures. Both water-free recovery and waterflooding recovery increase as the decrease of the storage ratio of matrix to fractures. Pulsing cyclic water-injection is better than intermittently cyclic water-injection. In BHMFRs with heterogeneity of fracture density, injection in the area with low fracture density and production in the area with high fracture density can achieve better effects than the reverse scenario for both waterflooding and followed EOR techniques. If gas flooding is selected as the EOR technique, producer should be perforated at the lower layers of the reservoir. Suitable gel particles not only get a good EOR effect by effective plugging, but also can create a more favorable condition for surfactant flooding. In our experiments, another 2-4% of OOIP was produced by PPG flooding. Surfactant can enhance the oil recovery by both removing the adsorbed oil on the fracture surface and promoting imbibition in matrix. 3-5% of OOIP was recovered by surfactant flooding and soaking in our experiments.",15,16,1
Oil Recovery,Drilling,"Parizad, Amirhossein; Shahbazi, Khalil; Tanha, Abbas Ayatizadeh",Enhancement of polymeric water-based drilling fluid properties using nanoparticles,Drilling fluid; TiO2 nanofluid viscosity; Nanofluid thermal and electrical conductivities; Nanofluid filtration; Nanofluid thermal resistance: nanofluid shale; recovery,SIZE; NANOFLUIDS; VISCOSITY; BEHAVIOR; STABILITY,"The maturity of shallow depth and conventional petroleum reserves together with growing demand for energy have forced the oil industry to drill harsh and deep reserves. Nanotechnology has the ability to improve drilling fluid performance for drilling deeper and harsher environments. In this study, a water-based drilling fluid containing polymers was set as the base fluid. TiO2 nanoparticle was employed to improve rheology, electrical and thermal conductivities of the resultant drilling fluids. The test fluids were made by addition of different concentrations of TiO2 nanoparticle and KCl salt to the base fluid. The resultant samples were examined at different temperatures and 19 different shear rates. Presence of TiO2 particles enhanced not only the rheological behavior but also thermal and electrical conductivities of the drilling fluids up to 25% and 41%, respectively. Moreover, the addition of TiO2 particles increased thermal resistance, shale recovery up to 97.2% and also decreased the filtration volume up to 27%. Moreover, the viscosities of aqueous TiO2 dispersions at different temperatures and TiO2 and KCl concentrations were measured. The TiO2 nanoparticle has good soloubility in hot HCl and HF acids. It was found that the base aqueous fluid viscosity directly affects the resultant drilling fluid viscosity. In this regard, an analysis was performed and a model was proposed.",30,30,2
Oil Recovery,Drilling,"Xie, Binqiang; Ting, Li; Zhang, Yan; Liu, Chen",Rheological properties of bentonite-free water-based drilling fluids with novel polymer viscosifier,Water-soluble polymers; Viscosifier; Thermo-thickening; Rheology; Bentonite-free drilling fluid,ACRYLAMIDE-BASED TERPOLYMER; ENHANCED OIL-RECOVERY; AQUEOUS-SOLUTION; GRAFT-COPOLYMERS; THERMOASSOCIATIVE COPOLYMERS; CELLULOSE NANOPARTICLES; FORMATION DAMAGE; PERFORMANCE; BEHAVIOR; ADDITIVES,"Water-based drilling fluids with no bentonite content was particularly advantageous in oil and natural gas exploration due to the excellent characteristics including faster rates of penetration, enhanced hole cleaning, less formation damage, etc. However, how to keep the excellent rheological regulation of bentonite-free drilling fluids was still one of the most serious issues for the mud designers. In this study, novel polymer viscosifier (SDKP) was prepared under optimal synthesis conditions through the copolymerization of N-vinylcaprolactam and sodium 2-acrylamido-2-methylpropane sulfonate. The effect of SDKP on rheological behavior of bentonite-free fluids was studied according to American Petroleum Institute standard. Results showed that SDKP could improve the rheological properties of bentonite-free fluids. In addition, the good thermal stability and salt stability in improving rheological behavior of fluids made SDKP more attractive. Rheological behavior of SDKP based bentonite-free fluids at different temperatures was also evaluated. Results showed that SDKP based bentonite-free fluids showed certain thermo-viscosifying behavior in the temperature range of 80-140 degrees C even in high salinity, which was benefit for carrying cuttings. Shear test showed that the magnitude of the thermo-thickening viscosity was very sensitive to shear rate, and SDKP containing fluids became better shear-thinning upon heating, which could be more easily pumped into the well. In addition, the mechanism of SDKP in improving rheological behavior of bentonite-free fluids was revealed based on the investigation of morphology of SDKP through Environmental Scanning Electron Microscopy experiment.",24,25,3
Oil Recovery,Drilling,"AlTwaijri, Mohammad; Xia, Zhaohui; Yu, Wei; Qu, Liangchao; Hu, Yunpeng; Xu, Yifei; Sepehrnoori, Kamy",Numerical study of complex fracture geometry effect on two-phase performance of shale-gas wells using the fast EDFM method,Shale gas; Complex fractures; Natural fractures; Two-phase flow; Water flowback,WATER; SIMULATION; TRANSPORT; RESERVOIR; MODEL; FLOWBACK; OIL,"Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced ( hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of local grid refinement approach, hydraulic fractures are assumed to be planar ( orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational resources. In this paper, we introduce an embedded discrete fracture model (EDFM) to explicitly model complex fracture geometries. The EDFM efficient approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, we constructed a 3D reservoir model to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In our investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set of natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of nonorthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells.",23,23,3
Oil Recovery,Drilling,"Zhong, Hanyi; Qiu, Zhengsong; Chai, Jinpeng; Guo, Baoyu; Sun, Dong; Liu, Junyi",A preliminary study of the preparation of shale stabilizer with oil sludge - From waste to resource,Oil sludge; Asphalt; Shale stabilizer; Drilling fluid; Preparation,WATER-TREATMENT; BIOREMEDIATION; FORMULATION; RECOVERY,"To convert the hazardous and waste oil sludge into shale stabilizer using in drilling fluid, a novel preparing method has been proposed in the current study. According to the characteristics of oil sludge, the preparation procedure was designed learning from conventional asphaltic-type shale stabilizer preparation method. Several additives such as gilsonite, calcium carbonate, surfactants (hexadecyltrimethylammonium chloride (CTAC) and polyoxyethylene octylphenol ether (OP-10)), polymers (polyethylene glycol (PEG-2000) and cationic polyacrylamide (CPAM)), and fluid loss reducers (sulfonated lignite and potassium humate) were incorporated into oil sludge with the assistance of melting, stirring, kneading, and drying. After the sequential steps of asphaltization, emulsification, and stabilization, a powdered shale stabilizer product (SS-OS) was obtained. The effect of SS-OS on rheology, filtration, and lubricity of drilling fluid bentonite dispersions was tested. Furthermore, the properties of stabilizing shale were evaluated. The results indicated that SS-OS could effectively inhibit shale swelling, dispersion, and exhibit excellent sealing performance. Moreover, it helped to reduce the fluid loss and significantly improve the lubricity of the drilling fluid. From the preliminary study, it was concluded that the strategy of preparing shale stabilizer with oil sludge could be employed to overcome waste, energy and environmental problems simultaneously and show promising application.",20,22,1
Oil Recovery,Drilling,"Wang, Zhihao; Wu, Yuanpeng; Luo, Pingya; Tian, Yingpei; Lin, Yuanhua; Guo, Qipeng",Poly (sodium p-styrene sulfonate) modified Fe3O4 nanoparticles as effective additives in water-based drilling fluids,Water-based drilling fluids; Fe3O4 nanoparticles; Poly (sodium p-styrene sulfonate); Rheology; Fluid loss,CONTROLLING FILTRATION PROPERTIES; RHEOLOGICAL PROPERTIES; BENTONITE SUSPENSIONS; HIGH-TEMPERATURES; HIGH-PRESSURE; LOSS AGENT; BEHAVIOR; PERFORMANCE; SHALE; STABILIZATION,"In this work, a series of low solid phase, economic and excellent performance water-based drilling fluids (WBDFs) were obtained by introducing nanoparticles into conventional WBDFs. Fe3O4 nanoparticles which were surface modified by poly (sodium p-styrene sulfonate) (PSSS) through 3-(trimethoxysilyl) proryl methacrylate (TMSPMA) were adopted in low solid WBDFs containing 4 wt % bentonite (BT). The effect of temperature on rheological property and fluid filtration was investigated. When the concentration of Fe3O4/PSSS nanoparticles reached 0.1 wt %, shear thinning of WBDFs will be perfect at different temperatures. When the concentration of Fe3O4/PSSS nanoparticles reached 0.25 wt %, the WBDFs had superior rheological properties, as compared to other concentrations of the particles in salt environment. Rheological curves provide a closely fit for the Bingham model at low temperature, however, the curves fit Herschel-Bulkley model at higher temperature. Rheological tests indicated that higher concentration of Fe3O4/PSSS nanoparticles can effectively improve salt (KCl) tolerance. Under high temperature and high press (HTHP) filtration test, WBDFs with Fe3O4/PSSS nanoparticles exhibited minimum filtration loss volume with the concentration of Fe3O4/PSSS nanoparticles as low as 0.1 wt % at different temperatures. For salt tolerance test, the higher concentration of the Fe3O4/PSSS nanoparticles leads to the lower the amount of fluid loss at the same concentration of KCl. With the concentration of nanoparticles grows to 0.1 wt %, the amount of fluid loss volume was minimum, indicating that Fe3O4/PSSS nanoparticles in WBDFs improve the filtration. The WBDFs with performance improved by Fe3O4/PSSS nanoparticles can be used as effective drilling fluids even under high temperature and high salinity, demonstrating that the modified fluids are potential candidates for drilling in deep and salty formation.",19,20,8
Oil Recovery,Drilling,"Santos, Jessika Marina; Petri, Irineu Junior; Silva Mota, Ana Carolina; Morais, Anderson dos Santos; Ataide, Carlos Henrique",Optimization of the batch decontamination process of drill cuttings by microwave heating,Synthetic drilling fluid; Microwave heating; Gas chromatography; Drilling waste,REMEDIATION; DISPOSAL; CAVITY; FLUIDS,"In the drilling of oil and gas wells synthetic fluids can be used to remove rock fragments generated during the operation. However, the use of these fluids generates a solid-liquid mixture that must be separated in order to reduce the operational costs by the recovery of the fluid adhered to the solids and also to guarantee compliance with environmental legislation regarding drilling waste disposal. Therefore, the objective of this study was to evaluate the influence of some process variables on the decontamination of drill cuttings by microwave heating. Experimental conditions relative to the heating time, bed temperature and mass of samples contaminated with synthetic drilling fluid were optimized by means of a design of experiments (DOE) and a canonical analysis, reaching organic residual contents lower than 1% (mass). Furthermore, numerical simulations were executed for a better understanding of the microwave heating and drying process. Analyses using the gas chromatography technique were performed in order to evaluate possible composition changes in the recovered liquid samples during the condensation operation, which showed themselves to be sensitive to heating at higher temperatures.",18,19,3
Oil Recovery,Drilling,"Ameli, Forough; Mohammadi, Kaveh",A novel optimization technique for Fast-SAGD process in a heterogeneous reservoir using discrete variables and repetition inhibitory algorithm,Fast SAGD; Optimization; Genetic algorithm; Discrete variables; Repetition inhibitory algorithm,ENHANCED OIL-RECOVERY; IMPERIALIST COMPETITIVE ALGORITHM; ASSISTED GRAVITY DRAINAGE; HEAVY OIL; INTERFACIAL-TENSION; GRID GENERATION; TEMPERATURE; STEAM; SIMULATION; IMPLEMENTATION,"One of the most prevalent methods for enhanced oil recovery in heavy oil reservoirs is thermal techniques. Fast-SAGD process is an advance method of enhance oil recovery in which offset wells are drilled for cyclic steam injection and production. This leads to increasing the production efficiency. Optimization of this process was performed using various techniques including genetic algorithm (GA), imperialist competitive algorithm (ICA), and particle swarm optimization (PSO). Combination of recovery factor and cumulative steam to oil ratio was introduced as the objective function. This study represents a novel supplementary technique implemented in optimization algorithms to increase its speed, significantly. In this technique, effective parameters were defined using sensitivity analysis. Then they were converted to discrete variables. To discretize the selected parameters, three different functions including logarithmic, square, and linear were applied using Minitab 18. Moreover, repetition inhibitory algorithm (RIA) was implemented in optimization algorithms for the first time to prevent recalculation of duplicate states in optimization for the next generation, and to speed-up the optimization process. The results of sensitivity analysis indicated that maximum and minimum effective parameters were attributed to Fast-SAGD production well height and soak time, respectively. Results indicated that among various optimization algorithms, GA worked 6% better in comparison to other optimization techniques and linear discretization function resulted in better optimized point in a shorter time. Results indicated that optimization process using discrete variables and repetition inhibitory algorithm led to the optimized point 6.33 times faster than discrete optimization procedure without RIA. This was 16.46 times faster in comparison to continuous optimization algorithm. Moreover using RIA led to termination of optimization algorithm 9.67 times faster than continuous mode.",15,15,2
Oil Recovery,Drilling,"Akhtar, Tarek Firoze; Ahmed, Ramadan; Elgaddafi, Rida; Shah, Subhash; Amani, Mahmmod",Rheological behavior of aqueous foams at high pressure,Foam; Rheology; Yield stress; Non-Newtonian fluid; Friction pressure loss; Wall-slip,CONSTITUTIVE EQUATION; SHEAR; FLOW,"Aqueous foams are used in many oil field applications including drilling, fracturing, and enhanced oil recovery operations. The success of all these operations strongly depends on viscosity and stability of foam. Rheology of foams is a function of foam quality (i.e. gas volume fraction), liquid phase viscosity, pressure, and temperature. Besides, foam generation method and stability are factors that influence its rheology. This article presents results of an experimental study performed to investigate the effects of foam quality, pressure, and wall slip on aqueous-foam rheology. Extensive tests were conducted using a foam recirculating flow loop consisting of three pipe viscometers. Experiments were performed at ambient temperature, and varying pressure (6.89-20.68 MPa), foam quality (40-80%), and pipe diameter (3.06, 6.22 and 12.67 mm). The foam was generated by passing a mixture of water containing 2% surfactant solution and gas phase (nitrogen) through a needle valve. To minimize degradation while testing, the foam was regenerated by circulating at the maximum flow rate (0.55 L/min) before each flow measurement was made. Results indicate strong non-Newtonian behavior of foam, which closely fits the power law model. For foams with more than 55% quality, measured viscosities were higher than the ones reported in the literature. Noticeable wall slip was not observed. Foam viscosity change because of pressure variation at a constant foam quality was negligible. Foams with quality higher than 70% exhibited yield pseudoplastic behavior. Their rheological behavior can be described better by Herschel-Bulkley model than power law model when the shear rate is below 20 1/s.",14,14,1
Oil Recovery,Hydraulic Fracture,"Teklu, Tadesse Weldu; Li, Xiaopeng; Zhou, Zhou; Alharthy, Najeeb; Wang, Lei; Abass, Hazim",Low-salinity water and surfactants for hydraulic fracturing and EOR of shales,Low-salinity water; Low-salinity water plus srufactnat; Osmosis; Capillary pressure; Wettability alteration; IFT decrease; Hydraulic fracturing and EOR of shales,OIL-RECOVERY; UNCONVENTIONAL RESERVOIRS; IMBIBITION; WETTABILITY; TRANSPORT,"There are significant recoverable oil and gas resources stored in shale reservoirs throughout the world. Horizontal well with multistage hydraulic fracturing is an enabling technology for economic production of these shale resources. Recovery factors of liquid rich shale reservoirs is typically less than 10%, hence, there is an incentive for implementing enhanced oil recovery (EOR) technologies to improve oil production from these very tight reservoirs. Brine, chemical (surfactant), gas, or combination of these fluids imbibition or injection in huff-n-puff scenario could improve oil recovery of liquid rich shale reservoirs. In this study, low-salinity water and low-salinity water + surfactant imbibition are assessed as both hydraulic fracturing and EOR fluids in liquid rich shale reservoirs. Osmosis, capillary pressure, wettability alteration, and other effects are among the mechanisms by which these fluids can improve oil recovery from shale reservoirs. These favorable effects were investigated through imbibition experiments. Experiments show: (a) low-salinity water huff-n-puff in tight formations can improve oil production from tight formations. This is because wettability alteration, capillary, and osmotic forces; (b) surfactant + low-salinity-water huff-n-puff can further improve oil production due to additional IFT decrease and wettability alteration by surfactants; hence, improve oil production from stimulated ultra-tight formations. Based on experimental observations and literature reviewed, low-salinity water huff-n-puff (until economical), followed by low-salinity water + surfactant huff-n-puff EOR process is recommended to optimize production from liquid rich shale reservoirs, while minimizing cost. These fluids can be used to reduce matrix-fracture skin damage. The effectiveness of these hydraulic fracturing and EOR fluids in shales is highly dependent on the existence and extent of natural fractures or laminations within the stimulated reservoir volume; this is because osmosis and diffusion are very slow processes.",27,29,7
Oil Recovery,Hydraulic Fracture,"Hu, Yuqi; Weijermars, Ruud; Zuo, Lihua; Yu, Wei",Benchmarking EUR estimates for hydraulically fractured wells with and without fracture hits using various DCA methods,Production forecasting; EUR estimates; Modified Hyperbolic Decline Model; Duong model; Logistic Growth Analysis Model; Power Law Exponential,SHALE GAS-RESERVOIRS,"Various decline curve analysis (DCA) methods can be applied to forecast the production performance of hydrocarbon wells, including horizontal wells stimulated with hydraulic fracturing. Yet, which method is more preferable remains in doubt. The objective of this study is to evaluate various DCA methods by history matching and hindcasting both synthetic and field production data in order to assess for each method the reliability of production forecasts and the estimated ultimate recovery (EUR). Five DCA methods have been evaluated because of their computational simplicity and broad application. These methods are the Modified Hyperbolic Decline model (MHD), Duong model, Logistic Growth Analysis Model (LGM), and the Power Law Exponential (PLE, with D-infinity = 0 and D-infinity = 8) Decline models. Each method was evaluated using three data sets: synthetic shale oil production rates based on a CMG reservoir model using Eagle Ford reservoir characteristics, data from producing Eagle Ford wells and from Austin Chalk wells. The hindcast method was applied to the Eagle Ford synthetic wells to establish the EUR deviation between the synthetic reservoir model production forecast and the various DCA methods. The weighted residuals of history matched production rates for Eagle Ford indicate that the MHD and Duong models give the lowest matching errors (as low as 1.32%) and the highest EUR estimations (as high as 3,447,609 stb). The PLE model (with D-infinity not equal 0) gives the most conservative EUR estimation, and also the least reliable history matching method (on our Eagle Ford data sets), which therefore is the least preferable DCA method. For the Austin Chalk wells in our study, all methods generate fairly similar EUR predictions with similar matching errors (from 13% to 15%) so that the DCA method preference becomes indifferent. This study also touches upon the relationship between DCA results when well interference occurs due to various hydraulic fracture hits. Shale wells that primarily contain hydraulic fractures and few natural fractures (Eagle Ford) give the most reliable forecasts using the MHD and Duong DCA methods. However, wells in the Austin Chalk, a naturally fractured reservoir, show little difference between the forecast accuracy from the various DCA methods.",25,28,0
Oil Recovery,Hydraulic Fracture,"Liang, Tianbo; Li, Qingguang; Liang, Xingyuan; Yao, Erdong; Wang, Yanqing; Li, Yuan; Chen, Mai; Zhou, Fujian; Lu, Jun",Evaluation of liquid nanofluid as fracturing fluid additive on enhanced oil recovery from low-permeability reservoirs,Fracturing fluid additive; EOR; Tight oil; Wettability alteration,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; GRAVITY DRAINAGE; HIGH-TEMPERATURE; WATER BLOCKING; SHALE; SURFACTANTS; WET; CARBONATES; SYSTEM,"Hydraulic fracturing creates a complex fracture network that makes the oil production from low-permeability reservoirs economical. However, significant amount of water is likely lost into the rock matrix during hydraulic fracturing. This can cause formation damage due to multiphase flow, thus hindering the oil production rate. Surfactants can alter rock wettability and/or reduce oil-water interfacial tension (IFT), and it has been proposed to be used to mitigate such water blockage and enhance oil recovery. Among different approaches of using surfactants, forming liquid nanofluid (LNF) can minimize the adsorption of surfactants on rock surface, and it is likely to be one of the best options for low-permeability rocks with extensive surface area. In this study, the key properties of a well-screened LNF are evaluated, and then compared with a commercial flowback surfactant (CFS) that is widely used in the field. Pressure transmission test is further applied, which can determine the change of rock permeability due to different fluids and the potential formation damage due to multiphase flow. A systematic evaluation method is thus established to screen fracturing fluid additives to enhance oil production from low-permeability reservoirs both effectively and efficiently.",24,28,4
Oil Recovery,Hydraulic Fracture,"AlTwaijri, Mohammad; Xia, Zhaohui; Yu, Wei; Qu, Liangchao; Hu, Yunpeng; Xu, Yifei; Sepehrnoori, Kamy",Numerical study of complex fracture geometry effect on two-phase performance of shale-gas wells using the fast EDFM method,Shale gas; Complex fractures; Natural fractures; Two-phase flow; Water flowback,WATER; SIMULATION; TRANSPORT; RESERVOIR; MODEL; FLOWBACK; OIL,"Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced ( hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of local grid refinement approach, hydraulic fractures are assumed to be planar ( orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational resources. In this paper, we introduce an embedded discrete fracture model (EDFM) to explicitly model complex fracture geometries. The EDFM efficient approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, we constructed a 3D reservoir model to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In our investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set of natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of nonorthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells.",23,23,3
Oil Recovery,Hydraulic Fracture,"Hasham, Aleem A.; Abedini, Ali; Jatukaran, Arnav; Persad, Aaron; Sinton, David",Visualization of fracturing fluid dynamics in a nanofluidic chip,Fracturing fluid; Infiltration; Entrapment; Recovery; Nanofluidic,MICROFLUIDICS-BASED MEASUREMENT; PORE-SCALE ANALYSIS; SPONTANEOUS IMBIBITION; OIL-RECOVERY; GAS SHALES; HEAVY OIL; CO2; TEMPERATURE; PRESSURE,"Hydraulic fracturing is responsible for remarkable production from shale and tight formations, albeit at the cost of significant water usage. The flow dynamics of oil and fracturing fluid in nanopores remains largely uncharacterized, in part due to the challenge of conducting experiments at nanoscales. In this paper, we demonstrate a nanofluidic-based approach to visualize the fluid displacement during hydraulic fracturing. Nanoporous silicon-glass chips with circular and square grain shapes and identical depth of 175 nm were fabricated using reactiveion etching (RIE) and anodic bonding. Leveraging the inherent fluorescence property of the oil, the fluorescence microscopy was used to record the dynamics of the fluid displacement inside the chip. Performance of three different fracturing fluids - deionized water, potassium chloride (KCl) solution, and slick water - were evaluated based on the volumetric infiltration in the nanoporous network, entrapment of fracturing fluid in the porous media, and total production during drawdown. The KCl solution had the highest infiltration rate (fill factor of 0.68) and the lowest entrapment factor (0.39), resulting in the highest fracturing fluid recovery representing 43% in the square grain geometry with similar results for circular grains. With the fast quantification and ease of operation here, the nanofluidic approach enables a rapid screening of different fracturing fluids to inform shale oil operators.",20,21,3
Oil Recovery,Hydraulic Fracture,"Weijermars, Ruud; Alves, Ibere Nascentes","High-resolution visualization of flow velocities near frac-tips and flow interference of multi-fracked Eagle Ford wells, Brazos County, Texas",Drained rock volume; Multi-staged fractured wells; Eagle Ford Formation,PRESSURE,"This study outlines a workflow that combines reservoir characterization and decline curve-based production analysis with a physics-based drainage model that quantifies where fluid is drained from, based on the fracture treatment architecture. Decline curve analysis, applied to production data from four multi-fracked wells in the Eagle Ford formation (Brazos County, East Texas), provides forecasts for the estimated ultimate recovery (EUR). About 50% of EUR is realized in the first 1000 days (similar to 3 years) of the well-life. The drainage model shows where in the reservoir the produced fluid is actually drained from, based on the estimated reservoir parameters. This study includes several fundamental assessments of factors that may impact any drainage model, such as (1) the pressure front propagation time responsible for the depth of investigation, (2) pressure effects due to up-scaling of fracture patterns into a reduced number of fractures, and (3) interaction of fluid velocity patterns with pressure depletion zones. The drainage model for the Eagle Ford wells in our case study suggests that the first generation of hydraulic fractures recovers less than 1% of the original oil in place. With recovery factors so low, a repetitive schedule of periodic refracking the wells - provided the first refracks prove successful - is highly recommended.",19,19,0
Oil Recovery,Gas Channeling,"Wei, Peng; Pu, Wanfen; Sun, Lin; Pu, Yong; Wang, Song; Fang, Zhengkui",Oil recovery enhancement in low permeable and severe heterogeneous oil reservoirs via gas and foam flooding,Low permeability; Heterogeneity; Enhanced oil recovery; Nitrogen and CO2; Foam flooding,MINIMUM MISCIBILITY PRESSURE; MOBILITY CONTROL; NITROGEN FOAM; CO2; STABILITY; DISPLACEMENT; PERFORMANCE; INJECTION,"In view of the co-existence of the low permeability and severe heterogeneity, the effective tertiary technique for the enhanced oil recovery is still in progress. In this study, on the base of the simulation of SH reservoir conditions, we conducted the trinal-core flooding experiments about gas flooding (N-2 and CO2), WAG (N-2 and CO2) injection and foam flooding (N-2 and CO2). Combined with some static investigations, we found that CO2 flooding achieves additional oil recovery due to the development of near-miscibility and CO2 extraction, and the WAG injection can relieve the gas channeling associated with gas flooding. As for the foam flooding, CO2 foam has the advantage of oil displacement in a higher permeability layer and nitrogen foam is capable of diverting the flow to the least permeability zone in the strong heterogeneity formation and sharply increasing the oil recovery. It is also found that, in the pilot test of SH reservoir, nitrogen foam flooding is qualified for flow adjustment, water controlling and oil recovery enhancement in the low permeable and severe heterogeneous reservoir.",31,33,8
Oil Recovery,Gas Channeling,"Qu, Ming; Hou, Jirui; Qi, Pengpeng; Zhao, Fenglan; Ma, Shixi; Churchwell, Lauren; Wang, Qian; Li, Hui; Yang, Tianyuan",Experimental study of fluid behaviors from water and nitrogen floods on a 3-D visual fractured-vuggy model,Carbonate reservoir; 3-D physical experiment; Fluid flow behavior; Water flooding; Gas flooding; Enhanced oil recovery,3-DIMENSIONAL PHYSICAL SIMULATION; CARBONATE RESERVOIRS; OIL; PERFORMANCE; INJECTION; RECOVERY; UNIT,"Tahe oil field is a fractured-vuggy carbonate oil field in China. The fluid flow behaviors in this type of reservoir are complex due to multiple flow paths through the matrix, fractures and vugs. The main challenges of production include complicated oil-water distributions, rising state of water cone in different flow units, unclear multiphase flow behaviors, and lack of understanding of the fluid flow mechanism. Based on a geological map of the Tahe oil field, a physical 3-D fractured-vuggy model was designed and fabricated. Water and gas flooding experiments were performed, while the multiphase flow behaviors were captured with a high-resolution camera system. The pressure response was also monitored at different oil displacement stages. The results show that the 3-D physical model can be used to systematically and comprehensively investigate the fluid flow behaviors during the oil displacement process. The oil-water interfaces of prolific wells rise more rapidly than that from the stripper wells, leading to an uneven distribution of internal flow fields and cross-well interferences. Water breaks through early and water channeling is more significant in fractured than vuggy wells. The oil-water flow behavior in fractured-vuggy combinations is mainly determined by fractured-vuggy structure, viscous force, wettability, and the ratio of displacement forces to gravity. During nitrogen gas flooding, gas caps occur from gas displacing the remaining oil at the top of the reservoir. The synergistic interaction between nitrogen gas and injected water contributes to additional oil recovery. This study provides a guide for improving production performance in fractured-vuggy carbonate reservoirs.",23,27,2
Oil Recovery,Gas Channeling,"Hou, Jirui; Luo, Min; Zhu, Daoyi",Foam-EOR method in fractured-vuggy carbonate reservoirs: Mechanism analysis and injection parameter study,Carbonate reservoirs; Fracture; Vug; Foam; EOR; Injection parameters,3-DIMENSIONAL PHYSICAL SIMULATION; FLOW,"Fractured vuggy carbonate reservoirs in the Tahe Oilfield, China, have many diverse and unevenly distributed reservoir spaces. These spaces mainly consist of corrosion pores, high-density fractures, and large vugs. Reservoir development began with natural energy and pressure maintenance methods. However, a rapid rise of the water cut always led to poor oil production. Gas enhanced oil recovery (EOR) has shown notable improvement in the Tahe Oilfield; however, the recovery efficiency was limited by gas channeling. In this paper, a two-dimensional (2D) physical model was developed for a more detailed visual of the flow characteristics and the effect of the injection parameters (i.e., the injection rate, the injection slug size, the injection timing and the injection position) were evaluated. Water flooding can produce a certain amount of oil; however, the remaining oil types are the same as those found during the bottom water invasion period, that is, attic oil, bypass oil, and oil films. A better approach is N-2 flooding, which can replace the attic oil at the top of the vug by gravitational differentiation. An even better method is N-2 foam flooding. When the injection volume of N-2 foam reached a certain level, foams accumulated in the flow channels, decreased fluid mobility, inhibited the gas channeling, and expanded sweep efficiency. Moreover, the N-2 foam had excellent effects on oil film stripping, crude oil emulsification, and carrying oil droplets, thereby improving the microscopic displacement efficiency. In addition, the results of injection parameter effect can help researchers and reservoir engineers better understand and implement the foam-EOR method in the fractured vuggy carbonate reservoirs.",21,22,12
Oil Recovery,Gas Channeling,"Song, Zhaojie; Hou, Jirui; Liu, Xiaochun; Wei, Qi; Hao, Hongda; Zhang, Liya",Conformance control for CO2-EOR in naturally fractured low permeability oil reservoirs,CO2 flooding; Low permeability oil reservoir; Gas channeling; CO2 production control,CARBON-DIOXIDE; CO2 STORAGE; TIGHT OIL; RECOVERY; GAS; PERFORMANCE; IMPROVEMENT,"Poor sweep efficiency seriously limits field applications of CO2-EOR, especially in fractured reservoirs. The investigation of CO2 production performance and the method to control CO2 production becomes a key to successfully run a CO2-EOR project. In this study, artificial sandstone cores were used to perform a series of CO2 flooding experiments at reservoir conditions of pressure, temperature and formation water salinity. Injection pressure and rock heterogeneity were taken into account to study their effect on CO2 production performance. Two-stage gas channeling control with three different scenarios, including PLS gel and ethylenediamine, starch gel and ethylenediamine, and starch gel and CO2 foam, was presented to improve the conformance in 3-D fractured-core models. Based on production performance and experimental observation, three production stages were clearly stated, including gas-free production stage, oil/gas co-production stage, and gas channeling stage. Oil/ gas co-production stage contributed the most to oil recovery. This finding was very consistent with the practical production performance of CO2 flooding in oil fields. The conformance improvement and the increase in injection pressure (within permissible range bearing in mind of fracturing pressure) could remarkably enhance the oil recovery at oil/gas co-production stage. In 3-D radial flow experiments, the two-stage gas channeling control presented great potential in delaying gas production and improving CO2 flooding efficiency. The combination of starch gel and ethylenediamine achieved the best result. The starch gel could effectively block the fracture, while the viscous reactant of ethylenediamine and in-situ CO2 within high permeability layer could successfully tune injected CO2 to flood low permeability layer. This study could help field engineers determine the optimal timing of CO2 production control, and also offered an optimal method to improve the conformance for CO2-EOR.",17,17,8
Oil Recovery,Swelling,"Suleimanov, Baghir A.; Latifov, Yashar A.; Veliyev, Elchin F.; Frampton, Harry",Comparative analysis of the EOR mechanisms by using low salinity and low hardness alkaline water,EOR; Low hardness alkali water; Sandstone flooding; Bentonite swelling; Low salinity water; Emulsion,IMPROVED OIL-RECOVERY; BRINE ROCK SYSTEMS; WETTABILITY ALTERATION; CRUDE-OIL; SPONTANEOUS IMBIBITION; SANDSTONE; TEMPERATURE; IONS,"This paper discusses the application of low hardness alkali water compositions (LHAW) as a secondary and tertiary displacement agent for EOR. A comparative analysis of the impact of low salinity water (LSW) and LHAW water on interfacial tension, contact angle on rock, adsorption of ions, emulsion stability and clay swelling is presented. LHAW application contributes to the formation of stable water in oil (w/o) emulsions and a decrease in clay swelling compared to LSW. Adsorption values for both fluids are similar. Contact angle measurements show that both LSW and LHAW reduce interfacial tension compared to Synthetic Caspian Sea water (SCSW), by up to 17% and 94% respectively. Similar results were observed for contact angle measurements. Flooding experiments were conducted in secondary and tertiary modes. In secondary flooding the two water compositions LHAW-2 and LHAW-1 increased the oil recovery (%OOIP) in comparison with SCSW at water breakthrough, by 29% and 25% respectively. The final oil recovery increases were 21% and 15% respectively. In tertiary flooding, tests showed that LHAW-2 and LHAW-1 oil recoveries (%OOIP) compared to LSW were 13% and 10% respectively. The oil recovery rate for LHAW solutions was not linear versus lnt as was that for LSW. This was proposed as a consequence of emulsions generation while water-cut is below 50% however, above 50% water cut the rate stabilizes.",25,25,0
Oil Recovery,Swelling,"Lenji, Majid Abedi; Haghshenasfard, Masoud; Sefti, Mohsen Vafaie; Salehi, Mahsa Baghban; Heidari, Aghdas",Experimental study of swelling and rheological behavior of preformed particle gel used in water shutoff treatment,Preformed particle gel; Swelling ratio; PPG strength; Core flooding; Water cut reduction,ENHANCED OIL-RECOVERY; CONFORMANCE CONTROL; NUMERICAL-SIMULATION; PHENOLIC RESIN; HYDROGELS; POLYMER; POLYACRYLAMIDE; PERMEABILITY; PH; TRANSPORT,"Production of water effluents in mature reservoirs subjected to water flooding face many difficulties that might, ultimately, lead to their abandonment. Gel shutoff treatment of such reservoirs using preformed particle gel (PPG) is a technique used to block fracture channels and to insulate highly permeable zones. The technique not only reduces water production but leads also to successful conformance control. The present study introduces a novel type of PPG with an extremely high swelling ratio. The PPG is made up of polyacrylamide and Aluminum nitrate nanohydrate, which acts like a superabsorbent to absorb water equivalent in weight to 1000-2000 times the dry weight of the gel. Tests were conducted in the present experiment to investigate the effects of polymer and crosslinker concentrations, temperature, salinity, and pH on the swelling of PPG. Results showed that increasing polymer and crosslinker concentrations as well as enhanced salinity led to declining PPG swelling ratio. While PPG swelling ratio was not considerable outside the pH range of 5-9, its rate within this range was relatively high. Moreover, PPG swelling ratio increased only slightly with increasing temperature by up to 100 degrees C, beyond which the 3D network structure of PPG collapsed. Rheological tests were performed to determine PPG strength in three samples selected based on least salt sensitivity factor values. In addition, the core flooding test was performed to evaluate the blocking efficiency and the performance of the three samples in reducing water production in sandpacks. The test results revealed that PPG reduced water effluents in the sandpack by 30%-65%.",22,22,3
Oil Recovery,Swelling,"Zhong, Hanyi; Qiu, Zhengsong; Chai, Jinpeng; Guo, Baoyu; Sun, Dong; Liu, Junyi",A preliminary study of the preparation of shale stabilizer with oil sludge - From waste to resource,Oil sludge; Asphalt; Shale stabilizer; Drilling fluid; Preparation,WATER-TREATMENT; BIOREMEDIATION; FORMULATION; RECOVERY,"To convert the hazardous and waste oil sludge into shale stabilizer using in drilling fluid, a novel preparing method has been proposed in the current study. According to the characteristics of oil sludge, the preparation procedure was designed learning from conventional asphaltic-type shale stabilizer preparation method. Several additives such as gilsonite, calcium carbonate, surfactants (hexadecyltrimethylammonium chloride (CTAC) and polyoxyethylene octylphenol ether (OP-10)), polymers (polyethylene glycol (PEG-2000) and cationic polyacrylamide (CPAM)), and fluid loss reducers (sulfonated lignite and potassium humate) were incorporated into oil sludge with the assistance of melting, stirring, kneading, and drying. After the sequential steps of asphaltization, emulsification, and stabilization, a powdered shale stabilizer product (SS-OS) was obtained. The effect of SS-OS on rheology, filtration, and lubricity of drilling fluid bentonite dispersions was tested. Furthermore, the properties of stabilizing shale were evaluated. The results indicated that SS-OS could effectively inhibit shale swelling, dispersion, and exhibit excellent sealing performance. Moreover, it helped to reduce the fluid loss and significantly improve the lubricity of the drilling fluid. From the preliminary study, it was concluded that the strategy of preparing shale stabilizer with oil sludge could be employed to overcome waste, energy and environmental problems simultaneously and show promising application.",20,22,1
Oil Recovery,Swelling,"Akhtar, Maaz; Qamar, Sayyad Zahid; Pervez, Tasneem; Al-Jahwari, Farooq K.",Performance evaluation of swelling elastomer seals,Swelling elastomer; Seal/contact pressure; Finite element analysis; Performance evaluation; Seal parameters; Swelling conditions,CONSTITUTIVE MODELS; RUBBER; SIMULATIONS; ELASTICITY; EXPANSION; BEHAVIOR; SET,"Swell packers are now being widely used for increased recovery from difficult oil and gas reservoirs and for remediation of various well problems. It is important to know how the elastomer actually swells in a particular well, how much time is required to achieve sealing, and what sealing pressure is generated. No published work is available that numerically investigates elastomer seal performance based on actual material properties at various stages of swelling. Current work uses finite element simulation to investigate swelling elastomer seal behavior in downhole petroleum applications. Variations in sealing pressure are studied for seal length, seal thickness, compression ratio, water salinity, swelling time, and type of well completion. Month-long swelling experiments on samples of two actual elastomers provide input to the numerical model in terms of real material and deformation data. Contact pressure was found to increase with swelling, at a higher rate in the first few days, then more slowly. Higher sealing pressure was observed in the case of swelling in lower-salinity brine, larger length of the sealing element, higher compression ratio of the seal, and elastomer swelling against rock formation as compared to steel outer-casing. These results can help field engineers decide which swelling elastomer and what seal configuration to use under a given set of field parameters. The study can also be used by application designers and academic researchers as a starting point for swelling elastomer based seal design and analysis.",19,21,7
Oil Recovery,Eagle Ford,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun",Data analysis for CO2-EOR in shale-oil reservoirs based on a laboratory database,CO2-EOR in unconventional reservoirs; CO2-EOR in shale oil reservoirs; Unconventional EOR methods; Lab data analysis for EOR data screening,,"Unconventional resources have played a significant role in changing oil industry plans recently. Shale formations in North America such as Bakken, Niobrara, and Eagle Ford have huge oil in place, 100-900 Billion barrels of recoverable oil in Bakken only. However, the primary oil recovery is still low as 5-10%. EOR methods are currently considered as a new concept in unconventional reservoirs due to the immature information about these plays. Injecting carbon dioxide (CO2) might be the most potential strategy to improve oil recovery in such complex plays (Alfarge et al., 2017a,b). Jin et al. (2016) conducted an experimental study to investigate improving oil recovery by CO2 injection in 21 natural preserved core samples from Bakken Petroleum System (BPS). Their experimental results indicated that CO2 injection has a significant potential to improve oil transportability in these Nano-pores formations. In this study, data analysis for feasibility of CO2-EOR has been conducted on 95 cases of natural preserved cores collected from different formations including 44 cases from Middle Bakken, 26 cases from Lower Bakken, 17 from Upper Bakken, 4 cases from Three Forks, and 4 cases from unknown formation/formations. The relationship between the improved oil recovery by the injected CO2 and 6 rock properties including porosity, permeability, mean pore throat radius, total organic carbon content (TOC), water saturation, and oil saturation has been separately determined and physically discussed. Furthermore, the relationships between the improved oil recovery obtained by the injected CO2 and 4 operating parameters including CO2 bath pressure, CO2 bath temperature, and core sample bulk size, and exposing time have been also separately investigated. A Proxy model to associate the functionality of the improved oil recovery by CO2 injection and these 10 parameters have been constructed. Moreover, statistical methods for Design of Experiments (DOE) have been used to rank the most important parameters affecting CO2-EOR performance in the microscale level (lab scale) of these unconventional reservoirs. This study provides an important set of lab-based data obtained from natural preserved cores to find out the applicability of CO2-EOR in these unconventional reservoirs. Also, this research demonstrates some key points which could help in understanding CO2-EOR mechanisms in shale plays since they are much complex and very different from conventional formations.",27,28,0
Oil Recovery,Eagle Ford,"Hu, Yuqi; Weijermars, Ruud; Zuo, Lihua; Yu, Wei",Benchmarking EUR estimates for hydraulically fractured wells with and without fracture hits using various DCA methods,Production forecasting; EUR estimates; Modified Hyperbolic Decline Model; Duong model; Logistic Growth Analysis Model; Power Law Exponential,SHALE GAS-RESERVOIRS,"Various decline curve analysis (DCA) methods can be applied to forecast the production performance of hydrocarbon wells, including horizontal wells stimulated with hydraulic fracturing. Yet, which method is more preferable remains in doubt. The objective of this study is to evaluate various DCA methods by history matching and hindcasting both synthetic and field production data in order to assess for each method the reliability of production forecasts and the estimated ultimate recovery (EUR). Five DCA methods have been evaluated because of their computational simplicity and broad application. These methods are the Modified Hyperbolic Decline model (MHD), Duong model, Logistic Growth Analysis Model (LGM), and the Power Law Exponential (PLE, with D-infinity = 0 and D-infinity = 8) Decline models. Each method was evaluated using three data sets: synthetic shale oil production rates based on a CMG reservoir model using Eagle Ford reservoir characteristics, data from producing Eagle Ford wells and from Austin Chalk wells. The hindcast method was applied to the Eagle Ford synthetic wells to establish the EUR deviation between the synthetic reservoir model production forecast and the various DCA methods. The weighted residuals of history matched production rates for Eagle Ford indicate that the MHD and Duong models give the lowest matching errors (as low as 1.32%) and the highest EUR estimations (as high as 3,447,609 stb). The PLE model (with D-infinity not equal 0) gives the most conservative EUR estimation, and also the least reliable history matching method (on our Eagle Ford data sets), which therefore is the least preferable DCA method. For the Austin Chalk wells in our study, all methods generate fairly similar EUR predictions with similar matching errors (from 13% to 15%) so that the DCA method preference becomes indifferent. This study also touches upon the relationship between DCA results when well interference occurs due to various hydraulic fracture hits. Shale wells that primarily contain hydraulic fractures and few natural fractures (Eagle Ford) give the most reliable forecasts using the MHD and Duong DCA methods. However, wells in the Austin Chalk, a naturally fractured reservoir, show little difference between the forecast accuracy from the various DCA methods.",25,28,0
Oil Recovery,Eagle Ford,"Weijermars, Ruud; Alves, Ibere Nascentes","High-resolution visualization of flow velocities near frac-tips and flow interference of multi-fracked Eagle Ford wells, Brazos County, Texas",Drained rock volume; Multi-staged fractured wells; Eagle Ford Formation,PRESSURE,"This study outlines a workflow that combines reservoir characterization and decline curve-based production analysis with a physics-based drainage model that quantifies where fluid is drained from, based on the fracture treatment architecture. Decline curve analysis, applied to production data from four multi-fracked wells in the Eagle Ford formation (Brazos County, East Texas), provides forecasts for the estimated ultimate recovery (EUR). About 50% of EUR is realized in the first 1000 days (similar to 3 years) of the well-life. The drainage model shows where in the reservoir the produced fluid is actually drained from, based on the estimated reservoir parameters. This study includes several fundamental assessments of factors that may impact any drainage model, such as (1) the pressure front propagation time responsible for the depth of investigation, (2) pressure effects due to up-scaling of fracture patterns into a reduced number of fractures, and (3) interaction of fluid velocity patterns with pressure depletion zones. The drainage model for the Eagle Ford wells in our case study suggests that the first generation of hydraulic fractures recovers less than 1% of the original oil in place. With recovery factors so low, a repetitive schedule of periodic refracking the wells - provided the first refracks prove successful - is highly recommended.",19,19,0
Oil Recovery,Oil Sludge,"Liu, Chuhan; Zhang, Yin; Sun, Shanshan; Huang, Lixin; Yu, Li; Liu, Xiaonan; Lai, Ruiqiu; Luo, Yijing; Zhang, Zhiyong; Zhang, Zhongzhi",Oil recovery from tank bottom sludge using rhamnolipids,Oil sludge; Oil recovery; Pseudomonas aeruginosa; Biosurfactant,CRUDE-OIL; CONTAMINATED SOIL; PETROLEUM; DEMULSIFICATION; BIOSURFACTANTS; PSEUDOMONAS; PYROLYSIS; EMULSIONS,"Oil sludge has become a major impediment to the development of the petroleum and petrochemical industries with the growth of oil production worldwide. In this research, rhamnolipid biosurfactant produced by Pseudomonas aeruginosa was used to recover oil from oil tank bottom sludge. The optimum value of the fermentation broth (with rhamnolipid biosurfactant concentration of 5.4 g/L) addition was a volume fraction of 2% (v/v). Optimal temperature (65 degrees C), liquid/solid ratio (3:1), washing time (3 h), and agitation intensity (300 rpm) for oil recovery were determined. Wastewater from oil recovery was flocculated with 400 mg/L polyaluminum chloride for reuse. The moisture of the recovered oil was (0.42 +/- 0.12) %, which could directly enter into the refinery process. The solid particles in the oil sludge exhibited a porous structure that adsorbed a significant amount of oil and increased the difficulty of oil recovery. Results showed that the fermentation broth of P. aeruginosa can be used to recover oil from oil sludge and has potential industrial applications.",34,38,5
Oil Recovery,Oil Sludge,"Zhong, Hanyi; Qiu, Zhengsong; Chai, Jinpeng; Guo, Baoyu; Sun, Dong; Liu, Junyi",A preliminary study of the preparation of shale stabilizer with oil sludge - From waste to resource,Oil sludge; Asphalt; Shale stabilizer; Drilling fluid; Preparation,WATER-TREATMENT; BIOREMEDIATION; FORMULATION; RECOVERY,"To convert the hazardous and waste oil sludge into shale stabilizer using in drilling fluid, a novel preparing method has been proposed in the current study. According to the characteristics of oil sludge, the preparation procedure was designed learning from conventional asphaltic-type shale stabilizer preparation method. Several additives such as gilsonite, calcium carbonate, surfactants (hexadecyltrimethylammonium chloride (CTAC) and polyoxyethylene octylphenol ether (OP-10)), polymers (polyethylene glycol (PEG-2000) and cationic polyacrylamide (CPAM)), and fluid loss reducers (sulfonated lignite and potassium humate) were incorporated into oil sludge with the assistance of melting, stirring, kneading, and drying. After the sequential steps of asphaltization, emulsification, and stabilization, a powdered shale stabilizer product (SS-OS) was obtained. The effect of SS-OS on rheology, filtration, and lubricity of drilling fluid bentonite dispersions was tested. Furthermore, the properties of stabilizing shale were evaluated. The results indicated that SS-OS could effectively inhibit shale swelling, dispersion, and exhibit excellent sealing performance. Moreover, it helped to reduce the fluid loss and significantly improve the lubricity of the drilling fluid. From the preliminary study, it was concluded that the strategy of preparing shale stabilizer with oil sludge could be employed to overcome waste, energy and environmental problems simultaneously and show promising application.",20,22,1
Oil Recovery,Shale Gas-reservoirs,"Hu, Yuqi; Weijermars, Ruud; Zuo, Lihua; Yu, Wei",Benchmarking EUR estimates for hydraulically fractured wells with and without fracture hits using various DCA methods,Production forecasting; EUR estimates; Modified Hyperbolic Decline Model; Duong model; Logistic Growth Analysis Model; Power Law Exponential,SHALE GAS-RESERVOIRS,"Various decline curve analysis (DCA) methods can be applied to forecast the production performance of hydrocarbon wells, including horizontal wells stimulated with hydraulic fracturing. Yet, which method is more preferable remains in doubt. The objective of this study is to evaluate various DCA methods by history matching and hindcasting both synthetic and field production data in order to assess for each method the reliability of production forecasts and the estimated ultimate recovery (EUR). Five DCA methods have been evaluated because of their computational simplicity and broad application. These methods are the Modified Hyperbolic Decline model (MHD), Duong model, Logistic Growth Analysis Model (LGM), and the Power Law Exponential (PLE, with D-infinity = 0 and D-infinity = 8) Decline models. Each method was evaluated using three data sets: synthetic shale oil production rates based on a CMG reservoir model using Eagle Ford reservoir characteristics, data from producing Eagle Ford wells and from Austin Chalk wells. The hindcast method was applied to the Eagle Ford synthetic wells to establish the EUR deviation between the synthetic reservoir model production forecast and the various DCA methods. The weighted residuals of history matched production rates for Eagle Ford indicate that the MHD and Duong models give the lowest matching errors (as low as 1.32%) and the highest EUR estimations (as high as 3,447,609 stb). The PLE model (with D-infinity not equal 0) gives the most conservative EUR estimation, and also the least reliable history matching method (on our Eagle Ford data sets), which therefore is the least preferable DCA method. For the Austin Chalk wells in our study, all methods generate fairly similar EUR predictions with similar matching errors (from 13% to 15%) so that the DCA method preference becomes indifferent. This study also touches upon the relationship between DCA results when well interference occurs due to various hydraulic fracture hits. Shale wells that primarily contain hydraulic fractures and few natural fractures (Eagle Ford) give the most reliable forecasts using the MHD and Duong DCA methods. However, wells in the Austin Chalk, a naturally fractured reservoir, show little difference between the forecast accuracy from the various DCA methods.",25,28,0
Oil Recovery,Shale Gas-reservoirs,"Javaheri, Ali; Habibi, Ali; Dehghanpour, Hassan; Wood, James M.",Imbibition oil recovery from tight rocks with dual-wettability behavior,,SHALE GAS-RESERVOIRS; MERCURY-INTRUSION; WATER-ADSORPTION; PORE STRUCTURE; BRINE; PLAY,"Previous studies demonstrate that the Montney rock samples have a dual-wettability pore network. Recovery of the oil retained in small hydrophobic pores is a unique challenge. In this study, we apply dual-core imbibition (DCI) method on several Montney core plugs and introduce imbibition-recovery (IR) trio to investigate the recovery mechanisms in rocks with dual-wettability pore network. First, we evaluate the wetting affinity of five twin core-plugs from the Montney Formation by measuring spontaneous imbibition of reservoir oil and brine, and by measuring equilibrium contact angle. We place one plug of each pair in the oil and the other in the brine, and measure the weight change periodically. Second, we place the oil-saturated plugs in the brine to visualize the expelled oil droplets and measure volume of the recovered oil. We comparatively analyze the spontaneous imbibition data from the first step and the oil recovery data from the second step in one imbibition-recovery trio (oil imbibition, brine imbibition, and imbibition oil recovery). The results of air-liquid contact angle and spontaneous imbibition tests on dry samples suggest that affinity of the samples to oil is higher than that to brine, in an air-liquid system. However, the results of liquid-liquid contact angle and countercurrent imbibition tests suggest that affinity of the samples to water is higher than that to oil, in a liquid-liquid system. For each twin set, the oil recovery curve follows the trend of brine imbibition curve, and the final oil recovery is always less than the equilibrated water uptake of dry samples. This observation indicates that water can only access the hydrophilic part of the pore network initially saturated with oil.",15,18,4
Crude Oil,Asphaltene,"Khalaf, Mohammed H.; Mansoori, G. Ali",A new insight into asphaltenes aggregation onset at molecular level in crude oil (an MD simulation study),Asphaltene aggregation; Crude oil; Electrostatic energy; Hydrogen bond; Molecular dynamics; Van der Waals energy,DYNAMICS; ASSOCIATION; DEPOSITION; SOLVENTS; COAL,"The findings reported here is to understand the nature of asphaltenes aggregation behavior at the molecular level in crude oil. Previous studies have been rich with the statistical and macroscopic aspects of heavy organics behavior in petroleum fluids. Molecular dynamics simulations of three different model asphaltene molecules in a ""modeled crude oil"" composed of n-heptane and o-xylene were conducted. The roles of van der Waals (vdW), hydrogen bond (H-b), and electrostatic (ES) interaction energies on asphaltenes aggregation were investigated. Trends in aggregations, radial distribution functions (RDFs), vdW, H-b, and ES interactions were produced and analyzed. Our studies indicated asphaltenes with different molecular structures behaved differently from one another. At high paraffinic conditions, the preferred stacking of asphaltene molecules was face-to-face. The presence of H-b enhanced the stability of the aggregate. The number of H-bs varied in each model of asphaltene, depending on their detailed structures. The ES interactions between asphaltenes were either attraction or repulsion depending on the molecular structure. Overall, the major factor was the architecture of each asphaltene molecule, such as the number and length of chains, the number and position of heteroatoms, and the number and size of the aromatic cores where they are linked together to represent asphaltene behavior.",41,42,3
Crude Oil,Asphaltene,"Taheri-Shakib, Jaber; Shekarifard, Ali; Naderi, Hassan",Characterization of the wax precipitation in Iranian crude oil based on Wax Appearance Temperature (WAT): Part 1. The influence of electromagnetic waves,WAX; Heavy crude oil; WAT; Microwave; Asphaltene,YIELD-STRESS; CLOUD POINT; POUR POINT; CRYSTALLIZATION; ASPHALTENES; INHIBITORS; COPOLYMERS; MICROWAVE; PARAFFIN; BEHAVIOR,"This paper investigated the effects of microwaves (MW) on Wax Appearance Temperature (WAT), the shape and morphology of wax crystals, and the content of elements in crude oil. After WAT was determined using cross-polarized microscopy (CPM), the intra-molecular bonds and the structure of the molecules were determined by subjecting crude oil and its wax content to Fourier-transform infrared (FTIR) spectroscopy analysis. Cracking and simultaneous evaporation of crude-oil combinations due to irradiation with MW caused peaks with different intensities in the oils' spectrums to appear. In addition, with irradiation, peaks reappeared that had been hidden in the range of virgin oil samples, and which were more closely related to aromatic compounds. The two processes of cracking and evaporation together resulted in a lighter oil sample with a lower WAT, which is evident in the samples' FTIR spectrum. Analysis of the images from the wax crystals under a polarization light microscope with image processing revealed a close connection between the shape and size of the wax particles and peak intensity of the FTIR spectrum and the crude-oil composition. Oil samples exposed to MW radiation had more rounded crystals and more similar proportions than virgin-oil samples. Radiation of MW waves caused asphaltene cracking to produce saturated, aromatic, and resin compounds. Since asphaltene is the heaviest oil-producing compound, this conversion lightened the oil and reduced the WAT. MW radiation also increased the amount of aromatic compounds derived from the resin in oil. The presence of asphaltene as one of the heavy-oil compounds and its interaction with wax molecules was investigated. It was observed that with respect to the naphthenic/polar of the wax sample, the decrease in the amount of asphaltene in the oil sample after irradiation reduced the interactions between the wax molecules and asphaltenes, and subsequently reduced the WAT. Scanning electron microscopy (SEM) images showed that the MW wax samples were composed of rounded and compacted particles, making it difficult to detect single grains. The size of the grains in the SEM images of MW samples was smaller than in the virgin sample. MW affected the dispersion and the mean size and shape of the wax particles under both the polarized light microscope and SEM; they also affected the bond/molecular structure as determined by FTIR and the amount of resin, asphaltene, saturation, and aromatics of the oil constituents, and decreased the average carbon number of the oil samples, which lowered the WAT.",36,38,1
Crude Oil,Asphaltene,"Gafurov, M. R.; Volodin, M. A.; Rodionov, A. A.; Sorokina, A. T.; Dolomatov, M. Yu.; Petrov, A. V.; Vakhin, A. V.; Mamin, G. V.; Orlinskii, S. B.",EPR study of spectra transformations of the intrinsic vanadyl-porphyrin complexes in heavy crude oils with temperature to probe the asphaltenes' aggregation,Bitumen; Crude oil; Heavy oil; Rotational correlation time; Temperature dependence; ESR,ELECTRON-PARAMAGNETIC-RESONANCE; IN-SITU; SPIN-RESONANCE; ATMOSPHERIC RESIDUES; ROTATIONAL MOBILITY; V=O COMPLEXES; 3.4 T; SYSTEMS; STABILITY; RESINS,Temperature dependencies of electron paramagnetic resonance spectra of intrinsic paramagnetic vanadyl complexes and dynamical viscosity for two heavy crude oils and asphalt samples are measured. Transitions between the different motional conditions (from the rigid to the fast motion regimes) are observed. The rotational correlation times (in the model of the isotropic diffusion) are extracted. It is shown that the characteristic temperatures for the motional regime transitions are mainly defined by the asphaltenes' content. From our analysis it follows that the thermal treatment leads to the destruction of the asphaltene complexes onto the 4-5 small pieces. The results indicate that paramagnetic vanadyl complexes are the sensitive intrinsic probes to study qualitatively and quantitatively structural transformations of aspahltenes of heavy crude oils in-situ.,31,31,0
Crude Oil,Asphaltene,"Taheri-Shakib, Jaber; Rajabi-Kochi, Mahyar; Kazemzadeh, Ezzatallah; Naderi, Hassan; Shekarifard, Ali",A comprehensive study of the impact of wax compositions on the wax appearance temperature (WAT) of some Iranian crude oils: An experimental investigation,Wax; Asphaltene; Wax appearance temperature (WAT); Polar compounds; Crystal; Heavy oils,CRYSTALLIZATION; ASPHALTENES; PARAFFIN; FLOW; PRECIPITATION; COPOLYMERS; GELATION; MODEL; GELS; THERMOMICROSCOPY,"In this study, the effect of the molecular and structural wax properties of five oil samples from reservoirs in southwest Iran on the wax appearance temperature (WAT), shape, and morphology of wax crystals was investigated. After determining the WAT by cross-polarized microscopy (CPM) and viscometer, the wax was subjected to Fourier transform infrared (FTIR) spectroscopy analysis to determine the intermolecular bonds and structure of the molecules. The results show that there is a close relationship between the shape and size of the wax particle and the intensity and types of peaks in the FTIR spectrum of the wax. Paraffinic wax samples had rounded crystals of varying sizes, while polar/naphthenic compounds formed needle-shaped crystals. In the wax structure of some crude-oil samples, although normal alkanes are the main component of the wax, polar and naphthenic structures, albeit small, can also exist. The experiments showed that polar compounds also existed in the naphthenic wax sample, although the paraffin wax sample contained no polar/naphthenic compounds. The presence of asphaltene in crude oil and in polar/naphthenic wax samples affected the WAT and the crystalline form. As the amount of asphaltene increased, the interaction between the polar/naphthenic wax and asphaltene molecules increased; consequently, the WAT also increased. Energy-dispersive spectroscopy (EDS) analysis showed that as the wax sample loses its hydrocarbon nature, its carbon content decreases, and changes in the SNO elements in the wax structure occur, the WAT proportionally increases. Scanning electron microscopy (SEM) images of wax samples showed that semi-microcrystalline samples were composed of rounded and compacted grains; however, paraffinic waxes consisted of a network of large tubular crystals similar in shape to rice grains. The presence of polar/naphthenic compounds in the wax structure changed the shape and density of particles, as shown in SEM images. The dispersion, mean size, and shape of the wax particles, both under the polarized light microscope and under SEM, depend on the molecular/bonding structure of the wax, the elemental composition, and the amount of asphaltene.",27,27,1
Crude Oil,Asphaltene,"Taheri-Shakib, Jaber; Rajabi-Kochi, Mahyar; Kazemzadeh, Ezzatallah; Naderi, Hassan; Salimidelshad, Yaser; Esfahani, Mohammad Reza","A comprehensive study of asphaltene fractionation based on adsorption onto calcite, dolomite and sandstone",Asphaltene fractions; Adsorption; FTIR; Elemental analysis; Zeta potential,APPEARANCE TEMPERATURE WAT; HEAVY-OIL; HEATING TIME; CRUDE OILS; PART 1.; AGGREGATION; MICROWAVE; PRECIPITATION; SOLUBILITY; DEPOSITION,"In this study, based on a new procedure, asphaltene fractions of Sarvak oil samples were determined based on their adhesion to calcite, dolomite, and sandstone surfaces and their properties were evaluated. In irreversibly adsorbed asphaltenes, the highest concentrations of elements were 4.23 wt.% nitrogen (N) on the calcite surface, 7.12 wt.% sulfur (S) on dolomite surface, and 6.18 wt.% S and oxygen (O) on the sandstone surface. The dispersion of asphaltene fraction constituents on the surface, is approximately the same across the calcite sample, but in the dolomite sample, the highest adsorption of S correlates to the presence of magnesium (Mg). However, in sandstone samples, the highest S adsorption is achieved by potassium (K). The most dispersion of O occurs at the surface of the sandstone samples; according to matching through EDS mapping, due to the presence of silicon (Si), O has considerable dispersion. Asphaltene fractions also make lighter carbon compounds. It is important to note that in all samples, C-17 is the highest peak seen in irreversibly adsorbed asphaltenes. In addition, the zeta potential is negatively affected by increasing the adsorption properties of asphaltene fractions; this depends on the concentration of asphaltene elements adhering to the surface. The O-H polar peak in the irreversibly absorbed asphaltene/sandstone sample is higher due to the presence of O, compared to the other samples. In all three mineral samples, bulk asphaltene and adsorbed fractions have roughly the same values for alkyl groups. The concentration of carbonyl, carboxylic acid, or derivative groups in adsorbed fractions in calcite and sandstone samples show a higher intensity.",24,24,0
Crude Oil,Asphaltene,"Sitnov, Sergey A.; Mukhamatdinov, Irek I.; Vakhin, Alexey V.; Ivanova, Anna G.; Voronina, Elena V.",Composition of aquathermolysis catalysts forming in situ from oil-soluble catalyst precursor mixtures,Aquathermolysis; Mixed oxides; Transition metals; Catalyst precursor; Heavy oil; In-situ upgrading,HIGH-TEMPERATURE CHEMISTRY; HIGH-VISCOSITY OIL; HEAVY CRUDE OILS; ORGANIC-MATTER; SUPERCRITICAL WATER; CONVERSION; IRON; HETEROCYCLES; CARBOCYCLES; COMBUSTION,"Increasing efficiency of thermal recovery methods of heavy oil through injection of destructive hydrogenation catalysts precursors is a relevant task. In this paper the composition and properties of the active binary catalysts, which formed from a mixture of oil-soluble iron-, nickel- and copper-based precursors have been studied by XRD, Mossbauer spectroscopy, SEM, EDX-mapping methods. Moreover, the efficiency of a mixture of the corresponding metals in reducing the content of heavy components (SARA) of heavy crude oil from Ashal'cha field (Republic of Tatarstan) have been investigated. Mossbauer spectroscopy and EDX-mapping detected the formation of not only spinel ferrites MFe2O4 (where M = Ni or Cu), but also individual oxides. Moreover, in case of nickel-based catalyst three phases are formed: magnetite FeO center dot Fe2O3, spinel ferrite NiFe2O4 and superparamagnetic finely dispersed phase of iron oxides (and probably nickel oxides). According to XRD results, the oxides formed in the first stage transform into nonstoichiometric spinel ferrites Cu0.86Fe2.14O4 and Ni1.43Fe1.7O4 under hydrothermal influences. It is related with the thermodynamically beneficial processes of conversion of this specific phase composition. Based on the SARA and elemental analysis of the initial and converted oil, it was found that catalytic aquathermolysis decreases the content of asphaltenes and resins (about 45%) in the presence of catalyst nanoparticles, which indicates an improvement in the quality of the heavy oil.",22,23,2
Crude Oil,Asphaltene,"Taheri-Shakib, Jaber; Shekarifard, Ali; Naderi, Hassan",Experimental investigation of the asphaltene deposition in porous media: Accounting for the microwave and ultrasonic effects,Asphaltene precipitation; Permeability; Microwaves; Ultrasonic waves; Polar components; Porous media,HEAVY CRUDE-OIL; MODELING FORMATION DAMAGE; PRECIPITATION; PERMEABILITY; IRRADIATION; DESULFURIZATION; FLOCCULATION; CARBONATES; RECOVERY; COAL,"This study examines the effects of ultrasonic waves (US) and microwaves (MW) on the permeability in carbonate cores with different permeabilities of asphaltenes deposited therein. Using US with toluene injection restores permeability in cores with a permeability of less than 20 md, about 18.8% and 29% higher than injection of toluene without US. The US creates turbulence and cavitation, causing a change in the structure of the asphaltene conglomerations deposited in the cores. These structural changes may be due to increased levels of contact between precipitates and better penetration of the injected fluid which facilitate the process of removing them from the cores. MW, in addition to changing the structure of asphaltene clusters within the cores, reduces the amount of their polar elements, including sulfur (S), nitrogen (N), and oxygen (O). Under MW irradiation, the sulfur, nitrogen, and oxygen values were 23.5%, 18.4% and 48%, respectively. This decrease in the amount of asphaltene polar elements, which is due to their high capacity to absorb MW can reduce the negative charges in asphaltene particles. The zeta potential results also indicated that the negative charges of asphaltene particles decreased and became more positive as a result of MW radiation (from -12.31 mV to -7.59 mV). Fourier transform infrared spectroscopy (FTIR) spectra tests also confirmed these results. The polar bands of the asphaltene particles deposited inside the cores (OH, S-H; C=O) had a decreasing trend and escaped from the structure of the asphaltene clusters. Decreasing the polar values, especially those of the compounds with negative electrical charge (SO) actually reduces the adhesive force between asphaltene and limestone that has positive electrical charges. This phenomenon causes the removal of asphaltene particles from the porous rock media. The rate at which permeability is restored also indicates that MW radiation is much higher than the previous one (US thorn Toluene), especially cores with low permeability. The results of this study could be a major step towards removing asphaltene precipitates in oil reservoirs using US and MW technologies.",21,21,5
Crude Oil,Asphaltene,"Lashkarbolooki, Mostafa; Ayatollahi, Shahab","The effects of pH, acidity, asphaltene and resin fraction on crude oil/water interfacial tension",IFT; EOR; pH; Asphaltene; Resin; Crude oil,OIL-RECOVERY; HEAVY OIL; ACTIVE FRACTIONS; SURFACTANT; STABILITY; ALKALI; EMULSIFICATION; SYNERGY,"A basic understanding of the activities of indigenous surfactants of crude oil at the water/oil interface as a function of aqueous phase pH can give us a better insight into the alkaline enhanced oil recovery processes. The present study aimed to elucidate the effect of salinity and crude oil type, specifically the influence of resin and asphaltene molecules during alkaline flooding through interfacial tension (IFT) measurements via pendant drop and spinning techniques. Several model oils containing asphaltene and resin fractions were prepared and their IFTs were compared with those of the original crude oils. Moreover, the elemental analyses of asphaltene and resin fractions were performed, and the total acid numbers of all oils were measured as well. The IFT results of three studied crude oils and the asphaltenic and resinous model oils with sea water and deionized water underlined the importance of the degree of salinity, and qualitative and quantitative nature of resin and asphaltene fractions. It was also revealed that the amount of asphaltene and resin fractions as well as their structural nitrogen and oxygen contents were the most influential parameters on the IFT of crude oil as a function of pH values. In addition, the variations of IFT crude oils/the ionic solution and deionized water were more noticeable in the basic aqueous solutions.",21,22,1
Crude Oil,Asphaltene,"Li, Xingxun; Guo, Yunmei; Sun, Qiang; Lan, Wenjie; Liu, Aixian; Guo, Xuqiang",Experimental study for the impacts of flow rate and concentration of asphaltene precipitant on dynamic asphaltene deposition in microcapillary medium,Asphaltene deposition; Visualization; Capillary flow; Microcapillary; Pore scale,ENHANCED OIL-RECOVERY; POROUS-MEDIA; CAPILLARY-FLOW; CO2 INJECTION; CONTACT-ANGLE; CRUDE-OIL; AGGREGATION PHENOMENA; INTERFACIAL-TENSION; PRESSURE DEPLETION; NATURAL DEPLETION,"Asphaltenes have been referred to 'cholesterol of petroleum' and the heaviest and the most complex components in crude oil. Asphaltene aggregation and deposition have always been a challenging issue on fluid transport in porous media for oil recovery and production processes in industries. Many experimental efforts have been done to study asphaltene aggregation and deposition from crude oil. Most of these works were carried out by coreflood tests or in bulk solution. Only several macroscopic parameters, such as pressure variation and permeability reduction caused by asphlatene deposition, were studied. Few experimental studies have been done to make the direct pore-scale visualization of dynamic asphaltene deposition behavior in capillary flow. In this study, we developed a new experimental approach to directly visualize and measure the dynamic asphaltene deposition process in capillary flow. Effects of concentration of asphaltene precipitant and flowrate were examined. The results indicate that the concentration of precipitant has a significant effect on the dynamic asphaltene deposition in capillary flow. The size of asphaltene deposit increases significantly with elapsed time and size distribution becomes wider at higher precipitant concentration. Higher concentration of asphaltene precipitant could lead to higher deposition rate. The results also indicate that higher flowrate causes faster growth of asphaltene deposits in capillary flow. Larger sizes of asphaltene deposits are formed and number of asphaltene deposits decreases with the elapsed time at higher flowrate. The results produced provide new sights into the dynamic asphaltene deposition in capillary flow at a pore scale. They could contribute to predict the growth rate of arterial asphaltene deposition in porous media and develop accurate numerical simulator for enhanced oil recovery purpose in industries.",19,20,5
Crude Oil,Asphaltene,"Lashkarbolooki, Mostafa; Riazi, Masoud; Ayatollahi, Shahab",Effect of CO2 and crude oil type on the dynamic interfacial tension of crude oil/carbonated water at different operational conditions,Dynamic IFT; Carbonated water; CO2; Adsorption time; Temperature; Pressure,CARBONATED WATER; AQUEOUS-SOLUTIONS; INJECTION; RECOVERY; PH; EQUILIBRIUM; TEMPERATURE; PERFORMANCE; ASPHALTENE; ADSORPTION,"Concerns about climate change have persuaded the researchers to examine CO2 injection in the form of carbonated water (CW) into oil reservoir as a safe and effective CO2 storage and enhanced oil recovery process. Although interfacial tension (IFT) between crude oil and injected fluid has a vital role on the displacement of fluids in porous media, the effect of CO2 and crude oil type on the dynamic IFT of crude oil under different operational conditions is not well understood. Accordingly, this study was carried out to assess the effects of temperature, pressure, crude oil type and CO2 on the dynamic IFT of crude oil/CW. To achieve this goal, two types of crude oil were provided from southern Iranian oil reservoirs and dynamic IFTs with CW were measured in a wide range of temperatures and pressures (i.e. temperature range of 30-80 degrees C and pressure range of 500-4000 psi); the obtained results were compared with the system without CO2. In addition, the adsorption time of carbonated aqueous phase/crude oil, obtained based on the mono exponential decay model, was also compared with unadulterated water/crude oil system. The outcome of this study showed that crude oil type has the most significant effect on the IFT of crude oil/CW compared to pressure, temperature and CO2 content. In more details, the IFT of crude oil/CW can be affected by the amount and type of acidic/basic components in the crude oil as well as pH of the aqueous solution. Besides, the obtained results revealed that the effect of temperature was more considerable on the IFT of the heavy crude oil compared with the light crude oil in both studied aqueous solutions (i.e. unadulterated water and CW). Although the inversion phase temperature was obtained for unadulterated water/studied crude oils at all studied pressures, this phenomenon was not observed for crude oil/CW at elevated pressure, due to the high amount of CO2 at this condition.",17,17,3
Crude Oil,Asphaltene,"Nasri, Zarrin; Mozafari, Motahareh",Multivariable statistical analysis and optimization of Iranian heavy crude oil upgrading using microwave technology by response surface methodology (RSM),Heavy crude oil; Upgrading; Microwaves; Response surface methodology,ULTRASONIC IRRADIATION; HORIZONTAL WELL; DEMULSIFICATION; EMULSIONS; PERFORMANCE; PYROLYSIS; RECOVERY,"Conventional methods to upgrade heavy oil due to high pressure, low production efficiency, and low product quality have not been recognized as profitable methods. These complications resulted in using innovative technologies in this area. In this paper, the statistical analysis and process conditions optimization of Iranian heavy crude oil upgrading have been performed using microwave technology, for the first time. The heavy crude oil is from Iranian west Paydar field, with specifications including API 18.53, viscosity 78.76 cSt (at 20 degrees C). In order to optimize process conditions for upgrading heavy crude oil, independent variables include power level (40-70-100%), process time (5-12.5-20) (min), activated carbon as sensitizer (0-5-10) (wt%), and Fe as catalyst (0-3-6) (wt%). Surface temperature, API ratio, viscosity ratio, and asphaltene reduction have been considered as response variables. The Box-Behnken design and response surface methodology (RSM) have been applied to determine parameters levels and to model the responses, respectively. The results show that the optimal conditions to maximize surface temperature, API ratio, and asphaltene reduction, and to minimize viscosity ratio involve power level of 100%, process time of 20 min, activated carbon of 10 wt%, Fe catalyst of 4.06 wt% which leads to 23.31API ratio, 31.6% asphaltene reduction, and 43.37% viscosity reduction. The predicted conditions agreed with the experimental values, representing the models accuracy.",16,17,3
Crude Oil,Asphaltene,"Sedighi, Mehdi; Mohammadi, Majid; Sedighi, Mojtaba",Green SAPO-5 supported NiO nanoparticles as a novel adsorbent for removal of petroleum asphaltenes: Financial assessment,Asphaltene; Adsorption; NiO/SAPO-5; RSM; Stock returns; Extended CAPM,RESPONSE-SURFACE METHODOLOGY; OIL PRICE SHOCKS; MOLECULAR-SIEVES; LANGMUIR ISOTHERM; CRUDE-OIL; TIO2/SIO2 NANOFLUIDS; MARKET EQUILIBRIUM; EUROPEAN COUNTRIES; THERMAL-CRACKING; MINERAL SURFACES,"In this paper, a NiO/SAPO-5 composite was prepared as a unique adsorbent to remove asphaltene from a model oil solution. The adsorbent is synthesized via an eco-friendly template (tetramethylguanidine, TMG). The surface structure of the adsorbent was characterized by TEM, BET, XRD, FTIR analysis. Response surface methodology was applied to maximize asphaltene removal by NiO/SAPO-5 composites. Influence of initial pH, D/C and temperature on the removal efficiency of asphaltene was analyzed. The predicted optimum D/C, pH and temperature were determined to be 0.07 [g/(mg/L)], 4.75 and 298 K, respectively. Under these conditions, the removal efficiency of asphaltene was predicted to be 88%. Moreover, the adsorption equilibrium data are particularly well matched to the Freundlich isotherm model at low temperatures (298 and 325 K) and to the Langmuir model at high temperatures (342 and 353 K). As well as, the financial assessment of asphaltene removal concerning stock returns of oil and petrochemical companies is evaluated.",15,17,1
Crude Oil,Asphaltene,"Zheng, Ce; Zhu, Mingming; Zareie, Reza; Zhang, Dongke","Characterisation of subfractions of asphaltenes extracted from an oil sand using NMR, DEPT and MALDI-TOF",Asphaltenes; DEPT; Molecular structure; NMR; Oil sand; Fractions,NUCLEAR-MAGNETIC-RESONANCE; SOLID-STATE NMR; PETROLEUM ASPHALTENES; MASS-SPECTROMETRY; MOLECULAR-WEIGHT; CRUDE-OIL; STRUCTURAL PARAMETERS; FRACTIONS; C-13; SPECTROSCOPY,"This paper reports the findings of an investigation into molecular structures and properties of an oil sand asphaltene sample and its subfractions. The asphaltene sample extracted from Buton Oil Sand (Indonesia) was fractionated stepwise into four subfractions by precipitation in a binary solvent system made from mixtures of dichloromethane/n-heptane with volumetric ratios of 30/70, 20/80 and 10/90, respectively. The average molecular structural parameters, including the average polycyclic aromatic hydrocarbon size, average side chain length and average molecular weight of the oil sand asphaltene sample and its subfractions, were measured and compared, using characterisation data obtained from nuclear magnetic resonance in combination with distortionless enhancement by polarisation transfer. The molecular weight distributions of the asphaltene samples were measured using a matrix-assisted laser desorption/ionisation time-of-flight mass spectrometry. The results indicated that the island molecular architecture was featured in all the asphaltene samples. The average polycyclic aromatic hydrocarbon size was found to be 7 rings for the least soluble subfraction, 6 rings for the other subfractions and the oil sand asphaltenes. The fractionation mechanism was dictated by polarity difference amongst subfractions as a result of relative luxuriance of the aliphatic parts. The use of C-13 NMR, DEPT and MALDI-TOF was shown to provide a useful means for characterisation and estimation of molecular structures of the asphaltenes.",14,14,2
Crude Oil,Asphaltene,"Mehrabi-Kalajahi, Seyed Saeed; Varfolomeev, Mikhail A.; Yuan, Chengdong; Emelianov, Dmitrii A.; Khayarov, Khasan R.; Klimovitskii, Alexander I.; Rodionov, Alexander A.; Orlinskii, Sergei B.; Gafurov, Marat R.; Afanasiev, Igor S.; Fedorchenko, Gennadii D.; Lubnina, Elena V.",EPR as a complementary tool for the analysis of low-temperature oxidation reactions of crude oils,Crude oil; In-situ combustion; Air injection; Oxidation; EPR; Free radical concentration,IN-SITU COMBUSTION; VANADYL-PORPHYRIN COMPLEXES; SARA FRACTIONS; PARAMAGNETIC-RESONANCE; KINETIC-ANALYSIS; AIR INJECTION; HEAVY OIL; LIGHT; ASPHALTENES; BEHAVIOR,"Air injection is a promising method for enhanced oil recovery (EOR) in both conventional and unconventional oil sources. It is widely accepted that oxidation reactions between oil and injected air determine the success of an air injection process. In this study, electron paramagnetic resonance (EPR) was introduced as a new route to investigate the occurrence of low-temperature oxidation (LTO) and its behavior by monitoring the signals of free radicals. The EPR experiments were conducted for the different crude oil samples (light, medium and heavy) heated in both static air and flow air (air-bubbling) conditions under different temperatures from 25 degrees C to 180 degrees C. The results showed that the free-radical concentrations exhibited a good correspondence on the heating temperature. Furthermore, nuclear magnetic resonance (NMR), Fourier-transform infrared spectroscopy (FTIR) and differential scanning calorimetry (DSC) experiments were carried out to help to analyze the oxidation process and verify the EPR results. It turned out that the EPR results can be well supported by NMR, FTIR and DSC data, which indicates that proposed EPR monitoring method can be applied as a fast and low-cost technique to investigate LTO under mild reaction conditions. Simultaneously, the combination of EPR, NMR, FTIR and DSC can help to better understand the LTO mechanism and to monitor the application of in-situ combustion technique in the field.",14,14,1
Crude Oil,Asphaltene,"Plata-Gryl, Maksymilian; Jungnickel, Christian; Boczkaj, Grzegorz",An improved scalable method of isolating asphaltenes,Asphaltenes; Bitumen; Soxhlet; Precipitation; Sorbents; Extraction,N-HEPTANE ASPHALTENES; CRUDE OILS; PRECIPITATION TEMPERATURE; MOLECULAR-WEIGHT; PETROLEUM; RESINS; HEAVY; SEPARATION; FRACTIONS; SOLUBILITY,"A new, improved and scalable procedure of asphaltene fraction isolation is presented and compared to standard test methods. The new procedure uses 1:40 feedstock to solvent (n-heptane) ratio (g/mL), filtration through a cellulosic thimble and extensive washing in a Soxhlet type extractor. The group type composition and purity of the asphaltene fractions have been examined using thin-layer chromatography with flame-ionization detection. This study revealed that the new procedure provides a higher purity of asphaltene fraction resulting in a more accurate determination of its content in bitumens when comparing to the standard test method. Moreover, an attempt of evaluation of the scale-up possibility of the proposed and standard test methods was made, revealing that new procedure is more scalable than standard test methods. It is possible to obtain large quantities of a high purity asphaltene fraction even on a process scale. This feature is crucial for technical analytics, for researchers studying asphaltenes characteristic as well as for other novel applications of asphaltenes such as its use as sorbents in separation techniques.",14,14,0
Crude Oil,Degrees C,"Liu, Chuhan; Zhang, Yin; Sun, Shanshan; Huang, Lixin; Yu, Li; Liu, Xiaonan; Lai, Ruiqiu; Luo, Yijing; Zhang, Zhiyong; Zhang, Zhongzhi",Oil recovery from tank bottom sludge using rhamnolipids,Oil sludge; Oil recovery; Pseudomonas aeruginosa; Biosurfactant,CRUDE-OIL; CONTAMINATED SOIL; PETROLEUM; DEMULSIFICATION; BIOSURFACTANTS; PSEUDOMONAS; PYROLYSIS; EMULSIONS,"Oil sludge has become a major impediment to the development of the petroleum and petrochemical industries with the growth of oil production worldwide. In this research, rhamnolipid biosurfactant produced by Pseudomonas aeruginosa was used to recover oil from oil tank bottom sludge. The optimum value of the fermentation broth (with rhamnolipid biosurfactant concentration of 5.4 g/L) addition was a volume fraction of 2% (v/v). Optimal temperature (65 degrees C), liquid/solid ratio (3:1), washing time (3 h), and agitation intensity (300 rpm) for oil recovery were determined. Wastewater from oil recovery was flocculated with 400 mg/L polyaluminum chloride for reuse. The moisture of the recovered oil was (0.42 +/- 0.12) %, which could directly enter into the refinery process. The solid particles in the oil sludge exhibited a porous structure that adsorbed a significant amount of oil and increased the difficulty of oil recovery. Results showed that the fermentation broth of P. aeruginosa can be used to recover oil from oil sludge and has potential industrial applications.",34,38,5
Crude Oil,Degrees C,"Goswami, Rishiraj; Chaturvedi, Krishna Raghav; Kumar, Ravi Shankar; Chon, Bo Hyun; Sharma, Tushar",Effect of ionic strength on crude emulsification and EOR potential of micellar flood for oil recovery applications in high saline environment,Crude oil; Emulsion; Micellar flood; Rheology; SDS; Salt,NANOPARTICLE-SURFACTANT-POLYMER; IN-WATER EMULSIONS; INTERFACIAL-TENSION; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; HIGH-TEMPERATURE; SYSTEM; BEHAVIOR; CALCIUM; STABILITY,"Micellar flooding is one of the chemical oil recovery techniques in which micelle action emulsifies the crude oil to be mobilized in form of emulsion from a subsurface porous media. However, the subsurface conditions such as high ionic strength and temperature are challenges to the successful use of micellar flood owing to the deterioration of micelle action suggesting no crude emulsification. The ionic compounds dissociate into different ions that may further affect micelle action via loss in viscosity and pressure drop, increased water cut, and mobility contrast between micellar flood and displaced oil. Thus, investigation leading to the successful use of micellar flood, context to crude emulsion, in extreme salinity and temperature is vital to extend the use of chemical methods in new reservoirs. In this work, a typical surfactant sodium dodecyl sulfate (SDS) solution with critical micelle concentration (0.8 wt%) was tested to emulsify a fresh crude oil in the presence of varying ionic strength (0-4 wt%, NaCl/CaCl2 and temperature (40-98 degrees C). The efficacy of SDS micelles to produce crude emulsion significantly reduced with increasing salt concentration as reported through microscopic, rheological, and flooding experiments, particularly for divalent salt (CaCl2) than monovalent salt (NaCl). The increase in temperature (> 40 degrees C) further curtailed the growth of crude emulsion, mainly due to enhanced droplet coalescence; thus the use of micellar flood is critical in a reservoir enriched with high salinity and high temperature. Salinity effect on emulsion viscosity is reported through rheological measurements. The study highlighted important aspects of surfactant flooding and is a forward step towards the use of SDS based micellar flood at complex reservoir conditions.",29,28,1
Crude Oil,Degrees C,"Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Yuan, Chengdong; Zhang, Jizhou; Han, Xiaoqiang; Yang, Yang; Peng, Xiaoqiang; Wu, Junxue",Comprehensive investigations into low temperature oxidation of heavy crude oil,Low temperature oxidation; Heavy crude oil; Thermal behavior; Kinetics; Coke; Oxidized oil,IN-SITU-COMBUSTION; AIR INJECTION; SARA FRACTIONS; KINETICS; RECOVERY; LIGHT; BEHAVIOR; RESERVOIRS; PYROLYSIS; TGA/DSC,"Due to the significance of low temperature oxidation (LTO) process on the subsequent oxidation reactions and oil recovery for in situ combustion (ISC), this work aimed at conducting a series of comprehensive investigations into LTO of heavy crude oil. The LTO behavior of heavy oil was analyzed by static oxidation experiments. Then the alterations in oil characteristics due to LTO were investigated through coke content measurements, flammability tests and scanning electron microscopic (SEM) observations. Additionally, the effect of LTO on thermal behavior and kinetics of heavy oil was researched using thermogravimetry (TG)/differential scanning calorimetry (DSC) technique. The results showed that the temperature played a crucial role in LTO of heavy oil. Almost no coke was deposited at 80 degrees C. The amount of coke deposition at 160 degrees C averaged 0.346 g coke/g oil, which was roughly 4.2 times higher than that at 120 degrees C. The oxidized oil at 160 degrees C possessed the most superior flammability at ambient temperature and atmospheric pressure in comparison to that at 80 and 120 degrees C. The surface morphologies of oxidized oil at 160 degrees C and its formed coke were quite rough, which boosted the subsequent combustion reactions. The results of TG/DSC unravelled that the oxidized oils were subjected to higher mass loss and exothermic effect at the fuel deposition (FD) and high temperature oxidation (HTO) stages as compared to crude oil. After the static LTO, the activation energy in the LTO and FD stages for heavy oil was increased, while that in the HTO stage was reduced. Compared with crude oil and oxidized oils, the coke deposited during the static LTO presented the highest thermal release and reaction activity in the HTO interval. This paper can provide some new insights regarding LTO mechanisms of heavy oil to rich the ISC technology.",27,32,1
Crude Oil,Degrees C,"Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Yuan, Chengdong; Pan, Jingjun; Wang, Ruyan; Chen, Long; Kan, Ni",Low-temperature oxidation of light and heavy oils via thermal analysis: Kinetic analysis and temperature zone division,Low-temperature oxidation; Light and heavy oils; Thermal analysis; Kinetic analysis; Temperature zone division,PRESSURE AIR INJECTION; CRUDE-OIL; THERMOGRAVIMETRIC ANALYSIS; COMBUSTION KINETICS; SARA FRACTIONS; PYROLYSIS; BEHAVIORS; RECOVERY; MODEL; DECOMPOSITION,"This research is intended to investigate low-temperature oxidation (LTO) behavior and kinetics of light and heavy oils and to divide their LTO intervals. Ramped thermogravimetry/derivative thermogravimetry (TG/DTG) and differential scanning calorimetry (DSC) experiments and isothermal TG experiments with different temperature intervals were used to characterize LTO behavior and to obtain kinetic parameters determined by Ozawa-Flynn-Wall (OFW) and general reaction rate models. The results indicated that there were three (two) distinct variation trends about the conversion rate versus temperature for light (heavy) oil in the LTO region, manifesting the LTO interval of light (heavy) oil should be controlled by multiple-step mechanisms and divided into at least three (two) reaction subintervals. The LTO interval of both light and heavy oils used could be subdivided into three temperature intervals inferred from the variation trend of activation energy over temperature for ramped experiments. Additionally, the LTO region of both light and heavy oils held three subzones in the aspect of isothermal tests. For light oil, the reaction rate augmented from 50 to 250 degrees C where the activation energy was positive, while it reduced from 250 to 350 degrees C coupled with negative activation energy. As for heavy oil, the reaction rate presented an increasing trend in the first and third subintervals (50-150 degrees C and 250 350 degrees C) with positive activation energy and a declining trend in the second subinterval (150 250 degrees C) with negative activation energy. It is believed that this research can add new insights to the LTO interval division of crude oil regarding to the isothermal and non-isothermal conditions, which are of significance for understanding LTO reaction pathways and mechanisms.",26,27,1
Crude Oil,Degrees C,"Gu, Xuefan; Zhang, Fan; Li, Yongfei; Zhang, Jie; Chen, Shijun; Qu, Chengtun; Chen, Gang",Investigation of cationic surfactants as clean flow improvers for crude oil and a mechanism study,Cationic surfactants; Crude oil; Flow improver; Viscosity; Pour point,RELATIVELY LOW-TEMPERATURE; HEAVY OIL; CANOLA OIL; AQUATHERMOLYSIS; COMPLEX; COPOLYMER,"Cetyl trimethyl ammonium chloride (CTAC), cetyl trimethyl ammonium bromide (CTAB), and octadecyl trimethylammonium chloride (OTAC) were evaluated as clean flow improvers for crude oil. The results showed that all of them have some effect on the viscosity of crude oil in a certain temperature range, and can depress the pour point, among which CTAC is the most potent one. The viscosity was reduced to below 540 mPa s under different concentration at 35 degrees C by CTAC, and it can depress the pour points by 7.5 degrees C with the concentration of 0.03%. DSC analysis and microscopic morphology analysis discovered the interaction of CTAC and saturated hydrocarbon component of the crude oil, which can reduce the wax peak temperature and wax precipitation point of crude oil. CTAC may precipitate and pack with the long-chain alkane to form the crystal nucleus, while the cationic part and the corresponding Cl- anion can act as a wax crystal modifier and block the wax crystal to grow up, thereby reduce the risk to form three-dimensional networks.",23,24,2
Crude Oil,Degrees C,"Perles, C. E.; Guersoni, V. C. B.; Bannwart, A. C.",Rheological study of crude oil/water interface - The effect of temperature and brine on interfacial film,Dilatational rheology; Water-oil interface; Interfacial film; Dilatational viscoelasticity,OIL-EMULSIONS; STABILITY; TENSIOMETRY; RESOLUTION; DROP,"It is of fundamental importance for the petroleum industry to promote the coalescence of water droplets that may be dispersed in oil. Therefore, it is necessary to understand the rheological properties of the water/oil interface, which is straightly related to emulsion stability. This work aimed to present a practical approach about water/oil interface in realistic systems, i.e., using a crude oil and water or brine solution, the last one with the same composition of the water produced along with the oil production. Thus, it was investigated the water/crude oil and brine/crude oil interfaces in terms of their rheological properties at temperatures ranging from 30 degrees C to 60 degrees C. The interfacial rheological measurements were performed by the oscillatory pendant drop technique. The results indicated that temperature has a negligible effect on the interface properties; however, the salt content in the water phase resulted in an increase in the viscous modulus between 30 degrees C and 60 degrees C. The interfacial viscous and elastic moduli were shown to be dependent on the droplet oscillation period. Despite the elastic modulus being almost the same for water and brine, for the brine system the viscous modulus was significantly higher than that observed for water.",21,21,3
Crude Oil,Degrees C,"Wang, Chao; Liu, Pengcheng; Wang, Fushun; Atadurdyyev, Bayramberdi; Ovluyagulyyev, Mergen",Experimental study on effects of CO2 and improving oil recovery for CO2 assisted SAGD in super-heavy-oil reservoirs,Super-heavy oil reservoir; Steam assisted gravity drainage (SAGD); Reduce viscosity; Carbon dioxide; Thermal oil recovery,GRAVITY DRAINAGE; STEAM; EOR; PERFORMANCE; INJECTION; SEQUESTRATION; MECHANISM; PRESSURE; BEHAVIOR; SOLVENT,"When developing heavy-oil reservoirs using steam-assisted gravity drainage (SAGD) technology, CO2 is often used to reduce the viscosity of heavy oil and the heat loss of the steam chamber, thereby enhancing oil recovery. The limitation of experimental apparatuses, results in a maximum temperature of the reaction kettle of no more than 150 degrees C. Thus, the solubility of CO2 in super-heavy oil and its impact on decreasing viscosity beyond 150 degrees C requires further discussion. Considering these issues, a high-temperature-resistant heavy-oil mixing apparatus was designed to measure the solubility of CO2 in super-heavy oil and the relative density and viscosity of super-heavy oil under high temperatures and pressures. Core flooding experiments under 200 degrees C were conducted to explore the effects of CO2 on oil displacement efficiency. The results indicated that solubility of CO2 became significantly lower at 200 degrees C, when the viscosity and relative density of super-heavy oil decreased as pressure increased. The viscosity of super-heavy oil saturated with CO2 decreased by 71.2%, and relative density decreased by 10.1% at 200 degrees C compared to those of degassed crude. At temperatures of 120 degrees C, 150 degrees C and 200 degrees C, the ultimate displacement efficiency of super-heavy oil increased by 6.6%, 19.2% and 21.4%, respectively, compared to a temperature of 60 degrees C. At pressures of 1.0 MPa, 2.0 MPa and 4.0 MPa, the ultimate displacement efficiency (46.7%) of super-heavy oil increased by 5.2%, 4.0% and 5.9%, respectively, compared to a pressure of 0.5 MPa. The experiments showed that CO2 injection can effectively reduce the relative density and viscosity of super-heavy oil and improve oil recovery under high temperatures and pressures. CO2 has good potential to improve SAGD efficiency in developing super-heavy-oil reservoirs.",20,21,4
Crude Oil,Degrees C,"Ren, Guangwei; Nguyen, Quoc P.; Hon Chung Lau",Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants,CO2 soluble surfactants; Partition coefficient; CO2 foam; Fractured carbonate reservoir; EOR,INTERFACIAL-TENSION; GRAVITY DRAINAGE; MOBILITY CONTROL; CRUDE-OIL; DISPLACEMENT; EOR; MICROEMULSIONS; WETTABILITY; SOLUBILITY; REDUCTION,"Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions. A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 degrees C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water. RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam. These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.",19,20,2
Crude Oil,Degrees C,"Lashkarbolooki, Mostafa; Riazi, Masoud; Ayatollahi, Shahab",Effect of CO2 and crude oil type on the dynamic interfacial tension of crude oil/carbonated water at different operational conditions,Dynamic IFT; Carbonated water; CO2; Adsorption time; Temperature; Pressure,CARBONATED WATER; AQUEOUS-SOLUTIONS; INJECTION; RECOVERY; PH; EQUILIBRIUM; TEMPERATURE; PERFORMANCE; ASPHALTENE; ADSORPTION,"Concerns about climate change have persuaded the researchers to examine CO2 injection in the form of carbonated water (CW) into oil reservoir as a safe and effective CO2 storage and enhanced oil recovery process. Although interfacial tension (IFT) between crude oil and injected fluid has a vital role on the displacement of fluids in porous media, the effect of CO2 and crude oil type on the dynamic IFT of crude oil under different operational conditions is not well understood. Accordingly, this study was carried out to assess the effects of temperature, pressure, crude oil type and CO2 on the dynamic IFT of crude oil/CW. To achieve this goal, two types of crude oil were provided from southern Iranian oil reservoirs and dynamic IFTs with CW were measured in a wide range of temperatures and pressures (i.e. temperature range of 30-80 degrees C and pressure range of 500-4000 psi); the obtained results were compared with the system without CO2. In addition, the adsorption time of carbonated aqueous phase/crude oil, obtained based on the mono exponential decay model, was also compared with unadulterated water/crude oil system. The outcome of this study showed that crude oil type has the most significant effect on the IFT of crude oil/CW compared to pressure, temperature and CO2 content. In more details, the IFT of crude oil/CW can be affected by the amount and type of acidic/basic components in the crude oil as well as pH of the aqueous solution. Besides, the obtained results revealed that the effect of temperature was more considerable on the IFT of the heavy crude oil compared with the light crude oil in both studied aqueous solutions (i.e. unadulterated water and CW). Although the inversion phase temperature was obtained for unadulterated water/studied crude oils at all studied pressures, this phenomenon was not observed for crude oil/CW at elevated pressure, due to the high amount of CO2 at this condition.",17,17,3
Crude Oil,Degrees C,"Nasri, Zarrin; Mozafari, Motahareh",Multivariable statistical analysis and optimization of Iranian heavy crude oil upgrading using microwave technology by response surface methodology (RSM),Heavy crude oil; Upgrading; Microwaves; Response surface methodology,ULTRASONIC IRRADIATION; HORIZONTAL WELL; DEMULSIFICATION; EMULSIONS; PERFORMANCE; PYROLYSIS; RECOVERY,"Conventional methods to upgrade heavy oil due to high pressure, low production efficiency, and low product quality have not been recognized as profitable methods. These complications resulted in using innovative technologies in this area. In this paper, the statistical analysis and process conditions optimization of Iranian heavy crude oil upgrading have been performed using microwave technology, for the first time. The heavy crude oil is from Iranian west Paydar field, with specifications including API 18.53, viscosity 78.76 cSt (at 20 degrees C). In order to optimize process conditions for upgrading heavy crude oil, independent variables include power level (40-70-100%), process time (5-12.5-20) (min), activated carbon as sensitizer (0-5-10) (wt%), and Fe as catalyst (0-3-6) (wt%). Surface temperature, API ratio, viscosity ratio, and asphaltene reduction have been considered as response variables. The Box-Behnken design and response surface methodology (RSM) have been applied to determine parameters levels and to model the responses, respectively. The results show that the optimal conditions to maximize surface temperature, API ratio, and asphaltene reduction, and to minimize viscosity ratio involve power level of 100%, process time of 20 min, activated carbon of 10 wt%, Fe catalyst of 4.06 wt% which leads to 23.31API ratio, 31.6% asphaltene reduction, and 43.37% viscosity reduction. The predicted conditions agreed with the experimental values, representing the models accuracy.",16,17,3
Crude Oil,Degrees C,"Foss, Lev; Petrukhina, Natalia; Kayukova, Galina; Amerkhanov, Marat; Romanov, Gennady; Ganeeva, Yulia","Changes in hydrocarbon content of heavy oil during hydrothermal process with nickel, cobalt, and iron carboxylates",Heavy oil; Catalyst precursors; Changes in oil content; Heavy oil upgrading; Hydrothermal process (aquathermolysis); Hydrogen donor,HIGH-TEMPERATURE HYDROLYSIS; AQUEOUS ORGANIC-CHEMISTRY; CATALYTIC AQUATHERMOLYSIS; CRUDE-OIL; ATHABASCA BITUMEN; SANDS; WATER; TETRAHYDROTHIOPHENE; NANOCATALYSTS; NANOPARTICLES,"We conducted autoclave modeling experiments to study the process of upgrading heavy oil in the reservoir conditions and used carboxylates of transition metals (Ni, Co, Fe) as catalyst precursors. The process was carried out at temperatures of 250, 300, and 350 degrees C in the presence of a naphthenoaromatic hydrogen donor. We found that significant content changes of oil occur at temperatures of 300 and 350 degrees C accompanied by an increase of light fractions and a decrease of high molecular weight hydrocarbons. We studied the hydrocarbon composition of the initial oil and the products of the hydrothermal process as well as tetralin (proton donor) transformations to determine the patterns of influence of the process conditions and catalyst precursors.",15,16,3
Crude Oil,Degrees C,"Derguine-Mecheri, Louiza; Kebbouche-Gana, Salima; Khemili-Talbi, Souad; Djenane, Djamel",Screening and biosurfactant/bioemulsifier production from a high-salt-tolerant halophilic Cryptococcus strain YLF isolated from crude oil,Yeasts; Biosurfactant; Cryptococcus sp YLF; Agro industrial wastes; EOR,BIOSURFACTANT PRODUCTION; LIPOPEPTIDE BIOSURFACTANT; SURFACE-PROPERTIES; WASTE-WATER; CANDIDA; BOMBICOLA; YEAST; SOPHOROLIPIDS; BIOEMULSIFIER; QUANTITATION,"Biosurfactant-producing yeasts were isolated from different biotopes including food samples, waste and sand samples collected from areas contaminated with hydrocarbons in Algeria. Isolates were screened for biosurfactant/bioemulsifier production in mineral salt medium and in high salinity using emulsification index (E24), drop-collapse test, spread oil technique and hemolytic activity. Fifty of one hundred isolates were positive for almost all the qualitative tests, four of them were the best strains for biosurfactants production with emulsions over than 60%. More interestingly, one high-salt-tolerant yeast isolate was the most potent biosurfactants producing yeast with an emulsification index of 69.50 +/- 0.70. It was identified by morphological, physiological and biochemical tests and by 5.8s-rDNA Analysis as Cryptococcus sp. YLF. This strain produced biosurfactant using different carbon and nitrogen sources and when grown in low-cost fermentative media based on agro industrial by-products and wastes like whey, molasses, corn steep liquor, date syrup and olive mill wastewater (OMW) supplemented with NaCl (2.5 M). The biosurfactant produced by Cryptococcus sp. YLF was partially characterized as glycolipid based on the estimation of macromolecules, TLC and IR analysis. The crude biosurfactant demonstrated stability regarding surface tension reduction and emulsification activity in a range of temperatures (5-100 degrees C), pH (2-12) and high salinities (1-10%). The partially purified biosurfactant showed promising potential for application in enhanced oil recovery (EOR).",14,14,4
Crude Oil,Degrees C,"Mehrabi-Kalajahi, Seyed Saeed; Varfolomeev, Mikhail A.; Yuan, Chengdong; Emelianov, Dmitrii A.; Khayarov, Khasan R.; Klimovitskii, Alexander I.; Rodionov, Alexander A.; Orlinskii, Sergei B.; Gafurov, Marat R.; Afanasiev, Igor S.; Fedorchenko, Gennadii D.; Lubnina, Elena V.",EPR as a complementary tool for the analysis of low-temperature oxidation reactions of crude oils,Crude oil; In-situ combustion; Air injection; Oxidation; EPR; Free radical concentration,IN-SITU COMBUSTION; VANADYL-PORPHYRIN COMPLEXES; SARA FRACTIONS; PARAMAGNETIC-RESONANCE; KINETIC-ANALYSIS; AIR INJECTION; HEAVY OIL; LIGHT; ASPHALTENES; BEHAVIOR,"Air injection is a promising method for enhanced oil recovery (EOR) in both conventional and unconventional oil sources. It is widely accepted that oxidation reactions between oil and injected air determine the success of an air injection process. In this study, electron paramagnetic resonance (EPR) was introduced as a new route to investigate the occurrence of low-temperature oxidation (LTO) and its behavior by monitoring the signals of free radicals. The EPR experiments were conducted for the different crude oil samples (light, medium and heavy) heated in both static air and flow air (air-bubbling) conditions under different temperatures from 25 degrees C to 180 degrees C. The results showed that the free-radical concentrations exhibited a good correspondence on the heating temperature. Furthermore, nuclear magnetic resonance (NMR), Fourier-transform infrared spectroscopy (FTIR) and differential scanning calorimetry (DSC) experiments were carried out to help to analyze the oxidation process and verify the EPR results. It turned out that the EPR results can be well supported by NMR, FTIR and DSC data, which indicates that proposed EPR monitoring method can be applied as a fast and low-cost technique to investigate LTO under mild reaction conditions. Simultaneously, the combination of EPR, NMR, FTIR and DSC can help to better understand the LTO mechanism and to monitor the application of in-situ combustion technique in the field.",14,14,1
Crude Oil,Emulsion,"Simonsen, Galina; Strand, Mikael; Oye, Gisle",Potential applications of magnetic nanoparticles within separation in the petroleum industry,Magnetic nanoparticle; Emulsion; Crude oil; Separation; Oil droplet; Environment; Contents,IRON-OXIDE NANOPARTICLES; FLOW FRACTIONATION; WATER; REMOVAL; CATALYSIS; RECOVERY; METAL; FUNCTIONALIZATION; MICROPARTICLES; BEHAVIOR,"Magnetic nanoparticles have unique properties such as extremely large surface area per volume substance and strong magnetic response. In addition, the possibilities for surface functionalization make them exciting candidates for separation applications in oil and gas production and processing. Relevant separation applications discussed in this review are emulsion separation, oil spill clean-up, produced water purification, and mitigation of undesired phase separation. Surface coatings entailing polymers, surfactants, or inorganic compounds are typically used to protect and stabilize the nanoparticles and for further functionalization in targeting specific applications. The adsorption, or separation efficiency, of the functionalized nanoparticles in certain processes is found to reach as high as 99.99% and depends on the type of surface coating, proper nanoparticle dispersion in the target medium, and the chosen separation technique. Several magnetically driven methods available for nanoparticle recovery, or nanoparticle purification, are discussed with respect to their efficiency and possibilities for optimization. Safety concerns regarding the use of the nanoparticles in industrial work environments and potential risks of exposure are presented in the last section.",45,46,1
Crude Oil,Emulsion,"Pei, Haihua; Shu, Zhan; Zhang, Guicai; Ge, Jijiang; Jiang, Ping; Qin, Yu; Cao, Xu",Experimental study of nanoparticle and surfactant stabilized emulsion flooding to enhance heavy oil recovery,Emulsion flooding; Nanoparticles; Heavy oil; Sweep efficiency; Injection parameters,,"It is well known that the recovery of water flooding from heavy oil reservoirs is less than 30% or even 20% of the OOIP (original oil in place), due to its very high viscosity and thus extremely low mobility comparing to light oil at reservoir condition. In order to improve residual oil recovery after water flooding in ordinary heavy oil reservoirs, this study presents an experimental study of nanoparticle and surfactant stabilized emulsion flooding to enhance heavy oil recovery. It is indicated in the emulsion stability and rheology studies that the synergistic interaction of nanoparticle with surfactant can significantly improve the emulsion stability and increase the apparent viscosity of emulsion. The results of core flooding tests show that the residual oil recovery after water flooding can be significantly improved by the nanoparticle-surfactant stabilized emulsions flooding. The incremental oil recovery gradually increases with the increase of injected emulsion volume, but there is an optimal economic value of the injected volume. The low injection rate is more effective than high injection rate, and the continuous injection pattern shows higher tertiary oil recovery as compared to cyclic injection pattern. The nanoparticle-surfactant stabilized emulsion flooding has a great potential for enhanced oil recovery in waterflooded heavy oil reservoirs, with the permeability ranging from 500 mD to 2000 mD and the crude oil viscosity being lower than 1000 mPa s. The two-dimensional homogeneous sandpack flooding test indicates that the nanoparticle-surfactant stabilized emulsion flooding can not only improve the sweep efficiency by blocking the high permeable water channels, but also can improve the displacement efficiency by mobilizing the trapped oil.",36,38,14
Crude Oil,Emulsion,"Zhou, Yazhou; Yin, Daiyin; Cao, Rui; Zhang, Chengli",The mechanism for pore-throat scale emulsion displacing residual oil after water flooding,Pore-throat scale; Emulsion; Viscoelasticity; Surfactant flooding; Displacement mechanism,POROUS-MEDIA; CRUDE-OIL; SURFACE-TENSION; RECOVERY; PARAMETERS; REDUCTION; VISCOSITY; POLYMER; FLOW,"The reservoir characteristics and fluid property of Daqing Oilfield was taken as the research platform. The emulsion was prepared by core displacement experiment. The stability of emulsion was analyzed by measuring the Zeta potential at different emulsifier concentrations. The emulsion viscoelasticity was also measured in different water cut stage. Displacement experiments of emulsion and surfactant flooding (poor emulsification) at the same interfacial tension were conducted, and the displacement efficiency of pore-throat scale emulsion (particle size greater than throat diameter but less than pore diameter) was studied. Using a visual sand packed model, displacement experiments allowed for the observation of the pore-throat scale emulsion displacing oil drop and columnar residual oil, and the deformation and migration process of residual oil were analyzed. The mechanism of pore-throat scale emulsion displacing residual oil was studied. The results show that with the emulsifier concentration increases, the absolute value of emulsion Zeta potential increases, and the stability of emulsion increases, the stability of pore-throat emulsion is preferably. When the water cut is 63.2%, the emulsion viscoelasticity is most favorably. When the emulsifier concentration is 0.4%, the emulsion flooding can enhance recovery efficiency by 9.84% compared to surfactant flooding with the same interfacial tension. The viscoelastic deformation of the pore-throat scale emulsion can pull the oil drop and columnar residual oil, and the residual oil can migrate.",35,34,5
Crude Oil,Emulsion,"Liu, Chuhan; Zhang, Yin; Sun, Shanshan; Huang, Lixin; Yu, Li; Liu, Xiaonan; Lai, Ruiqiu; Luo, Yijing; Zhang, Zhiyong; Zhang, Zhongzhi",Oil recovery from tank bottom sludge using rhamnolipids,Oil sludge; Oil recovery; Pseudomonas aeruginosa; Biosurfactant,CRUDE-OIL; CONTAMINATED SOIL; PETROLEUM; DEMULSIFICATION; BIOSURFACTANTS; PSEUDOMONAS; PYROLYSIS; EMULSIONS,"Oil sludge has become a major impediment to the development of the petroleum and petrochemical industries with the growth of oil production worldwide. In this research, rhamnolipid biosurfactant produced by Pseudomonas aeruginosa was used to recover oil from oil tank bottom sludge. The optimum value of the fermentation broth (with rhamnolipid biosurfactant concentration of 5.4 g/L) addition was a volume fraction of 2% (v/v). Optimal temperature (65 degrees C), liquid/solid ratio (3:1), washing time (3 h), and agitation intensity (300 rpm) for oil recovery were determined. Wastewater from oil recovery was flocculated with 400 mg/L polyaluminum chloride for reuse. The moisture of the recovered oil was (0.42 +/- 0.12) %, which could directly enter into the refinery process. The solid particles in the oil sludge exhibited a porous structure that adsorbed a significant amount of oil and increased the difficulty of oil recovery. Results showed that the fermentation broth of P. aeruginosa can be used to recover oil from oil sludge and has potential industrial applications.",34,38,5
Crude Oil,Emulsion,"Goswami, Rishiraj; Chaturvedi, Krishna Raghav; Kumar, Ravi Shankar; Chon, Bo Hyun; Sharma, Tushar",Effect of ionic strength on crude emulsification and EOR potential of micellar flood for oil recovery applications in high saline environment,Crude oil; Emulsion; Micellar flood; Rheology; SDS; Salt,NANOPARTICLE-SURFACTANT-POLYMER; IN-WATER EMULSIONS; INTERFACIAL-TENSION; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; HIGH-TEMPERATURE; SYSTEM; BEHAVIOR; CALCIUM; STABILITY,"Micellar flooding is one of the chemical oil recovery techniques in which micelle action emulsifies the crude oil to be mobilized in form of emulsion from a subsurface porous media. However, the subsurface conditions such as high ionic strength and temperature are challenges to the successful use of micellar flood owing to the deterioration of micelle action suggesting no crude emulsification. The ionic compounds dissociate into different ions that may further affect micelle action via loss in viscosity and pressure drop, increased water cut, and mobility contrast between micellar flood and displaced oil. Thus, investigation leading to the successful use of micellar flood, context to crude emulsion, in extreme salinity and temperature is vital to extend the use of chemical methods in new reservoirs. In this work, a typical surfactant sodium dodecyl sulfate (SDS) solution with critical micelle concentration (0.8 wt%) was tested to emulsify a fresh crude oil in the presence of varying ionic strength (0-4 wt%, NaCl/CaCl2 and temperature (40-98 degrees C). The efficacy of SDS micelles to produce crude emulsion significantly reduced with increasing salt concentration as reported through microscopic, rheological, and flooding experiments, particularly for divalent salt (CaCl2) than monovalent salt (NaCl). The increase in temperature (> 40 degrees C) further curtailed the growth of crude emulsion, mainly due to enhanced droplet coalescence; thus the use of micellar flood is critical in a reservoir enriched with high salinity and high temperature. Salinity effect on emulsion viscosity is reported through rheological measurements. The study highlighted important aspects of surfactant flooding and is a forward step towards the use of SDS based micellar flood at complex reservoir conditions.",29,28,1
Crude Oil,Emulsion,"Feng, Haishun; Kang, Wanli; Zhang, Liming; Chen, Jun; Li, Zhe; Zhou, Qiong; Wu, Hairong",Experimental study on a fine emulsion flooding system to enhance oil recovery for low permeability reservoirs,Fine emulsion flooding; Low permeability reservoir; Enhanced oil recovery; Micromodel tests,HEAVY-OIL; POROUS-MEDIA; SURFACTANT; EMULSIFICATION; POLYMER; MECHANISM; PRESSURE; ALKALI; TIGHT,"Numerous studies and field application tests have shown that emulsification is an important mechanism to improve oil recovery. Fine emulsion (FE) with small droplets can improve oil recovery by displacing residual oil after water flooding at a low cost. In this work, a series of core displacement experiments were conducted to compare the effectiveness of different chemical flooding for crude oil. Then, the oil-water interfacial tension (IFT), viscosity and rheological properties were studied thoroughly to understand the displacement mechanism by using an interfacial tensiometer, a viscometer or a rheometer. Finally, micromodel flooding tests were performed to demonstrate the suitability and effectiveness of FE flooding for oil recovery for low permeability reservoirs. The displacement results show that the oil recovery efficiency can reach 16.8% after water flooding by the optimum FE flooding system. The FE flooding system has viscoelastic properties, strong emulsifying performance and stability. Such behavior can reduce the IFT value to the magnitude of 10(-1) mN/m and improve the mobility ratio. The displacement mechanism of FE enhanced oil recovery (EOR) is that emulsification can improve the displacement efficiency and increase the swept efficiency. The micromodel tests indicate that the emulsification mechanisms include emulsification carrying-on and the performance control of the O/W emulsion. The FE flooding system has powerful EOR potential for low permeability reservoirs.",27,28,8
Crude Oil,Emulsion,"Suleimanov, Baghir A.; Latifov, Yashar A.; Veliyev, Elchin F.; Frampton, Harry",Comparative analysis of the EOR mechanisms by using low salinity and low hardness alkaline water,EOR; Low hardness alkali water; Sandstone flooding; Bentonite swelling; Low salinity water; Emulsion,IMPROVED OIL-RECOVERY; BRINE ROCK SYSTEMS; WETTABILITY ALTERATION; CRUDE-OIL; SPONTANEOUS IMBIBITION; SANDSTONE; TEMPERATURE; IONS,"This paper discusses the application of low hardness alkali water compositions (LHAW) as a secondary and tertiary displacement agent for EOR. A comparative analysis of the impact of low salinity water (LSW) and LHAW water on interfacial tension, contact angle on rock, adsorption of ions, emulsion stability and clay swelling is presented. LHAW application contributes to the formation of stable water in oil (w/o) emulsions and a decrease in clay swelling compared to LSW. Adsorption values for both fluids are similar. Contact angle measurements show that both LSW and LHAW reduce interfacial tension compared to Synthetic Caspian Sea water (SCSW), by up to 17% and 94% respectively. Similar results were observed for contact angle measurements. Flooding experiments were conducted in secondary and tertiary modes. In secondary flooding the two water compositions LHAW-2 and LHAW-1 increased the oil recovery (%OOIP) in comparison with SCSW at water breakthrough, by 29% and 25% respectively. The final oil recovery increases were 21% and 15% respectively. In tertiary flooding, tests showed that LHAW-2 and LHAW-1 oil recoveries (%OOIP) compared to LSW were 13% and 10% respectively. The oil recovery rate for LHAW solutions was not linear versus lnt as was that for LSW. This was proposed as a consequence of emulsions generation while water-cut is below 50% however, above 50% water cut the rate stabilizes.",25,25,0
Crude Oil,Emulsion,"Perles, C. E.; Guersoni, V. C. B.; Bannwart, A. C.",Rheological study of crude oil/water interface - The effect of temperature and brine on interfacial film,Dilatational rheology; Water-oil interface; Interfacial film; Dilatational viscoelasticity,OIL-EMULSIONS; STABILITY; TENSIOMETRY; RESOLUTION; DROP,"It is of fundamental importance for the petroleum industry to promote the coalescence of water droplets that may be dispersed in oil. Therefore, it is necessary to understand the rheological properties of the water/oil interface, which is straightly related to emulsion stability. This work aimed to present a practical approach about water/oil interface in realistic systems, i.e., using a crude oil and water or brine solution, the last one with the same composition of the water produced along with the oil production. Thus, it was investigated the water/crude oil and brine/crude oil interfaces in terms of their rheological properties at temperatures ranging from 30 degrees C to 60 degrees C. The interfacial rheological measurements were performed by the oscillatory pendant drop technique. The results indicated that temperature has a negligible effect on the interface properties; however, the salt content in the water phase resulted in an increase in the viscous modulus between 30 degrees C and 60 degrees C. The interfacial viscous and elastic moduli were shown to be dependent on the droplet oscillation period. Despite the elastic modulus being almost the same for water and brine, for the brine system the viscous modulus was significantly higher than that observed for water.",21,21,3
Crude Oil,Emulsion,"Nasri, Zarrin; Mozafari, Motahareh",Multivariable statistical analysis and optimization of Iranian heavy crude oil upgrading using microwave technology by response surface methodology (RSM),Heavy crude oil; Upgrading; Microwaves; Response surface methodology,ULTRASONIC IRRADIATION; HORIZONTAL WELL; DEMULSIFICATION; EMULSIONS; PERFORMANCE; PYROLYSIS; RECOVERY,"Conventional methods to upgrade heavy oil due to high pressure, low production efficiency, and low product quality have not been recognized as profitable methods. These complications resulted in using innovative technologies in this area. In this paper, the statistical analysis and process conditions optimization of Iranian heavy crude oil upgrading have been performed using microwave technology, for the first time. The heavy crude oil is from Iranian west Paydar field, with specifications including API 18.53, viscosity 78.76 cSt (at 20 degrees C). In order to optimize process conditions for upgrading heavy crude oil, independent variables include power level (40-70-100%), process time (5-12.5-20) (min), activated carbon as sensitizer (0-5-10) (wt%), and Fe as catalyst (0-3-6) (wt%). Surface temperature, API ratio, viscosity ratio, and asphaltene reduction have been considered as response variables. The Box-Behnken design and response surface methodology (RSM) have been applied to determine parameters levels and to model the responses, respectively. The results show that the optimal conditions to maximize surface temperature, API ratio, and asphaltene reduction, and to minimize viscosity ratio involve power level of 100%, process time of 20 min, activated carbon of 10 wt%, Fe catalyst of 4.06 wt% which leads to 23.31API ratio, 31.6% asphaltene reduction, and 43.37% viscosity reduction. The predicted conditions agreed with the experimental values, representing the models accuracy.",16,17,3
Crude Oil,Emulsion,"Wong, Siew Fan; Dol, Sharul Sham; Wee, Siaw Khur; Chua, Han Bing","Miri light crude water-in-oil emulsions characterization - Rheological behaviour, stability and amount of emulsions formed",Water-in-oil; Emulsions; Characterization; Rheology; Stability,PIPELINE TRANSPORTATION; FLOW; VISCOSITY,"Emulsification, specifically formation of water-in-oil (W/O) emulsions, is a very common occurrence in the oil and gas industries which tend to occur naturally given the conditions of the industries. However, it is an unwanted phenomenon as it brings numerous harmful effects to the industries. So, this study aims to carry out a study on the characteristics of the W/O emulsions in order to develop a better understanding on the W/O emulsions. Three parameters, namely, water cuts (WC), Reynolds number and pipeline constrictions were studied. For each of the parameters, the region of study is: 0-40% WC; laminar (1100 < Re < 1800) and turbulent (2400 < Re < 2800) flow regime; and gradual contraction with a contraction ratio of 0.50 and 0.75 (GC 0.50 and GC 0.75) and sudden contraction with a contraction ratio of 0.50 and 0.75 (SC 0.50 and SC 0.75). In this study, rheometer and flow rig were used for the experiments. The W/O emulsions characteristics study is carried out based on analyzing the rheological behaviour of W/O emulsions, stability of the W/O emulsions and the amount of emulsions formed. From the rheological behaviour analysis, it is determined that emulsions have a very interesting rheological behaviour, where the emulsions exhibit a shear-thinning behaviour, at shear rates below 200 s(-1) (for 5-30% WC) and 350 s(-1) (for 35-90% WC) and behaves as a Newtonian fluid beyond the respective shear rates. Also, it is determined that phase inversion from W/O emulsions to O/W emulsions happens at 40% WC. Next, the study on the stability of W/O emulsions of different controlling parameters shows that, with the increase in the water cuts, the stability of the emulsions is increased; with the increase in the Reynolds number, the stability of emulsions is increased; the emulsions formed from the pipeline constriction type GC 0.50 and SC 0.50 is more stable than the emulsions formed from GC 0.75 and SC 0.75. In addition, the amount of emulsions formed at different governing parameters is also presented. The presented results show that-amount of emulsions formed increase with the increase in the Reynolds number; amount of emulsions formed increase with the increase in the water cuts; amount of emulsions formed are the same for different types of pipeline constriction. In conclusion, the findings of this study provide a significant contribution to the Malaysia's oil and gas industry as local offshore crude blend, which was Miri Light Crude (MLC) was used in the study and the outcome of this study can aid in the selection of parameters to be used in the field to allow lower stability emulsions formation as well as less emulsions formation.",16,16,2
Crude Oil,Emulsion,"Shi, Shuqiang; Wang, Yongqing; Liu, Yonghui; Wang, Lei",A new method for calculating the viscosity of W/O and O/W emulsion,Exploitation of oil; Water-in-oil emulsion; Oil-in-water emulsion; Viscosity,IN-OIL EMULSIONS; NEWTONIAN CONCENTRATED EMULSIONS; MOLECULAR DIMENSIONS; WATER; SUSPENSIONS; PREDICTION; MODELS; BEHAVIOR; SPHERES; FLOW,"The viscosity of water-in-oil and oil-in-water emulsions is a key parameter to understand during oil exploitation and transportation. Water content increases with the extraction of crude oil, especially in the middle and late periods of exploitation. Apparent viscosity increases as formation water content increases. However, apparent viscosity decreases when the water cut is beyond the phase transition point, after which, the water-in-oil emulsion becomes an oil-in-water emulsion. Many models for calculating the viscosity of W/O emulsions has been proposed, but methods for predicting the viscosity of O/W emulsions are rare. In this article, a method to calculate viscosity of W/O and O/W emulsions based on the Richardson and Taylor equations is introduced. Contrary to the existing correlations, the method presented here takes into account more factors, including water cut, temperature, shear rate, viscosity of oil and formation water. Additionally, whereas conventional correlations have been able to only calculate the viscosity of water-in-oil emulsions, the proposed method can also calculate the viscosity of oil-in-water emulsions. The accuracy and reliability of 5 conventional correlations and of this new method are assessed using the experimental data. The proposed model better fits the data when predicting the viscosity of W/O and O/W emulsions, with average absolute error of 12.71-16.43%.",15,15,11
Crude Oil,Emulsion,"Derguine-Mecheri, Louiza; Kebbouche-Gana, Salima; Khemili-Talbi, Souad; Djenane, Djamel",Screening and biosurfactant/bioemulsifier production from a high-salt-tolerant halophilic Cryptococcus strain YLF isolated from crude oil,Yeasts; Biosurfactant; Cryptococcus sp YLF; Agro industrial wastes; EOR,BIOSURFACTANT PRODUCTION; LIPOPEPTIDE BIOSURFACTANT; SURFACE-PROPERTIES; WASTE-WATER; CANDIDA; BOMBICOLA; YEAST; SOPHOROLIPIDS; BIOEMULSIFIER; QUANTITATION,"Biosurfactant-producing yeasts were isolated from different biotopes including food samples, waste and sand samples collected from areas contaminated with hydrocarbons in Algeria. Isolates were screened for biosurfactant/bioemulsifier production in mineral salt medium and in high salinity using emulsification index (E24), drop-collapse test, spread oil technique and hemolytic activity. Fifty of one hundred isolates were positive for almost all the qualitative tests, four of them were the best strains for biosurfactants production with emulsions over than 60%. More interestingly, one high-salt-tolerant yeast isolate was the most potent biosurfactants producing yeast with an emulsification index of 69.50 +/- 0.70. It was identified by morphological, physiological and biochemical tests and by 5.8s-rDNA Analysis as Cryptococcus sp. YLF. This strain produced biosurfactant using different carbon and nitrogen sources and when grown in low-cost fermentative media based on agro industrial by-products and wastes like whey, molasses, corn steep liquor, date syrup and olive mill wastewater (OMW) supplemented with NaCl (2.5 M). The biosurfactant produced by Cryptococcus sp. YLF was partially characterized as glycolipid based on the estimation of macromolecules, TLC and IR analysis. The crude biosurfactant demonstrated stability regarding surface tension reduction and emulsification activity in a range of temperatures (5-100 degrees C), pH (2-12) and high salinities (1-10%). The partially purified biosurfactant showed promising potential for application in enhanced oil recovery (EOR).",14,14,4
Crude Oil,Wettability Alteration,"You, Qing; Wang, Huan; Zhang, Yan; Liu, Yifei; Fang, Jichao; Dai, Caili",Experimental study on spontaneous imbibition of recycled fracturing flow-back fluid to enhance oil recovery in low permeability sandstone reservoirs,Recycled fracturing flow-back fluid; Spontaneous imbibition; Wettability alteration; Interfacial tension; Synergistic effect,WETTABILITY ALTERATION; SURFACTANT; NANOFLUIDS; CARBONATES; IFT,"In light of the high treatment costs for massive amounts of fracturing flow-back fluid and its harmfulness to the environment, a novel method of recycled fracturing flow-back fluid (RFFF) to enhance oil recovery by spontaneous imbibition is proposed in this study; this method does not allow the flow-back fluid back to the ground, thereby preventing negative impacts. The wettability alteration and interfacial tension (IFT) can effectively strengthen the spontaneous imbibition to enhance oil recovery in low-permeability sandstone reservoirs. This study combines the effects of wettability alteration and IFT with the use of the RFFF, which is composed of viscoelastic surfactants, on the spontaneous imbibition in low-permeability outcrop cores. Contact angle (CA) experiments, IFT experiments, and spontaneous imbibition experiments are conducted. The CA and IFT experimental results showed that the RFFF solutions changed the wettability of the core surface from oil-wet to waterwet and easily reduced the IFT between the crude oil and the RFFF solution to 10(-3)-10(-2) mN/m, which improved the oil recovery by changing the capillary forces. The spontaneous imbibition results showed that the RFFF solutions at concentrations of 0.03 - 0.10 wt% resulted in a higher imbibition recovery due to the synergistic effect of the wettability alteration and the IFT, which was attributed to the wedge film structure and the spreading force. It can be concluded that the use of the RFFF has the potential to further enhance oil recovery after fracturing the formation in low-permeability reservoirs without letting the fluid flow back to the ground. The proposed method is multi-functional and does not only improve the oil recovery by integrating fracturing and displacement methods but also reduces the costs of reservoir development and protects the environment.",100,103,14
Crude Oil,Wettability Alteration,"Nasralla, Ramez A.; Mahani, Hassan; van der Linde, Hilbert A.; Marcelis, Fons H. M.; Masalmeh, Shehadeh K.; Sergienko, Ekaterina; Brussee, Niels J.; Pieterse, Sebastiaan G. J.; Basu, Saptarshi",Low salinity waterflooding for a carbonate reservoir: Experimental evaluation and numerical interpretation,,ENHANCED OIL-RECOVERY; DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; IMPACT; TEMPERATURE,"Several laboratory studies and some field trials have already demonstrated the potential of lowering the injected brine salinity and/or manipulating composition to improve oil recovery in carbonate reservoirs. Laboratory SCAL tests such as coreflooding and imbibition are key steps to screen low salinity waterflood (LSF) for a particular field to (i) ensure that there is LSF response in the studied rock/oil/brine system, (ii) find the optimal brine salinity, (iii) extract relative permeability curves to be used in the reservoir simulation model and quantify the benefit of LSF and (iv) examine the compatibility of injected brine with formation brine and rock to derisk any potential scaling or formation damage caused by fines mobilization. This paper presents an extensive LSF SCAL study for a carbonate reservoir and the numerical interpretation of the tests. The SCAL experiments were performed at reservoir conditions using reservoir core plugs, dead crude oil and synthetic brines. The rock was characterized using porosity-permeability measurement semiquantitative, X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury intrusion capillary pressure (MICP) techniques. The characterization work showed that the plugs can be classified into two groups (uni-modal and bi-modal) based on pore throat size distribution which correlated with porosity-permeability cross-plots. The SCAL experiments were divided in two categories. Firstly, spontaneous imbibition and qualitative unsteady-state (USS) experiments were performed to demonstrate the effect of low salinity brines. In addition, these experiments helped to screen different brines (seawater and different dilutions of seawater) in order to choose the one that showed the most promising effect. Secondly, quantitative unsteady-state (USS) experiments were conducted and interpreted using numerical simulation to extract relative permeability curves for high salinity and low salinity brines by history- matching production and pressure data. The main conclusions of the study are: 1- The spontaneous imbibition and qualitative USS experiments showed extra oil production when switching from formation brine to seawater or diluted seawater subsequently, 2- Oil recovery by LSF can be maximized by injection of brine at a certain salinity threshold, at which lowering the brines salinity further did not lead to additional recovery improvement, 3- The LSF effect and optimal brine salinity varied in different layers of the reservoir which indicates that within the same reservoir the LSF effect is quite dependent on the rock type/ property and mineralogy, 4- The quantitative USS showed that LSF can improve the oil recovery factor by up to 7% at core scale compared to formation brine injection.",47,47,2
Crude Oil,Wettability Alteration,"Mahzari, Pedram; Sohrabi, Mehran; Cooke, Alexander J.; Carnegie, Andrew",Direct pore-scale visualization of interactions between different crude oils and low salinity brine,Micro-dispersion; Low salinity water injection; Crude oil; Pore scale; Enhanced oil recovery,INFRARED-SPECTROSCOPY; FTIR SPECTROSCOPY; RECOVERY; COMPONENTS,"Direct pore-scale visualizations using micromodels for low salinity water injection (LSWI) have revealed that the contact between low salinity water and crude oil can provoke formation of water-in-oil micro-dispersions. This experimental work, using a number of different crude oils, aims to visually study the link between micro-dispersion formation and pore surface wettability alteration by low salinity water injection. The effect of aging time on wettability alteration by LSWI was investigated. It was observed that mixed-wet conditions established with a moderate aging time would increase low salinity ability controlled by the oil characteristics. Moreover, under tertiary LSWI, the trapped oil was mobilized if the crude oils exhibited capabilities of forming micro-dispersions. Interestingly, when a crude oil with little or no propensity to form micro-dispersions was used, low salinity effects such as wettability alteration and improved oil recovery were absent. Also, micromodel experiments could enable the investigation of LSWI for waxy crude oil, which is difficult to do with other approaches. To demonstrate the impact of micro-dispersion formation on polar components of the oils, infrared analyses were performed indicating the importance of oil polar agents enriched in aromatics and sulfoxides on controlling the formation of the micro-dispersions. After using various crude oils, it was concluded that the effectiveness of LSWI as the method to increase oil recovery is predominantly controlled by two factors; (i) initial degree of wettability of pore surfaces and (ii) the propensity of crude oil to form micro-dispersions.",40,40,3
Crude Oil,Wettability Alteration,"Yousefvand, Hojat Alah; Jafari, Arezou",Stability and flooding analysis of nanosilica/ NaCl /HPAM/SDS solution for enhanced heavy oil recovery,Enhanced oil recovery; Wettability alteration; Stability; Micromodel; Nanosilica; Nanosuspension; Hydrolyzed polyacrylamide; Oil-wet medium,POLYMER-SOLUTION; NANOPARTICLES; DISPLACEMENT; WETTABILITY; PERFORMANCE; SUSPENSIONS; RESERVOIRS; CHINA,"Oil and gas are main sources of energy globally. Limitations on these resources and the ability to explore and exploit them has led to the development of new technologies for enhanced oil recovery. The massive amounts of oil remain in reservoirs must be removed using common enhanced oil recovery methods and other complex methods. Nanotechnology can help solve many problems in the oil and gas industry. Nanoparticles can assist production of oil from reservoirs on the nanometer scale. Nanoparticles can increase oil recovery through polymer flooding, but there are few studies on polymer performance in the presence of nanoparticles and salt, especially HPAM. The current study investigated HPAM/nano-silica for enhanced oil recovery and stability of the injected fluid. To prepare a stable solution for injection, different concentrations of HPAM, nanosilica, salt and water were tested and the best combination of materials was obtained. It was found that the addition of a surfactant is needed to control suspension stability. The results of stability tests indicate that salt is main cause of instability of nano-suspensions. At high salinity single-valence ions show effects similar to bivalence ions on the stability of nano-suspensions. SDS can adsorb onto nano-silica particles and supercharge the interface to stabilize the nano-suspensions. Stable fluid was injected into a strongly oil-wet five-spot glass micromodel saturated with heavy oil and image processing was applied to analyze the displacement mechanisms and calculate the efficiency of each flooding test. The viscosity was measured for precise analysis of the experimental data. The oil recovery factor after one pore volume of injected fluid indicates that the ultimate oil recovery improved in the presence of nanosilica particles, which increased the viscosity of the injected fluid and altered the wettability of the pore walls. Nanoparticles appear to have the ability to change the wettability to water-wet in some portions of the micromodel. Measurements showed that nanosilica particles did not change the IFT between the crude oil and injected fluid.",37,39,6
Crude Oil,Wettability Alteration,"Goswami, Rishiraj; Chaturvedi, Krishna Raghav; Kumar, Ravi Shankar; Chon, Bo Hyun; Sharma, Tushar",Effect of ionic strength on crude emulsification and EOR potential of micellar flood for oil recovery applications in high saline environment,Crude oil; Emulsion; Micellar flood; Rheology; SDS; Salt,NANOPARTICLE-SURFACTANT-POLYMER; IN-WATER EMULSIONS; INTERFACIAL-TENSION; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; HIGH-TEMPERATURE; SYSTEM; BEHAVIOR; CALCIUM; STABILITY,"Micellar flooding is one of the chemical oil recovery techniques in which micelle action emulsifies the crude oil to be mobilized in form of emulsion from a subsurface porous media. However, the subsurface conditions such as high ionic strength and temperature are challenges to the successful use of micellar flood owing to the deterioration of micelle action suggesting no crude emulsification. The ionic compounds dissociate into different ions that may further affect micelle action via loss in viscosity and pressure drop, increased water cut, and mobility contrast between micellar flood and displaced oil. Thus, investigation leading to the successful use of micellar flood, context to crude emulsion, in extreme salinity and temperature is vital to extend the use of chemical methods in new reservoirs. In this work, a typical surfactant sodium dodecyl sulfate (SDS) solution with critical micelle concentration (0.8 wt%) was tested to emulsify a fresh crude oil in the presence of varying ionic strength (0-4 wt%, NaCl/CaCl2 and temperature (40-98 degrees C). The efficacy of SDS micelles to produce crude emulsion significantly reduced with increasing salt concentration as reported through microscopic, rheological, and flooding experiments, particularly for divalent salt (CaCl2) than monovalent salt (NaCl). The increase in temperature (> 40 degrees C) further curtailed the growth of crude emulsion, mainly due to enhanced droplet coalescence; thus the use of micellar flood is critical in a reservoir enriched with high salinity and high temperature. Salinity effect on emulsion viscosity is reported through rheological measurements. The study highlighted important aspects of surfactant flooding and is a forward step towards the use of SDS based micellar flood at complex reservoir conditions.",29,28,1
Crude Oil,Wettability Alteration,"Suleimanov, Baghir A.; Latifov, Yashar A.; Veliyev, Elchin F.; Frampton, Harry",Comparative analysis of the EOR mechanisms by using low salinity and low hardness alkaline water,EOR; Low hardness alkali water; Sandstone flooding; Bentonite swelling; Low salinity water; Emulsion,IMPROVED OIL-RECOVERY; BRINE ROCK SYSTEMS; WETTABILITY ALTERATION; CRUDE-OIL; SPONTANEOUS IMBIBITION; SANDSTONE; TEMPERATURE; IONS,"This paper discusses the application of low hardness alkali water compositions (LHAW) as a secondary and tertiary displacement agent for EOR. A comparative analysis of the impact of low salinity water (LSW) and LHAW water on interfacial tension, contact angle on rock, adsorption of ions, emulsion stability and clay swelling is presented. LHAW application contributes to the formation of stable water in oil (w/o) emulsions and a decrease in clay swelling compared to LSW. Adsorption values for both fluids are similar. Contact angle measurements show that both LSW and LHAW reduce interfacial tension compared to Synthetic Caspian Sea water (SCSW), by up to 17% and 94% respectively. Similar results were observed for contact angle measurements. Flooding experiments were conducted in secondary and tertiary modes. In secondary flooding the two water compositions LHAW-2 and LHAW-1 increased the oil recovery (%OOIP) in comparison with SCSW at water breakthrough, by 29% and 25% respectively. The final oil recovery increases were 21% and 15% respectively. In tertiary flooding, tests showed that LHAW-2 and LHAW-1 oil recoveries (%OOIP) compared to LSW were 13% and 10% respectively. The oil recovery rate for LHAW solutions was not linear versus lnt as was that for LSW. This was proposed as a consequence of emulsions generation while water-cut is below 50% however, above 50% water cut the rate stabilizes.",25,25,0
Crude Oil,Wettability Alteration,"Ayirala, Subhash C.; Al-Saleh, Salah H.; Al-Yousef, Ali A.",Microscopic scale interactions of water ions at crude oil/water interface and their impact on oil mobilization in advanced water flooding,Enhanced oil recovery; Advanced water flood; Interfacial tension; Interfacial rheology; Surface potential; Coalescence times,POTENTIAL DETERMINING IONS; WETTABILITY ALTERATION; RECOVERY; SALINITY; CARBONATES; TEMPERATURE; RESERVOIRS; INJECTION; DROPLETS; SO42,"In this study, we performed interfacial shear rheology, surface potential and oil droplets coalescence time measurements to investigate microscopic scale interactions of various individual water ions at both air-water and crude oil-water interfaces. The measured interfacial rheology data indicated completely different interfacial behavior at crude oil-water interface when compared to air-water interface due to the presence of crude oil functional groups. Viscous dominated response was observed at crude oil-water interface for all brine compositions. Lower interfacial viscous modulus was observed for certain key ions such as calcium, and magnesium. The interfacial viscous modulus was found to be substantially much higher for sulfates, besides exhibiting some elasticity. The surface potential was gradually decreased by replacing seawater with calcium only brine. The better surface activity with seawater can be attributed to adsorption of more key water ions at the surface. These interesting results observed with calcium and magnesium ions at crude oil-water interface are expected to favorably impact oil mobilization in advanced water flooding processes. Such favorable interactions can quickly destabilize the interfacial film between oil and water (due to less viscous interfaces) to promote the coalescence between released oil droplets and enable faster oil mobilization. This coalescence process is also sequential and it would continue until the formation of small oil bank. The coalescence times measured between oil droplets confirmed the adverse impact of sulfate ions, to hinder the coalescence and delay oil mobilization, in consistent with interfacial shear rheology results. The new fundamental knowledge gained in this study would provide an important guidance on how to synergize water ion interactions at fluid-fluid interfaces with those at rock-fluids interfaces and optimize advanced water flooding processes in carbonate reservoirs.",19,19,3
Crude Oil,Wettability Alteration,"Aghaeifar, Zahra; Strand, Skule; Puntervold, Tina; Austad, Tor; Sajjad, Farasdaq Muchibbus",Smart Water injection strategies for optimized EOR in a high temperature offshore oil reservoir,,CRUDE-OIL; SALINITY; RECOVERY; WETTABILITY; ADSORPTION; KAOLINITE,"Smart Water injection is an EOR technique that is both environmentally friendly and easily implementable to a fractional cost compared to other water-based EOR methods. EOR by Smart Water is a wettability alteration process towards more water-wet conditions, which induces increased positive capillary forces and increased microscopic sweep efficiency. The objective of this work was to evaluate the injection strategy for Smart Water in an offshore high temperature sandstone reservoir, and compare the efficiency of seawater-based injection brines with low salinity brines, which can behave as Smart Water in sandstone reservoirs. Oil recovery experiments have been performed at reservoir conditions using preserved reservoir cores and reservoir fluids. Secondary low salinity injection gave an average of 33.5 %OOIP extra oil produced, compared to modified seawater injection. The tertiary low salinity EOR effect after modified seawater flooding gave an average of 11.8 %OOIP extra oil. Significant changes in produced water pH from initially acidic to alkaline conditions during low salinity injection were observed, favoring wettability alteration towards more water-wet conditions. The results confirmed that low salinity brine behaved as a Smart Water, contributing with significant extra oil recovery in a high temperature sandstone reservoir. Introducing Smart Water from day one in a reservoir, i.e. in secondary recovery mode, is significantly more efficient, regarding both response time and ultimate oil recovery, than tertiary mode Smart Water injection.",16,16,1
Crude Oil,Wettability Alteration,"Chandrasekhar, Sriram; Mohanty, Kishore K.",Effect of brine composition on oil-rock interaction by atomic force microscopy,Adhesion force; Low salinity brine; Calcite surface charge; Wettability alteration; Atomic force microscopy,SELF-ASSEMBLED MONOLAYERS; WETTABILITY ALTERATION; CALCITE SURFACE; CRUDE-OIL; SALINITY; IONS; DISSOLUTION; RECOVERY; SULFATE; MODEL,"Wettability alteration is known to occur in low salinity waterflooding of carbonate rocks. Oil droplets are thought to detach from the rock partially due to changes of the solid surface charge by multi-ion exchange with the brine. These mechanisms have been investigated in the past by measuring zeta potentials of calcite and oil, separately in test brines. In this work, the coupled calcite-brine-oil system was studied by measuring the adhesion force of an organic acid functionalized solid probe with a calcite surface, using an atomic force microscope. Brine compositions were varied in pH and ion concentration, to identify key conditions for minimum oil adhesion to calcite. Our experiments showed the strongest acid-calcite adhesion in formation brine. The adhesion force decreased in decreasing ionic strength NaCl brines, particularly below similar to 0.1 mol/L where the diffuse double layer expanded greatly. The complex composition brines of ultra-dilute seawater and excess sulfate seawater each gave the lowest adhesion due to a combination of double layer expansion, surface charge change and gypsum passivation of the calcite surface. Modifying seawater's Ca2+ and Mg2+ concentrations showed little change in the adhesion force despite being potential determining ions for calcite. Adhesion force responded the most to pH change. Increasing pH substantially decreased the adhesion force in seawater and excess sulfate seawater until a threshold value of pH 10. Above pH 10, the adhesion increased due to brine instability (to mineral precipitation) and material precipitation onto the calcite surface.",15,15,1
Crude Oil,Low Salinity,"Nasralla, Ramez A.; Mahani, Hassan; van der Linde, Hilbert A.; Marcelis, Fons H. M.; Masalmeh, Shehadeh K.; Sergienko, Ekaterina; Brussee, Niels J.; Pieterse, Sebastiaan G. J.; Basu, Saptarshi",Low salinity waterflooding for a carbonate reservoir: Experimental evaluation and numerical interpretation,,ENHANCED OIL-RECOVERY; DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; IMPACT; TEMPERATURE,"Several laboratory studies and some field trials have already demonstrated the potential of lowering the injected brine salinity and/or manipulating composition to improve oil recovery in carbonate reservoirs. Laboratory SCAL tests such as coreflooding and imbibition are key steps to screen low salinity waterflood (LSF) for a particular field to (i) ensure that there is LSF response in the studied rock/oil/brine system, (ii) find the optimal brine salinity, (iii) extract relative permeability curves to be used in the reservoir simulation model and quantify the benefit of LSF and (iv) examine the compatibility of injected brine with formation brine and rock to derisk any potential scaling or formation damage caused by fines mobilization. This paper presents an extensive LSF SCAL study for a carbonate reservoir and the numerical interpretation of the tests. The SCAL experiments were performed at reservoir conditions using reservoir core plugs, dead crude oil and synthetic brines. The rock was characterized using porosity-permeability measurement semiquantitative, X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury intrusion capillary pressure (MICP) techniques. The characterization work showed that the plugs can be classified into two groups (uni-modal and bi-modal) based on pore throat size distribution which correlated with porosity-permeability cross-plots. The SCAL experiments were divided in two categories. Firstly, spontaneous imbibition and qualitative unsteady-state (USS) experiments were performed to demonstrate the effect of low salinity brines. In addition, these experiments helped to screen different brines (seawater and different dilutions of seawater) in order to choose the one that showed the most promising effect. Secondly, quantitative unsteady-state (USS) experiments were conducted and interpreted using numerical simulation to extract relative permeability curves for high salinity and low salinity brines by history- matching production and pressure data. The main conclusions of the study are: 1- The spontaneous imbibition and qualitative USS experiments showed extra oil production when switching from formation brine to seawater or diluted seawater subsequently, 2- Oil recovery by LSF can be maximized by injection of brine at a certain salinity threshold, at which lowering the brines salinity further did not lead to additional recovery improvement, 3- The LSF effect and optimal brine salinity varied in different layers of the reservoir which indicates that within the same reservoir the LSF effect is quite dependent on the rock type/ property and mineralogy, 4- The quantitative USS showed that LSF can improve the oil recovery factor by up to 7% at core scale compared to formation brine injection.",47,47,2
Crude Oil,Low Salinity,"Xie, Quan; Sari, Ahmad; Pu, Wanfen; Chen, Yongqiang; Brady, Patrick V.; Al Maskari, Nasser; Saeedi, Ali",pH effect on wettability of oil/brine/carbonate system: Implications for low salinity water flooding,Carbonate reservoirs; Low salinity water; Wettability; Geochemical modelling; pH,SURFACE COMPLEXATION MODEL; IMPROVED OIL-RECOVERY; IMPACT; CHALK; CARBONATES; SANDSTONE; EOR,"Wettability of oil/brine/carbonate system is a critical parameter to govern subsurface multi-phase flow behaviour, thus remaining oil saturation and ultimate oil recovery in carbonate reservoirs. Despite the fact that salinity level, ionic strength, oil composition and rock chemistry (e.g., limestone and dolomite) have been extensively investigated, few work has been done regarding the effect of pH on oil/brine/rock interaction, thus wettability. We thereby measured contact angles at two different pH (pH = 3 and 8) in the presence of either 1 mol/L Na2SO4 or 1 mol/L CaCl2 using a crude oil with acid number of 1.7 and base number of 1.2 mg KOH/g. Moreover, we performed a geochemical modelling study in light of the diffuse double layer to understand how pH controls the number of surface species at interfaces of oil/brine and brine/carbonate. Our results show that pH scales with oil/brine/carbonate wettability, demonstrating that pH is one of the controlling factors to govern the system wettability. Further, our results suggest that pH (6.5-7.5) likely triggers an oil-wet system, which is favourable for low salinity water flooding, but pH < 5 usually exhibits a water-wet system, which explains why low salinity effect is not always observed in carbonate reservoirs. This also confirms that CO2 flooding, carbonated water flooding, and CO2 huff-and-puff FOR very likely renders a strongly water-wet system due to H+ adsorption on the interface of oil/brine and brine/carbonate as a result of CO2 dissolution.",43,43,2
Crude Oil,Low Salinity,"Mahzari, Pedram; Sohrabi, Mehran; Cooke, Alexander J.; Carnegie, Andrew",Direct pore-scale visualization of interactions between different crude oils and low salinity brine,Micro-dispersion; Low salinity water injection; Crude oil; Pore scale; Enhanced oil recovery,INFRARED-SPECTROSCOPY; FTIR SPECTROSCOPY; RECOVERY; COMPONENTS,"Direct pore-scale visualizations using micromodels for low salinity water injection (LSWI) have revealed that the contact between low salinity water and crude oil can provoke formation of water-in-oil micro-dispersions. This experimental work, using a number of different crude oils, aims to visually study the link between micro-dispersion formation and pore surface wettability alteration by low salinity water injection. The effect of aging time on wettability alteration by LSWI was investigated. It was observed that mixed-wet conditions established with a moderate aging time would increase low salinity ability controlled by the oil characteristics. Moreover, under tertiary LSWI, the trapped oil was mobilized if the crude oils exhibited capabilities of forming micro-dispersions. Interestingly, when a crude oil with little or no propensity to form micro-dispersions was used, low salinity effects such as wettability alteration and improved oil recovery were absent. Also, micromodel experiments could enable the investigation of LSWI for waxy crude oil, which is difficult to do with other approaches. To demonstrate the impact of micro-dispersion formation on polar components of the oils, infrared analyses were performed indicating the importance of oil polar agents enriched in aromatics and sulfoxides on controlling the formation of the micro-dispersions. After using various crude oils, it was concluded that the effectiveness of LSWI as the method to increase oil recovery is predominantly controlled by two factors; (i) initial degree of wettability of pore surfaces and (ii) the propensity of crude oil to form micro-dispersions.",40,40,3
Crude Oil,Low Salinity,"Suleimanov, Baghir A.; Latifov, Yashar A.; Veliyev, Elchin F.; Frampton, Harry",Comparative analysis of the EOR mechanisms by using low salinity and low hardness alkaline water,EOR; Low hardness alkali water; Sandstone flooding; Bentonite swelling; Low salinity water; Emulsion,IMPROVED OIL-RECOVERY; BRINE ROCK SYSTEMS; WETTABILITY ALTERATION; CRUDE-OIL; SPONTANEOUS IMBIBITION; SANDSTONE; TEMPERATURE; IONS,"This paper discusses the application of low hardness alkali water compositions (LHAW) as a secondary and tertiary displacement agent for EOR. A comparative analysis of the impact of low salinity water (LSW) and LHAW water on interfacial tension, contact angle on rock, adsorption of ions, emulsion stability and clay swelling is presented. LHAW application contributes to the formation of stable water in oil (w/o) emulsions and a decrease in clay swelling compared to LSW. Adsorption values for both fluids are similar. Contact angle measurements show that both LSW and LHAW reduce interfacial tension compared to Synthetic Caspian Sea water (SCSW), by up to 17% and 94% respectively. Similar results were observed for contact angle measurements. Flooding experiments were conducted in secondary and tertiary modes. In secondary flooding the two water compositions LHAW-2 and LHAW-1 increased the oil recovery (%OOIP) in comparison with SCSW at water breakthrough, by 29% and 25% respectively. The final oil recovery increases were 21% and 15% respectively. In tertiary flooding, tests showed that LHAW-2 and LHAW-1 oil recoveries (%OOIP) compared to LSW were 13% and 10% respectively. The oil recovery rate for LHAW solutions was not linear versus lnt as was that for LSW. This was proposed as a consequence of emulsions generation while water-cut is below 50% however, above 50% water cut the rate stabilizes.",25,25,0
Crude Oil,Low Salinity,"Mwangi, Paulina; Brady, Patrick V.; Radonjic, Mileva; Thyne, Geoffrey",The effect of organic acids on wettability of sandstone and carbonate rocks,Wettability; Low salinity; Waterflooding; Organic acids,IMPROVED OIL-RECOVERY; LOW-SALINITY WATER; SPONTANEOUS IMBIBITION; MODEL COMPOUNDS; RESERVOIRS; MECHANISMS; CHALK; BASE; IONS,"This paper examines the role of crude oil's organic acid surface active compounds (SAC) in determining the reservoir wettability over a range of salinities and temperatures. To isolate the effects of individual SACs, this project used model oil mixtures of pure decane and single SACs to represent the oleic phase. Due to the large number of experiments in this study, we used wettability measurement method by the modified flotation technique (MFT) to produce fast, reliable, and quantitative results. The results showed that oil wetting by decane increased with temperature for carbonate rocks. Sandstones oil wetting showed little temperature dependency. The presence of long-chained acids in decane increased oil wetting in sandstone and carbonate rocks as salinity was lowered, while the short-chained acid increased water wetting under the same conditions. The effect of organic acids on wettability was slightly enhanced with increasing temperature for all rock types.",21,23,2
Crude Oil,Low Salinity,"Shabaninejad, Mehdi; Middlelton, Jill; Fogden, Andrew",Systematic pore-scale study of low salinity recovery from Berea sandstone analyzed by micro-CT,Low salinity water flooding; Spontaneous imbibition; Micro CT; Image analysis; Wettability,FINES MIGRATION; OIL-RECOVERY; SEGMENTATION,"The low salinity effect in clay-rich outcrop sandstones is probed by micro-CT imaging and analysis. A set of eight Berea sandstone mini-plugs underwent primary drainage and aging in crude oil to a mixed-wet state, followed by spontaneous imbibition of high and low salinity brines and imaging of this sequence of prepared starting and endpoint states. Tomogram registration and analysis were used to determine the salinity-induced changes in oil volume, oil/rock and oil/brine interfacial areas, and oil/brine interfacial mean curvature. Pore-scale statistics were extracted to explore any local correlation between the low salinity effect and pore geometry/topology. The qualitative observations and quantitative analyses demonstrated that the small oil recovery by the low salinity effect corresponded to a slight shift towards water-wet.",20,20,1
Crude Oil,Low Salinity,"Aghaeifar, Zahra; Strand, Skule; Puntervold, Tina; Austad, Tor; Sajjad, Farasdaq Muchibbus",Smart Water injection strategies for optimized EOR in a high temperature offshore oil reservoir,,CRUDE-OIL; SALINITY; RECOVERY; WETTABILITY; ADSORPTION; KAOLINITE,"Smart Water injection is an EOR technique that is both environmentally friendly and easily implementable to a fractional cost compared to other water-based EOR methods. EOR by Smart Water is a wettability alteration process towards more water-wet conditions, which induces increased positive capillary forces and increased microscopic sweep efficiency. The objective of this work was to evaluate the injection strategy for Smart Water in an offshore high temperature sandstone reservoir, and compare the efficiency of seawater-based injection brines with low salinity brines, which can behave as Smart Water in sandstone reservoirs. Oil recovery experiments have been performed at reservoir conditions using preserved reservoir cores and reservoir fluids. Secondary low salinity injection gave an average of 33.5 %OOIP extra oil produced, compared to modified seawater injection. The tertiary low salinity EOR effect after modified seawater flooding gave an average of 11.8 %OOIP extra oil. Significant changes in produced water pH from initially acidic to alkaline conditions during low salinity injection were observed, favoring wettability alteration towards more water-wet conditions. The results confirmed that low salinity brine behaved as a Smart Water, contributing with significant extra oil recovery in a high temperature sandstone reservoir. Introducing Smart Water from day one in a reservoir, i.e. in secondary recovery mode, is significantly more efficient, regarding both response time and ultimate oil recovery, than tertiary mode Smart Water injection.",16,16,1
Crude Oil,Low Salinity,"Chandrasekhar, Sriram; Mohanty, Kishore K.",Effect of brine composition on oil-rock interaction by atomic force microscopy,Adhesion force; Low salinity brine; Calcite surface charge; Wettability alteration; Atomic force microscopy,SELF-ASSEMBLED MONOLAYERS; WETTABILITY ALTERATION; CALCITE SURFACE; CRUDE-OIL; SALINITY; IONS; DISSOLUTION; RECOVERY; SULFATE; MODEL,"Wettability alteration is known to occur in low salinity waterflooding of carbonate rocks. Oil droplets are thought to detach from the rock partially due to changes of the solid surface charge by multi-ion exchange with the brine. These mechanisms have been investigated in the past by measuring zeta potentials of calcite and oil, separately in test brines. In this work, the coupled calcite-brine-oil system was studied by measuring the adhesion force of an organic acid functionalized solid probe with a calcite surface, using an atomic force microscope. Brine compositions were varied in pH and ion concentration, to identify key conditions for minimum oil adhesion to calcite. Our experiments showed the strongest acid-calcite adhesion in formation brine. The adhesion force decreased in decreasing ionic strength NaCl brines, particularly below similar to 0.1 mol/L where the diffuse double layer expanded greatly. The complex composition brines of ultra-dilute seawater and excess sulfate seawater each gave the lowest adhesion due to a combination of double layer expansion, surface charge change and gypsum passivation of the calcite surface. Modifying seawater's Ca2+ and Mg2+ concentrations showed little change in the adhesion force despite being potential determining ions for calcite. Adhesion force responded the most to pH change. Increasing pH substantially decreased the adhesion force in seawater and excess sulfate seawater until a threshold value of pH 10. Above pH 10, the adhesion increased due to brine instability (to mineral precipitation) and material precipitation onto the calcite surface.",15,15,1
Crude Oil,Wax,"Taheri-Shakib, Jaber; Shekarifard, Ali; Naderi, Hassan",Characterization of the wax precipitation in Iranian crude oil based on Wax Appearance Temperature (WAT): Part 1. The influence of electromagnetic waves,WAX; Heavy crude oil; WAT; Microwave; Asphaltene,YIELD-STRESS; CLOUD POINT; POUR POINT; CRYSTALLIZATION; ASPHALTENES; INHIBITORS; COPOLYMERS; MICROWAVE; PARAFFIN; BEHAVIOR,"This paper investigated the effects of microwaves (MW) on Wax Appearance Temperature (WAT), the shape and morphology of wax crystals, and the content of elements in crude oil. After WAT was determined using cross-polarized microscopy (CPM), the intra-molecular bonds and the structure of the molecules were determined by subjecting crude oil and its wax content to Fourier-transform infrared (FTIR) spectroscopy analysis. Cracking and simultaneous evaporation of crude-oil combinations due to irradiation with MW caused peaks with different intensities in the oils' spectrums to appear. In addition, with irradiation, peaks reappeared that had been hidden in the range of virgin oil samples, and which were more closely related to aromatic compounds. The two processes of cracking and evaporation together resulted in a lighter oil sample with a lower WAT, which is evident in the samples' FTIR spectrum. Analysis of the images from the wax crystals under a polarization light microscope with image processing revealed a close connection between the shape and size of the wax particles and peak intensity of the FTIR spectrum and the crude-oil composition. Oil samples exposed to MW radiation had more rounded crystals and more similar proportions than virgin-oil samples. Radiation of MW waves caused asphaltene cracking to produce saturated, aromatic, and resin compounds. Since asphaltene is the heaviest oil-producing compound, this conversion lightened the oil and reduced the WAT. MW radiation also increased the amount of aromatic compounds derived from the resin in oil. The presence of asphaltene as one of the heavy-oil compounds and its interaction with wax molecules was investigated. It was observed that with respect to the naphthenic/polar of the wax sample, the decrease in the amount of asphaltene in the oil sample after irradiation reduced the interactions between the wax molecules and asphaltenes, and subsequently reduced the WAT. Scanning electron microscopy (SEM) images showed that the MW wax samples were composed of rounded and compacted particles, making it difficult to detect single grains. The size of the grains in the SEM images of MW samples was smaller than in the virgin sample. MW affected the dispersion and the mean size and shape of the wax particles under both the polarized light microscope and SEM; they also affected the bond/molecular structure as determined by FTIR and the amount of resin, asphaltene, saturation, and aromatics of the oil constituents, and decreased the average carbon number of the oil samples, which lowered the WAT.",36,38,1
Crude Oil,Wax,"Taheri-Shakib, Jaber; Rajabi-Kochi, Mahyar; Kazemzadeh, Ezzatallah; Naderi, Hassan; Shekarifard, Ali",A comprehensive study of the impact of wax compositions on the wax appearance temperature (WAT) of some Iranian crude oils: An experimental investigation,Wax; Asphaltene; Wax appearance temperature (WAT); Polar compounds; Crystal; Heavy oils,CRYSTALLIZATION; ASPHALTENES; PARAFFIN; FLOW; PRECIPITATION; COPOLYMERS; GELATION; MODEL; GELS; THERMOMICROSCOPY,"In this study, the effect of the molecular and structural wax properties of five oil samples from reservoirs in southwest Iran on the wax appearance temperature (WAT), shape, and morphology of wax crystals was investigated. After determining the WAT by cross-polarized microscopy (CPM) and viscometer, the wax was subjected to Fourier transform infrared (FTIR) spectroscopy analysis to determine the intermolecular bonds and structure of the molecules. The results show that there is a close relationship between the shape and size of the wax particle and the intensity and types of peaks in the FTIR spectrum of the wax. Paraffinic wax samples had rounded crystals of varying sizes, while polar/naphthenic compounds formed needle-shaped crystals. In the wax structure of some crude-oil samples, although normal alkanes are the main component of the wax, polar and naphthenic structures, albeit small, can also exist. The experiments showed that polar compounds also existed in the naphthenic wax sample, although the paraffin wax sample contained no polar/naphthenic compounds. The presence of asphaltene in crude oil and in polar/naphthenic wax samples affected the WAT and the crystalline form. As the amount of asphaltene increased, the interaction between the polar/naphthenic wax and asphaltene molecules increased; consequently, the WAT also increased. Energy-dispersive spectroscopy (EDS) analysis showed that as the wax sample loses its hydrocarbon nature, its carbon content decreases, and changes in the SNO elements in the wax structure occur, the WAT proportionally increases. Scanning electron microscopy (SEM) images of wax samples showed that semi-microcrystalline samples were composed of rounded and compacted grains; however, paraffinic waxes consisted of a network of large tubular crystals similar in shape to rice grains. The presence of polar/naphthenic compounds in the wax structure changed the shape and density of particles, as shown in SEM images. The dispersion, mean size, and shape of the wax particles, both under the polarized light microscope and under SEM, depend on the molecular/bonding structure of the wax, the elemental composition, and the amount of asphaltene.",27,27,1
Crude Oil,Wax,"Deka, Barasha; Sharma, Rohit; Mandal, Arnab; Mahto, Vikas",Synthesis and evaluation of oleic acid based polymeric additive as pour point depressant to improve flow properties of Indian waxy crude oil,Cloud point; Pour point depressants; Wax precipitation; Rheology; Crude oil,,"During production of crude oil, surface temperature is much less than reservoir temperature. As a result hindrance in flow occurs due to wax precipitation in surface flowlines and if the temperature goes below the pour point, crude oil completely stops flowing. This research paper aims at determining the effect of a laboratory synthesized novel Pour Point Depressant (PPD) on the pour point depression and rheological properties of a crude oil sample and comparing its performance with a commercial flow improver. Triethanolamine was polymerized to form its trimer and then esterified with oleic acid to form tri-triethanolamine di oleate. Characterisation of the crude oil sample and the synthesized PPD were performed as per ASTM methods and the effects of the PPD on pour point and rheology of crude oil were thoroughly analysed using pour point apparatus and Physica rheometer respectively. Effect of the synthesized PPD on different components and wax appearance of crude oil is also verified. Experimental investigations furnishes that the synthesized PPD and the commercial flow improver enhanced the flow properties of the crude oil, but the effects of the synthesized PPD are significantly better compared to the commercial one in terms of reduction in pour point, viscosity and yield stress which shows the potential of synthesized PPD to control the flow assurance problem caused by Indian waxy crude oils.",24,24,1
Crude Oil,Wax,"Gu, Xuefan; Zhang, Fan; Li, Yongfei; Zhang, Jie; Chen, Shijun; Qu, Chengtun; Chen, Gang",Investigation of cationic surfactants as clean flow improvers for crude oil and a mechanism study,Cationic surfactants; Crude oil; Flow improver; Viscosity; Pour point,RELATIVELY LOW-TEMPERATURE; HEAVY OIL; CANOLA OIL; AQUATHERMOLYSIS; COMPLEX; COPOLYMER,"Cetyl trimethyl ammonium chloride (CTAC), cetyl trimethyl ammonium bromide (CTAB), and octadecyl trimethylammonium chloride (OTAC) were evaluated as clean flow improvers for crude oil. The results showed that all of them have some effect on the viscosity of crude oil in a certain temperature range, and can depress the pour point, among which CTAC is the most potent one. The viscosity was reduced to below 540 mPa s under different concentration at 35 degrees C by CTAC, and it can depress the pour points by 7.5 degrees C with the concentration of 0.03%. DSC analysis and microscopic morphology analysis discovered the interaction of CTAC and saturated hydrocarbon component of the crude oil, which can reduce the wax peak temperature and wax precipitation point of crude oil. CTAC may precipitate and pack with the long-chain alkane to form the crystal nucleus, while the cationic part and the corresponding Cl- anion can act as a wax crystal modifier and block the wax crystal to grow up, thereby reduce the risk to form three-dimensional networks.",23,24,2
Crude Oil,Wax,"Akinyemi, O. P.; Udonne, J. D.; Oyedeko, K. F.",Study of effects of blend of plant seed oils on wax deposition tendencies of Nigerian waxy crude oil,Blend of plant seed oil; Wax deposition tendency; Paraffin inhibition efficiency; Waxy crude oil,,"Paraffin wax deposition has been a reoccurring problem in transportation of waxy crude oil in the oil industry. Chemical treatment had been the most convenient and economical method for tackling this problem. This paper considered the study on effects of blends of plant seed oils on wax deposition tendencies of Nigerian waxy crude oil. Three waxy crude oil samples obtained from Niger Delta region of Nigeria were characterized to determine their wax deposition tendencies, pour point, American Petroleum Institute gravity (APIg), wax content and viscosity using standard methods. The impacts of the blend of Jatropha seed oil (JSO) and castor seed oil (CSO) on the wax deposition tendencies of the crude oil samples were determined both in cold finger test and under a dynamic flow. The results obtained showed that blend of castor seed oil with 40% Jatropha seed oil reduced the wax deposition tendencies of the crude oil samples appreciably both in cold finger test and dynamic flow condition. The blend of CSO with 40% JSO gave optimum positive impacts on the pour point and wax deposition tendencies of the waxy crude oils in cold finger tests. The paraffin inhibition efficiency (PIE) attained under this condition was minimum of 79.1% for the crude oil samples at concentration of 0.1%v/v of additive with crude oil. Dynamic flow test using the optimum blend seed oil confirmed that the seed oils performed favourably as wax deposition inhibitor and flow improver at low temperatures and low concentrations of 0.10% additive to crude oil. It is recommended that blend of non-edible CSO and JSO be considered for usage as wax deposition inhibitor and flow improver in the Nigeria oil industry.",19,20,2
Crude Oil,Wax,"Li, Weidong; Huang, Qiyu; Dong, Xue; Gao, Xuedong; Hou, Lei; Wang, Wenda",A theoretical model for predicting the wax breaking force during pipeline pigging,Pigging; Orthogonal cutting; Slip-line field; Disk deformation; Wax breaking model; Pig design,CRUDE-OIL; OPERATING-CONDITIONS; DEPOSITION; REMOVAL; DSC,"Pipeline pigging is a major conventional wax remediation technique for waxy crude oil transportation. Predicting the wax breaking force, a decisive parameter for pigging arrangements, however still remains an open question, primarily due to the ambiguities in wax removal physics as well as a lack of methods. To address this issue, here we propose a new theoretical wax breaking model to explain the wax removal mechanism and predict the wax breaking force, allowing the no empirical parameters or correction factors. It is met by introducing orthogonal cutting in wax removal explanation and employing slip-line field theory in wax breaking force calculation. Scraping disk deformation is incorporated in this model. An indirect trial method is adopted for the wax-disk frictional angle determination. To check its correctness, we conducted verification experiments with 29-mm-ID and 50-mm-ID pipes. Good agreement between the predicted and measured wax breaking forces has been observed with the maximum and average relative deviations being 21.98% and 8.85% respectively. Moreover, case study suggests this model can potentially enable applications in pig design. Recommendations on pig geometry are accordingly given in detail. On the whole, calculating the wax breaking force, this presented model benefits in optimizing the pig design. In a broader perspective, it further helps to avoid pig stall.",18,19,2
Crude Oil,Wax,"Ruwoldt, Jost; Kurniawan, Muh; Oschmann, Hans-Jorg",Non-linear dependency of wax appearance temperature on cooling rate,Paraffin wax; Wax appearance temperature; Cooling rate; Wax deposition; Flow assurance; Crude oil production,DIFFERENTIAL SCANNING CALORIMETRY; CRUDE OILS; POINT DEPRESSANTS; CRYSTALLIZATION; MODEL; THERMOMICROSCOPY; PRECIPITATION; GELS; DSC; SOLUBILITY,"The Wax Appearance Temperature (WAT) is usually the first parameter to consider, when assessing whether paraffin wax contained in the crude oil can become an issue during production. As such, correct determination of the WAT is crucial. Changes in cooling rate can cause large differences in the measured WAT. This article therefore investigates the relationship between WAT and cooling rate in detail. A new algorithm is devised to determine the WAT from experimental data more accurately. This algorithm is tested with waxy model solutions and crude oil, and the results are compared between established techniques such as differential scanning calorimetry (DSC), cross-polarized microscopy (CPM), and viscometry. The data is in good agreement with modelling from homogeneous nucleation theory. Contrary to the general belief, the results show a predominantly non-linear dependency of WAT on cooling rate within the tested range of 20 degrees C/min to 0.5 degrees C/min. The assumption of linearity is therefore an oversimplification. Linear extrapolation to a zero cooling rate should only be done for cooling rates between 0.5 degrees C/min and 2 degrees C/min, as this range showed to be approximately linear. However, large gaps can exist between the theoretical solubility limit and the measured or extrapolated WAT. Moreover, for some samples one technique could be more sensitive at high cooling rates, whereas another technique could be more sensitive at lower cooling rates. It is therefore concluded that when assessing WAT, testing a representative range of cooling rates in addition to testing multiple instruments could be helpful in determining the worst-case-scenario.",17,17,0
Crude Oil,CO2,"Xie, Quan; Sari, Ahmad; Pu, Wanfen; Chen, Yongqiang; Brady, Patrick V.; Al Maskari, Nasser; Saeedi, Ali",pH effect on wettability of oil/brine/carbonate system: Implications for low salinity water flooding,Carbonate reservoirs; Low salinity water; Wettability; Geochemical modelling; pH,SURFACE COMPLEXATION MODEL; IMPROVED OIL-RECOVERY; IMPACT; CHALK; CARBONATES; SANDSTONE; EOR,"Wettability of oil/brine/carbonate system is a critical parameter to govern subsurface multi-phase flow behaviour, thus remaining oil saturation and ultimate oil recovery in carbonate reservoirs. Despite the fact that salinity level, ionic strength, oil composition and rock chemistry (e.g., limestone and dolomite) have been extensively investigated, few work has been done regarding the effect of pH on oil/brine/rock interaction, thus wettability. We thereby measured contact angles at two different pH (pH = 3 and 8) in the presence of either 1 mol/L Na2SO4 or 1 mol/L CaCl2 using a crude oil with acid number of 1.7 and base number of 1.2 mg KOH/g. Moreover, we performed a geochemical modelling study in light of the diffuse double layer to understand how pH controls the number of surface species at interfaces of oil/brine and brine/carbonate. Our results show that pH scales with oil/brine/carbonate wettability, demonstrating that pH is one of the controlling factors to govern the system wettability. Further, our results suggest that pH (6.5-7.5) likely triggers an oil-wet system, which is favourable for low salinity water flooding, but pH < 5 usually exhibits a water-wet system, which explains why low salinity effect is not always observed in carbonate reservoirs. This also confirms that CO2 flooding, carbonated water flooding, and CO2 huff-and-puff FOR very likely renders a strongly water-wet system due to H+ adsorption on the interface of oil/brine and brine/carbonate as a result of CO2 dissolution.",43,43,2
Crude Oil,CO2,"Seyyedi, Mojtaba; Mahzari, Pedram; Sohrabi, Mehran",A comparative study of oil compositional variations during CO2 and carbonated water injection scenarios for EOR,Carbonated water injection; CO2; CO2 storage; Compositional variations; New gaseous phase; EOR,CRUDE-OIL; RECOVERY; STORAGE,"With the significant increase in the atmospheric concentration of CO2, the interest for a combination of Enhanced Oil Recovery (EOR) and safe underground storage of CO2 in oil reservoirs has been increased. Two applicable methods that can address these concerns are CO2 flooding and carbonated water injection ( CWI). Mutual interactions taking place between oil and free CO2 or carbonated water (i.e. dissolve CO2 in the aqueous phase) would possess a fundamental difference. For free CO2 and oils, a combination of condensing/ vaporizing type of mass transfer would occur. However, in the case of carbonated water, a one- way mass transfer of CO2 from the aqueous phase to the oil can take place. This would lead to significant differences in the oil properties after dynamic interactions with free CO2 or carbonated water. In this study, for the first time, we are aiming to comprehensively address these concerns. An integrated approach was conducted to perform a series of carefully designed high-pressure and high-temperature direct visualizations (micromodel) as well as contact (PVT) experiments using a representative live oil. The results of pore-scale visualization experiments revealed an adverse strong extraction taking place during CO2 injection. Due to this extraction, the remaining oil after CO2 flooding was heavier than the original oil and its production was even more difficult. Contrary to that, during CWI the resident oil became lighter (lower viscosity) and no evidence of substantial extraction or oil downgrading was observed. To confirm pore-scale observations, PVT experiments were performed that revealed a strong adverse compositional change happening during CO2-oil single contact test. The oil contacted with CO2 was heavier than the original oil and a heavy condensate formed mainly from the medium components of oil was produced. However, during CW-oil multiple contacts test, the oil composition did not change and only after extensive cell volumes of CW comes in contact with the live oil; a slight change in the oil composition was observed. This slight change was due to the small extraction of light components of the oil into the new gaseous phase and it was observed in the form of a condensate. The produced condensate was lighter than the one produced from CO2-oil single contact test that reveals even after significant cell volumes of CW comes in contact with oil, the compositional change in oil is negligible compared to that of CO2 injection. The results of this study will shed some lights on the complex fluid-fluid interactions and oil compositional variations that take place during conventional CO2 and carbonated water injection in oil reservoirs.",23,24,3
Crude Oil,CO2,"Wang, Chao; Liu, Pengcheng; Wang, Fushun; Atadurdyyev, Bayramberdi; Ovluyagulyyev, Mergen",Experimental study on effects of CO2 and improving oil recovery for CO2 assisted SAGD in super-heavy-oil reservoirs,Super-heavy oil reservoir; Steam assisted gravity drainage (SAGD); Reduce viscosity; Carbon dioxide; Thermal oil recovery,GRAVITY DRAINAGE; STEAM; EOR; PERFORMANCE; INJECTION; SEQUESTRATION; MECHANISM; PRESSURE; BEHAVIOR; SOLVENT,"When developing heavy-oil reservoirs using steam-assisted gravity drainage (SAGD) technology, CO2 is often used to reduce the viscosity of heavy oil and the heat loss of the steam chamber, thereby enhancing oil recovery. The limitation of experimental apparatuses, results in a maximum temperature of the reaction kettle of no more than 150 degrees C. Thus, the solubility of CO2 in super-heavy oil and its impact on decreasing viscosity beyond 150 degrees C requires further discussion. Considering these issues, a high-temperature-resistant heavy-oil mixing apparatus was designed to measure the solubility of CO2 in super-heavy oil and the relative density and viscosity of super-heavy oil under high temperatures and pressures. Core flooding experiments under 200 degrees C were conducted to explore the effects of CO2 on oil displacement efficiency. The results indicated that solubility of CO2 became significantly lower at 200 degrees C, when the viscosity and relative density of super-heavy oil decreased as pressure increased. The viscosity of super-heavy oil saturated with CO2 decreased by 71.2%, and relative density decreased by 10.1% at 200 degrees C compared to those of degassed crude. At temperatures of 120 degrees C, 150 degrees C and 200 degrees C, the ultimate displacement efficiency of super-heavy oil increased by 6.6%, 19.2% and 21.4%, respectively, compared to a temperature of 60 degrees C. At pressures of 1.0 MPa, 2.0 MPa and 4.0 MPa, the ultimate displacement efficiency (46.7%) of super-heavy oil increased by 5.2%, 4.0% and 5.9%, respectively, compared to a pressure of 0.5 MPa. The experiments showed that CO2 injection can effectively reduce the relative density and viscosity of super-heavy oil and improve oil recovery under high temperatures and pressures. CO2 has good potential to improve SAGD efficiency in developing super-heavy-oil reservoirs.",20,21,4
Crude Oil,CO2,"Li, Xingxun; Guo, Yunmei; Sun, Qiang; Lan, Wenjie; Liu, Aixian; Guo, Xuqiang",Experimental study for the impacts of flow rate and concentration of asphaltene precipitant on dynamic asphaltene deposition in microcapillary medium,Asphaltene deposition; Visualization; Capillary flow; Microcapillary; Pore scale,ENHANCED OIL-RECOVERY; POROUS-MEDIA; CAPILLARY-FLOW; CO2 INJECTION; CONTACT-ANGLE; CRUDE-OIL; AGGREGATION PHENOMENA; INTERFACIAL-TENSION; PRESSURE DEPLETION; NATURAL DEPLETION,"Asphaltenes have been referred to 'cholesterol of petroleum' and the heaviest and the most complex components in crude oil. Asphaltene aggregation and deposition have always been a challenging issue on fluid transport in porous media for oil recovery and production processes in industries. Many experimental efforts have been done to study asphaltene aggregation and deposition from crude oil. Most of these works were carried out by coreflood tests or in bulk solution. Only several macroscopic parameters, such as pressure variation and permeability reduction caused by asphlatene deposition, were studied. Few experimental studies have been done to make the direct pore-scale visualization of dynamic asphaltene deposition behavior in capillary flow. In this study, we developed a new experimental approach to directly visualize and measure the dynamic asphaltene deposition process in capillary flow. Effects of concentration of asphaltene precipitant and flowrate were examined. The results indicate that the concentration of precipitant has a significant effect on the dynamic asphaltene deposition in capillary flow. The size of asphaltene deposit increases significantly with elapsed time and size distribution becomes wider at higher precipitant concentration. Higher concentration of asphaltene precipitant could lead to higher deposition rate. The results also indicate that higher flowrate causes faster growth of asphaltene deposits in capillary flow. Larger sizes of asphaltene deposits are formed and number of asphaltene deposits decreases with the elapsed time at higher flowrate. The results produced provide new sights into the dynamic asphaltene deposition in capillary flow at a pore scale. They could contribute to predict the growth rate of arterial asphaltene deposition in porous media and develop accurate numerical simulator for enhanced oil recovery purpose in industries.",19,20,5
Crude Oil,CO2,"Guo, Feng; Aryana, Saman A.",Improved sweep efficiency due to foam flooding in a heterogeneous microfluidic device,Heterogeneous microfluidic device; Foam flood; Trapezoidal cross-section; Capillary entry pressure,ENHANCED OIL-RECOVERY; POROUS-MEDIA; 2-PHASE FLOW; DISPLACEMENT; MICROMODEL; SURFACTANT; NETWORK; MECHANISMS; GENERATION; BEHAVIOR,"In this work, the flow behavior of foam and its impact on mobility control in displacing oil are investigated using a glass microfluidic device comprising a complex heterogeneous porous medium. The medium, fabricated with a centrally located low permeability zone and two high permeability zones on its sides, is initially saturated with crude oil. A blend of surfactants are used to stabilize CO2 foam in the presence of crude oil. Flow behavior in the microfluidic device is captured using a high-resolution camera. Foam is able to mobilize and recover oil trapped in the low permeability zone by increasing the resistance to flow in the high permeability zones and diverting the surfactant solution into the adjacent low-permeability zone. Foam remains gas-rich in the high permeability zones and solvent-rich in the low permeability zone throughout the experiments. The observed displacement dynamics are explained by characterizing channel geometries and calculating capillary entry pressure values for various fluids and zones of the medium.",19,21,4
Crude Oil,CO2,"Ren, Guangwei; Nguyen, Quoc P.; Hon Chung Lau",Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants,CO2 soluble surfactants; Partition coefficient; CO2 foam; Fractured carbonate reservoir; EOR,INTERFACIAL-TENSION; GRAVITY DRAINAGE; MOBILITY CONTROL; CRUDE-OIL; DISPLACEMENT; EOR; MICROEMULSIONS; WETTABILITY; SOLUBILITY; REDUCTION,"Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions. A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 degrees C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water. RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam. These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.",19,20,2
Crude Oil,CO2,"Lashkarbolooki, Mostafa; Riazi, Masoud; Ayatollahi, Shahab",Effect of CO2 and crude oil type on the dynamic interfacial tension of crude oil/carbonated water at different operational conditions,Dynamic IFT; Carbonated water; CO2; Adsorption time; Temperature; Pressure,CARBONATED WATER; AQUEOUS-SOLUTIONS; INJECTION; RECOVERY; PH; EQUILIBRIUM; TEMPERATURE; PERFORMANCE; ASPHALTENE; ADSORPTION,"Concerns about climate change have persuaded the researchers to examine CO2 injection in the form of carbonated water (CW) into oil reservoir as a safe and effective CO2 storage and enhanced oil recovery process. Although interfacial tension (IFT) between crude oil and injected fluid has a vital role on the displacement of fluids in porous media, the effect of CO2 and crude oil type on the dynamic IFT of crude oil under different operational conditions is not well understood. Accordingly, this study was carried out to assess the effects of temperature, pressure, crude oil type and CO2 on the dynamic IFT of crude oil/CW. To achieve this goal, two types of crude oil were provided from southern Iranian oil reservoirs and dynamic IFTs with CW were measured in a wide range of temperatures and pressures (i.e. temperature range of 30-80 degrees C and pressure range of 500-4000 psi); the obtained results were compared with the system without CO2. In addition, the adsorption time of carbonated aqueous phase/crude oil, obtained based on the mono exponential decay model, was also compared with unadulterated water/crude oil system. The outcome of this study showed that crude oil type has the most significant effect on the IFT of crude oil/CW compared to pressure, temperature and CO2 content. In more details, the IFT of crude oil/CW can be affected by the amount and type of acidic/basic components in the crude oil as well as pH of the aqueous solution. Besides, the obtained results revealed that the effect of temperature was more considerable on the IFT of the heavy crude oil compared with the light crude oil in both studied aqueous solutions (i.e. unadulterated water and CW). Although the inversion phase temperature was obtained for unadulterated water/studied crude oils at all studied pressures, this phenomenon was not observed for crude oil/CW at elevated pressure, due to the high amount of CO2 at this condition.",17,17,3
Crude Oil,Simulation,"Nasralla, Ramez A.; Mahani, Hassan; van der Linde, Hilbert A.; Marcelis, Fons H. M.; Masalmeh, Shehadeh K.; Sergienko, Ekaterina; Brussee, Niels J.; Pieterse, Sebastiaan G. J.; Basu, Saptarshi",Low salinity waterflooding for a carbonate reservoir: Experimental evaluation and numerical interpretation,,ENHANCED OIL-RECOVERY; DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; IMPACT; TEMPERATURE,"Several laboratory studies and some field trials have already demonstrated the potential of lowering the injected brine salinity and/or manipulating composition to improve oil recovery in carbonate reservoirs. Laboratory SCAL tests such as coreflooding and imbibition are key steps to screen low salinity waterflood (LSF) for a particular field to (i) ensure that there is LSF response in the studied rock/oil/brine system, (ii) find the optimal brine salinity, (iii) extract relative permeability curves to be used in the reservoir simulation model and quantify the benefit of LSF and (iv) examine the compatibility of injected brine with formation brine and rock to derisk any potential scaling or formation damage caused by fines mobilization. This paper presents an extensive LSF SCAL study for a carbonate reservoir and the numerical interpretation of the tests. The SCAL experiments were performed at reservoir conditions using reservoir core plugs, dead crude oil and synthetic brines. The rock was characterized using porosity-permeability measurement semiquantitative, X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury intrusion capillary pressure (MICP) techniques. The characterization work showed that the plugs can be classified into two groups (uni-modal and bi-modal) based on pore throat size distribution which correlated with porosity-permeability cross-plots. The SCAL experiments were divided in two categories. Firstly, spontaneous imbibition and qualitative unsteady-state (USS) experiments were performed to demonstrate the effect of low salinity brines. In addition, these experiments helped to screen different brines (seawater and different dilutions of seawater) in order to choose the one that showed the most promising effect. Secondly, quantitative unsteady-state (USS) experiments were conducted and interpreted using numerical simulation to extract relative permeability curves for high salinity and low salinity brines by history- matching production and pressure data. The main conclusions of the study are: 1- The spontaneous imbibition and qualitative USS experiments showed extra oil production when switching from formation brine to seawater or diluted seawater subsequently, 2- Oil recovery by LSF can be maximized by injection of brine at a certain salinity threshold, at which lowering the brines salinity further did not lead to additional recovery improvement, 3- The LSF effect and optimal brine salinity varied in different layers of the reservoir which indicates that within the same reservoir the LSF effect is quite dependent on the rock type/ property and mineralogy, 4- The quantitative USS showed that LSF can improve the oil recovery factor by up to 7% at core scale compared to formation brine injection.",47,47,2
Crude Oil,Simulation,"Khalaf, Mohammed H.; Mansoori, G. Ali",A new insight into asphaltenes aggregation onset at molecular level in crude oil (an MD simulation study),Asphaltene aggregation; Crude oil; Electrostatic energy; Hydrogen bond; Molecular dynamics; Van der Waals energy,DYNAMICS; ASSOCIATION; DEPOSITION; SOLVENTS; COAL,"The findings reported here is to understand the nature of asphaltenes aggregation behavior at the molecular level in crude oil. Previous studies have been rich with the statistical and macroscopic aspects of heavy organics behavior in petroleum fluids. Molecular dynamics simulations of three different model asphaltene molecules in a ""modeled crude oil"" composed of n-heptane and o-xylene were conducted. The roles of van der Waals (vdW), hydrogen bond (H-b), and electrostatic (ES) interaction energies on asphaltenes aggregation were investigated. Trends in aggregations, radial distribution functions (RDFs), vdW, H-b, and ES interactions were produced and analyzed. Our studies indicated asphaltenes with different molecular structures behaved differently from one another. At high paraffinic conditions, the preferred stacking of asphaltene molecules was face-to-face. The presence of H-b enhanced the stability of the aggregate. The number of H-bs varied in each model of asphaltene, depending on their detailed structures. The ES interactions between asphaltenes were either attraction or repulsion depending on the molecular structure. Overall, the major factor was the architecture of each asphaltene molecule, such as the number and length of chains, the number and position of heteroatoms, and the number and size of the aromatic cores where they are linked together to represent asphaltene behavior.",41,42,3
Crude Oil,Simulation,"Hou, Jirui; Luo, Min; Zhu, Daoyi",Foam-EOR method in fractured-vuggy carbonate reservoirs: Mechanism analysis and injection parameter study,Carbonate reservoirs; Fracture; Vug; Foam; EOR; Injection parameters,3-DIMENSIONAL PHYSICAL SIMULATION; FLOW,"Fractured vuggy carbonate reservoirs in the Tahe Oilfield, China, have many diverse and unevenly distributed reservoir spaces. These spaces mainly consist of corrosion pores, high-density fractures, and large vugs. Reservoir development began with natural energy and pressure maintenance methods. However, a rapid rise of the water cut always led to poor oil production. Gas enhanced oil recovery (EOR) has shown notable improvement in the Tahe Oilfield; however, the recovery efficiency was limited by gas channeling. In this paper, a two-dimensional (2D) physical model was developed for a more detailed visual of the flow characteristics and the effect of the injection parameters (i.e., the injection rate, the injection slug size, the injection timing and the injection position) were evaluated. Water flooding can produce a certain amount of oil; however, the remaining oil types are the same as those found during the bottom water invasion period, that is, attic oil, bypass oil, and oil films. A better approach is N-2 flooding, which can replace the attic oil at the top of the vug by gravitational differentiation. An even better method is N-2 foam flooding. When the injection volume of N-2 foam reached a certain level, foams accumulated in the flow channels, decreased fluid mobility, inhibited the gas channeling, and expanded sweep efficiency. Moreover, the N-2 foam had excellent effects on oil film stripping, crude oil emulsification, and carrying oil droplets, thereby improving the microscopic displacement efficiency. In addition, the results of injection parameter effect can help researchers and reservoir engineers better understand and implement the foam-EOR method in the fractured vuggy carbonate reservoirs.",21,22,12
Crude Oil,Simulation,"Li, Xingxun; Guo, Yunmei; Sun, Qiang; Lan, Wenjie; Liu, Aixian; Guo, Xuqiang",Experimental study for the impacts of flow rate and concentration of asphaltene precipitant on dynamic asphaltene deposition in microcapillary medium,Asphaltene deposition; Visualization; Capillary flow; Microcapillary; Pore scale,ENHANCED OIL-RECOVERY; POROUS-MEDIA; CAPILLARY-FLOW; CO2 INJECTION; CONTACT-ANGLE; CRUDE-OIL; AGGREGATION PHENOMENA; INTERFACIAL-TENSION; PRESSURE DEPLETION; NATURAL DEPLETION,"Asphaltenes have been referred to 'cholesterol of petroleum' and the heaviest and the most complex components in crude oil. Asphaltene aggregation and deposition have always been a challenging issue on fluid transport in porous media for oil recovery and production processes in industries. Many experimental efforts have been done to study asphaltene aggregation and deposition from crude oil. Most of these works were carried out by coreflood tests or in bulk solution. Only several macroscopic parameters, such as pressure variation and permeability reduction caused by asphlatene deposition, were studied. Few experimental studies have been done to make the direct pore-scale visualization of dynamic asphaltene deposition behavior in capillary flow. In this study, we developed a new experimental approach to directly visualize and measure the dynamic asphaltene deposition process in capillary flow. Effects of concentration of asphaltene precipitant and flowrate were examined. The results indicate that the concentration of precipitant has a significant effect on the dynamic asphaltene deposition in capillary flow. The size of asphaltene deposit increases significantly with elapsed time and size distribution becomes wider at higher precipitant concentration. Higher concentration of asphaltene precipitant could lead to higher deposition rate. The results also indicate that higher flowrate causes faster growth of asphaltene deposits in capillary flow. Larger sizes of asphaltene deposits are formed and number of asphaltene deposits decreases with the elapsed time at higher flowrate. The results produced provide new sights into the dynamic asphaltene deposition in capillary flow at a pore scale. They could contribute to predict the growth rate of arterial asphaltene deposition in porous media and develop accurate numerical simulator for enhanced oil recovery purpose in industries.",19,20,5
Crude Oil,Simulation,"Derakhshanfard, Fahimeh; Mehralizadeh, Amir",Application of artificial neural networks for viscosity of crude oil-based nanofluids containing oxides nanoparticles,Artificial neural network; RBF; Nanofluids; Oxide nanoparticles; Viscosity,THERMAL-CONDUCTIVITY; PARTICLE-SIZE; HEAT-TRANSFER,"In this research, the effect of general performances of radial basis function (RBF) method of artificial neural networks (ANN) with laboratory data on NiO, WO3, TiO2, ZnO and FeO3 nanoparticles in different temperatures and mass fractions on viscosity of crude oil were studied. The morphology and nanoparticles stability were analyzed with the DLS and TEM analysis. The results showed that the average nanoparticles diameter ranged from 10 to 40 nm for different oxide nanoparticles. For learning RBF networks, the major method for calculating isotropic Gaussian basis functions span for RBF networks containing special algorithm were presented. The results declared RBF neural networks had an acceptable performance because of having strong academic basic and ability of filtering the noises. This method contain all the experimental data perfectly, and provides the possibility of using different mass fractions and temperatures and simulated charts for knowing the information about the viscosity. For TiO2, ZnO and FeO3 nanoparticles, adding small amounts of nanoparticles decreased the relative viscosity comparing to the base fluid viscosity. But for WO3 and NiO nanoparticles the viscosity of nanofluids was higher than base fluid with any mass fractions.",16,16,1
Crude Oil,Simulation,"Yuan, Qing; Wu, Changchun; Yu, Bo; Han, Dongxu; Zhang, Xinyu; Cai, Lei; Sun, Dongliang",Study on the thermal characteristics of crude oil batch pipelining with differential outlet temperature and inconstant flow rate,Crude oil; Batch pipelining; Inconstant flow rate; Thermal characteristics; Gradient-type flow rate distribution,,"When several kinds of crude oil need to be transported, the batch pipelining is a better choice than the ""single-pipeline-single-oil"" and blending pipelining due to its advantages. In the batch pipelining process, to avoid the frequent operations on the pumps and control valves, the flow rate is generally inconstant in practice. All previous studies simplify the flow rate distribution as a constant one, which largely deviates from the engineering practice. Focused on this point, based on the features of the batch pipelining in practice, the gradient-type flow rate distribution model and corresponding calculation approach are proposed in this paper. The accuracy of this model and corresponding calculation approach are verified by the field data, and it indicates that the accuracy of numerical results can meet the engineering requirement. Further, the thermal characteristics of the batch pipelining are found by numerical simulation and the further analysis is carried out to make these characteristics more convincing. Finally, the shortcoming of the step-type flow rate distribution with simple expression is pointed out. It is found that the adoption of the step-type flow rate distribution in the simulation would introduce a prominent deviation when the change period of flow rate is relatively long. To overcome this shortcoming, the proposed gradient-type flow rate distribution, whose accuracy is higher, is an alternative method.",15,15,1
Crude Oil,Channeling,"Pei, Haihua; Shu, Zhan; Zhang, Guicai; Ge, Jijiang; Jiang, Ping; Qin, Yu; Cao, Xu",Experimental study of nanoparticle and surfactant stabilized emulsion flooding to enhance heavy oil recovery,Emulsion flooding; Nanoparticles; Heavy oil; Sweep efficiency; Injection parameters,,"It is well known that the recovery of water flooding from heavy oil reservoirs is less than 30% or even 20% of the OOIP (original oil in place), due to its very high viscosity and thus extremely low mobility comparing to light oil at reservoir condition. In order to improve residual oil recovery after water flooding in ordinary heavy oil reservoirs, this study presents an experimental study of nanoparticle and surfactant stabilized emulsion flooding to enhance heavy oil recovery. It is indicated in the emulsion stability and rheology studies that the synergistic interaction of nanoparticle with surfactant can significantly improve the emulsion stability and increase the apparent viscosity of emulsion. The results of core flooding tests show that the residual oil recovery after water flooding can be significantly improved by the nanoparticle-surfactant stabilized emulsions flooding. The incremental oil recovery gradually increases with the increase of injected emulsion volume, but there is an optimal economic value of the injected volume. The low injection rate is more effective than high injection rate, and the continuous injection pattern shows higher tertiary oil recovery as compared to cyclic injection pattern. The nanoparticle-surfactant stabilized emulsion flooding has a great potential for enhanced oil recovery in waterflooded heavy oil reservoirs, with the permeability ranging from 500 mD to 2000 mD and the crude oil viscosity being lower than 1000 mPa s. The two-dimensional homogeneous sandpack flooding test indicates that the nanoparticle-surfactant stabilized emulsion flooding can not only improve the sweep efficiency by blocking the high permeable water channels, but also can improve the displacement efficiency by mobilizing the trapped oil.",36,38,14
Crude Oil,Channeling,"Hou, Jirui; Luo, Min; Zhu, Daoyi",Foam-EOR method in fractured-vuggy carbonate reservoirs: Mechanism analysis and injection parameter study,Carbonate reservoirs; Fracture; Vug; Foam; EOR; Injection parameters,3-DIMENSIONAL PHYSICAL SIMULATION; FLOW,"Fractured vuggy carbonate reservoirs in the Tahe Oilfield, China, have many diverse and unevenly distributed reservoir spaces. These spaces mainly consist of corrosion pores, high-density fractures, and large vugs. Reservoir development began with natural energy and pressure maintenance methods. However, a rapid rise of the water cut always led to poor oil production. Gas enhanced oil recovery (EOR) has shown notable improvement in the Tahe Oilfield; however, the recovery efficiency was limited by gas channeling. In this paper, a two-dimensional (2D) physical model was developed for a more detailed visual of the flow characteristics and the effect of the injection parameters (i.e., the injection rate, the injection slug size, the injection timing and the injection position) were evaluated. Water flooding can produce a certain amount of oil; however, the remaining oil types are the same as those found during the bottom water invasion period, that is, attic oil, bypass oil, and oil films. A better approach is N-2 flooding, which can replace the attic oil at the top of the vug by gravitational differentiation. An even better method is N-2 foam flooding. When the injection volume of N-2 foam reached a certain level, foams accumulated in the flow channels, decreased fluid mobility, inhibited the gas channeling, and expanded sweep efficiency. Moreover, the N-2 foam had excellent effects on oil film stripping, crude oil emulsification, and carrying oil droplets, thereby improving the microscopic displacement efficiency. In addition, the results of injection parameter effect can help researchers and reservoir engineers better understand and implement the foam-EOR method in the fractured vuggy carbonate reservoirs.",21,22,12
Crude Oil,Channeling,"Guo, Feng; Aryana, Saman A.",Improved sweep efficiency due to foam flooding in a heterogeneous microfluidic device,Heterogeneous microfluidic device; Foam flood; Trapezoidal cross-section; Capillary entry pressure,ENHANCED OIL-RECOVERY; POROUS-MEDIA; 2-PHASE FLOW; DISPLACEMENT; MICROMODEL; SURFACTANT; NETWORK; MECHANISMS; GENERATION; BEHAVIOR,"In this work, the flow behavior of foam and its impact on mobility control in displacing oil are investigated using a glass microfluidic device comprising a complex heterogeneous porous medium. The medium, fabricated with a centrally located low permeability zone and two high permeability zones on its sides, is initially saturated with crude oil. A blend of surfactants are used to stabilize CO2 foam in the presence of crude oil. Flow behavior in the microfluidic device is captured using a high-resolution camera. Foam is able to mobilize and recover oil trapped in the low permeability zone by increasing the resistance to flow in the high permeability zones and diverting the surfactant solution into the adjacent low-permeability zone. Foam remains gas-rich in the high permeability zones and solvent-rich in the low permeability zone throughout the experiments. The observed displacement dynamics are explained by characterizing channel geometries and calculating capillary entry pressure values for various fluids and zones of the medium.",19,21,4
Crude Oil,Channeling,"Wang, Yanwei; Liu, Huiqing; Chen, Zhangxin; Wu, Zhengbin; Pang, Zhanxi; Dong, Xiaohu; Chen, Fangxuan",A visualized investigation on the mechanisms of anti-water coning process using nitrogen injection in horizontal wells,Nitrogen; Bottom water flooding; Visual experiment; Mechanisms; Bubble,PACKED-BED REACTOR; COALESCENCE; PORE; MODEL,"Horizontal wells have been widely used in oil reservoirs with bottom aquifer. As bottom water coning occurs, water cut of the production well rises sharply and the output declines rapidly. In this paper, an experimental study on the mechanism of anti-water coning and oil production increment by injecting nitrogen in horizontal wells was carried out. A theory of bubbling behaviors induced by gas permeating through a porous medium is skillfully applied to analyze the mechanisms of anti-water coning by injecting nitrogen. A series of visual experiments and a one-dimensional displacement experiment are conducted to intuitively study bubble characteristics and blocking mechanisms in porous media, as well as the microscopic mechanisms of the improvement of well performance by injecting nitrogen. The results show that there are three forms of nitrogen in the water channeling path: tiny bubble, elongated bubble, and gas channeling, which are related to water saturation and gas injection volume in the water channel. Elongated bubble, the main mechanism of anti-water coning by injecting nitrogen, can block high-permeable water channeling path to a certain extent. As the viscosity of crude oil increases, the negative effect of anti-water coning and the increment of bottom water sweeping range show up. It is suitable for non-homogeneous reservoirs, which is conducive to the exploitation of oil on the top layer in low permeability oil region. It can also largely increase the sweeping area of bottom water in low permeability reservoirs. But for high permeability formation, water suppression effect is poor. The earlier the injection of nitrogen gas, the better the effect of inhibiting water encroachment which can even reduce the water cut to zero. However, the effect of oil production increment will be not that good. This paper provides reference for the study in anti-water coning and increasing oil production by injecting nitrogen through the horizontal wells.",16,16,2
Crude Oil,Comparative Analysis,"Rakhmatullin, I. Z.; Efimov, S. V.; Tyurin, V. A.; Al-Muntaser, A. A.; Klimovitskii, A. E.; Varfolomeev, M. A.; Klochkov, V. V.",Application of high resolution NMR (H-1 and C-13) and FTIR spectroscopy for characterization of light and heavy crude oils,Crude oil; H-1 NMR spectroscopy; C-13 NMR spectroscopy; FTIR spectroscopy; SARA fraction; Functional group,INFRARED-SPECTROSCOPY; PEPTIDE; PARAMETERS; AROMATICS; BITUMEN; ALKANES,"High-resolution nuclear magnetic resonance (NMR) and Fourier transform infrared (FTIR) spectroscopy experiments were applied to obtain detailed information on the hydrocarbon chemistry of three light and three heavy crude oils. Quantitative fractions of aromatic molecules and functional groups constituting oil hydrocarbons were determined by C-13 NMR spectroscopy and comparative analysis of the oil samples with different viscosity, origin and preliminary treatment. SARA composition and some important information about aromaticity, oxidation behavior, branching, aliphaticity and sulfurization of studied oil samples were obtained. Integral characteristics of high-resolution NMR and FTIR spectra have a great potential to study the structure and characterization of light and heavy crude oils, which could substitute present traditional fractionation procedures. Relationships between spectroscopic parameters obtained by high-resolution NMR and FTIR spectroscopy methods and crude oil compositions can be useful for fast prediction of crude oil properties due to different type of treatment, including thermal methods for enhanced oil recovery. Also quantitative proportions of functional groups obtained by NMR and spectral indices obtained by FTIR can be one of the criteria for developing fingerprint approach.",38,38,4
Crude Oil,Comparative Analysis,"Suleimanov, Baghir A.; Latifov, Yashar A.; Veliyev, Elchin F.; Frampton, Harry",Comparative analysis of the EOR mechanisms by using low salinity and low hardness alkaline water,EOR; Low hardness alkali water; Sandstone flooding; Bentonite swelling; Low salinity water; Emulsion,IMPROVED OIL-RECOVERY; BRINE ROCK SYSTEMS; WETTABILITY ALTERATION; CRUDE-OIL; SPONTANEOUS IMBIBITION; SANDSTONE; TEMPERATURE; IONS,"This paper discusses the application of low hardness alkali water compositions (LHAW) as a secondary and tertiary displacement agent for EOR. A comparative analysis of the impact of low salinity water (LSW) and LHAW water on interfacial tension, contact angle on rock, adsorption of ions, emulsion stability and clay swelling is presented. LHAW application contributes to the formation of stable water in oil (w/o) emulsions and a decrease in clay swelling compared to LSW. Adsorption values for both fluids are similar. Contact angle measurements show that both LSW and LHAW reduce interfacial tension compared to Synthetic Caspian Sea water (SCSW), by up to 17% and 94% respectively. Similar results were observed for contact angle measurements. Flooding experiments were conducted in secondary and tertiary modes. In secondary flooding the two water compositions LHAW-2 and LHAW-1 increased the oil recovery (%OOIP) in comparison with SCSW at water breakthrough, by 29% and 25% respectively. The final oil recovery increases were 21% and 15% respectively. In tertiary flooding, tests showed that LHAW-2 and LHAW-1 oil recoveries (%OOIP) compared to LSW were 13% and 10% respectively. The oil recovery rate for LHAW solutions was not linear versus lnt as was that for LSW. This was proposed as a consequence of emulsions generation while water-cut is below 50% however, above 50% water cut the rate stabilizes.",25,25,0
Crude Oil,Comparative Analysis,"Taheri-Shakib, Jaber; Rajabi-Kochi, Mahyar; Kazemzadeh, Ezzatallah; Naderi, Hassan; Salimidelshad, Yaser; Esfahani, Mohammad Reza","A comprehensive study of asphaltene fractionation based on adsorption onto calcite, dolomite and sandstone",Asphaltene fractions; Adsorption; FTIR; Elemental analysis; Zeta potential,APPEARANCE TEMPERATURE WAT; HEAVY-OIL; HEATING TIME; CRUDE OILS; PART 1.; AGGREGATION; MICROWAVE; PRECIPITATION; SOLUBILITY; DEPOSITION,"In this study, based on a new procedure, asphaltene fractions of Sarvak oil samples were determined based on their adhesion to calcite, dolomite, and sandstone surfaces and their properties were evaluated. In irreversibly adsorbed asphaltenes, the highest concentrations of elements were 4.23 wt.% nitrogen (N) on the calcite surface, 7.12 wt.% sulfur (S) on dolomite surface, and 6.18 wt.% S and oxygen (O) on the sandstone surface. The dispersion of asphaltene fraction constituents on the surface, is approximately the same across the calcite sample, but in the dolomite sample, the highest adsorption of S correlates to the presence of magnesium (Mg). However, in sandstone samples, the highest S adsorption is achieved by potassium (K). The most dispersion of O occurs at the surface of the sandstone samples; according to matching through EDS mapping, due to the presence of silicon (Si), O has considerable dispersion. Asphaltene fractions also make lighter carbon compounds. It is important to note that in all samples, C-17 is the highest peak seen in irreversibly adsorbed asphaltenes. In addition, the zeta potential is negatively affected by increasing the adsorption properties of asphaltene fractions; this depends on the concentration of asphaltene elements adhering to the surface. The O-H polar peak in the irreversibly absorbed asphaltene/sandstone sample is higher due to the presence of O, compared to the other samples. In all three mineral samples, bulk asphaltene and adsorbed fractions have roughly the same values for alkyl groups. The concentration of carbonyl, carboxylic acid, or derivative groups in adsorbed fractions in calcite and sandstone samples show a higher intensity.",24,24,0
Crude Oil,Comparative Analysis,"Derakhshanfard, Fahimeh; Mehralizadeh, Amir",Application of artificial neural networks for viscosity of crude oil-based nanofluids containing oxides nanoparticles,Artificial neural network; RBF; Nanofluids; Oxide nanoparticles; Viscosity,THERMAL-CONDUCTIVITY; PARTICLE-SIZE; HEAT-TRANSFER,"In this research, the effect of general performances of radial basis function (RBF) method of artificial neural networks (ANN) with laboratory data on NiO, WO3, TiO2, ZnO and FeO3 nanoparticles in different temperatures and mass fractions on viscosity of crude oil were studied. The morphology and nanoparticles stability were analyzed with the DLS and TEM analysis. The results showed that the average nanoparticles diameter ranged from 10 to 40 nm for different oxide nanoparticles. For learning RBF networks, the major method for calculating isotropic Gaussian basis functions span for RBF networks containing special algorithm were presented. The results declared RBF neural networks had an acceptable performance because of having strong academic basic and ability of filtering the noises. This method contain all the experimental data perfectly, and provides the possibility of using different mass fractions and temperatures and simulated charts for knowing the information about the viscosity. For TiO2, ZnO and FeO3 nanoparticles, adding small amounts of nanoparticles decreased the relative viscosity comparing to the base fluid viscosity. But for WO3 and NiO nanoparticles the viscosity of nanofluids was higher than base fluid with any mass fractions.",16,16,1
Crude Oil,Bottom,"Liu, Chuhan; Zhang, Yin; Sun, Shanshan; Huang, Lixin; Yu, Li; Liu, Xiaonan; Lai, Ruiqiu; Luo, Yijing; Zhang, Zhiyong; Zhang, Zhongzhi",Oil recovery from tank bottom sludge using rhamnolipids,Oil sludge; Oil recovery; Pseudomonas aeruginosa; Biosurfactant,CRUDE-OIL; CONTAMINATED SOIL; PETROLEUM; DEMULSIFICATION; BIOSURFACTANTS; PSEUDOMONAS; PYROLYSIS; EMULSIONS,"Oil sludge has become a major impediment to the development of the petroleum and petrochemical industries with the growth of oil production worldwide. In this research, rhamnolipid biosurfactant produced by Pseudomonas aeruginosa was used to recover oil from oil tank bottom sludge. The optimum value of the fermentation broth (with rhamnolipid biosurfactant concentration of 5.4 g/L) addition was a volume fraction of 2% (v/v). Optimal temperature (65 degrees C), liquid/solid ratio (3:1), washing time (3 h), and agitation intensity (300 rpm) for oil recovery were determined. Wastewater from oil recovery was flocculated with 400 mg/L polyaluminum chloride for reuse. The moisture of the recovered oil was (0.42 +/- 0.12) %, which could directly enter into the refinery process. The solid particles in the oil sludge exhibited a porous structure that adsorbed a significant amount of oil and increased the difficulty of oil recovery. Results showed that the fermentation broth of P. aeruginosa can be used to recover oil from oil sludge and has potential industrial applications.",34,38,5
Crude Oil,Bottom,"Hou, Jirui; Luo, Min; Zhu, Daoyi",Foam-EOR method in fractured-vuggy carbonate reservoirs: Mechanism analysis and injection parameter study,Carbonate reservoirs; Fracture; Vug; Foam; EOR; Injection parameters,3-DIMENSIONAL PHYSICAL SIMULATION; FLOW,"Fractured vuggy carbonate reservoirs in the Tahe Oilfield, China, have many diverse and unevenly distributed reservoir spaces. These spaces mainly consist of corrosion pores, high-density fractures, and large vugs. Reservoir development began with natural energy and pressure maintenance methods. However, a rapid rise of the water cut always led to poor oil production. Gas enhanced oil recovery (EOR) has shown notable improvement in the Tahe Oilfield; however, the recovery efficiency was limited by gas channeling. In this paper, a two-dimensional (2D) physical model was developed for a more detailed visual of the flow characteristics and the effect of the injection parameters (i.e., the injection rate, the injection slug size, the injection timing and the injection position) were evaluated. Water flooding can produce a certain amount of oil; however, the remaining oil types are the same as those found during the bottom water invasion period, that is, attic oil, bypass oil, and oil films. A better approach is N-2 flooding, which can replace the attic oil at the top of the vug by gravitational differentiation. An even better method is N-2 foam flooding. When the injection volume of N-2 foam reached a certain level, foams accumulated in the flow channels, decreased fluid mobility, inhibited the gas channeling, and expanded sweep efficiency. Moreover, the N-2 foam had excellent effects on oil film stripping, crude oil emulsification, and carrying oil droplets, thereby improving the microscopic displacement efficiency. In addition, the results of injection parameter effect can help researchers and reservoir engineers better understand and implement the foam-EOR method in the fractured vuggy carbonate reservoirs.",21,22,12
Crude Oil,Bottom,"Wang, Yanwei; Liu, Huiqing; Chen, Zhangxin; Wu, Zhengbin; Pang, Zhanxi; Dong, Xiaohu; Chen, Fangxuan",A visualized investigation on the mechanisms of anti-water coning process using nitrogen injection in horizontal wells,Nitrogen; Bottom water flooding; Visual experiment; Mechanisms; Bubble,PACKED-BED REACTOR; COALESCENCE; PORE; MODEL,"Horizontal wells have been widely used in oil reservoirs with bottom aquifer. As bottom water coning occurs, water cut of the production well rises sharply and the output declines rapidly. In this paper, an experimental study on the mechanism of anti-water coning and oil production increment by injecting nitrogen in horizontal wells was carried out. A theory of bubbling behaviors induced by gas permeating through a porous medium is skillfully applied to analyze the mechanisms of anti-water coning by injecting nitrogen. A series of visual experiments and a one-dimensional displacement experiment are conducted to intuitively study bubble characteristics and blocking mechanisms in porous media, as well as the microscopic mechanisms of the improvement of well performance by injecting nitrogen. The results show that there are three forms of nitrogen in the water channeling path: tiny bubble, elongated bubble, and gas channeling, which are related to water saturation and gas injection volume in the water channel. Elongated bubble, the main mechanism of anti-water coning by injecting nitrogen, can block high-permeable water channeling path to a certain extent. As the viscosity of crude oil increases, the negative effect of anti-water coning and the increment of bottom water sweeping range show up. It is suitable for non-homogeneous reservoirs, which is conducive to the exploitation of oil on the top layer in low permeability oil region. It can also largely increase the sweeping area of bottom water in low permeability reservoirs. But for high permeability formation, water suppression effect is poor. The earlier the injection of nitrogen gas, the better the effect of inhibiting water encroachment which can even reduce the water cut to zero. However, the effect of oil production increment will be not that good. This paper provides reference for the study in anti-water coning and increasing oil production by injecting nitrogen through the horizontal wells.",16,16,2
Crude Oil,Horizontal Wells,"Nasri, Zarrin; Mozafari, Motahareh",Multivariable statistical analysis and optimization of Iranian heavy crude oil upgrading using microwave technology by response surface methodology (RSM),Heavy crude oil; Upgrading; Microwaves; Response surface methodology,ULTRASONIC IRRADIATION; HORIZONTAL WELL; DEMULSIFICATION; EMULSIONS; PERFORMANCE; PYROLYSIS; RECOVERY,"Conventional methods to upgrade heavy oil due to high pressure, low production efficiency, and low product quality have not been recognized as profitable methods. These complications resulted in using innovative technologies in this area. In this paper, the statistical analysis and process conditions optimization of Iranian heavy crude oil upgrading have been performed using microwave technology, for the first time. The heavy crude oil is from Iranian west Paydar field, with specifications including API 18.53, viscosity 78.76 cSt (at 20 degrees C). In order to optimize process conditions for upgrading heavy crude oil, independent variables include power level (40-70-100%), process time (5-12.5-20) (min), activated carbon as sensitizer (0-5-10) (wt%), and Fe as catalyst (0-3-6) (wt%). Surface temperature, API ratio, viscosity ratio, and asphaltene reduction have been considered as response variables. The Box-Behnken design and response surface methodology (RSM) have been applied to determine parameters levels and to model the responses, respectively. The results show that the optimal conditions to maximize surface temperature, API ratio, and asphaltene reduction, and to minimize viscosity ratio involve power level of 100%, process time of 20 min, activated carbon of 10 wt%, Fe catalyst of 4.06 wt% which leads to 23.31API ratio, 31.6% asphaltene reduction, and 43.37% viscosity reduction. The predicted conditions agreed with the experimental values, representing the models accuracy.",16,17,3
Crude Oil,Horizontal Wells,"Wang, Yanwei; Liu, Huiqing; Chen, Zhangxin; Wu, Zhengbin; Pang, Zhanxi; Dong, Xiaohu; Chen, Fangxuan",A visualized investigation on the mechanisms of anti-water coning process using nitrogen injection in horizontal wells,Nitrogen; Bottom water flooding; Visual experiment; Mechanisms; Bubble,PACKED-BED REACTOR; COALESCENCE; PORE; MODEL,"Horizontal wells have been widely used in oil reservoirs with bottom aquifer. As bottom water coning occurs, water cut of the production well rises sharply and the output declines rapidly. In this paper, an experimental study on the mechanism of anti-water coning and oil production increment by injecting nitrogen in horizontal wells was carried out. A theory of bubbling behaviors induced by gas permeating through a porous medium is skillfully applied to analyze the mechanisms of anti-water coning by injecting nitrogen. A series of visual experiments and a one-dimensional displacement experiment are conducted to intuitively study bubble characteristics and blocking mechanisms in porous media, as well as the microscopic mechanisms of the improvement of well performance by injecting nitrogen. The results show that there are three forms of nitrogen in the water channeling path: tiny bubble, elongated bubble, and gas channeling, which are related to water saturation and gas injection volume in the water channel. Elongated bubble, the main mechanism of anti-water coning by injecting nitrogen, can block high-permeable water channeling path to a certain extent. As the viscosity of crude oil increases, the negative effect of anti-water coning and the increment of bottom water sweeping range show up. It is suitable for non-homogeneous reservoirs, which is conducive to the exploitation of oil on the top layer in low permeability oil region. It can also largely increase the sweeping area of bottom water in low permeability reservoirs. But for high permeability formation, water suppression effect is poor. The earlier the injection of nitrogen gas, the better the effect of inhibiting water encroachment which can even reduce the water cut to zero. However, the effect of oil production increment will be not that good. This paper provides reference for the study in anti-water coning and increasing oil production by injecting nitrogen through the horizontal wells.",16,16,2
Crude Oil,C-13 NMR,"Rakhmatullin, I. Z.; Efimov, S. V.; Tyurin, V. A.; Al-Muntaser, A. A.; Klimovitskii, A. E.; Varfolomeev, M. A.; Klochkov, V. V.",Application of high resolution NMR (H-1 and C-13) and FTIR spectroscopy for characterization of light and heavy crude oils,Crude oil; H-1 NMR spectroscopy; C-13 NMR spectroscopy; FTIR spectroscopy; SARA fraction; Functional group,INFRARED-SPECTROSCOPY; PEPTIDE; PARAMETERS; AROMATICS; BITUMEN; ALKANES,"High-resolution nuclear magnetic resonance (NMR) and Fourier transform infrared (FTIR) spectroscopy experiments were applied to obtain detailed information on the hydrocarbon chemistry of three light and three heavy crude oils. Quantitative fractions of aromatic molecules and functional groups constituting oil hydrocarbons were determined by C-13 NMR spectroscopy and comparative analysis of the oil samples with different viscosity, origin and preliminary treatment. SARA composition and some important information about aromaticity, oxidation behavior, branching, aliphaticity and sulfurization of studied oil samples were obtained. Integral characteristics of high-resolution NMR and FTIR spectra have a great potential to study the structure and characterization of light and heavy crude oils, which could substitute present traditional fractionation procedures. Relationships between spectroscopic parameters obtained by high-resolution NMR and FTIR spectroscopy methods and crude oil compositions can be useful for fast prediction of crude oil properties due to different type of treatment, including thermal methods for enhanced oil recovery. Also quantitative proportions of functional groups obtained by NMR and spectral indices obtained by FTIR can be one of the criteria for developing fingerprint approach.",38,38,4
Crude Oil,C-13 NMR,"Zheng, Ce; Zhu, Mingming; Zareie, Reza; Zhang, Dongke","Characterisation of subfractions of asphaltenes extracted from an oil sand using NMR, DEPT and MALDI-TOF",Asphaltenes; DEPT; Molecular structure; NMR; Oil sand; Fractions,NUCLEAR-MAGNETIC-RESONANCE; SOLID-STATE NMR; PETROLEUM ASPHALTENES; MASS-SPECTROMETRY; MOLECULAR-WEIGHT; CRUDE-OIL; STRUCTURAL PARAMETERS; FRACTIONS; C-13; SPECTROSCOPY,"This paper reports the findings of an investigation into molecular structures and properties of an oil sand asphaltene sample and its subfractions. The asphaltene sample extracted from Buton Oil Sand (Indonesia) was fractionated stepwise into four subfractions by precipitation in a binary solvent system made from mixtures of dichloromethane/n-heptane with volumetric ratios of 30/70, 20/80 and 10/90, respectively. The average molecular structural parameters, including the average polycyclic aromatic hydrocarbon size, average side chain length and average molecular weight of the oil sand asphaltene sample and its subfractions, were measured and compared, using characterisation data obtained from nuclear magnetic resonance in combination with distortionless enhancement by polarisation transfer. The molecular weight distributions of the asphaltene samples were measured using a matrix-assisted laser desorption/ionisation time-of-flight mass spectrometry. The results indicated that the island molecular architecture was featured in all the asphaltene samples. The average polycyclic aromatic hydrocarbon size was found to be 7 rings for the least soluble subfraction, 6 rings for the other subfractions and the oil sand asphaltenes. The fractionation mechanism was dictated by polarity difference amongst subfractions as a result of relative luxuriance of the aliphatic parts. The use of C-13 NMR, DEPT and MALDI-TOF was shown to provide a useful means for characterisation and estimation of molecular structures of the asphaltenes.",14,14,2
Crude Oil,Oxide Nanoparticles,"Sitnov, Sergey A.; Mukhamatdinov, Irek I.; Vakhin, Alexey V.; Ivanova, Anna G.; Voronina, Elena V.",Composition of aquathermolysis catalysts forming in situ from oil-soluble catalyst precursor mixtures,Aquathermolysis; Mixed oxides; Transition metals; Catalyst precursor; Heavy oil; In-situ upgrading,HIGH-TEMPERATURE CHEMISTRY; HIGH-VISCOSITY OIL; HEAVY CRUDE OILS; ORGANIC-MATTER; SUPERCRITICAL WATER; CONVERSION; IRON; HETEROCYCLES; CARBOCYCLES; COMBUSTION,"Increasing efficiency of thermal recovery methods of heavy oil through injection of destructive hydrogenation catalysts precursors is a relevant task. In this paper the composition and properties of the active binary catalysts, which formed from a mixture of oil-soluble iron-, nickel- and copper-based precursors have been studied by XRD, Mossbauer spectroscopy, SEM, EDX-mapping methods. Moreover, the efficiency of a mixture of the corresponding metals in reducing the content of heavy components (SARA) of heavy crude oil from Ashal'cha field (Republic of Tatarstan) have been investigated. Mossbauer spectroscopy and EDX-mapping detected the formation of not only spinel ferrites MFe2O4 (where M = Ni or Cu), but also individual oxides. Moreover, in case of nickel-based catalyst three phases are formed: magnetite FeO center dot Fe2O3, spinel ferrite NiFe2O4 and superparamagnetic finely dispersed phase of iron oxides (and probably nickel oxides). According to XRD results, the oxides formed in the first stage transform into nonstoichiometric spinel ferrites Cu0.86Fe2.14O4 and Ni1.43Fe1.7O4 under hydrothermal influences. It is related with the thermodynamically beneficial processes of conversion of this specific phase composition. Based on the SARA and elemental analysis of the initial and converted oil, it was found that catalytic aquathermolysis decreases the content of asphaltenes and resins (about 45%) in the presence of catalyst nanoparticles, which indicates an improvement in the quality of the heavy oil.",22,23,2
Crude Oil,Oxide Nanoparticles,"Derakhshanfard, Fahimeh; Mehralizadeh, Amir",Application of artificial neural networks for viscosity of crude oil-based nanofluids containing oxides nanoparticles,Artificial neural network; RBF; Nanofluids; Oxide nanoparticles; Viscosity,THERMAL-CONDUCTIVITY; PARTICLE-SIZE; HEAT-TRANSFER,"In this research, the effect of general performances of radial basis function (RBF) method of artificial neural networks (ANN) with laboratory data on NiO, WO3, TiO2, ZnO and FeO3 nanoparticles in different temperatures and mass fractions on viscosity of crude oil were studied. The morphology and nanoparticles stability were analyzed with the DLS and TEM analysis. The results showed that the average nanoparticles diameter ranged from 10 to 40 nm for different oxide nanoparticles. For learning RBF networks, the major method for calculating isotropic Gaussian basis functions span for RBF networks containing special algorithm were presented. The results declared RBF neural networks had an acceptable performance because of having strong academic basic and ability of filtering the noises. This method contain all the experimental data perfectly, and provides the possibility of using different mass fractions and temperatures and simulated charts for knowing the information about the viscosity. For TiO2, ZnO and FeO3 nanoparticles, adding small amounts of nanoparticles decreased the relative viscosity comparing to the base fluid viscosity. But for WO3 and NiO nanoparticles the viscosity of nanofluids was higher than base fluid with any mass fractions.",16,16,1
Shale Gas,Natural Fractures,"Hou, Bing; Zhang, Ruxin; Zeng, Yijin; Fu, Weineng; Muhadasi, Yeerfulati; Chen, Mian",Analysis of hydraulic fracture initiation and propagation in deep shale formation with high horizontal stress difference,Hydraulic fracture; Complex fracture network; Discontinuities; Pump rate; AE monitoring,GAS-RESERVOIRS; BEHAVIOR; ROCK,"Deeply buried shale formations (vertical depth > 3500 m) that are rich in shale gas are abundant in south China. The primary problems in the exploitation of these formations are the relatively small stimulated reservoir volume (SRV) and low production rates in comparison with their shallower counterparts. These issues are attributed to the high fracturing pressure, limited fracture extension because of sand plugging, significant horizontal stress contrast, and discontinuities produced during hydraulic fracturing. To accurately evaluate and improve the SRV in deep shale formations, the mechanism of fracture propagation must be understood and described. In this regard, a series of large-scale true tri-axial experiments with acoustic emission (AE) monitoring were conducted to characterize the fracture initiation and propagation in a selected deep shale formation. It was found that the difficulty in the complex fracture network formation was because the high stress contrast controls the fracture propagation path to generate large main fractures instead of activating discontinuities. The hydraulic fractures initiated either from open-hole positions or stress concentration locations on a wellbore wall that displayed two types of intersection in terms of crossing and deflection. In general, four types of fracture morphologies were identified: transverse fracture, transverse fracture with bedding planes, natural fracture with bedding planes, and transverse fracture with bedding planes and natural fractures. In addition, the horizontal stress contrast, fluid viscosity, pump rate and fracturing procedure on fracture propagation were evaluated for their effect on the resulting SRV. A low-viscosity fluid can activate discontinuities to form a complex fracture network, whereas a high-viscosity fluid is likely to produce large fractures under a high contrast in the horizontal stresses. On the basis of the above-mentioned analyses, a fracturing procedure applying a periodically varying pump rate and shut-in using a low-viscosity fluid was suggested to be an effective approach to enhance the interaction between the hydraulic fractures and discontinuities as well as to increase the fracture length.",58,65,4
Shale Gas,Natural Fractures,"Jia, Bao; Tsau, Jyun-Syung; Barati, Reza","Role of molecular diffusion in heterogeneous, naturally fractured shale reservoirs during CO2 huff-n-puff",Bakken shale reservoirs; Molecular diffusion; Heterogeneity; Correlation length; CO2 huff-n-puff,OIL; INJECTION; RECOVERY,"Shale reservoirs are characterized by high degree of heterogeneity and ultra-low matrix permeability. Natural fracture (both macro and micro) systems are important to increase the performance of shale reservoirs by providing flow path for the hydrocarbon from the nanopores in the matrix to the wellbore. Configurations of natural fractures also have significant implications for the recovery performance of shale gas and oil reservoirs. CO2 huff-n-puff or cyclic injection has been suggested to be a feasible way to recover oil from shales and the flow process is complex. Molecular diffusion is an important transport mechanism of the mixture of CO2 and oil, especially in tight formations. Based on these knowledge, various configurations of the natural fracture system in shale reservoirs with the dual porosity and dual permeability model were constructed, regarding Dykstra-Parsons (DP) coefficient and correlation length. Dykstra-Parson (DP) coefficient ranges from 0.40 to 0.78, and correlation length ranges from 50 ft to 3000 ft. Based on the geological setting of the Middle Bakken formation and the Bakken live oil PVT data, compositional models were performed to simulate the CO2 huff-n-puff process. CO2 injection begins after the primary recovery factor reaches 3% and both multiple-cycle and single-cycle of injection were investigated regarding the oil recovery performance and CO2 injectivity behavior. In the multiple-cycle scheme the period of one cycle is short; the injection, soak and production time are 10 days, 10 days and 100 days, respectively. In the single-cycle scheme, the period of one cycle is long, and gas injection volume is set to be constant with the soak time of 100 days. The impact of molecular diffusion during the huff-n-puff process is compared in different simulation scenarios. Findings in this work reveal the importance of the configuration of the pre-existing natural fracture system for the performance of the huff-n-puff process. Reservoir heterogeneity hampers primary production. However, during the puff production process, the negative impact of heterogeneity is less as the correlation length increases when the molecular diffusion is taken into account. There exists a threshold correlation length value wherein heterogeneity becomes favorable for improved oil recovery instead of hampering oil recovery, after taking into account of the molecular diffusion, which is approximately 1500 ft in this simulation study. The value of correlation length also affects the performance of multiple-cycle and single-cycle huff-n-puff processes differently because CO2 injectivity behavior is different in reservoirs characterized by different DP coefficients and correlation length: there exists a threshold time point when a longer correlation length begins to favor the injectivity, and the threshold time point is delayed for a scenario with a larger DP coefficient.",41,42,2
Shale Gas,Natural Fractures,"Zhou, Dawei; Zhang, Guangqing; Zhao, Pengyun; Wang, Yuanyuan; Xu, Shengfan",Effects of post-instability induced by supercritical CO2 phase change on fracture dynamic propagation,Supercritical CO2 fracturing; Phase change; Post-instability; Equilibrium energy model; Fracture propagation coefficient,CARBON-DIOXIDE; GAS; FLUID; SHALE; WATER; STIMULATION; PRESSURE,"The effects of non-aqueous fracturing on unconventional reservoir stimulation have been investigated by laboratory and field work. Supercritical carbon dioxide (SC-CO2) is a notable non-aqueous fracturing fluid due to its potential to increase production, to reduce water requirements, and to minimize environmental impacts. In this paper, laboratory experiments conducted on polymethyl methacrylate (PMMA) are used to study the post-instability induced by SC-CO2 phase change on fracture dynamic propagation. Experimental results show that the fracture propagating speed of SC-CO2 fracturing is two order greater than that of hydraulic fracturing, and extensive hackle fractures occur in SC-CO2 fracturing. SC-CO2 phase change are mainly responsible for fracture post-instability, which dominates fracture propagation in SC-CO2 fracturing. Meanwhile, an equilibrium energy model of fracture dynamic propagation is proposed to describe the energy variation and transformation in porous medium. The concept of fracture propagation coefficient, i.e., the ratio of energy supplied by injection to fracture energy, is defined. SC-CO2 fracture propagation coefficient is much larger compared to hydraulic fracturing, suggesting that enough kinetic energy can accelerate fracture growth. This research may contribute to field application that SC-CO2 fracturing is likely to be an effective stimulation treatment, even in reservoir of undeveloped natural fractures.",34,35,4
Shale Gas,Natural Fractures,"Chen, Zhiqiang; Yang, Zhengming; Wang, Moran",Hydro-mechanical coupled mechanisms of hydraulic fracture propagation in rocks with cemented natural fractures,Hydraulic fracture; Cemented fracture; Natural fracture; LBM-DEM,LATTICE-BOLTZMANN METHOD; GENERAL SHAPES; BARNETT SHALE; FLUID-FLOW; PERMEABILITY; MODEL; DISCONTINUITIES; CRITERION,"Natural fractures commonly exist in unconventional reservoirs such as shale and tight gas sandstone, which are mostly cemented (or sealed) with minerals and not able to contribute to reservoir storage or rock permeability. However, during hydraulic fracture stimulation, these cemented natural fractures will be encountered and influence hydraulic fracture geometry greatly and, thereby, gas production. In this work, hydraulic fracture propagation in rock with cemented natural fracture is investigated using our recently developed and validated hydromechanical coupled LBM-DEM model. The numerical results show that both the strength ratio (between cemented natural fracture and host rock) and the approach angle (between hydraulic and cemented natural fracture) significantly affect the hydraulic fracture propagation. A larger strength contrast or a smaller approach angle will be more conducive to deflection, which is consistent with experimental observation. For rocks with weakly cemented natural fractures, deflection is mainly caused by shear failure in weakly cemented fracture. However, for rocks with strongly cemented natural fractures, deflection happens accompanying with tensile failure in host rock along the cement wall, which cannot be captured by the previous numerical models where the cemented natural fracture is treated as a bonded interface. In addition, complex fracture network is more easily formed if multiple weakly cemented natural fractures are orthogonal to the hydraulic fracture propagation direction.",31,32,3
Shale Gas,Natural Fractures,"Ren, Lan; Lin, Ran; Zhao, Jinzhou; Rasouli, Vamegh; Zhao, Jiangyu; Yang, Hao",Stimulated reservoir volume estimation for shale gas fracturing: Mechanism and modeling approach,Hydraulic fracturing; Stimulated reservoir volume; Fractures propagation; Shale gas; Mathematical model,HYDRAULIC FRACTURE; HORIZONTAL WELL; PROPAGATION; PERMEABILITY,"Multi-stage fracturing, following horizontal well drilling, is the key technology in shale gas reservoir development to enhance the recovery from such tight formations for economic production. The stimulated reservoir volume (SRV), which correlates closely to fracturing performance, is a quantitative measure for both pre-fracturing design and post-fracturing evaluation. However, an accurate estimation of the SRV is a long-standing challenge, because it requires a great knowledge of various parameters and complex mechanisms. In this study, we developed a mathematical model to estimate the SRV through simulating the main process during shale fracturing-multiple simultaneous hydraulic fractures propagate, perturbing the formation stress and raising the reservoir pressure; meanwhile, the stress change and pressure rise may jointly make natural fractures occur failure, and the SRV is estimated based on the volume of the naturally fractured zone that experiences tensile or shear failure. Hybrid numerical methods have been employed in this study. It applies displacement discontinuity method (DDM) to simulate non-planar hydraulic fractures propagation and represent the induced stress triggered by hydraulic fractures. The reservoir pressure is calculated by finite difference method (FDM). The failure state of natural fractures is predicted by the tensor equations deduced from Warpinski's failure theory. The model considers complex but important physical mechanisms that involved in the shale fracturing, including unequal flowrate distribution among each hydraulic fracture, non-planar hydraulic fractures propagation under stress interference, reservoir permeability increase with SRV extending (pressure & stress-depend), different failure states of natural fractures, etc. We validated our model by comparing its simulation results with analytical solution, published papers and onsite microseismic monitoring data. A field case study was performed to show the dynamic processes of hydraulic fractures propagation, reservoir permeability increase, and the SRV expansion during shale gas fracturing. Sensitivity analysis was conducted to investigate the influence of geological condition and fracturing parameters on SRV.",29,30,3
Shale Gas,Natural Fractures,"Wang, Xinghua; Ding, Wenlong; Cui, Long; Wang, Ruyue; He, Jianhua; Li, Ang; Gu, Yang; Liu, Jingshou; Xiao, Zikang; Fu, Fuquan","The developmental characteristics of natural fractures and their significance for reservoirs in the Cambrian Niutitang marine shale of the Sangzhi block, southern China",Sangzhi block; Niutitang Shale; Natural fracture; Characteristics; Controlling factors,ORGANIC-RICH SHALE; CENGONG BLOCK; NUMERICAL-SIMULATION; DOMINANT FACTORS; BASIN,"The great potential that southern China has for marine shale gas resources is well known, yet shale gas production is very small. Exploration and development of southern China has lagged because of the complicated structural history of this region. Thus, it is important to recognize the tectonic history of this region and to carefully describe the developmental characteristics of natural fractures associated with the tectonic evolution of southern China. In this paper, we discuss the developmental characteristics of natural fractures based on the description and statistical analysis of natural fractures in outcrops, cores and thin sections, and from several experimental tests. Fractures examined in outcrop appear to be principally fold-fault related, regional tectonic, bedding or weathering fractures. Fractures observed in core are mainly shear fractures, tension fractures, and shear-tension fractures. Most of these fractures are sealed by calcite. Micro fractures and pores are well developed. Analysis of the crosscutting relation of micro fractures suggests that the study area has been subject to at least two tectonic movements, consistent with our investigation of core. Fracture development appears to have been strongly influenced by structural evolution. However, fracture density displays a weak negative correlation with organic matter content. Further, fracture density appears to correlate positively with quartz content. Vertical variations of mineralogy appear to have influenced fracture generation and, therefore, hydrocarbon migration within the Niutitang Shale.",29,29,0
Shale Gas,Natural Fractures,"Teklu, Tadesse Weldu; Li, Xiaopeng; Zhou, Zhou; Alharthy, Najeeb; Wang, Lei; Abass, Hazim",Low-salinity water and surfactants for hydraulic fracturing and EOR of shales,Low-salinity water; Low-salinity water plus srufactnat; Osmosis; Capillary pressure; Wettability alteration; IFT decrease; Hydraulic fracturing and EOR of shales,OIL-RECOVERY; UNCONVENTIONAL RESERVOIRS; IMBIBITION; WETTABILITY; TRANSPORT,"There are significant recoverable oil and gas resources stored in shale reservoirs throughout the world. Horizontal well with multistage hydraulic fracturing is an enabling technology for economic production of these shale resources. Recovery factors of liquid rich shale reservoirs is typically less than 10%, hence, there is an incentive for implementing enhanced oil recovery (EOR) technologies to improve oil production from these very tight reservoirs. Brine, chemical (surfactant), gas, or combination of these fluids imbibition or injection in huff-n-puff scenario could improve oil recovery of liquid rich shale reservoirs. In this study, low-salinity water and low-salinity water + surfactant imbibition are assessed as both hydraulic fracturing and EOR fluids in liquid rich shale reservoirs. Osmosis, capillary pressure, wettability alteration, and other effects are among the mechanisms by which these fluids can improve oil recovery from shale reservoirs. These favorable effects were investigated through imbibition experiments. Experiments show: (a) low-salinity water huff-n-puff in tight formations can improve oil production from tight formations. This is because wettability alteration, capillary, and osmotic forces; (b) surfactant + low-salinity-water huff-n-puff can further improve oil production due to additional IFT decrease and wettability alteration by surfactants; hence, improve oil production from stimulated ultra-tight formations. Based on experimental observations and literature reviewed, low-salinity water huff-n-puff (until economical), followed by low-salinity water + surfactant huff-n-puff EOR process is recommended to optimize production from liquid rich shale reservoirs, while minimizing cost. These fluids can be used to reduce matrix-fracture skin damage. The effectiveness of these hydraulic fracturing and EOR fluids in shales is highly dependent on the existence and extent of natural fractures or laminations within the stimulated reservoir volume; this is because osmosis and diffusion are very slow processes.",27,29,7
Shale Gas,Natural Fractures,"AlTwaijri, Mohammad; Xia, Zhaohui; Yu, Wei; Qu, Liangchao; Hu, Yunpeng; Xu, Yifei; Sepehrnoori, Kamy",Numerical study of complex fracture geometry effect on two-phase performance of shale-gas wells using the fast EDFM method,Shale gas; Complex fractures; Natural fractures; Two-phase flow; Water flowback,WATER; SIMULATION; TRANSPORT; RESERVOIR; MODEL; FLOWBACK; OIL,"Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced ( hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of local grid refinement approach, hydraulic fractures are assumed to be planar ( orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational resources. In this paper, we introduce an embedded discrete fracture model (EDFM) to explicitly model complex fracture geometries. The EDFM efficient approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, we constructed a 3D reservoir model to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In our investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set of natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of nonorthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells.",23,23,3
Shale Gas,Natural Fractures,"Wang, HanYi",Discrete fracture networks modeling of shale gas production and revisit rate transient analysis in heterogeneous fractured reservoirs,Discrete fracture network (DFN); Shale gas production; Rate transient analysis (RTA); Complex fracture networks; Naturally fractured reservoirs; Heterogeneous reservoirs,WELL PRODUCTION; LINEAR FLOW; PERMEABILITY; SLIPPAGE; BEHAVIOR; IMPACT,"Horizontal wells with multiple hydraulic fractures are necessary stimulation technique for economically developing tight and shale gas reservoirs. In such reservoirs, the conventional well-test techniques are not suitable because of ultralow formation permeability. Rate transient analysis (RTA) is the widely used tool for analyzing these reservoirs for the purpose of reserves estimation, hydraulic fracture stimulation optimization, and development planning. However, the conventional rate transient analysis is based on the models that were derived from idealistic assumptions for homogenous reservoirs. In this article, we first review the industry's common practice for rate transient analysis and discuss why the idealized conceptual model may not be adequate for analyzing production data from shale gas reservoirs. Then, a unified shale gas reservoir model based on Discrete Fracture Networks (DFN) is presented to investigate how each mechanism influences shale gas production and the corresponding rate transient behavior. It is found that shale gas production and rate transient behavior are significantly impacted by reservoir heterogeneity, fracture networks, non-Darcy flow, gas adsorption and completion efficiency. Short early-time linear flow with long transitional flow period is an indication of either existence of abundant complex fracture networks or heterogeneous completion with unevenly distributed hydraulic fractures. Consider the nature of non-unique results of RTA, information from other independent sources is required to achieve a consistent and holistic interpretation.",23,23,2
Shale Gas,Natural Fractures,"Meng, Shangzhi; Li, Yong; Wang, Lei; Wang, Kai; Pan, Zhejun",A mathematical model for gas and water production from overlapping fractured coalbed methane and tight gas reservoirs,Coproduction; Coalbed methane; Tight gas; Interference phenomenon; Unconventional natural gas coproduction,RELATIVE PERMEABILITY; NATURAL-GAS; ORDOS BASIN; WELL TEST; CHINA; ACCUMULATIONS; ADSORPTION; SIMULATION; GEOLOGY; STRATA,"With the continuous expansion, exploration and development of unconventional natural gas resources, mainly coalbed methane, shale gas and tight gas, some areas overlapped by two or three types of unconventional natural gas reservoirs are explored, e.g., the Linxing, Shilou and Linfen blocks located in the east margin of the Ordos Basin, China. Gas extraction from an individual reservoir becomes not economic as gas resources are not fully recovered; thus, gas coproduction from two or multiple layers is an effective method for improving gas production. In this work, a mathematical model of gas and water two-phase flow for the coproduction of coalbed methane and tight gas is developed. The adsorption characteristics, stress-sensitive and matrix shrinkage effects on coal permeability, and the stress-sensitive effect of tight sandstone are all considered in the model. The gas production related parameters, such as bottom hole flowing pressure, reservoir pressure differences, reservoir properties (e.g., permeability, cleat compressibility of coal, and Langmuir isotherm parameters) are discussed and compared with different geological conditions. The results show that the gas and water flow from the coalbed and sandstone reservoirs show no interference between each other under a constant pressure drainage system; the sandstone reservoirs show a fast pressure drawdown with a high gas production rate decline, while the coalbed reservoir is slow in pressure drawdown and the gas production rate increases gradually. The properties of a specific reservoir have a great influence on its own gas production performance, but with no influence on the other reservoirs. It was found that a lower constant drainage pressure should be adopted in the case of stress-sensitive effects, and coal with a lower cleat compression coefficient and Poisson's ratio value is better for higher gas production. The production contribution from each layer can be acquired if a specific production rate is set. If the reservoir pressure difference between the two reservoirs is too high (for instance at least > 3 MPa in the cases studied in this work), gas and water intrusion may happen, but the reservoirs would be balanced quickly. Thus, the coproduction of coalbed methane and tight gas from one well bore is feasible, and more work should be conducted on proposing a proper drainage strategy to improve the gas resource recovery efficiency in coal-bearing strata.",18,19,5
Shale Gas,Natural Fractures,"Wu, Jingjing; Zhang, Shaohe; Cao, Han; Zheng, Mingming; Sun, Pinghe; Luo, Xu","Fracability evaluation of shale gas reservoir-A case study in the Lower Cambrian Niutitang formation, northwestern Hunan, China",Fracability evaluation; Northwestern Hunan; Shale gas reservoir; Lower Cambrian Niutitang; Combination weight method; Acoustic emission (AE) event,FRACTURES; BASIN,"Four main fracability-related factors, brittleness, quartz content, diagenesis and natural fracture, are analyzed for the shale in Lower Cambrian Niutitang formation, Northwestern Hunan. The quantitative evaluation of fissure ratio of shale was achieved by combining SEM technique and Image J. It shows that the Lower Cambrian Niutitang formation shale in the study area has large content of brittle minerals, high brittleness index, high degree of thermal evolution, and well developed fractures, which therefore indicate advantageous conditions for the fracturing of shale gas reservoir. In addition, a mathematical model integrates the four factors is proposed based on the combination weight method to quantitatively evaluate the fracability of the shale in the study area. It was found that the optimum area for fracturing in the study area is Xianfeng, Longshan, Sangzhi and Cili due to their relatively high fracability indexes. Also the shale fracability in this area can be divided into three levels according to the characteristics of reservoir parameters and it is suggested to select shale with fracability index above 0.4354 to be fractured. The lab hydraulic fracturing tests of the shale samples are conducted to verify the accuracy of the quantification model. The experiment results agree with the fracablity index predicted by the proposed quantification model.",16,19,6
Shale Gas,Natural Fractures,"Ranjith, P. G.; Wanniarachchi, W. A. M.; Perera, M. S. A.; Rathnaweera, T. D.",Investigation of the effect of foam flow rate on foam-based hydraulic fracturing of shale reservoir rocks with natural fractures: An experimental study,Foam; Fracturing; Breakdown pressure; Flow rate; Fracture permeability; CT scanning,PERMEABILITY; PRESSURE; ENERGY; GAS; PROPAGATION,"Foam-based hydraulic fracturing has been identified as a good solution for the extraction of natural gas from deep shale reservoirs, due to its unique advantages such as low water consumption and high proppant carrying capacity. However, lack of knowledge of foam-based shale fracturing and complex nature of two-phase foam, make it challenging to use in field conditions, and one unclear area is the effect of the foam flow rate on fracturing and fracture characteristics. Therefore, the aim of this study was to investigate the effect of foam flow rate on breakdown pressure, fracture permeability and generated fracture characteristics. In order to achieve this, a series of hydraulic fracturing experiments was conducted for shale rocks with existing natural fractures, using nitrogen-based foam. Fracture permeability was also evaluated for intact and fractured rock samples. Micro-CT scanning technology was adopted to characterise the geometrical properties of fractures, in order to investigate the effect of foam flow rate within the fracture. Experimental results show that the breakdown pressure increases by 30% while energy release decreases by 78% when the foam flow rate increases from 10 to 70 ml/min. In addition, the results suggest that the permeability of a fractured sample at 10 ml/min injection rate is about 15 times higher than that of a fractured sample at 70 ml/min injection rate. The findings of this study reveal that low foam-flow rates can create a better inter-connected fracture network than higher flow rates.",15,15,4
Shale Gas,Natural Fractures,"Zhao, Xianyu; Wang, Tao; Elsworth, Derek; He, Yunlong; Zhou, Wei; Zhuang, Li; Zeng, Jun; Wang, Suifeng",Controls of natural fractures on the texture of hydraulic fractures in rock,Hydraulic fracturing; Jointed rock mass; DEM; Crack propagation,SIMULATION; MODEL,"Hydraulic fracturing plays an important role in the exploitation of oil, shale gas and coal seam gas resources-all of which contain natural fractures. We systematically explore the role of the pre-existing texture of such natural fractures on the form of the resulting stimulated reservoir volume (SRV). A blocky discrete element model (DEM) coupled with fluid flow is used to explore this response. Numerical predictions for the evolution of fluid pressure and fracture width at the well are compared with first-order analytical approximations of the zero-toughness solution (FMO). We then construct four typical joint system models separately comprising orthogonal, staggered, diagonal and randomly oriented joints and conduct the virtual hydraulic fracturing simulations via DEM. This defines the influence of structure on breakdown pressure and fracture propagation and allows the analysis of the main factors that influence behavior and resulting SRV. Results for the four forms of jointed rock mass show that: (1) the aggregate/mean extension direction of the fractures is always along the direction of the maximum principal stress but significant deviations may result from the pre-existing fractures; (2) there are negative correlations between the maximum fracture aperture with both Poisson ratio and elastic modulus, but the breakdown pressure is only weakly correlated with Poisson ratio and elastic modulus; (3) an increase in injection rate results in a broader fracture process zone extending orthogonal to the principal fracture, and the breakdown pressure and interior fracture aperture also increase; (4) an increase in fluid viscosity makes the fractures more difficult to extend, and the breakdown pressure and interior fracture aperture both increase accordingly.",14,14,3
Shale Gas,Natural Fractures,"Liu, Jingshou; Ding, Wenlong; Wang, Ruyue; Yang, Haimeng; Wang, Xinghua; Li, Ang",Methodology for quantitative prediction of fracture sealing with a case study of the lower Cambrian Niutitang Formation in the Cen'gong block in South China,Fracture sealing; Shale reservoir; Paleotectonic stress field; Lower Cambrian; Cen'gong block,PALEOTECTONIC STRESS-FIELDS; SHALE-GAS; PRESERVATION CONDITIONS; CRUSTAL DEFORMATION; NATURAL FRACTURES; NORTHERN GUIZHOU; BASIN; RESERVOIRS; SIMULATION; DEPRESSION,"Industrial levels of shale gas have been produced from the Niutitang Formation in the lower Cambrian of the Cen'gong block, South China. The practice of exploration and development of shale gas in the Cen'gong block shows that the abundance of gas in different layers and wells is closely related to the degree of development of fractures. In this study, data obtained from outcrops, cores, and thin sections from the Cen'gong block were used to determine the development characteristics of such natural fractures. Combined with the analysis of burial history and fluid inclusions, the stress fields during three periods (the Yanshanian period, Himalayan period and neotectonic period) are suspected to play a critical role in fracture sealing. The paleotectonic stress tensor is determined using fault activity analysis, acoustic emission tests, and burial history. The magnitude and direction of current in situ stresses are determined by drilling-induced fractures, deviated well information, and cross multipole array acoustic (XMAC) logging. Under the constraints of XMAC logging interpretation and mechanical experiments, the spatial distribution of mechanical parameters is obtained by seismic inversion, and 3D heterogeneous geomechanical models are established using a finite element method (FEM). Then, the fracture density, reactivity, and aperture are identified. The results show that the magnitudes of the maximum horizontal principal stress during the Yanshanian period, the Himalayan period, and the neotectonic period are 150-170 MPa, 110-130 MPa, and 35-45 MPa, respectively. Using the fracture sealing calculation model, the fracture sealing that developed in the Himalayan period is the worst, the fracture sealing that developed in the Yanshanian period is intermediate, and the fracture sealing that developed in the neotectonic period is the best. Based on three-dimensional heterogeneous geomechanical modeling and tectonic stress evolution estimates, the fracture sealing calculation model proposed in this paper can be widely used in the evaluation of the preservation conditions of shale reservoirs, tight sandstone reservoirs and low-permeability reservoirs in complex tectonic areas.",14,15,2
Shale Gas,Shale Samples,"Wang, Xixin; Hou, Jiagen; Song, Suihong; Wang, Dongmei; Gong, Lei; Ma, Ke; Liu, Yuming; Li, Yongqiang; Yan, Lin",Combining pressure-controlled porosimetry and rate-controlled porosimetry to investigate the fractal characteristics of full-range pores in tight oil reservoirs,Tight oil reservoir; Pore size distributions; Fractal characteristics; Mineral composition; Mercury intrusion porosimetry,NUCLEAR-MAGNETIC-RESONANCE; PERMIAN LUCAOGOU FORMATION; SIZE DISTRIBUTION; ORDOS BASIN; SONGLIAO BASIN; GAS SANDSTONES; JUNGGAR BASIN; JIMUSAER SAG; DIMENSION; SHALE,"Tight oil reservoirs have the characteristics of wide pore size range and complex pore system. The understanding of pore characteristics is the basis for studying the accumulation and migration of oil and gas. To better study the fractal characteristics of full-range pores in Lucaogou tight oil reservoir, scanning electron microscopy (SEM) and mercury intrusion porosimetry (MIP) were used to obtain the pore size. XRD was used to obtain the mineral composition. In addition, fractal analysis was performed on the samples based on MIP data. The results show fracture pore (FP), residual interparticle pore (RIP), dissolution pore (DP) and clay dominated pore (CDP) are the main pore types. The interparticle pores is commonly largest in size, followed by dissolution pores. Quartz and feldspar play dominant roles in the composition in Lucaogou tight oil reservoir. The full-range pore size distribution (PSD) curves ranged from 3.6 nm to 400 mu m with two main distribution intervals. The fractal dimensions (D-1, D-2 and D-3) reflect the complexity of CDPs, DPs and RIPs, respectively. The average values of fractal dimensions were 2.88, 2.8 and 2.56, the smaller pores have more complex pore system. The pore structure of clay dominated pores is most complex. The more complex the pore structure, the worse the reservoir performance. Quartz shows negative correlation with D-3, Clay shows positive correlation with D-1, and feldspar is positively correlated with D-2. D-1, D-2 and D-3 are negatively correlated to porosity, D-1 shows a strong negative correlation with permeability.",68,70,6
Shale Gas,Shale Samples,"Kivi, Iman Rahimzadeh; Ameri, Mohammadjavad; Molladavoodi, Hamed",Shale brittleness evaluation based on energy balance analysis of stress-strain curves,Brittleness; Fracturing; Shale gas; Energy transformation; Carbonaceous texture,ROCK BRITTLENESS; MECHANICAL-PROPERTIES; FRACABILITY EVALUATION; UNIAXIAL COMPRESSION; INDEX ESTIMATION; BARNETT SHALE; PERTH BASIN; STRENGTH; FRACTURE; RESERVOIRS,"Brittleness is a key mechanical characteristic of rock and critical to various engineering practices particularly to design efficient fracturing stimulation of unconventional shale gas reservoirs. Variety of brittleness definitions and evaluation criteria have been proposed to describe rock failure behavior; however, their suitability and reliability have yet to be verified. In this paper, the existing brittleness indices were reviewed in detail and their applicability to reflect rock brittle characteristics were then investigated. The analysis indicated that most of expressions cannot describe brittle failure characteristics of rock efficiently and either partially or thoroughly fail to correctly address the impact of stress state on rock brittleness. Therefore, a new brittleness evaluation method was proposed based on promising energy transformation analysis of the complete stress-strain behavior of rock under compression. The new criterion is capable of dealing with the plastic energy dissipation mechanisms in the pre-peak region and the extent and rate to which rock strength degrades during macroscopic fracturing in the post-peak stage. Besides, the proposed brittleness index describes the entire transition of rock failure behavior of class I, from completely plastic to absolutely brittle states, in a continuous scale corresponding to 0 to 1. The applicability and outperformance of the proposed brittleness index were then verified against uniaxial and triaxial compression test results of some carbonaceous lithofacies from the Garau shale gas play within the Lurestan Basin, Iran. Samples under compression revealed various deformation and failure characteristics transitioned from brittle to semi-brittle behaviors with increasing confining pressure. Application of the brittleness indices to the tested rock specimens clearly demonstrated that the developed energy-based expression is able to rigorously capture the relative brittleness sequences of lithofacies and evolution trends under application of confinement, whereas further proved lack of either sufficient physical basis or appropriate formulation strategy in the existing indices. Accordingly, the new evaluation method seems to provide reliable estimates of rock brittleness in various field practices even though further verification is necessary. Finally, the important relation between microstructural carbonaceous texture and rock brittleness was discussed.",61,67,9
Shale Gas,Shale Samples,"Huang, Hexin; Sun, Wei; Ji, Wenming; Zhang, Ronghui; Du, Kun; Zhang, Shaohua; Ren, Dazhong; Wang, Youwei; Chen, Lei; Zhang, Xi","Effects of pore-throat structure on gas permeability in the tight sandstone reservoirs of the Upper Triassic Yanchang formation in the Western Ordos Basin, China",Yanchang formation tight sandstone; Permeability; Movable fluid porosity; Nuclear magnetic resonance; Constant-rate mercury injection,SIZE DISTRIBUTIONS; CAPILLARY-PRESSURE; MERCURY INTRUSION; NMR; SHALE; CONDUCTIVITY; PREDICTION; QUALITY,"The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.",48,48,7
Shale Gas,Shale Samples,"Luo, Sheng; Lutkenhaus, Jodie L.; Nasrabadi, Hadi",Use of differential scanning calorimetry to study phase behavior of hydrocarbon mixtures in nano-scale porous media,Phase behavior; Shale; Confinement; Thermal methods; Nanopores,EQUATION-OF-STATE; CAPILLARY-PRESSURE; CONFINED FLUIDS; TEMPERATURE-DEPENDENCE; EQUILIBRIUM; NANOPORES; PORES; ADSORPTION; SOLIDS; SHALES,"The phase behavior of petroleum fluids is a challenging problem in shale oil and gas production. Due to strong surface-fluid interactions and complex pore geometries in shale nanopores, PVT properties of fluids in shale are altered from those of conventional reservoirs and cannot be described by bulk-phase thermodynamics. To our best knowledge, the experimental data for hydrocarbon phase behavior in shale systems is severely absent. The experimental difficulty lies in introducing the nanoporous environment and finding an effective technique to study the fluid-nanoporous media system. In this work, we investigate the phase change of mixtures of hydrocarbons in nano-scale capillaries using a thermal laboratory technique, differential scanning calorimetry (DSC), which probes the thermal properties by measuring the heat exchange evolution of a sample during a temperature ramp. Porous media controlled-pore glasses (CPGs) are applied to model the nano-porous structure of shale reservoirs. CPGs (pore diameters 4.1 and 37.9 nm) infiltrated with hydrocarbons (octane and decane binary mixtures) are subjected to DSC. It is observed that at 37.9 nm the bubble point shift is negligible, but at 4.1 nm two distinct vaporization incidents occur with deviations as great as \xB120 K relative to the bulk. The unusual observation of bubble points for mixtures in 4.1 nm pores suggests compositional heterogeneity in the nanopore. The bubble point is modeled using Peng-Robinson equation of state (PR EOS) with the capillary pressure considered. The flash calculation is performed based on isofugacity and an interfacial tension model is accommodated. The modeling gives an exaggerated bubble point temperature shift and does not match the experimental results. This suggests the poor accuracy of the PR EOS/capillary pressure model in describing the behavior of nanoconfined fluid mixtures.",38,38,3
Shale Gas,Shale Samples,"Wang, Y.; Li, C. H.; Hao, J.; Zhou, R. Q.",X-ray micro-tomography for investigation of meso-structural changes and crack evolution in Longmaxi formation shale during compressive deformation,Shale fracturing; Micro-tomography CT; X-ray imaging; Fracture evolution; Longmaxi shale,HIGH-RESOLUTION; MECHANICAL-PROPERTIES; TRIAXIAL COMPRESSION; COMPUTED-TOMOGRAPHY; CREEP; ROCK; MICROTOMOGRAPHY; VISUALIZATION; PROPAGATION; SIMULATION,"Shale is a typical heterogeneous geomaterial and investigation of the meso-structural changes and crack evolution is beneficial to shale gas development. Understanding the microscopic failure mechanism is undoubtedly crucial to hydraulic fracturing treatment. In this paper, real-time high-resolution X-ray Computed (micro-) Tomography (X-ray CT) with was used for the first time to deform shale sample experimentally under unconfined axial compression. Organic matter, pyrite, and micro-fractures were volumetrically rendered with a resolution of 11.27 mu m, and 2D/3D image investigations enabled us to explore the structure and fracture evolution of the sample due to in-situ compression. This work reveals that the stress-induced deformation of shale is found to be dependent on organic matter compaction, pyrite spatial evolution, and micro-fracture initiation, propagation, and coalescence. The volume of organic matter decreases with the increase of axial stress; and the spatial distribution of pyrite changes at different loading stages, but the effective volume is almost the same. The formation of macroscopic fractures similar to 20 degrees oblique to the loading direction was observed. The cracks initiate in the tensile cracks between the bedding plane at the bottom of the sample and shear fractures are composed of tensile cracks connected by an ""X"" shape. The layered deposited structure and weak cementation between layers are the main factors controlling the failure mechanism.",33,36,4
Shale Gas,Shale Samples,"Liu, Kouqi; Ostadhassan, Mehdi; Kong, Lingyun",Multifractal characteristics of Longmaxi Shale pore structures by N-2 adsorption: A model comparison,N-2 adsorption; BJH model; DFT model; Shale; Multifractal; Comparison,TECTONICALLY DEFORMED COALS; SICHUAN BASIN; NITROGEN ADSORPTION; MERCURY POROSIMETRY; SIZE DISTRIBUTIONS; FRACTAL DIMENSION; ARGON ADSORPTION; POROUS MATERIALS; GAS-ADSORPTION; CHINA,"N-2 adsorption is one of the most widely used techniques to assess pore structures of shale samples due to its ability for characterizing pores in nanoscale. Various models have been developed to quantify pore structures based on adsorption isotherms. In this regard, using a suitable model can give us more accurate pore structure information. The Barret, Joyner and Halenda (BJH) model along with density functional theory (DFT), two most frequently used ones for pore structures of shales, employed on Longmaxi shale samples and compared. BJH model can be divided into two sub-models: adsorption (BJHAD) and desorption (BJHDE). First, the multifractal analysis was used to quantify the heterogeneity of pore size distributions derived from these models. Second, partial least regression analysis (PLS) was employed to quantify the correlations between pore structures and rock compositions. The results showed that pore structures (volume and surface area) and pore heterogeneity derived from BJHAD, BJHDE and DFT model would differ. In addition, PLS results indicated that minerals (except dolomite and clay) and organic matter would correlate positively while clay minerals negatively with pore surface area and volume independent of the method that was used. Finally, the comparison of results from these three methods demonstrated that DFT model is superior to BJHAD and BJHDE for pore structure characterization in shale gas formations.",27,30,11
Shale Gas,Shale Samples,"Xi, Zhaodong; Tang, Shuheng; Wang, Jing","The reservoir characterization and shale gas potential of the Niutitang formation: Case study of the SY well in northwest Hunan Province, South China",Middle and upper Yangtze regions; The lower cambrian shale; Niutitang formation; Pore structure; Shale gas,PORE STRUCTURE CHARACTERISTICS; CAMBRIAN LUJIAPING SHALE; THRUST-FOLD BELT; MARINE SHALE; SICHUAN BASIN; FRACTAL CHARACTERISTICS; YANGTZE PLATFORM; THERMAL MATURITY; WESTERN HUNAN; BLACK SHALES,"Marine shale is extensive throughout the subsurface, and commercially well-developed as natural gas producers throughout south China, attracting attention in recent years by both politicians and scientists on a variety of issues. Previous research on shale has predominantly focused on the Longmaxi and Niutitang Formations in the Sichuan Basin, but rarely on the periphery in northwestern Hunan Province where the Niutitang Formation has long been known as a potential shale gas reservoir. In this study, hydrocarbon generation potential, reserving performance, and shale gas potential of the Niutitang Formation from northwestern Hunan Province was studied to determine its gas producing potential. Total organic carbon (TOC) analysis, rock-eval pyrolysis, vitrinite reflectance and organic maceral analysis, mercury intrusion, nitrogen adsorption, and methane adsorption were run on a total of 52 samples from the SY well consisting of the Upper and Lower Members of the Niutitang Formation. Analysis of the results showed that the Niutitang shale has high TOC content (2.37% on average), high thermal maturity (3.15% on average), and oil-prone kerogen types, indicating good shale gas potential in the study area. The shale consists of relatively high concentrations of brittle minerals (quartz and feldspar, 69% on average) and low clay content (22% on average), indicating a brittle shale. The shale is a tight formation, with measured porosity averaging 2.66% (free gas potential) and methane adsorption capacity averaged 1.55 cm(3)/g (adsorbed gas potential). TOC and burial depth control reservoir space of the shale. The Lower Member samples had lower porosity but higher methane adsorption capacity than those from the Upper Member, indicating that a relatively larger amount of gas may occur as adsorbed gas in the Lower Member. It is suggested that the Lower Member of the Niutitang Formation is the ideal location for exploration and development of shale gas due to consistently thick organic-rich layers, high TOC content, high brittleness index, and stronger adsorption capacity.",27,29,3
Shale Gas,Shale Samples,"Al-Ameri, Aymen; Gamadi, Talal; Ispas, Ion",Evaluation of the near fracture face formation damage caused by the spontaneously imbibed fracturing fluid in unconventional gas reservoirs,Fracturing fluid spontaneous imbibition; Friction reducer pad fluid; Polymer adsorption; Nonionic surfactant; Bedding plane; Imbibition capillary pressure; Imbibition water relative permeability curves,SPONTANEOUS IMBIBITION; POROUS-MEDIA; RELATIVE PERMEABILITY; CAPILLARY RISE; SHALE; GRAVITY,"In the present study, spontaneous imbibition experiments, steady-state permeability measurements, and numerical simulation were integrated to quantify the changes in the effective water permeability, capillary pressure, and water relative permeability curves due to the polymer adsorption of the spontaneously imbibed fracturing fluid. The effect of the nonionic surfactant and core bedding plane on the fluid spontaneous imbibition volumes were also investigated. The researchers considered the impact of the spontaneous imbibition of a friction reducer fluid in tight sand and shale core samples. Three comparative systematic spontaneous imbibition experiments were conducted for each of the core samples using brine, anionic friction reducer fluid, and brine again. The core sample water permeability before and after the imbibition experiment was measured using a constant rate steady-state permeability apparatus. The polymer adsorption from the spontaneously imbibed fracturing fluid significantly reduced the brine spontaneous imbibition volumes in tight sand samples and in shale samples, though to a lesser degree. Moreover, the effective water permeability was decreased because of the polymer adsorption effect. Therefore, the polymer adsorption during hydraulic fracturing reduces the fluid leak-off into the formation and also the fluid flowback. The nonionic surfactant increased the fluid spontaneous imbibition volumes in both tight sand and shale samples. Thus, adding a nonionic surfactant to the friction reducer pad fluid during hydraulic fracturing leads to enhance both of the fluid leak-off and fluid flowback. The results also showed that the effect of polymer adsorption on the imbibition rates is less when the rock-fluid contact surface is parallel to the bedding plane. The imbibition potentials and imbibition capillary pressure curves were calculated before and after polymer adsorption. The polymer adsorption led to a slight increase in the capillary pressure; moreover, the tight sand samples had higher capillary pressure than the shale samples. The imbibition water relative permeability curves were calculated using ECLIPSE commercial simulator. The polymer adsorption significantly reduces the water relative permeability curves for tight sand samples and in less degree for shale samples.",24,24,6
Shale Gas,Shale Samples,"Bakshi, Tuli; Prusty, B. K.; Pathak, K.; Pal, S. K.",Pore characteristics of Damodar valley shale and their effect on gas storage potential,Organic matter; Mineralogy; Pore characteristics; Microporosity; Sorption; Shale gas reservoirs,FORT-WORTH BASIN; NORTHEASTERN BRITISH-COLUMBIA; MISSISSIPPIAN BARNETT SHALE; METHANE SORPTION CAPACITY; NORTH-CENTRAL TEXAS; COALBED METHANE; HYDROCARBON GENERATION; SIZE DISTRIBUTION; THERMAL MATURITY; BOWEN BASIN,"The current global interest in fine grained sedimentary shale rock is driven by its ability to store gas in the pore spaces in them. The current study focuses on the understanding of the gas storage capacity of less explored Damodar Valley shales of India, in light of pore characteristics of organic matter and clay minerals. In this study, four samples were collected from different parts of Damodar valley basin and their geochemical composition, pore structure and adsorption capacity were investigated by XRD studies, rock-eval analyses, low-pressure N-2-CO2 adsorption analyses and high-pressure methane adsorption experiment. The samples were also studied to know their hydrocarbon potential. The relationship between mineralogy, organic matter, and pore-structure was analyzed and finally, their effect on methane sorption capacity was discussed. The shale samples are found to be clay rich. The average clay content of the shale samples is 50.69% and average quartz content is 31.65%. Presence of excellent TOC content (4.8%-37.36%) with a predominance of type III organic matter and Tmax varying from 440 degrees C to 465 degrees C suggests a very good to excellent hydrocarbon generation potential in all the samples. The correlation between the TOC and V-L was found to be positive indicating a positive influence of organic matter on methane sorption capacity of the studied samples. However, a lack of correlation between total clay and CH4-V-L indicates that the role of clay minerals on methane sorption behavior of these shales are inconclusive. A positive correlation between CO2 micropore volume, CH4-V-L and TOC suggest microporous nature of organic matter within the shale samples and their positive control on methane sorption potential. The negative correlation of clay mineral with CO2 micropore volume suggests a lack of microporosity in the clay minerals of the collected shale samples. It was also observed that thermally mature shale samples have higher micropore volume and surface area, and are prone to higher methane sorption capacity compared to that of less mature shales.",23,23,2
Shale Gas,Shale Samples,"Han, Hui; Ding, Zhengang; Dong, Caiyuan; Liu, Yan; Chen, Shijia; Lu, Jungang; Xue, Yaru; Peng, Siqiao; Gao, Yuan","Fractal characteristics of bulk-mudrock, washed, and kerogen samples of Chang 7 member mudrocks from the Ordos Basin, China",Chang 7 mudrocks; Kerogen; Low-pressure gas adsorption; Fractal dimension; FHH model; Pore structure,PORE STRUCTURE CHARACTERIZATION; CAMBRIAN LUJIAPING SHALE; SILURIAN LONGMAXI SHALES; CH4 ADSORPTION CAPACITY; THRUST-FOLD BELT; GAS-ADSORPTION; LACUSTRINE SHALE; ORGANIC-MATTER; SICHUAN BASIN; SOUTHWESTERN CHINA,"We performed low-pressure N-2 physisorption experiments to investigate and compare the fractal characteristics of bulk-mudrock, washed, and kerogen samples of Chang 7 mudrocks from the Ordos Basin, China. Their fractal dimensions D were obtained from adsorption data using the Frenkel-Halsey-Hill (FHH) method. The D values for the bulk-mudrock samples were slightly lower than those of the washed samples, while the kerogen samples showed lowest values. The results suggest that the surfaces of the washed samples were rougher than the bulk-mudrock samples and that the kerogen samples had the smoothest surfaces. For the bulk-mudrock and washed samples, D decreased with increasing total organic carbon content, suggesting that organic matter has lower fractal dimension than other fractions in mudrocks. D decreased with increasing free oil, indicating that the fractal dimension can be used to characterize the residual oil content in lacustrine mudrocks approximately. For the bulk-mudrock and washed samples, there are positive trends between fractal dimension and surface area and pore volume. However, similar trends cannot been found in kerogen samples, indicating that the fractal dimensions obtained from low-pressure N-2 adsorption experiments cannot describe the fractal characteristics of the kerogen samples well. The fractal dimension decreased with the increasing average pore diameter, which can be attributed to that the samples with higher fractal dimensions contained more small pores and had higher surface area.",19,19,2
Shale Gas,Shale Samples,"Zou, Jie; Rezaee, Reza; Yuan, Yujie",Investigation on the adsorption kinetics and diffusion of methane in shale samples,Shale gas; Adsorption rate; Diffusion; Bidisperse model; Methane,PORE STRUCTURE; ORGANIC-MATTER; GAS SYSTEMS; COAL; TRANSPORT; CAPACITY; CO2; DISTRIBUTIONS; RESERVOIRS; ISOTHERMS,"Shale gas is becoming increasingly important to mitigate the energy crisis of the world. Understanding the mechanisms of gas transport in shale matrix is crucial for development strategies. In this study, methane adsorption kinetics in shale samples were measured under different pressures and temperatures. The results of methane adsorption rate were fitted by the bidisperse diffusion model. Pore structure of the shale samples were characterized by low-pressure N-2 and CO2 adsorption. The results showed that pressure has a negative effect on methane adsorption rate and diffusion, while the effect of temperature is positive. Combining the total organic carbon(TOC) and pore structure, methane adsorption rate and effective diffusivity were compared between all the shale samples. The methane adsorption rate under high pressure(50bar) is positively related to the TOC content. The micropore volume showed a moderate positive relation with the methane adsorption rate at 30bar. A weak positive relation exists between the TOC and effective diffusivity at low pressure and the effective diffusivity at low pressure shows an increasing trend with micropore(< 2 nm) volume. A hypothetic pore model is proposed: micropore in shales controls gas diffusion as pore throat which connects pores.",18,18,3
Shale Gas,Shale Samples,"Wu, Jingjing; Zhang, Shaohe; Cao, Han; Zheng, Mingming; Sun, Pinghe; Luo, Xu","Fracability evaluation of shale gas reservoir-A case study in the Lower Cambrian Niutitang formation, northwestern Hunan, China",Fracability evaluation; Northwestern Hunan; Shale gas reservoir; Lower Cambrian Niutitang; Combination weight method; Acoustic emission (AE) event,FRACTURES; BASIN,"Four main fracability-related factors, brittleness, quartz content, diagenesis and natural fracture, are analyzed for the shale in Lower Cambrian Niutitang formation, Northwestern Hunan. The quantitative evaluation of fissure ratio of shale was achieved by combining SEM technique and Image J. It shows that the Lower Cambrian Niutitang formation shale in the study area has large content of brittle minerals, high brittleness index, high degree of thermal evolution, and well developed fractures, which therefore indicate advantageous conditions for the fracturing of shale gas reservoir. In addition, a mathematical model integrates the four factors is proposed based on the combination weight method to quantitatively evaluate the fracability of the shale in the study area. It was found that the optimum area for fracturing in the study area is Xianfeng, Longshan, Sangzhi and Cili due to their relatively high fracability indexes. Also the shale fracability in this area can be divided into three levels according to the characteristics of reservoir parameters and it is suggested to select shale with fracability index above 0.4354 to be fractured. The lab hydraulic fracturing tests of the shale samples are conducted to verify the accuracy of the quantification model. The experiment results agree with the fracablity index predicted by the proposed quantification model.",16,19,6
Shale Gas,Shale Samples,"Ranjith, P. G.; Wanniarachchi, W. A. M.; Perera, M. S. A.; Rathnaweera, T. D.",Investigation of the effect of foam flow rate on foam-based hydraulic fracturing of shale reservoir rocks with natural fractures: An experimental study,Foam; Fracturing; Breakdown pressure; Flow rate; Fracture permeability; CT scanning,PERMEABILITY; PRESSURE; ENERGY; GAS; PROPAGATION,"Foam-based hydraulic fracturing has been identified as a good solution for the extraction of natural gas from deep shale reservoirs, due to its unique advantages such as low water consumption and high proppant carrying capacity. However, lack of knowledge of foam-based shale fracturing and complex nature of two-phase foam, make it challenging to use in field conditions, and one unclear area is the effect of the foam flow rate on fracturing and fracture characteristics. Therefore, the aim of this study was to investigate the effect of foam flow rate on breakdown pressure, fracture permeability and generated fracture characteristics. In order to achieve this, a series of hydraulic fracturing experiments was conducted for shale rocks with existing natural fractures, using nitrogen-based foam. Fracture permeability was also evaluated for intact and fractured rock samples. Micro-CT scanning technology was adopted to characterise the geometrical properties of fractures, in order to investigate the effect of foam flow rate within the fracture. Experimental results show that the breakdown pressure increases by 30% while energy release decreases by 78% when the foam flow rate increases from 10 to 70 ml/min. In addition, the results suggest that the permeability of a fractured sample at 10 ml/min injection rate is about 15 times higher than that of a fractured sample at 70 ml/min injection rate. The findings of this study reveal that low foam-flow rates can create a better inter-connected fracture network than higher flow rates.",15,15,4
Shale Gas,Shale Samples,"Zhou, Yu; Lei, Yafeng; Chen, Wei; Yu, Weigang",Enhance low temperature oxidization of shale gas recovery using hydrogen peroxide,Shale; Organic matter; Hydrogen peroxide; Pyrolysis; Pore,ORGANIC-MATTER; PORE STRUCTURE; OIL-SHALE; SODIUM-HYPOCHLORITE; MINERAL MATRIX; ORDOS BASIN; TG-FTIR; PYROLYSIS; CHINA; COMBUSTION,"Gas extraction from shale has been challenging due to extremely low permeability in shale formations. Recently, high temperature treatment methods were introduced to remove organic matters from shale to increase shale pore diameter and reservoir permeability. In this study, hydrogen peroxide was used as oxidizer to react with organic matters in shale samples for 6, 12, 24, and 48 h, respectively. X-ray diffraction (XRD) tests were employed to study the mineral compositions. Then, thermal decomposition experiments of shale samples were also conducted by the combined Thermogravimetry-Fourier transform infrared spectroscopy (TG-FTIR) technique to analyze the weight loss behaviors and gas emission in N-2 environment during pyrolysis. Afterwards, the effect of pyrolysis and reaction duration on pore diameter were investigated by liquid nitrogen adsorption and desorption tests. Finally, scanning electron microscopy (SEM) images of the shale samples were analyzed to reveal pore structure change on the surface of shale samples. From the experiments, it was found that the organic matters could react with H2O2 at ambient temperature and pore diameter increased with reaction time. The mean pore diameter increased by 40% when samples were treated with H2O2 for 48 h. More larger pores were observed on the surface of both pyrolyzed and H2O2 treated shale samples from the SEM images. Moreover, the pyrolyzed samples have larger pores compared to the H2O2 treated samples due to the decomposition of minerals at high temperature.",14,16,2
Shale Gas,Horizontal Wells,"Hou, Bing; Zhang, Ruxin; Zeng, Yijin; Fu, Weineng; Muhadasi, Yeerfulati; Chen, Mian",Analysis of hydraulic fracture initiation and propagation in deep shale formation with high horizontal stress difference,Hydraulic fracture; Complex fracture network; Discontinuities; Pump rate; AE monitoring,GAS-RESERVOIRS; BEHAVIOR; ROCK,"Deeply buried shale formations (vertical depth > 3500 m) that are rich in shale gas are abundant in south China. The primary problems in the exploitation of these formations are the relatively small stimulated reservoir volume (SRV) and low production rates in comparison with their shallower counterparts. These issues are attributed to the high fracturing pressure, limited fracture extension because of sand plugging, significant horizontal stress contrast, and discontinuities produced during hydraulic fracturing. To accurately evaluate and improve the SRV in deep shale formations, the mechanism of fracture propagation must be understood and described. In this regard, a series of large-scale true tri-axial experiments with acoustic emission (AE) monitoring were conducted to characterize the fracture initiation and propagation in a selected deep shale formation. It was found that the difficulty in the complex fracture network formation was because the high stress contrast controls the fracture propagation path to generate large main fractures instead of activating discontinuities. The hydraulic fractures initiated either from open-hole positions or stress concentration locations on a wellbore wall that displayed two types of intersection in terms of crossing and deflection. In general, four types of fracture morphologies were identified: transverse fracture, transverse fracture with bedding planes, natural fracture with bedding planes, and transverse fracture with bedding planes and natural fractures. In addition, the horizontal stress contrast, fluid viscosity, pump rate and fracturing procedure on fracture propagation were evaluated for their effect on the resulting SRV. A low-viscosity fluid can activate discontinuities to form a complex fracture network, whereas a high-viscosity fluid is likely to produce large fractures under a high contrast in the horizontal stresses. On the basis of the above-mentioned analyses, a fracturing procedure applying a periodically varying pump rate and shut-in using a low-viscosity fluid was suggested to be an effective approach to enhance the interaction between the hydraulic fractures and discontinuities as well as to increase the fracture length.",58,65,4
Shale Gas,Horizontal Wells,"Liu, Liyuan; Zhu, Wancheng; Wei, Chenhui; Elsworth, Derek; Wang, Jiehao",Microcrack-based geomechanical modeling of rock-gas interaction during supercritical CO2 fracturing,Supercritical CO2 fracturing; Gas adsorption; Internal swelling stress; Rock damage; Numerical simulation,SHALE GAS; CARBON-DIOXIDE; HORIZONTAL WELLS; COAL; PERMEABILITY; PROPAGATION; ADSORPTION; CHALLENGES; CAPTURE; SCALE,"Relative to water-based fluids, non-aqueous fracturing fluids have the potential to increase production, reduce water requirements, and to minimize environmental impacts. Since the viscosity of supercritical CO2 is one-tenth that of water, its density is close to that of water, and is capable of promoting sorptive rejection of methane, it is an attractive substitute for water in the extraction of shale gas and coalbed methane. The following defines a geomechanical model accommodating the interaction of fluid flow, adsorption-induced swelling stress, solid deformation and damage to quantify rock-gas interactions during supercritical CO2 fracturing for shale gas production. The architecture of the shale is accommodated that includes both pore-and micro-crack-based porosity. According to the microcrack model representing shales with low porosity, both analytical and numerical results show that the effective stress coefficient is much smaller than unity. We analyze the potential advantages of fracturing using supercritical CO2 including enhanced fracturing and fracture propagation, increased desorption of methane adsorbed in organic-rich portions of the shale and the potential for partial carbon sequestration. Rock-gas interactions include both the linear poroelastic response and the chemo-mechanical interaction due to sorption. Simulation results demonstrate that supercritical CO2 fracturing indeed has a lower fracture initiation pressure and a significantly lower breakdown pressure, as observed in experiments, and that fractures with greater complexity than those developed with liquid CO2 and water fracturing result. With increasing dynamic viscosity of the fracturing fluids, the predicted breakdown pressure also increases, consistent with experimental observations.",40,43,8
Shale Gas,Horizontal Wells,"Zhang, Yushuai; Zhang, Jincai; Yuan, Bin; Yin, Shangxian",In-situ stresses controlling hydraulic fracture propagation and fracture breakdown pressure,Hydraulic fracture; In-situ stresses; Horizontal stress; Breakdown pressure; Depletion; Fracture curving,INSITU STRESSES; WELLS; PREDICTION; BOREHOLE; RESERVOIRS; MAGNITUDE; ROCKS; FLOW,"In-situ stress impact on hydraulic fracturing is investigated to enhance hydraulic fracturing performance. Lithology-controlled lower and upper bounds of the horizontal stresses are proposed, and an improved stress polygon method is presented. This improved method can narrow the area of the conventional stress polygon, particularly in shales; therefore, constrain the in-situ stress estimate. The lithology-controlled stresses indicate that a shale has a higher minimum horizontal stress and can be used as a barrier of the hydraulic fracture propagation when hydraulic fracturing is performed in adjacent sandstones. However, when hydraulic fracturing is performed in a shale oil or gas formation, a stress-barrier formation may not exist on the top or the bottom of the shale reservoir, and this will cause the hydraulic fractures to propagate out of the reservoir zone. We also examine the effects of the maximum and minimum horizontal stresses, shear stresses and depletion on the fracture initiation, breakdown, propagation and containment. Shear stresses cause hydraulic fractures kinking; from this evidence, we find that a horizontal well can be drilled with a certain angle to the minimum stress direction because in most cases the hydraulic fractures eventually curve to the maximum stress direction. In addition, we propose a new method to calculate the fracture breakdown pressure based on fracture mechanics. The proposed method predicts a higher breakdown pressure than the conventional one, which may better estimate the breakdown pressure.",38,40,3
Shale Gas,Horizontal Wells,"Xi, Yan; Li, Jun; Liu, Gonghui; Cha, Chunqing; Fu, Yongqiang",Numerical investigation for different casing deformation reasons in Weiyuan-Changning shale gas field during multistage hydraulic fracturing,Volume fracturing; Casing deformation; Numerical calculation; Lithologic interface; Cement void; Formation slipping,UNCONVENTIONAL RESERVOIRS; HORIZONTAL WELLS; FINITE-ELEMENT; DESIGN; VOLUME; PRESSURE; WEAR,"Casing deformation has been found to be a very significant issue in the development process of shale gas in China. The rate of casing deformation is 34.34% (34 wells of 101), and statistical data show that it decreased the test output of wells by approximately 30%. Based on investigation and analysis of the engineering and geological conditions of 25 wells, 12 of which have casing deformations, both physical models and finite element models were established. Furthermore, the effects of fracturing pressure, geostress, anisotropy, lithologic interface, temperature variation, and cement void were analyzed. The results show the following. a) When the casing deformation points appear far away from point A (the landing point, which is the starting point of the horizontal segment), the influence of the lithologic interface on casing stress plays a decisive role under the combined effect of internal and external pressures when the cement sheath is completed. b) Under the same conditions, but when the casing is in contact with the borehole wall near the bottom because of gravity, a narrow fluid retention space was formed, leading to cementing sheath voids. The effect of cement void pressure reduction is the main reason behind the casing deformation. c) When casing deformation points appear near point A, the activation of the weak plane in the beddings during fracturing causes the casing deformation. The stress of 14 casing deformation points was calculated according to actual engineering and geological conditions, and 78.6% of the results were consistent with field measurements.",35,41,3
Shale Gas,Horizontal Wells,"Ren, Lan; Lin, Ran; Zhao, Jinzhou; Rasouli, Vamegh; Zhao, Jiangyu; Yang, Hao",Stimulated reservoir volume estimation for shale gas fracturing: Mechanism and modeling approach,Hydraulic fracturing; Stimulated reservoir volume; Fractures propagation; Shale gas; Mathematical model,HYDRAULIC FRACTURE; HORIZONTAL WELL; PROPAGATION; PERMEABILITY,"Multi-stage fracturing, following horizontal well drilling, is the key technology in shale gas reservoir development to enhance the recovery from such tight formations for economic production. The stimulated reservoir volume (SRV), which correlates closely to fracturing performance, is a quantitative measure for both pre-fracturing design and post-fracturing evaluation. However, an accurate estimation of the SRV is a long-standing challenge, because it requires a great knowledge of various parameters and complex mechanisms. In this study, we developed a mathematical model to estimate the SRV through simulating the main process during shale fracturing-multiple simultaneous hydraulic fractures propagate, perturbing the formation stress and raising the reservoir pressure; meanwhile, the stress change and pressure rise may jointly make natural fractures occur failure, and the SRV is estimated based on the volume of the naturally fractured zone that experiences tensile or shear failure. Hybrid numerical methods have been employed in this study. It applies displacement discontinuity method (DDM) to simulate non-planar hydraulic fractures propagation and represent the induced stress triggered by hydraulic fractures. The reservoir pressure is calculated by finite difference method (FDM). The failure state of natural fractures is predicted by the tensor equations deduced from Warpinski's failure theory. The model considers complex but important physical mechanisms that involved in the shale fracturing, including unequal flowrate distribution among each hydraulic fracture, non-planar hydraulic fractures propagation under stress interference, reservoir permeability increase with SRV extending (pressure & stress-depend), different failure states of natural fractures, etc. We validated our model by comparing its simulation results with analytical solution, published papers and onsite microseismic monitoring data. A field case study was performed to show the dynamic processes of hydraulic fractures propagation, reservoir permeability increase, and the SRV expansion during shale gas fracturing. Sensitivity analysis was conducted to investigate the influence of geological condition and fracturing parameters on SRV.",29,30,3
Shale Gas,Horizontal Wells,"Teklu, Tadesse Weldu; Li, Xiaopeng; Zhou, Zhou; Alharthy, Najeeb; Wang, Lei; Abass, Hazim",Low-salinity water and surfactants for hydraulic fracturing and EOR of shales,Low-salinity water; Low-salinity water plus srufactnat; Osmosis; Capillary pressure; Wettability alteration; IFT decrease; Hydraulic fracturing and EOR of shales,OIL-RECOVERY; UNCONVENTIONAL RESERVOIRS; IMBIBITION; WETTABILITY; TRANSPORT,"There are significant recoverable oil and gas resources stored in shale reservoirs throughout the world. Horizontal well with multistage hydraulic fracturing is an enabling technology for economic production of these shale resources. Recovery factors of liquid rich shale reservoirs is typically less than 10%, hence, there is an incentive for implementing enhanced oil recovery (EOR) technologies to improve oil production from these very tight reservoirs. Brine, chemical (surfactant), gas, or combination of these fluids imbibition or injection in huff-n-puff scenario could improve oil recovery of liquid rich shale reservoirs. In this study, low-salinity water and low-salinity water + surfactant imbibition are assessed as both hydraulic fracturing and EOR fluids in liquid rich shale reservoirs. Osmosis, capillary pressure, wettability alteration, and other effects are among the mechanisms by which these fluids can improve oil recovery from shale reservoirs. These favorable effects were investigated through imbibition experiments. Experiments show: (a) low-salinity water huff-n-puff in tight formations can improve oil production from tight formations. This is because wettability alteration, capillary, and osmotic forces; (b) surfactant + low-salinity-water huff-n-puff can further improve oil production due to additional IFT decrease and wettability alteration by surfactants; hence, improve oil production from stimulated ultra-tight formations. Based on experimental observations and literature reviewed, low-salinity water huff-n-puff (until economical), followed by low-salinity water + surfactant huff-n-puff EOR process is recommended to optimize production from liquid rich shale reservoirs, while minimizing cost. These fluids can be used to reduce matrix-fracture skin damage. The effectiveness of these hydraulic fracturing and EOR fluids in shales is highly dependent on the existence and extent of natural fractures or laminations within the stimulated reservoir volume; this is because osmosis and diffusion are very slow processes.",27,29,7
Shale Gas,Horizontal Wells,"Kenomore, Michael; Hassan, Mohamed; Malakooti, Reza; Dhakal, Hom; Shah, Amjad",Shale gas production decline trend over time in the Barnett Shale,Estimated ultimate recovery; Barnett shale; Arp's hyperbolic; Doung's method; Modified hyperbolic,,"Natural gas produced from shale formations in the United States over the past decade have altered the oil and gas industry remarkably. The Barnett shale was at the forefront of the shale gas revolution in the United States and was considered to be the highest producing natural gas field in the United States until 2012, yielding the top producer spot to the Marcellus shale. Due to the uncertainty regarding the accurate determination of Estimated Ultimate Recoverable (EUR) in shale gas reservoirs, this paper aims to assess EUR values for the Barnett shale using empirical decline curve methods like the Arp's hyperbolic, Modified Arp's hyperbolic and Doung's method. In addition, we investigated the economic viability of wells over time in the Barnett under various probabilities of success. Throughout this paper, reference is made to two key publications where a similar work was carried out for various shale plays in the United States, including the Barnett shale - though only the Arp's hyperbolic decline was employed. The dataset in this paper consisted of more horizontal wells from covering more counties within the Barnett shale compared to other similar studies. We conclude that either the Arp's hyperbolic or Doung's method can be used to forecast EUR in the Barnett shale as only marginal differences were observed. This is on the basis that production history exceeds 10 months (a maximum of 80 months production history was used). We also obtained reliable and conservative estimates of EUR compared to previous studies.",23,23,5
Shale Gas,Horizontal Wells,"AlTwaijri, Mohammad; Xia, Zhaohui; Yu, Wei; Qu, Liangchao; Hu, Yunpeng; Xu, Yifei; Sepehrnoori, Kamy",Numerical study of complex fracture geometry effect on two-phase performance of shale-gas wells using the fast EDFM method,Shale gas; Complex fractures; Natural fractures; Two-phase flow; Water flowback,WATER; SIMULATION; TRANSPORT; RESERVOIR; MODEL; FLOWBACK; OIL,"Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced ( hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of local grid refinement approach, hydraulic fractures are assumed to be planar ( orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational resources. In this paper, we introduce an embedded discrete fracture model (EDFM) to explicitly model complex fracture geometries. The EDFM efficient approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, we constructed a 3D reservoir model to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In our investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set of natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of nonorthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells.",23,23,3
Shale Gas,Horizontal Wells,"Wang, HanYi",Discrete fracture networks modeling of shale gas production and revisit rate transient analysis in heterogeneous fractured reservoirs,Discrete fracture network (DFN); Shale gas production; Rate transient analysis (RTA); Complex fracture networks; Naturally fractured reservoirs; Heterogeneous reservoirs,WELL PRODUCTION; LINEAR FLOW; PERMEABILITY; SLIPPAGE; BEHAVIOR; IMPACT,"Horizontal wells with multiple hydraulic fractures are necessary stimulation technique for economically developing tight and shale gas reservoirs. In such reservoirs, the conventional well-test techniques are not suitable because of ultralow formation permeability. Rate transient analysis (RTA) is the widely used tool for analyzing these reservoirs for the purpose of reserves estimation, hydraulic fracture stimulation optimization, and development planning. However, the conventional rate transient analysis is based on the models that were derived from idealistic assumptions for homogenous reservoirs. In this article, we first review the industry's common practice for rate transient analysis and discuss why the idealized conceptual model may not be adequate for analyzing production data from shale gas reservoirs. Then, a unified shale gas reservoir model based on Discrete Fracture Networks (DFN) is presented to investigate how each mechanism influences shale gas production and the corresponding rate transient behavior. It is found that shale gas production and rate transient behavior are significantly impacted by reservoir heterogeneity, fracture networks, non-Darcy flow, gas adsorption and completion efficiency. Short early-time linear flow with long transitional flow period is an indication of either existence of abundant complex fracture networks or heterogeneous completion with unevenly distributed hydraulic fractures. Consider the nature of non-unique results of RTA, information from other independent sources is required to achieve a consistent and holistic interpretation.",23,23,2
Shale Gas,Horizontal Wells,"Yin, Fei; Han, Lihong; Yang, Shangyu; Deng, Yong; He, Yongming; Wu, Xingru",Casing deformation from fracture slip in hydraulic fracturing,Casing integrity; Hydraulic fracturing; Shale gas well; Shear slip,HORIZONTAL WELLS; SIMULATION; FAILURE,"Casing failure during hydraulic fracturing is infrequent, but its consequence and impact can be significant for the shale gas wells. It may result in inaccessible cased hole and environmental and safety concerns over wellbore integrity during the shale gas reservoir development. Based on theoretical analysis, numerical simulation and field measurement, the failure mechanisms of casings in shale gas wells are revealed. Through parametric sensitivity analysis, the countermeasures are recommended. Results indicate that one of the casing failure mechanisms in shale gas wells is shear deformation induced by the slip of shear fractures. The simulated casing deformation is consistent with the lead impression. Casing curvature is introduced to assess the traveling capability and casing integrity. The maximum curvature is significantly larger than that of normal directional borehole, which causes the resistance of downhole tools passing through casing. Decreasing the crossing angle and employing the cement with a low Young's modulus or even no cementing can be the effective measures to prevent casing failure in this mode. The research findings provide new evaluation criterion and controlling methods for casing integrity in shale gas wells under hydraulic fracturing.",21,25,2
Shale Gas,Horizontal Wells,"Pei, Shufeng; Wang, Yanyong; Zhang, Liang; Huang, Lijuan; Cui, Guodong; Zhang, Panfeng; Ren, Shaoran",An innovative nitrogen injection assisted in-situ conversion process for oil shale recovery: Mechanism and reservoir simulation study,In-situ conversion process; Nitrogen injection; Oil shale; Reservoir numerical simulation; Kerogen pyrolysis,HEAVY OIL; CRACKING; MODEL,"In-situ conversion process (ICP) can be an effective technique for the development of oil shale and ultra heavy oils, in which kerogen or heavy components will be cracked into light oils and gases via underground heating and pyrolysis, and the retorted oil can be recovered via conventional extraction techniques. Heating of targeted formation can be conducted using electrical heaters installed in vertical or horizontal wells, while a slow heating rate and lack of driving energy for oil production are the main issues of the conventional in-situ conversion process. In this study, an innovative nitrogen injection assisted in-situ conversion process (NAICP) was proposed to increase formation heating rate and improve oil production from oil shale. Reaction models of kerogen pyrolysis at elevated temperature were established, along with models for the evolution of porosity and permeability of oil shale formation during the pyrolysis process. The performance of nitrogen injection on the effectiveness of the ICP was then investigated through reservoir numerical simulation. The simulation results show that additional nitrogen injection can improve the heating rate of the oil shale formation, enhance oil production and energy efficiency in comparison with the conventional ICPs, which can be attributed to enhanced heat convection, pressurization effect and gas driving mechanism. Nitrogen injection assisted in-situ conversion process can be a promising technique for the exploitation of oil shale.",19,21,9
Shale Gas,Horizontal Wells,"Zhou, Jun; He, Shiming; Tang, Ming; Huang, Zhen; Chen, Yulin; Chi, Jun; Zhu, Yu; Yuan, Ping",Analysis of wellbore stability considering the effects of bedding planes and anisotropic seepage during drilling horizontal wells in the laminated formation,Anisotropic seepage; Bedding plane; Weak plane; Horizontal well; Wellbore stability,TRANSVERSELY ISOTROPIC MEDIUM; BOREHOLE STABILITY; INCLINED BOREHOLE; ACOUSTIC-EMISSION; SHALE ROCK; MODEL; PERMEABILITY; RESERVOIR; STRESS; FLOW,"With the exploration and development of gas shale in recent years, layer structures (bedding planes) of laminated rock and its effects on mechanical properties of rock and wellbore stability have arisen great attention. In this paper, we mainly concerns the wellbore stability during drilling horizontal wells in the laminated formation with horizontal bedding planes, meanwhile, the effects of anisotropy of permeability paralleled to bedding planes and that perpendicular to bedding planes are taken into consideration as well. Models of pore pressure distribution and seepage stresses under anisotropic seepage are established. Combining the effects of anisotropic seepage and bedding planes, we have investigated the equivalent collapse density (ECD) around horizontal wellbores. The results based on the input data in this paper reveal that the ECD considering the weakness of bedding planes is far higher than that without considering bedding planes, and the shape of zones where surrounding rock is relatively easier to collapse is similar as two couples of cat ears. The point where ECD reaches its maximum value tends to move from wellbore wall to internal rock if drilling close to the direction of minimum in-situ stress, and the higher anisotropic permeability ratio is, the more obvious the phenomenon is. The effect of anisotropic seepage can be ignored if the weakness of bedding planes is omitted, it otherwise can not be left out and the maximum ECD around wellbore instead of the maximum value at wellbore wall should be used to design for drilling operation. This study simultaneously investigates the effects of anisotropic seepage and weak bedding planes on wellbore stability during drilling horizontal wells, it is promising to provide a theoretical basis and practical guidance for the further researches on wellbore stability in future.",19,19,3
Shale Gas,Horizontal Wells,"Wang, J. G.; Hu, Bowen; Liu, Hua; Han, Yue; Liu, Jia",Effects of 'soft-hard' compaction and multiscale flow on the shale gas production from a multistage hydraulic fractured horizontal well,Three-zone model; Dual-porosity medium zone; Multiscale flow mechanism; 'Soft - hard' model; Fracture aperture,MISSISSIPPIAN BARNETT SHALE; APPARENT PERMEABILITY; POROUS-MEDIA; MODEL; RESERVOIRS; STRAIN; SIMULATION; DESORPTION; EVOLUTION; DIFFUSION,"In this study, the shale gas production from a multistage hydraulic fractured shale gas reservoir was analyzed. Firstly, the reservoir was divided into single-porosity medium zone, dual-porosity medium zone, and hydraulic fracture zone. Then, a mathematical model was established for the multiscale gas diffusion and adsorption/desorption mechanisms in matrix, the gas flow in fractures and the interaction between gas flow and shale deformation. Thirdly, this mathematical model was numerically solved within the platform of Comsol Multiphysics and verified by the history matching of the gas production data from Barnett and Marcellus shale reservoirs. Finally, sensitivity study was conducted to identify key parameters to the efficiency of gas recovery enhancement. It is found that hydraulic fracture aperture and initial permeability of fractures are positively correlated with gas production rate. The 'soft - hard' compaction of fractures can significantly modify gas production rate but the modification varies with gas production stage. The deformation and flow properties of hydraulic fractures have significant impacts on gas production rate, particularly in the early stage.",18,19,8
Shale Gas,Horizontal Wells,"Liu, Jingshou; Ding, Wenlong; Wang, Ruyue; Yang, Haimeng; Wang, Xinghua; Li, Ang",Methodology for quantitative prediction of fracture sealing with a case study of the lower Cambrian Niutitang Formation in the Cen'gong block in South China,Fracture sealing; Shale reservoir; Paleotectonic stress field; Lower Cambrian; Cen'gong block,PALEOTECTONIC STRESS-FIELDS; SHALE-GAS; PRESERVATION CONDITIONS; CRUSTAL DEFORMATION; NATURAL FRACTURES; NORTHERN GUIZHOU; BASIN; RESERVOIRS; SIMULATION; DEPRESSION,"Industrial levels of shale gas have been produced from the Niutitang Formation in the lower Cambrian of the Cen'gong block, South China. The practice of exploration and development of shale gas in the Cen'gong block shows that the abundance of gas in different layers and wells is closely related to the degree of development of fractures. In this study, data obtained from outcrops, cores, and thin sections from the Cen'gong block were used to determine the development characteristics of such natural fractures. Combined with the analysis of burial history and fluid inclusions, the stress fields during three periods (the Yanshanian period, Himalayan period and neotectonic period) are suspected to play a critical role in fracture sealing. The paleotectonic stress tensor is determined using fault activity analysis, acoustic emission tests, and burial history. The magnitude and direction of current in situ stresses are determined by drilling-induced fractures, deviated well information, and cross multipole array acoustic (XMAC) logging. Under the constraints of XMAC logging interpretation and mechanical experiments, the spatial distribution of mechanical parameters is obtained by seismic inversion, and 3D heterogeneous geomechanical models are established using a finite element method (FEM). Then, the fracture density, reactivity, and aperture are identified. The results show that the magnitudes of the maximum horizontal principal stress during the Yanshanian period, the Himalayan period, and the neotectonic period are 150-170 MPa, 110-130 MPa, and 35-45 MPa, respectively. Using the fracture sealing calculation model, the fracture sealing that developed in the Himalayan period is the worst, the fracture sealing that developed in the Yanshanian period is intermediate, and the fracture sealing that developed in the neotectonic period is the best. Based on three-dimensional heterogeneous geomechanical modeling and tectonic stress evolution estimates, the fracture sealing calculation model proposed in this paper can be widely used in the evaluation of the preservation conditions of shale reservoirs, tight sandstone reservoirs and low-permeability reservoirs in complex tectonic areas.",14,15,2
Shale Gas,Fracture Network,"Rui, Zhenhua; Cui, Kehang; Wang, Xiaoqing; Lu, Ju; Chen, Gang; Ling, Kegang; Patil, Shirish",A quantitative framework for evaluating unconventional well development,Unconventional well; Well evaluation; Quantitative framework; Factor analysis; Well complexity; Drilling performance,COMPLEX FRACTURE NETWORKS; TIGHT OIL-RESERVOIRS; HYDRAULIC FRACTURE; COST ESTIMATION; GAS-RESERVOIRS; SHALE; PIPELINE; MODEL; SIMULATION; PRODUCTIVITY,"Gaining a better understanding and measuring unconventional well complexity are vital to developing an oil and gas field successfully. However, there is a lack of quantitative assessment framework for evaluating unconventional wells. This paper created an index evaluation system to assess unconventional well readiness for development, which considers the various well characteristics. The unconventional well complexity index is calculated using five major level-1 elements, and the weight of each sub-element was calculated using the factor analysis statistical method. The well evaluation system was applied to evaluate 20 unconventional well programs for their readiness for development; the evaluation results were analyzed in terms of well complexity distribution and the relationship between unconventional well complexity and duration performance. Recommendations for dealing with various unconventional well complexity were also proposed. The evaluation framework was also verified to be an efficient method for assessing unconventional well development readiness.",82,82,7
Shale Gas,Fracture Network,"Hou, Bing; Zhang, Ruxin; Zeng, Yijin; Fu, Weineng; Muhadasi, Yeerfulati; Chen, Mian",Analysis of hydraulic fracture initiation and propagation in deep shale formation with high horizontal stress difference,Hydraulic fracture; Complex fracture network; Discontinuities; Pump rate; AE monitoring,GAS-RESERVOIRS; BEHAVIOR; ROCK,"Deeply buried shale formations (vertical depth > 3500 m) that are rich in shale gas are abundant in south China. The primary problems in the exploitation of these formations are the relatively small stimulated reservoir volume (SRV) and low production rates in comparison with their shallower counterparts. These issues are attributed to the high fracturing pressure, limited fracture extension because of sand plugging, significant horizontal stress contrast, and discontinuities produced during hydraulic fracturing. To accurately evaluate and improve the SRV in deep shale formations, the mechanism of fracture propagation must be understood and described. In this regard, a series of large-scale true tri-axial experiments with acoustic emission (AE) monitoring were conducted to characterize the fracture initiation and propagation in a selected deep shale formation. It was found that the difficulty in the complex fracture network formation was because the high stress contrast controls the fracture propagation path to generate large main fractures instead of activating discontinuities. The hydraulic fractures initiated either from open-hole positions or stress concentration locations on a wellbore wall that displayed two types of intersection in terms of crossing and deflection. In general, four types of fracture morphologies were identified: transverse fracture, transverse fracture with bedding planes, natural fracture with bedding planes, and transverse fracture with bedding planes and natural fractures. In addition, the horizontal stress contrast, fluid viscosity, pump rate and fracturing procedure on fracture propagation were evaluated for their effect on the resulting SRV. A low-viscosity fluid can activate discontinuities to form a complex fracture network, whereas a high-viscosity fluid is likely to produce large fractures under a high contrast in the horizontal stresses. On the basis of the above-mentioned analyses, a fracturing procedure applying a periodically varying pump rate and shut-in using a low-viscosity fluid was suggested to be an effective approach to enhance the interaction between the hydraulic fractures and discontinuities as well as to increase the fracture length.",58,65,4
Shale Gas,Fracture Network,"Chen, Zhiqiang; Yang, Zhengming; Wang, Moran",Hydro-mechanical coupled mechanisms of hydraulic fracture propagation in rocks with cemented natural fractures,Hydraulic fracture; Cemented fracture; Natural fracture; LBM-DEM,LATTICE-BOLTZMANN METHOD; GENERAL SHAPES; BARNETT SHALE; FLUID-FLOW; PERMEABILITY; MODEL; DISCONTINUITIES; CRITERION,"Natural fractures commonly exist in unconventional reservoirs such as shale and tight gas sandstone, which are mostly cemented (or sealed) with minerals and not able to contribute to reservoir storage or rock permeability. However, during hydraulic fracture stimulation, these cemented natural fractures will be encountered and influence hydraulic fracture geometry greatly and, thereby, gas production. In this work, hydraulic fracture propagation in rock with cemented natural fracture is investigated using our recently developed and validated hydromechanical coupled LBM-DEM model. The numerical results show that both the strength ratio (between cemented natural fracture and host rock) and the approach angle (between hydraulic and cemented natural fracture) significantly affect the hydraulic fracture propagation. A larger strength contrast or a smaller approach angle will be more conducive to deflection, which is consistent with experimental observation. For rocks with weakly cemented natural fractures, deflection is mainly caused by shear failure in weakly cemented fracture. However, for rocks with strongly cemented natural fractures, deflection happens accompanying with tensile failure in host rock along the cement wall, which cannot be captured by the previous numerical models where the cemented natural fracture is treated as a bonded interface. In addition, complex fracture network is more easily formed if multiple weakly cemented natural fractures are orthogonal to the hydraulic fracture propagation direction.",31,32,3
Shale Gas,Fracture Network,"Wang, HanYi",Discrete fracture networks modeling of shale gas production and revisit rate transient analysis in heterogeneous fractured reservoirs,Discrete fracture network (DFN); Shale gas production; Rate transient analysis (RTA); Complex fracture networks; Naturally fractured reservoirs; Heterogeneous reservoirs,WELL PRODUCTION; LINEAR FLOW; PERMEABILITY; SLIPPAGE; BEHAVIOR; IMPACT,"Horizontal wells with multiple hydraulic fractures are necessary stimulation technique for economically developing tight and shale gas reservoirs. In such reservoirs, the conventional well-test techniques are not suitable because of ultralow formation permeability. Rate transient analysis (RTA) is the widely used tool for analyzing these reservoirs for the purpose of reserves estimation, hydraulic fracture stimulation optimization, and development planning. However, the conventional rate transient analysis is based on the models that were derived from idealistic assumptions for homogenous reservoirs. In this article, we first review the industry's common practice for rate transient analysis and discuss why the idealized conceptual model may not be adequate for analyzing production data from shale gas reservoirs. Then, a unified shale gas reservoir model based on Discrete Fracture Networks (DFN) is presented to investigate how each mechanism influences shale gas production and the corresponding rate transient behavior. It is found that shale gas production and rate transient behavior are significantly impacted by reservoir heterogeneity, fracture networks, non-Darcy flow, gas adsorption and completion efficiency. Short early-time linear flow with long transitional flow period is an indication of either existence of abundant complex fracture networks or heterogeneous completion with unevenly distributed hydraulic fractures. Consider the nature of non-unique results of RTA, information from other independent sources is required to achieve a consistent and holistic interpretation.",23,23,2
Shale Gas,Fracture Network,"Shimizu, Hiroyuki; Ito, Takatoshi; Tamagawa, Tetsuya; Tezuka, Kazuhiko",A study of the effect of brittleness on hydraulic fracture complexity using a flow-coupled discrete element method,Tight reservoir; Hydraulic fracturing; Brittleness; Discrete element method; Pre-existing fracture,PARTICLE-SIZE; MODEL; ROCK; STRESS; MECHANICS; SHALE,"In recent years, hydraulic fracturing has emerged as an important technique for the development of unconventional tight gas and oil reservoirs, particularly shale reservoirs. Production from a tight reservoir requires hydraulic creation of a highly fractured network for significantly improving the hydraulic conductivity of the reservoir. Field observations have empirically indicated that fracture complexity tends to be higher in the case of higher rock brittleness which is defined as the combination of the Young's modulus and Poisson's ratio of a rock. The brittleness is considered as one of the most important mechanical rock properties of unconventional tight reservoirs. However, the physical relationship between fracture complexity and the brittleness remains unclear. In this study, a series of hydraulic fracturing simulations were performed using a flow-coupled discrete element method to gain insights into the effect of the brittleness on fracture propagation. The brittleness was adjusted under different combinations of Young's modulus and Poisson's ratio for four rock models. Considering mechanical rock properties and pre-existing fractures, the effective stress in the case of lower brittleness reduced to the tension only around the tip of the hydraulic and pre-existing fractures. On the contrary, the tensile region was more widely distributed along the pre-existing fracture in the case of higher brittleness. The effective tensile stress in a wider region should induce more microcracks, thereby enhancing the possibility of the hydraulic fracture branching off from the pre-existing fracture. These considerations indicate a positive correlation between the brittleness and the complexity of a hydraulically induced fracture system.",21,23,2
Shale Gas,Fracture Network,"Hasham, Aleem A.; Abedini, Ali; Jatukaran, Arnav; Persad, Aaron; Sinton, David",Visualization of fracturing fluid dynamics in a nanofluidic chip,Fracturing fluid; Infiltration; Entrapment; Recovery; Nanofluidic,MICROFLUIDICS-BASED MEASUREMENT; PORE-SCALE ANALYSIS; SPONTANEOUS IMBIBITION; OIL-RECOVERY; GAS SHALES; HEAVY OIL; CO2; TEMPERATURE; PRESSURE,"Hydraulic fracturing is responsible for remarkable production from shale and tight formations, albeit at the cost of significant water usage. The flow dynamics of oil and fracturing fluid in nanopores remains largely uncharacterized, in part due to the challenge of conducting experiments at nanoscales. In this paper, we demonstrate a nanofluidic-based approach to visualize the fluid displacement during hydraulic fracturing. Nanoporous silicon-glass chips with circular and square grain shapes and identical depth of 175 nm were fabricated using reactiveion etching (RIE) and anodic bonding. Leveraging the inherent fluorescence property of the oil, the fluorescence microscopy was used to record the dynamics of the fluid displacement inside the chip. Performance of three different fracturing fluids - deionized water, potassium chloride (KCl) solution, and slick water - were evaluated based on the volumetric infiltration in the nanoporous network, entrapment of fracturing fluid in the porous media, and total production during drawdown. The KCl solution had the highest infiltration rate (fill factor of 0.68) and the lowest entrapment factor (0.39), resulting in the highest fracturing fluid recovery representing 43% in the square grain geometry with similar results for circular grains. With the fast quantification and ease of operation here, the nanofluidic approach enables a rapid screening of different fracturing fluids to inform shale oil operators.",20,21,3
Shale Gas,Fracture Network,"Yan, Bicheng; Mi, Lidong; Wang, Yuhe; Tang, Hewei; An, Cheng; Killough, John E.",Multi-porosity multi-physics compositional simulation for gas storage and transport in highly heterogeneous shales,Shale gas reservoir; Compositional simulation; Non-darcy flow mechanism; Triple-porosity model; Discrete fracture network model; Upscaling; Connectivity,DISCRETE-FRACTURE MODEL; RESERVOIR SIMULATION; METHANE ADSORPTION; APERTURE; BEHAVIOR,"Shale gas reservoir is comprised of highly heterogeneous porosity systems including hydraulic/secondary fractures, inorganic and organic matrix. Multiple non-Darcy flow mechanisms in the shale matrix further bring challenges for modeling. In this paper, we developed a framework combining a multi-physics compositional simulator with Multi-Porosity Modeling preprocessor for gas storage and transport in shale. A Triple-Porosity Model is used to characterize the three porosity systems in shale gas reservoirs. In the fracture porosity the heterogeneous impact of secondary fractures distribution on matrix-to-fracture fluid transfer is revealed by shape factor distribution. They are upscaled with superior accuracy from a detailed Discrete Fracture Network Model (DFN) sector model, where orthogonal hydraulic fractures are explicitly discretized. With the occurrence of nanopores in shale matrix, the interaction between pore-wall and gas molecules is considered via Knudsen diffusion and gas slippage. Gas adsorption on the pore-wall of organic matrix is modeled by extended Langmuir isotherm. The inter-porosity and intra-porosity connectivities in the Triple-Porosity Model are flexibly controlled by arbitrary connections. Our results show that gas production in the Triple-Porosity Model with shape factor upscaled from DFN exhibits different production performance from models with uniform shape factor distribution. The deviations are caused by the dominance of different regions at different production periods. Connection topology in the shale gas reservoir is also comprehensively assessed. We demonstrate that the intra-porosity connections in the inorganic and organic matrix have negligible impact on the global gas flux, while the inter-porosity connections have different levels of importance for the gas production. Moreover, different combinations of flow and storage mechanisms are investigated. We show that Langmuir desorption maintains reservoir pressure, but gas slippage and Knudsen diffusion accelerate the pressure drop. Both mechanisms contribute to improve the gas production and the consideration of them simultaneously improve gas production most.",17,17,3
Shale Gas,Fracture Network,"Ranjith, P. G.; Wanniarachchi, W. A. M.; Perera, M. S. A.; Rathnaweera, T. D.",Investigation of the effect of foam flow rate on foam-based hydraulic fracturing of shale reservoir rocks with natural fractures: An experimental study,Foam; Fracturing; Breakdown pressure; Flow rate; Fracture permeability; CT scanning,PERMEABILITY; PRESSURE; ENERGY; GAS; PROPAGATION,"Foam-based hydraulic fracturing has been identified as a good solution for the extraction of natural gas from deep shale reservoirs, due to its unique advantages such as low water consumption and high proppant carrying capacity. However, lack of knowledge of foam-based shale fracturing and complex nature of two-phase foam, make it challenging to use in field conditions, and one unclear area is the effect of the foam flow rate on fracturing and fracture characteristics. Therefore, the aim of this study was to investigate the effect of foam flow rate on breakdown pressure, fracture permeability and generated fracture characteristics. In order to achieve this, a series of hydraulic fracturing experiments was conducted for shale rocks with existing natural fractures, using nitrogen-based foam. Fracture permeability was also evaluated for intact and fractured rock samples. Micro-CT scanning technology was adopted to characterise the geometrical properties of fractures, in order to investigate the effect of foam flow rate within the fracture. Experimental results show that the breakdown pressure increases by 30% while energy release decreases by 78% when the foam flow rate increases from 10 to 70 ml/min. In addition, the results suggest that the permeability of a fractured sample at 10 ml/min injection rate is about 15 times higher than that of a fractured sample at 70 ml/min injection rate. The findings of this study reveal that low foam-flow rates can create a better inter-connected fracture network than higher flow rates.",15,15,4
Shale Gas,Fracture Network,"Yan, Bicheng; Mi, Lidong; Chai, Zhi; Wang, Yuhe; Killough, John E.",An Enhanced Discrete Fracture Network model for multiphase flow in fractured reservoirs,Multiphase flow; Fractured reservoirs; Reservoir modeling; EDFN,NUMERICAL-SIMULATION; SHALE GAS; BEHAVIOR; BLOCKS,"We present an Enhanced Discrete Fracture Network (EDFN) model for multiphase flow simulation in fractured reservoirs. EDFN can efficiently represent complex fractured porous media and accurately simulate fluid exchange between matrix and fracture. By using EDFN the fracture network is discretized with minimum number of grids based on the fracture intersecting points and fracture extremities. The matrix is also optimally decomposed into coarse blocks with different geometries using a rapid image processing algorithm. Each coarse matrix block is designed to be associated with one fracture grid and then discretized logarithmically to handle 1D flow between matrix and fracture. EDFN can greatly optimize the discretization for fractured porous media to conform interconnected fractures of arbitrary orientations. Via unstructured format, EDFN is successfully linked with an in-house unstructured compositional simulator. We validate the accuracy of EDFN through a number of multiphase flow simulations in fractured porous media with/without considering capillary pressure. Its efficiency is demonstrated to be superior by using a much less grid blocks comparing with other approaches. Ultimately EDFN is applied to predict hydrocarbon production in a shale oil reservoir and it enables to capture multi-scale fluid transfer in such complex system.",15,15,3
Shale Gas,Sichuan BASIN,"Zhao, Tianyi; Li, Xiangfang; Ning, Zhengfu; Zhao, Huawei; Li, Meifen",Molecular simulation of methane adsorption on type II kerogen with the impact of water content,Molecular simulation; Methane adsorption; Kerogen; Moisture content; Shale gas,SHALE-GAS; ORGANIC-MATTER; THERMODYNAMIC PROPERTIES; SORPTION ISOTHERMS; THERMAL MATURITY; BARNETT SHALE; SICHUAN BASIN; PRESSURE; CO2; CAPACITY,"Based on realistic kerogen model, the effects of water content on methane (CH4) adsorption capacity were studied qualitatively and quantitatively using the molecular dynamics (MD) and Monte Carlo (MC) simulation methods. The methane single component adsorption process under the dry condition, methane and water two components competitive adsorption on dry kerogen, and methane single component adsorption on moist conditions (0.6, 1.2, 1.8, 2.4, and 3.0 wt%) were simulated. Adsorption processes under different temperatures (298, 323, and 348 K) were modeled, and the pressure was up to 20 MPa. Simulation results show that the absolute adsorption capacity of CH4 on the dry kerogen increases with the increasing pressure but decreases with the increasing temperature. The excess adsorption capacity increases up to a specific pressure and then declines with the increasing pressure. The competitive adsorption simulation results indicate that kerogen prefers to adsorb water (H2O) than CH4. At the pressure of 20 MPa and temperature of 298 K, the competitive adsorption capacity of CH4 (0.53 mmol/g) is only a seventh of the single component adsorption capacity of CH4 (3.92 mmol/g) on dry kerogen. The CH4 adsorption capacity on moist kerogen also decreases with the increasing moist content. Compared with the absolute adsorption capacity on the dry kerogen (3.92 mmol/g), the adsorption capacity on the moist kerogen reduces about 16%, 30%, 40%, 47%, and 55% at 20 MPa, respectively. The reduction of the adsorption capacity is attributed to the strong attraction between kerogen and water. At last, the effect of the water content on the shale gas adsorption is discussed under the micro-scale, and the adsorption capacity reduction curves were calculated under the reservoir conditions. The results show that the adsorption capacity of shale gas is significantly affected by water at the economically recoverable depth. The dry condition is considered as the situation of the maximal adsorption capacity of the shale gas reservoir. This study can serve as a reference for better understanding of the transportation and storage mechanism of shale gas under the reservoir conditions.",45,46,0
Shale Gas,Sichuan BASIN,"Liu, Kouqi; Ostadhassan, Mehdi; Kong, Lingyun",Multifractal characteristics of Longmaxi Shale pore structures by N-2 adsorption: A model comparison,N-2 adsorption; BJH model; DFT model; Shale; Multifractal; Comparison,TECTONICALLY DEFORMED COALS; SICHUAN BASIN; NITROGEN ADSORPTION; MERCURY POROSIMETRY; SIZE DISTRIBUTIONS; FRACTAL DIMENSION; ARGON ADSORPTION; POROUS MATERIALS; GAS-ADSORPTION; CHINA,"N-2 adsorption is one of the most widely used techniques to assess pore structures of shale samples due to its ability for characterizing pores in nanoscale. Various models have been developed to quantify pore structures based on adsorption isotherms. In this regard, using a suitable model can give us more accurate pore structure information. The Barret, Joyner and Halenda (BJH) model along with density functional theory (DFT), two most frequently used ones for pore structures of shales, employed on Longmaxi shale samples and compared. BJH model can be divided into two sub-models: adsorption (BJHAD) and desorption (BJHDE). First, the multifractal analysis was used to quantify the heterogeneity of pore size distributions derived from these models. Second, partial least regression analysis (PLS) was employed to quantify the correlations between pore structures and rock compositions. The results showed that pore structures (volume and surface area) and pore heterogeneity derived from BJHAD, BJHDE and DFT model would differ. In addition, PLS results indicated that minerals (except dolomite and clay) and organic matter would correlate positively while clay minerals negatively with pore surface area and volume independent of the method that was used. Finally, the comparison of results from these three methods demonstrated that DFT model is superior to BJHAD and BJHDE for pore structure characterization in shale gas formations.",27,30,11
Shale Gas,Sichuan BASIN,"Xi, Zhaodong; Tang, Shuheng; Wang, Jing","The reservoir characterization and shale gas potential of the Niutitang formation: Case study of the SY well in northwest Hunan Province, South China",Middle and upper Yangtze regions; The lower cambrian shale; Niutitang formation; Pore structure; Shale gas,PORE STRUCTURE CHARACTERISTICS; CAMBRIAN LUJIAPING SHALE; THRUST-FOLD BELT; MARINE SHALE; SICHUAN BASIN; FRACTAL CHARACTERISTICS; YANGTZE PLATFORM; THERMAL MATURITY; WESTERN HUNAN; BLACK SHALES,"Marine shale is extensive throughout the subsurface, and commercially well-developed as natural gas producers throughout south China, attracting attention in recent years by both politicians and scientists on a variety of issues. Previous research on shale has predominantly focused on the Longmaxi and Niutitang Formations in the Sichuan Basin, but rarely on the periphery in northwestern Hunan Province where the Niutitang Formation has long been known as a potential shale gas reservoir. In this study, hydrocarbon generation potential, reserving performance, and shale gas potential of the Niutitang Formation from northwestern Hunan Province was studied to determine its gas producing potential. Total organic carbon (TOC) analysis, rock-eval pyrolysis, vitrinite reflectance and organic maceral analysis, mercury intrusion, nitrogen adsorption, and methane adsorption were run on a total of 52 samples from the SY well consisting of the Upper and Lower Members of the Niutitang Formation. Analysis of the results showed that the Niutitang shale has high TOC content (2.37% on average), high thermal maturity (3.15% on average), and oil-prone kerogen types, indicating good shale gas potential in the study area. The shale consists of relatively high concentrations of brittle minerals (quartz and feldspar, 69% on average) and low clay content (22% on average), indicating a brittle shale. The shale is a tight formation, with measured porosity averaging 2.66% (free gas potential) and methane adsorption capacity averaged 1.55 cm(3)/g (adsorbed gas potential). TOC and burial depth control reservoir space of the shale. The Lower Member samples had lower porosity but higher methane adsorption capacity than those from the Upper Member, indicating that a relatively larger amount of gas may occur as adsorbed gas in the Lower Member. It is suggested that the Lower Member of the Niutitang Formation is the ideal location for exploration and development of shale gas due to consistently thick organic-rich layers, high TOC content, high brittleness index, and stronger adsorption capacity.",27,29,3
Shale Gas,Sichuan BASIN,"Ou, Chenghua; Li, Chaochun; Rui, Zhenhua; Ma, Qiao","Lithofacies distribution and gas-controlling characteristics of the Wufeng-Longmaxi black shales in the southeastern region of the Sichuan Basin, China",Wufeng-Longmaxi (WF-LMX) black shales; Shale lithofacies; Gas-controlling characteristics; Outcrop profiles; Jiaoshiba (JSB) gas field; Sichuan basin,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; APPALACHIAN BASIN; WELL PRODUCTIVITY; SOUTHERN SICHUAN; MARCELLUS SHALE; RESERVOIR SPACE; JIAOSHIBA AREA; EXPLORATION; SIMULATION,"The Wufeng-Longmaxi (WF-LMX) black shales in the southeastern region of the Sichuan Basin are currently the focus of shale gas exploration and development in China. In this study, field surveys and laboratory analyses of the Shuanghe (SH), Qilongcun (QLC), and Guanyinqiao (GYQ) outcrop profiles located within this region were conducted. Field data from the Jiaoshiba (JSB) gas field were also analyzed and interpreted. A systematic study of the distribution and evolutionary succession of the region's sedimentary microfacies and shale lithofacies, as well as the interrelationships between these facies, was conducted. An improved shale lithofacies classification scheme was developed. Fourteen lithofacies were identified, and variations in the types of shale lithofacies were found at different locations within the same sedimentary microfacies or member. Various shale lithofacies were found to have significantly different characteristics of total gas content and open flow rate, and certain lithofacies in the study area had very strong gas-controlling characteristics. This region has four dominant types of shale lithofacies: argillaceous, siliceous shale with rich total organic carbon (TOC) content; argillaceous, silty shale with high TOC content; argillaceous, silty shale with medium TOC content; and silty clay shale with low TOC content. Among these four lithofacies, the argillaceous, siliceous shale with rich TOC content and the argillaceous, silty shale with high TOC content facies are the best and second-best shale lithofacies, respectively, in terms of total gas content and open flow rate. These results of lithofacies distribution and gas-controlling characteristics in this region help provide useful reference information for predicting favorable targets for shale gas development.",21,26,5
Shale Gas,Sichuan BASIN,"Feng, Ziqi; Dong, Dazhong; Tian, Jinqiang; Qiu, Zhen; Wu, Wei; Zhang, Cong","Geochemical characteristics of Longmaxi Formation shale gas in the Weiyuan area, Sichuan Basin, China",Geochemical characteristics; Shale gas; Longmaxi Formation; Carbon isotope; Weiyuan area; Sichuan Basin,CARBON-ISOTOPE RATIOS; MISSISSIPPIAN BARNETT; REVERSALS; SYSTEMS; ACCUMULATION; METHANE; TRENDS; TEXAS,"Recently, shale-gas exploration in the Lower Silurian has been conducted in the Weiyuan area, southwestern Sichuan Basin, which has a special symbolic significance for the development of shale gas in China. According to the first systematic analysis of its geochemical characteristics, methane accounts for the vast majority (95.7%) of the Longmaxi Formation shale gas in the Weiyuan area, with extremely low wetness (C2-3/C1-3%) of 0.57%. Non-hydrocarbon gases consist of small amounts of N-2 and inorganic-induced CO2. The delta C-13(-CH4) values of shale gas range from -36.9 parts per thousand to -34.0 parts per thousand, and the delta C-13(-C2H6) values range from -42.8 parts per thousand to -37.5 parts per thousand indicating that the gases originate from sapropelic kerogen. A reversal in carbon-isotopic composition, i.e., delta C-13(-CH4) > delta C-13-(C2H6) > delta C-13(-C3H8), results from combined secondary effects such as secondary cracking and diffusion under extremely high thermal maturity. Geologic features of organic-rich shale and secondary effects at the overmature stage together lead to differences in geochemical characteristics of shale gas in the Weiyuan and Changning and Fuling (CF) areas, which can be used to indicate the distribution of geochemical parameters and predict shalegas production.",21,25,3
Shale Gas,Sichuan BASIN,"Han, Hui; Ding, Zhengang; Dong, Caiyuan; Liu, Yan; Chen, Shijia; Lu, Jungang; Xue, Yaru; Peng, Siqiao; Gao, Yuan","Fractal characteristics of bulk-mudrock, washed, and kerogen samples of Chang 7 member mudrocks from the Ordos Basin, China",Chang 7 mudrocks; Kerogen; Low-pressure gas adsorption; Fractal dimension; FHH model; Pore structure,PORE STRUCTURE CHARACTERIZATION; CAMBRIAN LUJIAPING SHALE; SILURIAN LONGMAXI SHALES; CH4 ADSORPTION CAPACITY; THRUST-FOLD BELT; GAS-ADSORPTION; LACUSTRINE SHALE; ORGANIC-MATTER; SICHUAN BASIN; SOUTHWESTERN CHINA,"We performed low-pressure N-2 physisorption experiments to investigate and compare the fractal characteristics of bulk-mudrock, washed, and kerogen samples of Chang 7 mudrocks from the Ordos Basin, China. Their fractal dimensions D were obtained from adsorption data using the Frenkel-Halsey-Hill (FHH) method. The D values for the bulk-mudrock samples were slightly lower than those of the washed samples, while the kerogen samples showed lowest values. The results suggest that the surfaces of the washed samples were rougher than the bulk-mudrock samples and that the kerogen samples had the smoothest surfaces. For the bulk-mudrock and washed samples, D decreased with increasing total organic carbon content, suggesting that organic matter has lower fractal dimension than other fractions in mudrocks. D decreased with increasing free oil, indicating that the fractal dimension can be used to characterize the residual oil content in lacustrine mudrocks approximately. For the bulk-mudrock and washed samples, there are positive trends between fractal dimension and surface area and pore volume. However, similar trends cannot been found in kerogen samples, indicating that the fractal dimensions obtained from low-pressure N-2 adsorption experiments cannot describe the fractal characteristics of the kerogen samples well. The fractal dimension decreased with the increasing average pore diameter, which can be attributed to that the samples with higher fractal dimensions contained more small pores and had higher surface area.",19,19,2
Shale Gas,Sichuan BASIN,"Zhu, Haiyan; Tang, Xuanhe; Liu, Qingyou; Li, Kuidong; Xiao, Jialin; Jiang, Shu; McLennan, John D.","4D multi-physical stress modelling during shale gas production: A case study of Sichuan Basin shale gas reservoir, China",Multi-physical modeling; 4D stress; Sichuan Basin shale gas reservoir; Interface code; Transverse isotropy,CO2 GEOLOGICAL STORAGE; ROCK; SIMULATION; WELL; GEOMECHANICS; IMPACT; COAL,"To investigate the time-lapse, three-dimensional (4D) stress during shale gas production, a multi-physical modeling method is proposed. This model enfranchises multiple years' scale dynamic production data. A finite difference method (FDM) reservoir simulator is used to couple thermal-hydrological-chemical (THC) processes, while a finite element method (FEM) geomechanical simulator takes on the role of a thermal-hydrological-mechanical (THM) coupling calculator. In order to couple the flow model with the geomechanical model, an interface (coupling) Python code is provided to communicate data between the finite difference (FD) and finite element (FE) grids. A set of FORTRAN routines are assigned to interpolate initial stress field and mechanical parameters into the geomechanical model based on field and experimental data. Ultimately, a 4D multi-physical model of Sichuan Basin shale gas reservoir (China) is proposed and analyzed. Based on the simulation results, the continuous reduction in reservoir pore pressure leads to evolving changes in the stress state and reservoir properties beyond the pre-consolidation pressure. Transversely isotropic characteristics have a considerable effect on the changes in the reservoir stresses and poro-elastic parameters. The results provide some fundamental insights for optimizing well patterns, ensuring wellbore stability, re-fracturing design and locating, drilling and completing infill wells.",15,18,4
Shale Gas,Bedding Planes,"Hou, Bing; Zhang, Ruxin; Zeng, Yijin; Fu, Weineng; Muhadasi, Yeerfulati; Chen, Mian",Analysis of hydraulic fracture initiation and propagation in deep shale formation with high horizontal stress difference,Hydraulic fracture; Complex fracture network; Discontinuities; Pump rate; AE monitoring,GAS-RESERVOIRS; BEHAVIOR; ROCK,"Deeply buried shale formations (vertical depth > 3500 m) that are rich in shale gas are abundant in south China. The primary problems in the exploitation of these formations are the relatively small stimulated reservoir volume (SRV) and low production rates in comparison with their shallower counterparts. These issues are attributed to the high fracturing pressure, limited fracture extension because of sand plugging, significant horizontal stress contrast, and discontinuities produced during hydraulic fracturing. To accurately evaluate and improve the SRV in deep shale formations, the mechanism of fracture propagation must be understood and described. In this regard, a series of large-scale true tri-axial experiments with acoustic emission (AE) monitoring were conducted to characterize the fracture initiation and propagation in a selected deep shale formation. It was found that the difficulty in the complex fracture network formation was because the high stress contrast controls the fracture propagation path to generate large main fractures instead of activating discontinuities. The hydraulic fractures initiated either from open-hole positions or stress concentration locations on a wellbore wall that displayed two types of intersection in terms of crossing and deflection. In general, four types of fracture morphologies were identified: transverse fracture, transverse fracture with bedding planes, natural fracture with bedding planes, and transverse fracture with bedding planes and natural fractures. In addition, the horizontal stress contrast, fluid viscosity, pump rate and fracturing procedure on fracture propagation were evaluated for their effect on the resulting SRV. A low-viscosity fluid can activate discontinuities to form a complex fracture network, whereas a high-viscosity fluid is likely to produce large fractures under a high contrast in the horizontal stresses. On the basis of the above-mentioned analyses, a fracturing procedure applying a periodically varying pump rate and shut-in using a low-viscosity fluid was suggested to be an effective approach to enhance the interaction between the hydraulic fractures and discontinuities as well as to increase the fracture length.",58,65,4
Shale Gas,Bedding Planes,"Wang, Y.; Li, C. H.; Hao, J.; Zhou, R. Q.",X-ray micro-tomography for investigation of meso-structural changes and crack evolution in Longmaxi formation shale during compressive deformation,Shale fracturing; Micro-tomography CT; X-ray imaging; Fracture evolution; Longmaxi shale,HIGH-RESOLUTION; MECHANICAL-PROPERTIES; TRIAXIAL COMPRESSION; COMPUTED-TOMOGRAPHY; CREEP; ROCK; MICROTOMOGRAPHY; VISUALIZATION; PROPAGATION; SIMULATION,"Shale is a typical heterogeneous geomaterial and investigation of the meso-structural changes and crack evolution is beneficial to shale gas development. Understanding the microscopic failure mechanism is undoubtedly crucial to hydraulic fracturing treatment. In this paper, real-time high-resolution X-ray Computed (micro-) Tomography (X-ray CT) with was used for the first time to deform shale sample experimentally under unconfined axial compression. Organic matter, pyrite, and micro-fractures were volumetrically rendered with a resolution of 11.27 mu m, and 2D/3D image investigations enabled us to explore the structure and fracture evolution of the sample due to in-situ compression. This work reveals that the stress-induced deformation of shale is found to be dependent on organic matter compaction, pyrite spatial evolution, and micro-fracture initiation, propagation, and coalescence. The volume of organic matter decreases with the increase of axial stress; and the spatial distribution of pyrite changes at different loading stages, but the effective volume is almost the same. The formation of macroscopic fractures similar to 20 degrees oblique to the loading direction was observed. The cracks initiate in the tensile cracks between the bedding plane at the bottom of the sample and shear fractures are composed of tensile cracks connected by an ""X"" shape. The layered deposited structure and weak cementation between layers are the main factors controlling the failure mechanism.",33,36,4
Shale Gas,Bedding Planes,"Kamali-Asl, Arash; Ghazanfari, Ehsan; Newell, Pania; Stevens, Mathew","Elastic, viscoelastic, and strength properties of Marcellus Shale specimens",Shale gas; Failure strength; Ultrasonic velocity; Creep models; Elastic moduli; Viscoelastic; Cyclic,FRACTURE INITIATION; DEFORMATION; ROCK; PROPAGATION; ANISOTROPY; FAILURE,"Shale gas rocks are characterized as clastic sedimentary rocks, with features such as obvious bedding planes, presence of micro-cracks, and high clay and organic content. These rocks are anisotropic and inhomogeneous, exhibiting a nonlinear response under loading. In order to optimize the required energy for hydraulic fracturing operation and production in shale gas reservoirs, and for constitutive and numerical modeling, it is important to characterize these shale gas rocks. In this study, the hysteresis, elastic-plastic, viscoelastic, and strength properties of Marcellus Shale specimens, retrieved from a deep well located in West Virginia, were evaluated through performing a series of creep, cyclic, and triaxial multi-stage failure tests on these specimens. Both elastic moduli and plastic deformations show significant levels of pressure dependency. Moreover, higher creep compliance and lower Young's modulus values were observed for clay-rich specimens. Both Power-Law and Burgers' models were found to capture the creep response of these specimens reasonably well. The dynamic moduli estimated from the ultrasonic velocity measurements at different stress levels were found to be higher than static moduli estimations. In addition, the changes in the internal micro-structure of the specimens resulted from variations in the stress condition, were found to affect the ultrasonic velocity measurements. The strength properties of the calcite/quartz-rich specimen, using multi-stage triaxial failure test, were estimated through both Mohr-Coulomb and Hoek-Brown failure criteria.",25,25,9
Shale Gas,Bedding Planes,"Al-Ameri, Aymen; Gamadi, Talal; Ispas, Ion",Evaluation of the near fracture face formation damage caused by the spontaneously imbibed fracturing fluid in unconventional gas reservoirs,Fracturing fluid spontaneous imbibition; Friction reducer pad fluid; Polymer adsorption; Nonionic surfactant; Bedding plane; Imbibition capillary pressure; Imbibition water relative permeability curves,SPONTANEOUS IMBIBITION; POROUS-MEDIA; RELATIVE PERMEABILITY; CAPILLARY RISE; SHALE; GRAVITY,"In the present study, spontaneous imbibition experiments, steady-state permeability measurements, and numerical simulation were integrated to quantify the changes in the effective water permeability, capillary pressure, and water relative permeability curves due to the polymer adsorption of the spontaneously imbibed fracturing fluid. The effect of the nonionic surfactant and core bedding plane on the fluid spontaneous imbibition volumes were also investigated. The researchers considered the impact of the spontaneous imbibition of a friction reducer fluid in tight sand and shale core samples. Three comparative systematic spontaneous imbibition experiments were conducted for each of the core samples using brine, anionic friction reducer fluid, and brine again. The core sample water permeability before and after the imbibition experiment was measured using a constant rate steady-state permeability apparatus. The polymer adsorption from the spontaneously imbibed fracturing fluid significantly reduced the brine spontaneous imbibition volumes in tight sand samples and in shale samples, though to a lesser degree. Moreover, the effective water permeability was decreased because of the polymer adsorption effect. Therefore, the polymer adsorption during hydraulic fracturing reduces the fluid leak-off into the formation and also the fluid flowback. The nonionic surfactant increased the fluid spontaneous imbibition volumes in both tight sand and shale samples. Thus, adding a nonionic surfactant to the friction reducer pad fluid during hydraulic fracturing leads to enhance both of the fluid leak-off and fluid flowback. The results also showed that the effect of polymer adsorption on the imbibition rates is less when the rock-fluid contact surface is parallel to the bedding plane. The imbibition potentials and imbibition capillary pressure curves were calculated before and after polymer adsorption. The polymer adsorption led to a slight increase in the capillary pressure; moreover, the tight sand samples had higher capillary pressure than the shale samples. The imbibition water relative permeability curves were calculated using ECLIPSE commercial simulator. The polymer adsorption significantly reduces the water relative permeability curves for tight sand samples and in less degree for shale samples.",24,24,6
Shale Gas,Bedding Planes,"Zhou, Jun; He, Shiming; Tang, Ming; Huang, Zhen; Chen, Yulin; Chi, Jun; Zhu, Yu; Yuan, Ping",Analysis of wellbore stability considering the effects of bedding planes and anisotropic seepage during drilling horizontal wells in the laminated formation,Anisotropic seepage; Bedding plane; Weak plane; Horizontal well; Wellbore stability,TRANSVERSELY ISOTROPIC MEDIUM; BOREHOLE STABILITY; INCLINED BOREHOLE; ACOUSTIC-EMISSION; SHALE ROCK; MODEL; PERMEABILITY; RESERVOIR; STRESS; FLOW,"With the exploration and development of gas shale in recent years, layer structures (bedding planes) of laminated rock and its effects on mechanical properties of rock and wellbore stability have arisen great attention. In this paper, we mainly concerns the wellbore stability during drilling horizontal wells in the laminated formation with horizontal bedding planes, meanwhile, the effects of anisotropy of permeability paralleled to bedding planes and that perpendicular to bedding planes are taken into consideration as well. Models of pore pressure distribution and seepage stresses under anisotropic seepage are established. Combining the effects of anisotropic seepage and bedding planes, we have investigated the equivalent collapse density (ECD) around horizontal wellbores. The results based on the input data in this paper reveal that the ECD considering the weakness of bedding planes is far higher than that without considering bedding planes, and the shape of zones where surrounding rock is relatively easier to collapse is similar as two couples of cat ears. The point where ECD reaches its maximum value tends to move from wellbore wall to internal rock if drilling close to the direction of minimum in-situ stress, and the higher anisotropic permeability ratio is, the more obvious the phenomenon is. The effect of anisotropic seepage can be ignored if the weakness of bedding planes is omitted, it otherwise can not be left out and the maximum ECD around wellbore instead of the maximum value at wellbore wall should be used to design for drilling operation. This study simultaneously investigates the effects of anisotropic seepage and weak bedding planes on wellbore stability during drilling horizontal wells, it is promising to provide a theoretical basis and practical guidance for the further researches on wellbore stability in future.",19,19,3
Shale Gas,Cement,"Xi, Yan; Li, Jun; Liu, Gonghui; Cha, Chunqing; Fu, Yongqiang",Numerical investigation for different casing deformation reasons in Weiyuan-Changning shale gas field during multistage hydraulic fracturing,Volume fracturing; Casing deformation; Numerical calculation; Lithologic interface; Cement void; Formation slipping,UNCONVENTIONAL RESERVOIRS; HORIZONTAL WELLS; FINITE-ELEMENT; DESIGN; VOLUME; PRESSURE; WEAR,"Casing deformation has been found to be a very significant issue in the development process of shale gas in China. The rate of casing deformation is 34.34% (34 wells of 101), and statistical data show that it decreased the test output of wells by approximately 30%. Based on investigation and analysis of the engineering and geological conditions of 25 wells, 12 of which have casing deformations, both physical models and finite element models were established. Furthermore, the effects of fracturing pressure, geostress, anisotropy, lithologic interface, temperature variation, and cement void were analyzed. The results show the following. a) When the casing deformation points appear far away from point A (the landing point, which is the starting point of the horizontal segment), the influence of the lithologic interface on casing stress plays a decisive role under the combined effect of internal and external pressures when the cement sheath is completed. b) Under the same conditions, but when the casing is in contact with the borehole wall near the bottom because of gravity, a narrow fluid retention space was formed, leading to cementing sheath voids. The effect of cement void pressure reduction is the main reason behind the casing deformation. c) When casing deformation points appear near point A, the activation of the weak plane in the beddings during fracturing causes the casing deformation. The stress of 14 casing deformation points was calculated according to actual engineering and geological conditions, and 78.6% of the results were consistent with field measurements.",35,41,3
Shale Gas,Cement,"Wang, Y.; Li, C. H.; Hao, J.; Zhou, R. Q.",X-ray micro-tomography for investigation of meso-structural changes and crack evolution in Longmaxi formation shale during compressive deformation,Shale fracturing; Micro-tomography CT; X-ray imaging; Fracture evolution; Longmaxi shale,HIGH-RESOLUTION; MECHANICAL-PROPERTIES; TRIAXIAL COMPRESSION; COMPUTED-TOMOGRAPHY; CREEP; ROCK; MICROTOMOGRAPHY; VISUALIZATION; PROPAGATION; SIMULATION,"Shale is a typical heterogeneous geomaterial and investigation of the meso-structural changes and crack evolution is beneficial to shale gas development. Understanding the microscopic failure mechanism is undoubtedly crucial to hydraulic fracturing treatment. In this paper, real-time high-resolution X-ray Computed (micro-) Tomography (X-ray CT) with was used for the first time to deform shale sample experimentally under unconfined axial compression. Organic matter, pyrite, and micro-fractures were volumetrically rendered with a resolution of 11.27 mu m, and 2D/3D image investigations enabled us to explore the structure and fracture evolution of the sample due to in-situ compression. This work reveals that the stress-induced deformation of shale is found to be dependent on organic matter compaction, pyrite spatial evolution, and micro-fracture initiation, propagation, and coalescence. The volume of organic matter decreases with the increase of axial stress; and the spatial distribution of pyrite changes at different loading stages, but the effective volume is almost the same. The formation of macroscopic fractures similar to 20 degrees oblique to the loading direction was observed. The cracks initiate in the tensile cracks between the bedding plane at the bottom of the sample and shear fractures are composed of tensile cracks connected by an ""X"" shape. The layered deposited structure and weak cementation between layers are the main factors controlling the failure mechanism.",33,36,4
Shale Gas,Cement,"Chen, Zhiqiang; Yang, Zhengming; Wang, Moran",Hydro-mechanical coupled mechanisms of hydraulic fracture propagation in rocks with cemented natural fractures,Hydraulic fracture; Cemented fracture; Natural fracture; LBM-DEM,LATTICE-BOLTZMANN METHOD; GENERAL SHAPES; BARNETT SHALE; FLUID-FLOW; PERMEABILITY; MODEL; DISCONTINUITIES; CRITERION,"Natural fractures commonly exist in unconventional reservoirs such as shale and tight gas sandstone, which are mostly cemented (or sealed) with minerals and not able to contribute to reservoir storage or rock permeability. However, during hydraulic fracture stimulation, these cemented natural fractures will be encountered and influence hydraulic fracture geometry greatly and, thereby, gas production. In this work, hydraulic fracture propagation in rock with cemented natural fracture is investigated using our recently developed and validated hydromechanical coupled LBM-DEM model. The numerical results show that both the strength ratio (between cemented natural fracture and host rock) and the approach angle (between hydraulic and cemented natural fracture) significantly affect the hydraulic fracture propagation. A larger strength contrast or a smaller approach angle will be more conducive to deflection, which is consistent with experimental observation. For rocks with weakly cemented natural fractures, deflection is mainly caused by shear failure in weakly cemented fracture. However, for rocks with strongly cemented natural fractures, deflection happens accompanying with tensile failure in host rock along the cement wall, which cannot be captured by the previous numerical models where the cemented natural fracture is treated as a bonded interface. In addition, complex fracture network is more easily formed if multiple weakly cemented natural fractures are orthogonal to the hydraulic fracture propagation direction.",31,32,3
Shale Gas,Cement,"Liu, Kui; Gao, Deli; Taleghani, Arash Dahi",Analysis on integrity of cement sheath in the vertical section of wells during hydraulic fracturing,Sustained casing pressure; Cement sheath; Shale gas; Well integrity; Hydraulic fracturing,WELLBORE,"The sustained casing pressure (SCP) problems occur mainly in intermediate casing that might affect the safety and efficiency of shale gas production. Cement sheath is the main barrier against leakage and migration of gas from the pay zone to the shallow zones. Since the production casing is cemented all the way up to the intermediate casing in the vertical section of the well, the in-situ stress can only act on the intermediate casing and not directly on production casing. Based on this situation, an analytical model considering the well completion steps is established to study the integrity of cement sheath as a two-layer casing-cement system. The effect of mechanical and geometrical parameters of casing and cement are further investigated through a sensitivity analysis. The results show that the tensile failure more likely occurs at the inner face of the cement sheath in the intermediate casing. The casing thickness is in favor of decreasing the tensile stress in the cement sheath. But on the contrary, increasing the thickness and elastic modulus of the cement sheath may increase the risk of tensile failure in the cement sheath while reducing the costs. However, an appropriate increase of back pressure in the annulus during cementing is beneficial to reduce the tensile stress in the cement sheath.",26,30,2
Shale Gas,Cement,"Yin, Fei; Han, Lihong; Yang, Shangyu; Deng, Yong; He, Yongming; Wu, Xingru",Casing deformation from fracture slip in hydraulic fracturing,Casing integrity; Hydraulic fracturing; Shale gas well; Shear slip,HORIZONTAL WELLS; SIMULATION; FAILURE,"Casing failure during hydraulic fracturing is infrequent, but its consequence and impact can be significant for the shale gas wells. It may result in inaccessible cased hole and environmental and safety concerns over wellbore integrity during the shale gas reservoir development. Based on theoretical analysis, numerical simulation and field measurement, the failure mechanisms of casings in shale gas wells are revealed. Through parametric sensitivity analysis, the countermeasures are recommended. Results indicate that one of the casing failure mechanisms in shale gas wells is shear deformation induced by the slip of shear fractures. The simulated casing deformation is consistent with the lead impression. Casing curvature is introduced to assess the traveling capability and casing integrity. The maximum curvature is significantly larger than that of normal directional borehole, which causes the resistance of downhole tools passing through casing. Decreasing the crossing angle and employing the cement with a low Young's modulus or even no cementing can be the effective measures to prevent casing failure in this mode. The research findings provide new evaluation criterion and controlling methods for casing integrity in shale gas wells under hydraulic fracturing.",21,25,2
Shale Gas,Breakdown Pressure,"Liu, Liyuan; Zhu, Wancheng; Wei, Chenhui; Elsworth, Derek; Wang, Jiehao",Microcrack-based geomechanical modeling of rock-gas interaction during supercritical CO2 fracturing,Supercritical CO2 fracturing; Gas adsorption; Internal swelling stress; Rock damage; Numerical simulation,SHALE GAS; CARBON-DIOXIDE; HORIZONTAL WELLS; COAL; PERMEABILITY; PROPAGATION; ADSORPTION; CHALLENGES; CAPTURE; SCALE,"Relative to water-based fluids, non-aqueous fracturing fluids have the potential to increase production, reduce water requirements, and to minimize environmental impacts. Since the viscosity of supercritical CO2 is one-tenth that of water, its density is close to that of water, and is capable of promoting sorptive rejection of methane, it is an attractive substitute for water in the extraction of shale gas and coalbed methane. The following defines a geomechanical model accommodating the interaction of fluid flow, adsorption-induced swelling stress, solid deformation and damage to quantify rock-gas interactions during supercritical CO2 fracturing for shale gas production. The architecture of the shale is accommodated that includes both pore-and micro-crack-based porosity. According to the microcrack model representing shales with low porosity, both analytical and numerical results show that the effective stress coefficient is much smaller than unity. We analyze the potential advantages of fracturing using supercritical CO2 including enhanced fracturing and fracture propagation, increased desorption of methane adsorbed in organic-rich portions of the shale and the potential for partial carbon sequestration. Rock-gas interactions include both the linear poroelastic response and the chemo-mechanical interaction due to sorption. Simulation results demonstrate that supercritical CO2 fracturing indeed has a lower fracture initiation pressure and a significantly lower breakdown pressure, as observed in experiments, and that fractures with greater complexity than those developed with liquid CO2 and water fracturing result. With increasing dynamic viscosity of the fracturing fluids, the predicted breakdown pressure also increases, consistent with experimental observations.",40,43,8
Shale Gas,Breakdown Pressure,"Zhang, Yushuai; Zhang, Jincai; Yuan, Bin; Yin, Shangxian",In-situ stresses controlling hydraulic fracture propagation and fracture breakdown pressure,Hydraulic fracture; In-situ stresses; Horizontal stress; Breakdown pressure; Depletion; Fracture curving,INSITU STRESSES; WELLS; PREDICTION; BOREHOLE; RESERVOIRS; MAGNITUDE; ROCKS; FLOW,"In-situ stress impact on hydraulic fracturing is investigated to enhance hydraulic fracturing performance. Lithology-controlled lower and upper bounds of the horizontal stresses are proposed, and an improved stress polygon method is presented. This improved method can narrow the area of the conventional stress polygon, particularly in shales; therefore, constrain the in-situ stress estimate. The lithology-controlled stresses indicate that a shale has a higher minimum horizontal stress and can be used as a barrier of the hydraulic fracture propagation when hydraulic fracturing is performed in adjacent sandstones. However, when hydraulic fracturing is performed in a shale oil or gas formation, a stress-barrier formation may not exist on the top or the bottom of the shale reservoir, and this will cause the hydraulic fractures to propagate out of the reservoir zone. We also examine the effects of the maximum and minimum horizontal stresses, shear stresses and depletion on the fracture initiation, breakdown, propagation and containment. Shear stresses cause hydraulic fractures kinking; from this evidence, we find that a horizontal well can be drilled with a certain angle to the minimum stress direction because in most cases the hydraulic fractures eventually curve to the maximum stress direction. In addition, we propose a new method to calculate the fracture breakdown pressure based on fracture mechanics. The proposed method predicts a higher breakdown pressure than the conventional one, which may better estimate the breakdown pressure.",38,40,3
Shale Gas,Breakdown Pressure,"Ranjith, P. G.; Wanniarachchi, W. A. M.; Perera, M. S. A.; Rathnaweera, T. D.",Investigation of the effect of foam flow rate on foam-based hydraulic fracturing of shale reservoir rocks with natural fractures: An experimental study,Foam; Fracturing; Breakdown pressure; Flow rate; Fracture permeability; CT scanning,PERMEABILITY; PRESSURE; ENERGY; GAS; PROPAGATION,"Foam-based hydraulic fracturing has been identified as a good solution for the extraction of natural gas from deep shale reservoirs, due to its unique advantages such as low water consumption and high proppant carrying capacity. However, lack of knowledge of foam-based shale fracturing and complex nature of two-phase foam, make it challenging to use in field conditions, and one unclear area is the effect of the foam flow rate on fracturing and fracture characteristics. Therefore, the aim of this study was to investigate the effect of foam flow rate on breakdown pressure, fracture permeability and generated fracture characteristics. In order to achieve this, a series of hydraulic fracturing experiments was conducted for shale rocks with existing natural fractures, using nitrogen-based foam. Fracture permeability was also evaluated for intact and fractured rock samples. Micro-CT scanning technology was adopted to characterise the geometrical properties of fractures, in order to investigate the effect of foam flow rate within the fracture. Experimental results show that the breakdown pressure increases by 30% while energy release decreases by 78% when the foam flow rate increases from 10 to 70 ml/min. In addition, the results suggest that the permeability of a fractured sample at 10 ml/min injection rate is about 15 times higher than that of a fractured sample at 70 ml/min injection rate. The findings of this study reveal that low foam-flow rates can create a better inter-connected fracture network than higher flow rates.",15,15,4
Shale Gas,Breakdown Pressure,"Zhao, Xianyu; Wang, Tao; Elsworth, Derek; He, Yunlong; Zhou, Wei; Zhuang, Li; Zeng, Jun; Wang, Suifeng",Controls of natural fractures on the texture of hydraulic fractures in rock,Hydraulic fracturing; Jointed rock mass; DEM; Crack propagation,SIMULATION; MODEL,"Hydraulic fracturing plays an important role in the exploitation of oil, shale gas and coal seam gas resources-all of which contain natural fractures. We systematically explore the role of the pre-existing texture of such natural fractures on the form of the resulting stimulated reservoir volume (SRV). A blocky discrete element model (DEM) coupled with fluid flow is used to explore this response. Numerical predictions for the evolution of fluid pressure and fracture width at the well are compared with first-order analytical approximations of the zero-toughness solution (FMO). We then construct four typical joint system models separately comprising orthogonal, staggered, diagonal and randomly oriented joints and conduct the virtual hydraulic fracturing simulations via DEM. This defines the influence of structure on breakdown pressure and fracture propagation and allows the analysis of the main factors that influence behavior and resulting SRV. Results for the four forms of jointed rock mass show that: (1) the aggregate/mean extension direction of the fractures is always along the direction of the maximum principal stress but significant deviations may result from the pre-existing fractures; (2) there are negative correlations between the maximum fracture aperture with both Poisson ratio and elastic modulus, but the breakdown pressure is only weakly correlated with Poisson ratio and elastic modulus; (3) an increase in injection rate results in a broader fracture process zone extending orthogonal to the principal fracture, and the breakdown pressure and interior fracture aperture also increase; (4) an increase in fluid viscosity makes the fractures more difficult to extend, and the breakdown pressure and interior fracture aperture both increase accordingly.",14,14,3
Shale Gas,Marcellus Shale,"Kamali-Asl, Arash; Ghazanfari, Ehsan; Newell, Pania; Stevens, Mathew","Elastic, viscoelastic, and strength properties of Marcellus Shale specimens",Shale gas; Failure strength; Ultrasonic velocity; Creep models; Elastic moduli; Viscoelastic; Cyclic,FRACTURE INITIATION; DEFORMATION; ROCK; PROPAGATION; ANISOTROPY; FAILURE,"Shale gas rocks are characterized as clastic sedimentary rocks, with features such as obvious bedding planes, presence of micro-cracks, and high clay and organic content. These rocks are anisotropic and inhomogeneous, exhibiting a nonlinear response under loading. In order to optimize the required energy for hydraulic fracturing operation and production in shale gas reservoirs, and for constitutive and numerical modeling, it is important to characterize these shale gas rocks. In this study, the hysteresis, elastic-plastic, viscoelastic, and strength properties of Marcellus Shale specimens, retrieved from a deep well located in West Virginia, were evaluated through performing a series of creep, cyclic, and triaxial multi-stage failure tests on these specimens. Both elastic moduli and plastic deformations show significant levels of pressure dependency. Moreover, higher creep compliance and lower Young's modulus values were observed for clay-rich specimens. Both Power-Law and Burgers' models were found to capture the creep response of these specimens reasonably well. The dynamic moduli estimated from the ultrasonic velocity measurements at different stress levels were found to be higher than static moduli estimations. In addition, the changes in the internal micro-structure of the specimens resulted from variations in the stress condition, were found to affect the ultrasonic velocity measurements. The strength properties of the calcite/quartz-rich specimen, using multi-stage triaxial failure test, were estimated through both Mohr-Coulomb and Hoek-Brown failure criteria.",25,25,9
Shale Gas,Marcellus Shale,"Kenomore, Michael; Hassan, Mohamed; Malakooti, Reza; Dhakal, Hom; Shah, Amjad",Shale gas production decline trend over time in the Barnett Shale,Estimated ultimate recovery; Barnett shale; Arp's hyperbolic; Doung's method; Modified hyperbolic,,"Natural gas produced from shale formations in the United States over the past decade have altered the oil and gas industry remarkably. The Barnett shale was at the forefront of the shale gas revolution in the United States and was considered to be the highest producing natural gas field in the United States until 2012, yielding the top producer spot to the Marcellus shale. Due to the uncertainty regarding the accurate determination of Estimated Ultimate Recoverable (EUR) in shale gas reservoirs, this paper aims to assess EUR values for the Barnett shale using empirical decline curve methods like the Arp's hyperbolic, Modified Arp's hyperbolic and Doung's method. In addition, we investigated the economic viability of wells over time in the Barnett under various probabilities of success. Throughout this paper, reference is made to two key publications where a similar work was carried out for various shale plays in the United States, including the Barnett shale - though only the Arp's hyperbolic decline was employed. The dataset in this paper consisted of more horizontal wells from covering more counties within the Barnett shale compared to other similar studies. We conclude that either the Arp's hyperbolic or Doung's method can be used to forecast EUR in the Barnett shale as only marginal differences were observed. This is on the basis that production history exceeds 10 months (a maximum of 80 months production history was used). We also obtained reliable and conservative estimates of EUR compared to previous studies.",23,23,5
Shale Gas,Marcellus Shale,"Ou, Chenghua; Li, Chaochun; Rui, Zhenhua; Ma, Qiao","Lithofacies distribution and gas-controlling characteristics of the Wufeng-Longmaxi black shales in the southeastern region of the Sichuan Basin, China",Wufeng-Longmaxi (WF-LMX) black shales; Shale lithofacies; Gas-controlling characteristics; Outcrop profiles; Jiaoshiba (JSB) gas field; Sichuan basin,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; APPALACHIAN BASIN; WELL PRODUCTIVITY; SOUTHERN SICHUAN; MARCELLUS SHALE; RESERVOIR SPACE; JIAOSHIBA AREA; EXPLORATION; SIMULATION,"The Wufeng-Longmaxi (WF-LMX) black shales in the southeastern region of the Sichuan Basin are currently the focus of shale gas exploration and development in China. In this study, field surveys and laboratory analyses of the Shuanghe (SH), Qilongcun (QLC), and Guanyinqiao (GYQ) outcrop profiles located within this region were conducted. Field data from the Jiaoshiba (JSB) gas field were also analyzed and interpreted. A systematic study of the distribution and evolutionary succession of the region's sedimentary microfacies and shale lithofacies, as well as the interrelationships between these facies, was conducted. An improved shale lithofacies classification scheme was developed. Fourteen lithofacies were identified, and variations in the types of shale lithofacies were found at different locations within the same sedimentary microfacies or member. Various shale lithofacies were found to have significantly different characteristics of total gas content and open flow rate, and certain lithofacies in the study area had very strong gas-controlling characteristics. This region has four dominant types of shale lithofacies: argillaceous, siliceous shale with rich total organic carbon (TOC) content; argillaceous, silty shale with high TOC content; argillaceous, silty shale with medium TOC content; and silty clay shale with low TOC content. Among these four lithofacies, the argillaceous, siliceous shale with rich TOC content and the argillaceous, silty shale with high TOC content facies are the best and second-best shale lithofacies, respectively, in terms of total gas content and open flow rate. These results of lithofacies distribution and gas-controlling characteristics in this region help provide useful reference information for predicting favorable targets for shale gas development.",21,26,5
Shale Gas,Marcellus Shale,"Wang, J. G.; Hu, Bowen; Liu, Hua; Han, Yue; Liu, Jia",Effects of 'soft-hard' compaction and multiscale flow on the shale gas production from a multistage hydraulic fractured horizontal well,Three-zone model; Dual-porosity medium zone; Multiscale flow mechanism; 'Soft - hard' model; Fracture aperture,MISSISSIPPIAN BARNETT SHALE; APPARENT PERMEABILITY; POROUS-MEDIA; MODEL; RESERVOIRS; STRAIN; SIMULATION; DESORPTION; EVOLUTION; DIFFUSION,"In this study, the shale gas production from a multistage hydraulic fractured shale gas reservoir was analyzed. Firstly, the reservoir was divided into single-porosity medium zone, dual-porosity medium zone, and hydraulic fracture zone. Then, a mathematical model was established for the multiscale gas diffusion and adsorption/desorption mechanisms in matrix, the gas flow in fractures and the interaction between gas flow and shale deformation. Thirdly, this mathematical model was numerically solved within the platform of Comsol Multiphysics and verified by the history matching of the gas production data from Barnett and Marcellus shale reservoirs. Finally, sensitivity study was conducted to identify key parameters to the efficiency of gas recovery enhancement. It is found that hydraulic fracture aperture and initial permeability of fractures are positively correlated with gas production rate. The 'soft - hard' compaction of fractures can significantly modify gas production rate but the modification varies with gas production stage. The deformation and flow properties of hydraulic fractures have significant impacts on gas production rate, particularly in the early stage.",18,19,8
Shale Gas,Shale Gas-reservoirs,"Rui, Zhenhua; Cui, Kehang; Wang, Xiaoqing; Lu, Ju; Chen, Gang; Ling, Kegang; Patil, Shirish",A quantitative framework for evaluating unconventional well development,Unconventional well; Well evaluation; Quantitative framework; Factor analysis; Well complexity; Drilling performance,COMPLEX FRACTURE NETWORKS; TIGHT OIL-RESERVOIRS; HYDRAULIC FRACTURE; COST ESTIMATION; GAS-RESERVOIRS; SHALE; PIPELINE; MODEL; SIMULATION; PRODUCTIVITY,"Gaining a better understanding and measuring unconventional well complexity are vital to developing an oil and gas field successfully. However, there is a lack of quantitative assessment framework for evaluating unconventional wells. This paper created an index evaluation system to assess unconventional well readiness for development, which considers the various well characteristics. The unconventional well complexity index is calculated using five major level-1 elements, and the weight of each sub-element was calculated using the factor analysis statistical method. The well evaluation system was applied to evaluate 20 unconventional well programs for their readiness for development; the evaluation results were analyzed in terms of well complexity distribution and the relationship between unconventional well complexity and duration performance. Recommendations for dealing with various unconventional well complexity were also proposed. The evaluation framework was also verified to be an efficient method for assessing unconventional well development readiness.",82,82,7
Shale Gas,Shale Gas-reservoirs,"Hou, Bing; Zhang, Ruxin; Zeng, Yijin; Fu, Weineng; Muhadasi, Yeerfulati; Chen, Mian",Analysis of hydraulic fracture initiation and propagation in deep shale formation with high horizontal stress difference,Hydraulic fracture; Complex fracture network; Discontinuities; Pump rate; AE monitoring,GAS-RESERVOIRS; BEHAVIOR; ROCK,"Deeply buried shale formations (vertical depth > 3500 m) that are rich in shale gas are abundant in south China. The primary problems in the exploitation of these formations are the relatively small stimulated reservoir volume (SRV) and low production rates in comparison with their shallower counterparts. These issues are attributed to the high fracturing pressure, limited fracture extension because of sand plugging, significant horizontal stress contrast, and discontinuities produced during hydraulic fracturing. To accurately evaluate and improve the SRV in deep shale formations, the mechanism of fracture propagation must be understood and described. In this regard, a series of large-scale true tri-axial experiments with acoustic emission (AE) monitoring were conducted to characterize the fracture initiation and propagation in a selected deep shale formation. It was found that the difficulty in the complex fracture network formation was because the high stress contrast controls the fracture propagation path to generate large main fractures instead of activating discontinuities. The hydraulic fractures initiated either from open-hole positions or stress concentration locations on a wellbore wall that displayed two types of intersection in terms of crossing and deflection. In general, four types of fracture morphologies were identified: transverse fracture, transverse fracture with bedding planes, natural fracture with bedding planes, and transverse fracture with bedding planes and natural fractures. In addition, the horizontal stress contrast, fluid viscosity, pump rate and fracturing procedure on fracture propagation were evaluated for their effect on the resulting SRV. A low-viscosity fluid can activate discontinuities to form a complex fracture network, whereas a high-viscosity fluid is likely to produce large fractures under a high contrast in the horizontal stresses. On the basis of the above-mentioned analyses, a fracturing procedure applying a periodically varying pump rate and shut-in using a low-viscosity fluid was suggested to be an effective approach to enhance the interaction between the hydraulic fractures and discontinuities as well as to increase the fracture length.",58,65,4
Shale Gas,Shale Gas-reservoirs,"Miao, Yanan; Li, Xiangfang; Zhou, Yunjian; Wu, Keliu; Chang, Yucui; Xiao, Zhihua; Wu, Nan; Lin, Wenji",A dynamic predictive permeability model in coal reservoirs: Effects of shrinkage behavior caused by water desorption,Permeability models; Coal reservoirs; Matrix shrinkage effect; Water desorption,SHALE GAS-RESERVOIRS; METHANE PRODUCTION; INORGANIC NANOPORES; SORPTION ISOTHERMS; VAPOR ADSORPTION; CARBON-DIOXIDE; MOISTURE; DIFFUSION; TRANSPORT; PRESSURE,"Forecasting production in coal reservoirs accurately has been of growing interest in the industry. Permeability of coal reservoirs is a key parameter affecting coalbed methane production. In terms of current literature, the dynamic variation of coal permeability mainly depends on the effect of effective stress, coal matrix shrinkage caused by gas desorption and gas slippage during coalbed well drainage. The volume occupied by water in coal matrix was overlooked and its effect on matrix desorption-shrinkage-effect has not been investigated ever. In this work, on the basis of S-D stress-permeability model (Shi and Durucan, 2004), a dynamic prediction model of coal permeability fully considering the effect of effective stress, coal matrix shrinkage caused by gas desorption, gas slippage and coal matrix shrinkage caused by water desorption was established. The dynamic variation of permeability in coalbed methane development was revealed. The reliability of proposed model for permeability variation was successfully verified through the excellent agreements compared with experimental results. In addition, comparisons among the commonly utilized models and the new model indicated that the predicted permeability from the new model is overestimated than other models, such as P-M, S-D, and C-B models. The large differences between the new model and traditional models explicitly stress the necessity and significance of considering the matrix shrinkage effect caused by water desorption on coal permeability, which should not be neglected. Furthermore, based on the proposed permeability model, the influence of relative humidity in coal matrix was seriously paid attention. The four effects for the dynamic permeability of coalbed methane well were compared and analyzed. Results illustrated that relative humidity has an important effect on coal permeability performance, which will increase the dynamic permeability in coal reservoirs. Accordingly, the effect of coal matrix shrinkage caused by water desorption will increase the dynamic permeability in coal reservoirs. The gas slippage has a little effect on dynamic permeability in coal reservoirs.",18,21,8
Shale Gas,non-Darcy Flow,"Wang, Xiukun; Sheng, James J.",Pore network modeling of the Non-Darcy flows in shale and tight formations,Pore network modeling; Non-darcy flow; Tight; Shale; Relative permeability,STEP-DECAY MEASUREMENTS; GAS-FLOW; CARBON NANOTUBES; PETROPHYSICAL INTERPRETATION; RELATIVE PERMEABILITY; NANOPORES; SLIPPAGE; RESERVOIRS; TRANSPORT; OIL,"Pore network modeling is a powerful tool to simulate multiphase flow in porous media. Quasi-static model is used in this work and the drainage displacement process is simulated. In shale and tight formations, there are proposed non-Darcy flow mechanisms: gas non-Darcy flow and liquid low velocity non-Darcy flow. The gas flow in shale and tight formations is generally classified in slip flow and transitional flow regimes according to the Knudsen number values. The BK model (Beskok and Karniadakis, 1999) is used for gas non-Darcy flow in this study and the liquid low velocity non-Darcy flow is mainly based on our previous work (Wang and Sheng, 2017a, b). Both effects are incorporated into our pore network model separately. For gas-water flow, gas is the non-wetting phase with gas non-Darcy flow and water is the wetting phase with Darcy flow. For oil-water flow, the low velocity non-Darcy flow is considered for both water and oil phases. Then our model is applied in 3 cases. Case 1 is the Berea sandstone (Valvatne, 2004), which is the benchmark for conventional pore network modeling. In this case, no non-Darcy flows is considered in our pore network model and it is totally Darcy flow. The absolute permeability and relative permeability are both matched with the experimental data. Case 2 is the Bossier tight gas sandstone (Rushing et al., 2003). Gas apparent permeability vs. pressure was measured at different water saturations in their experiments. In this way, the gas non-Darcy flow in two-phase conditions are verified. Case 3 is the Barnett shale (Moghaddam and Jamiolahmady, 2016), which is our major focus. The two types of non-Darcy flows are studied and further discussed in this case. Specifically, the effect of gas non-Darcy flow enhances the gas permeability 2.66 times of the Darcy permeability when pressure is 10 MPa, while the effect of liquid low velocity non-Darcy flow decreases the liquid permeability to 40% of the Darcy permeability when pressure gradient is 0.1 MPa/m. Two types of relative permeability (k(r)) definition are presented in this study: Darcy permeability based kr and normalized k(r) where non-Darcy permeability is used as the base permeability. In the results, the normalized relative permeability doesn't change much for both non-Darcy flows, which implies that we can probably assume the relative permeability unchanged and just consider the effect on absolute permeability, when we deal with these non-Darcy flow mechanisms.",23,24,2
Shale Gas,non-Darcy Flow,"Wang, HanYi",Discrete fracture networks modeling of shale gas production and revisit rate transient analysis in heterogeneous fractured reservoirs,Discrete fracture network (DFN); Shale gas production; Rate transient analysis (RTA); Complex fracture networks; Naturally fractured reservoirs; Heterogeneous reservoirs,WELL PRODUCTION; LINEAR FLOW; PERMEABILITY; SLIPPAGE; BEHAVIOR; IMPACT,"Horizontal wells with multiple hydraulic fractures are necessary stimulation technique for economically developing tight and shale gas reservoirs. In such reservoirs, the conventional well-test techniques are not suitable because of ultralow formation permeability. Rate transient analysis (RTA) is the widely used tool for analyzing these reservoirs for the purpose of reserves estimation, hydraulic fracture stimulation optimization, and development planning. However, the conventional rate transient analysis is based on the models that were derived from idealistic assumptions for homogenous reservoirs. In this article, we first review the industry's common practice for rate transient analysis and discuss why the idealized conceptual model may not be adequate for analyzing production data from shale gas reservoirs. Then, a unified shale gas reservoir model based on Discrete Fracture Networks (DFN) is presented to investigate how each mechanism influences shale gas production and the corresponding rate transient behavior. It is found that shale gas production and rate transient behavior are significantly impacted by reservoir heterogeneity, fracture networks, non-Darcy flow, gas adsorption and completion efficiency. Short early-time linear flow with long transitional flow period is an indication of either existence of abundant complex fracture networks or heterogeneous completion with unevenly distributed hydraulic fractures. Consider the nature of non-unique results of RTA, information from other independent sources is required to achieve a consistent and holistic interpretation.",23,23,2
Shale Gas,non-Darcy Flow,"Yan, Bicheng; Mi, Lidong; Wang, Yuhe; Tang, Hewei; An, Cheng; Killough, John E.",Multi-porosity multi-physics compositional simulation for gas storage and transport in highly heterogeneous shales,Shale gas reservoir; Compositional simulation; Non-darcy flow mechanism; Triple-porosity model; Discrete fracture network model; Upscaling; Connectivity,DISCRETE-FRACTURE MODEL; RESERVOIR SIMULATION; METHANE ADSORPTION; APERTURE; BEHAVIOR,"Shale gas reservoir is comprised of highly heterogeneous porosity systems including hydraulic/secondary fractures, inorganic and organic matrix. Multiple non-Darcy flow mechanisms in the shale matrix further bring challenges for modeling. In this paper, we developed a framework combining a multi-physics compositional simulator with Multi-Porosity Modeling preprocessor for gas storage and transport in shale. A Triple-Porosity Model is used to characterize the three porosity systems in shale gas reservoirs. In the fracture porosity the heterogeneous impact of secondary fractures distribution on matrix-to-fracture fluid transfer is revealed by shape factor distribution. They are upscaled with superior accuracy from a detailed Discrete Fracture Network Model (DFN) sector model, where orthogonal hydraulic fractures are explicitly discretized. With the occurrence of nanopores in shale matrix, the interaction between pore-wall and gas molecules is considered via Knudsen diffusion and gas slippage. Gas adsorption on the pore-wall of organic matrix is modeled by extended Langmuir isotherm. The inter-porosity and intra-porosity connectivities in the Triple-Porosity Model are flexibly controlled by arbitrary connections. Our results show that gas production in the Triple-Porosity Model with shape factor upscaled from DFN exhibits different production performance from models with uniform shape factor distribution. The deviations are caused by the dominance of different regions at different production periods. Connection topology in the shale gas reservoir is also comprehensively assessed. We demonstrate that the intra-porosity connections in the inorganic and organic matrix have negligible impact on the global gas flux, while the inter-porosity connections have different levels of importance for the gas production. Moreover, different combinations of flow and storage mechanisms are investigated. We show that Langmuir desorption maintains reservoir pressure, but gas slippage and Knudsen diffusion accelerate the pressure drop. Both mechanisms contribute to improve the gas production and the consideration of them simultaneously improve gas production most.",17,17,3
Shale Gas,Supercritical CO2,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Miao, Yanan; Han, Song; Chen, Zhili",Flow simulation of the mixture system of supercritical CO2 & superheated steam in toe-point injection horizontal wellbores,Toe-point injection; Horizontal wellbore; Supercritical CO2; Superheated steam; Inner heat exchange; Friction loss; Energy balance,HEAT-TRANSFER CHARACTERISTICS; 2-PHASE FLOW; OIL-RECOVERY; PERFORMANCE ANALYSIS; NONCONDENSING GASES; THERMAL FLUID; SHALE GAS; MODEL; TEMPERATURE; PREDICTION,"Conventional heavy oil recovery method of saturated steam injection at heel-point of horizontal wellbores is facing comparatively more serious fingering phenomenon. With this, oil companies are now actively developing new recovery method of supercritical CO2 - superheated steam injection in horizontal wellbores with toe-point injection technique. Firstly, considering the heat exchange between the inner tubing (IT) and annuli, a pipe flow model comprised of energy and momentum conservation equations is developed for the mixture flow in both IT and annuli. Then, coupled with the S-R-K real gas model, variable mass flow model and transient heat transfer model in oil layer, a comprehensive mathematical model is established. Numerical solutions of the mixture flow in toe-point injection wellbores are obtained through straight forward numerical method. Finally, model validation and sensitivity analysis are conducted. The results show that: (1). there exists a good agreement between predicted results and field data. The predicted temperature is higher when the heat exchange between IT and annuli is neglected. The predicted temperature is lower when the friction loss item is considered in the energy balance equation. (2). the temperature of the mixture increases when the mixture flows from toe-point to heel-point in annuli due to heat flow from IT to annuli. (3). While the absorption rate of the mixture in formation increases with increasing of the content of supercritical CO2, it can be offset by the decrease of temperature and enthalpy of the mixture. (4). Both of the mixture temperature and formation mixture absorption rate increase with increasing of injection pressure.",59,61,1
Shale Gas,Supercritical CO2,"Liu, Liyuan; Zhu, Wancheng; Wei, Chenhui; Elsworth, Derek; Wang, Jiehao",Microcrack-based geomechanical modeling of rock-gas interaction during supercritical CO2 fracturing,Supercritical CO2 fracturing; Gas adsorption; Internal swelling stress; Rock damage; Numerical simulation,SHALE GAS; CARBON-DIOXIDE; HORIZONTAL WELLS; COAL; PERMEABILITY; PROPAGATION; ADSORPTION; CHALLENGES; CAPTURE; SCALE,"Relative to water-based fluids, non-aqueous fracturing fluids have the potential to increase production, reduce water requirements, and to minimize environmental impacts. Since the viscosity of supercritical CO2 is one-tenth that of water, its density is close to that of water, and is capable of promoting sorptive rejection of methane, it is an attractive substitute for water in the extraction of shale gas and coalbed methane. The following defines a geomechanical model accommodating the interaction of fluid flow, adsorption-induced swelling stress, solid deformation and damage to quantify rock-gas interactions during supercritical CO2 fracturing for shale gas production. The architecture of the shale is accommodated that includes both pore-and micro-crack-based porosity. According to the microcrack model representing shales with low porosity, both analytical and numerical results show that the effective stress coefficient is much smaller than unity. We analyze the potential advantages of fracturing using supercritical CO2 including enhanced fracturing and fracture propagation, increased desorption of methane adsorbed in organic-rich portions of the shale and the potential for partial carbon sequestration. Rock-gas interactions include both the linear poroelastic response and the chemo-mechanical interaction due to sorption. Simulation results demonstrate that supercritical CO2 fracturing indeed has a lower fracture initiation pressure and a significantly lower breakdown pressure, as observed in experiments, and that fractures with greater complexity than those developed with liquid CO2 and water fracturing result. With increasing dynamic viscosity of the fracturing fluids, the predicted breakdown pressure also increases, consistent with experimental observations.",40,43,8
Shale Gas,Supercritical CO2,"Zhou, Dawei; Zhang, Guangqing; Zhao, Pengyun; Wang, Yuanyuan; Xu, Shengfan",Effects of post-instability induced by supercritical CO2 phase change on fracture dynamic propagation,Supercritical CO2 fracturing; Phase change; Post-instability; Equilibrium energy model; Fracture propagation coefficient,CARBON-DIOXIDE; GAS; FLUID; SHALE; WATER; STIMULATION; PRESSURE,"The effects of non-aqueous fracturing on unconventional reservoir stimulation have been investigated by laboratory and field work. Supercritical carbon dioxide (SC-CO2) is a notable non-aqueous fracturing fluid due to its potential to increase production, to reduce water requirements, and to minimize environmental impacts. In this paper, laboratory experiments conducted on polymethyl methacrylate (PMMA) are used to study the post-instability induced by SC-CO2 phase change on fracture dynamic propagation. Experimental results show that the fracture propagating speed of SC-CO2 fracturing is two order greater than that of hydraulic fracturing, and extensive hackle fractures occur in SC-CO2 fracturing. SC-CO2 phase change are mainly responsible for fracture post-instability, which dominates fracture propagation in SC-CO2 fracturing. Meanwhile, an equilibrium energy model of fracture dynamic propagation is proposed to describe the energy variation and transformation in porous medium. The concept of fracture propagation coefficient, i.e., the ratio of energy supplied by injection to fracture energy, is defined. SC-CO2 fracture propagation coefficient is much larger compared to hydraulic fracturing, suggesting that enough kinetic energy can accelerate fracture growth. This research may contribute to field application that SC-CO2 fracturing is likely to be an effective stimulation treatment, even in reservoir of undeveloped natural fractures.",34,35,4
Shale Gas,Molecular Diffusion,"Jia, Bao; Tsau, Jyun-Syung; Barati, Reza","Role of molecular diffusion in heterogeneous, naturally fractured shale reservoirs during CO2 huff-n-puff",Bakken shale reservoirs; Molecular diffusion; Heterogeneity; Correlation length; CO2 huff-n-puff,OIL; INJECTION; RECOVERY,"Shale reservoirs are characterized by high degree of heterogeneity and ultra-low matrix permeability. Natural fracture (both macro and micro) systems are important to increase the performance of shale reservoirs by providing flow path for the hydrocarbon from the nanopores in the matrix to the wellbore. Configurations of natural fractures also have significant implications for the recovery performance of shale gas and oil reservoirs. CO2 huff-n-puff or cyclic injection has been suggested to be a feasible way to recover oil from shales and the flow process is complex. Molecular diffusion is an important transport mechanism of the mixture of CO2 and oil, especially in tight formations. Based on these knowledge, various configurations of the natural fracture system in shale reservoirs with the dual porosity and dual permeability model were constructed, regarding Dykstra-Parsons (DP) coefficient and correlation length. Dykstra-Parson (DP) coefficient ranges from 0.40 to 0.78, and correlation length ranges from 50 ft to 3000 ft. Based on the geological setting of the Middle Bakken formation and the Bakken live oil PVT data, compositional models were performed to simulate the CO2 huff-n-puff process. CO2 injection begins after the primary recovery factor reaches 3% and both multiple-cycle and single-cycle of injection were investigated regarding the oil recovery performance and CO2 injectivity behavior. In the multiple-cycle scheme the period of one cycle is short; the injection, soak and production time are 10 days, 10 days and 100 days, respectively. In the single-cycle scheme, the period of one cycle is long, and gas injection volume is set to be constant with the soak time of 100 days. The impact of molecular diffusion during the huff-n-puff process is compared in different simulation scenarios. Findings in this work reveal the importance of the configuration of the pre-existing natural fracture system for the performance of the huff-n-puff process. Reservoir heterogeneity hampers primary production. However, during the puff production process, the negative impact of heterogeneity is less as the correlation length increases when the molecular diffusion is taken into account. There exists a threshold correlation length value wherein heterogeneity becomes favorable for improved oil recovery instead of hampering oil recovery, after taking into account of the molecular diffusion, which is approximately 1500 ft in this simulation study. The value of correlation length also affects the performance of multiple-cycle and single-cycle huff-n-puff processes differently because CO2 injectivity behavior is different in reservoirs characterized by different DP coefficients and correlation length: there exists a threshold time point when a longer correlation length begins to favor the injectivity, and the threshold time point is delayed for a scenario with a larger DP coefficient.",41,42,2
Shale Gas,Molecular Diffusion,"Zhang, Yuan; Yu, Wei; Li, Zhiping; Sepehrnoori, Kamy",Simulation study of factors affecting CO2 Huff-n-Puff process in tight oil reservoirs,CO2 Huff-n-Puff; Nanopore confinement; Molecular diffusion; Minimum miscibility pressure; Tight oil,SHALE; RECOVERY; FLUID; GAS; PERMEABILITY,"CO2 injection is one of the effective enhanced oil recovery (EOR) methods in conventional oil reservoirs, which has been widely applied in the tight oil reservoirs. Although there are some efforts on the investigation of engineering parameters such as fracture half-length, fracture conductivity, and fracture height, the effects of CO2 molecular diffusion, nanopore confinement, and stress-dependent deformation on CO2-EOR effectiveness are poorly understood. In this paper, we modified the conventional phase-equilibrium model to accurately compute the phase behavior in shale nanopores. Subsequently, we investigated the minimum miscibility pressure (MMP) of CO2-EOR process under different pore sizes. Afterwards, we evaluated the well performance of CO2 Huff-n-Puff process by fully capturing physics of CO2 molecular diffusion and nanopore confinement. The impacts of matrix permeability, CO2 injection rate and stress-dependent deformation mechanisms on the CO2 Huff-n-Puff process are examined in detail. The results show that CO2 diffusion and nanopore confinement play an important role in improving the oil recovery factor, which should be correctly implemented in reservoir simulation model. Additionally, matrix permeability, CO2 injection rate, and stress-dependent deformation mechanisms significantly influence the CO2 Huff-n-Puff process. This work enables operators to optimize the CO2 Huff-n-Puff process to improve the efficiency of CO2-EOR and CO2 storage in tight oil reservoirs.",40,43,2
Shale Gas,Polymer Adsorption,"Al-Ameri, Aymen; Gamadi, Talal; Ispas, Ion",Evaluation of the near fracture face formation damage caused by the spontaneously imbibed fracturing fluid in unconventional gas reservoirs,Fracturing fluid spontaneous imbibition; Friction reducer pad fluid; Polymer adsorption; Nonionic surfactant; Bedding plane; Imbibition capillary pressure; Imbibition water relative permeability curves,SPONTANEOUS IMBIBITION; POROUS-MEDIA; RELATIVE PERMEABILITY; CAPILLARY RISE; SHALE; GRAVITY,"In the present study, spontaneous imbibition experiments, steady-state permeability measurements, and numerical simulation were integrated to quantify the changes in the effective water permeability, capillary pressure, and water relative permeability curves due to the polymer adsorption of the spontaneously imbibed fracturing fluid. The effect of the nonionic surfactant and core bedding plane on the fluid spontaneous imbibition volumes were also investigated. The researchers considered the impact of the spontaneous imbibition of a friction reducer fluid in tight sand and shale core samples. Three comparative systematic spontaneous imbibition experiments were conducted for each of the core samples using brine, anionic friction reducer fluid, and brine again. The core sample water permeability before and after the imbibition experiment was measured using a constant rate steady-state permeability apparatus. The polymer adsorption from the spontaneously imbibed fracturing fluid significantly reduced the brine spontaneous imbibition volumes in tight sand samples and in shale samples, though to a lesser degree. Moreover, the effective water permeability was decreased because of the polymer adsorption effect. Therefore, the polymer adsorption during hydraulic fracturing reduces the fluid leak-off into the formation and also the fluid flowback. The nonionic surfactant increased the fluid spontaneous imbibition volumes in both tight sand and shale samples. Thus, adding a nonionic surfactant to the friction reducer pad fluid during hydraulic fracturing leads to enhance both of the fluid leak-off and fluid flowback. The results also showed that the effect of polymer adsorption on the imbibition rates is less when the rock-fluid contact surface is parallel to the bedding plane. The imbibition potentials and imbibition capillary pressure curves were calculated before and after polymer adsorption. The polymer adsorption led to a slight increase in the capillary pressure; moreover, the tight sand samples had higher capillary pressure than the shale samples. The imbibition water relative permeability curves were calculated using ECLIPSE commercial simulator. The polymer adsorption significantly reduces the water relative permeability curves for tight sand samples and in less degree for shale samples.",24,24,6
Shale Gas,Polymer Adsorption,"Zhang, Xianmin; Jiang, Guancheng; Dong, Tengfei; Wang, Le; Li, Xinliang; Wang, Guoshuai",An amphoteric polymer as a shale borehole stabilizer in water-based drilling fluids,Borehole stabilizer; Amphoteric polymers; Shale hydration; Micro-nanometer plugging; Water-based drilling fluid,ELEVATED-TEMPERATURE; WELLBORE INSTABILITY; POLYACRYLAMIDE; NANOPARTICLES; SPECTROSCOPY; WELLS; MUDS,"An amphoteric polymer P (acrylamide-styrene-butyl acrylate) (ASBA) was evaluated for use as a shale borehole stabilizer and for its ability to counter the problem of well instability during shale gas exploration and development. The hydrophilic groups in the ASBA increased the adsorption between the ASBA and the shale formation and the hydrophobic groups reduced the hydrophilicity of the sodium bentonite (BT). The addition of 1.6 wt% ASBA resulted in a water contact angle of the BT/ASBA that was more than 40 degrees larger than that of the BT. The amount of linear swelling decreased by 37.81% and the hot-rolling recovery rate of the shale cuttings was more than 60% higher in the 1.6 wt% ASBA solution than in deionized water. The ASBA exhibited micro/nanometer globules with an average diameter of 250.4 nm in aqueous solution. This was in agreement with the results of the morphology tests (scanning electron microscopy (SEM) and transmission electron microscopy (TEM)). The morphology tests, elemental analysis, and thermogravimetric analysis showed that the polymer was evenly dispersed in the aqueous solution and effectively adsorbed onto the BT instead of the free water. The soft globules changed under pressure and effectively plugged the various pores in the formation. Due to the hydrophobicity and the plugging effect, the ASBA prevented the BT aggregation and reduced the filtration loss; the American Petroleum Institute (API) filtration loss of the basic mud containing 1.6 wt% ASBA was reduced by 56.67% compared to the basic mud without ASBA after aging at 150 degrees C. Due to the excellent inhibition of the shale hydration and the micro/nanometer plugging performance, the ASBA has a potential application as a borehole stabilizer in drilling fluids.",19,20,4
Degrees C.,Heavy Oil,"Patel, Harshkumar; Shah, Subhash; Ahmed, Ramadan; Ucan, Sezai",Effects of nanoparticles and temperature on heavy oil viscosity,Heavy oil; Nanoparticles; Rheology; Viscosity reduction; Oil recovery; Optimum concentration,RECOVERY; AQUATHERMOLYSIS,"The objective of this research is to investigate the efficacy of nanoparticles in reducing the viscosity of heavy oil. In this study, three types of metal oxide nanoparticles (CuO, Fe2O3, and NiO) are employed, and their effect on heavy oil viscosity is examined at three different concentrations (0.05, 0.1, and 0.5 wt.% of oil). For all test fluids, rheological measurements were obtained at four different temperatures ranging from 27 to 71 degrees C. The experimental work is conducted with two extremely viscous heavy oil samples having viscosity of approximately 77 and 350 Pas at ambient temperature. This study is unprecedented in terms of viscosity of heavy oil samples investigated. The heavy oil samples used in this study are 9-40 times more viscous than those used in previous similar studies. The addition of nanoparticles resulted in a notable reduction in viscosity of both heavy oil samples. For each type of nanoparticles, 50-70% viscosity reduction was observed. The level of viscosity reduction is sensitive to the types of nanoparticles, their concentration, and fluid temperature. Moreover, the results indicate existence of an optimum concentration of nanoparticles at which maximum viscosity reduction occurs. This optimum concentration is a function of the metal type and fluid temperature. To explain observed viscosity alteration behavior, the paper provides a theoretical overview of various molecular-level physical and chemical interactions between nanoparticles and heavy oil. Additionally, the study presents a new heavy oil viscosity data and delineates some of the challenges associated with viscosity measurement of heavy oil. This research provides valuable information for future rheological and core-flooding studies involving nanoparticle stabilized solvent-based emulsions. Besides, remarkable viscosity reduction obtained in this work reinforces the industry's interest in developing an economically feasible nanoparticle-based technique and helps to solve real problems in the field.",30,31,10
Degrees C.,Heavy Oil,"Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Yuan, Chengdong; Zhang, Jizhou; Han, Xiaoqiang; Yang, Yang; Peng, Xiaoqiang; Wu, Junxue",Comprehensive investigations into low temperature oxidation of heavy crude oil,Low temperature oxidation; Heavy crude oil; Thermal behavior; Kinetics; Coke; Oxidized oil,IN-SITU-COMBUSTION; AIR INJECTION; SARA FRACTIONS; KINETICS; RECOVERY; LIGHT; BEHAVIOR; RESERVOIRS; PYROLYSIS; TGA/DSC,"Due to the significance of low temperature oxidation (LTO) process on the subsequent oxidation reactions and oil recovery for in situ combustion (ISC), this work aimed at conducting a series of comprehensive investigations into LTO of heavy crude oil. The LTO behavior of heavy oil was analyzed by static oxidation experiments. Then the alterations in oil characteristics due to LTO were investigated through coke content measurements, flammability tests and scanning electron microscopic (SEM) observations. Additionally, the effect of LTO on thermal behavior and kinetics of heavy oil was researched using thermogravimetry (TG)/differential scanning calorimetry (DSC) technique. The results showed that the temperature played a crucial role in LTO of heavy oil. Almost no coke was deposited at 80 degrees C. The amount of coke deposition at 160 degrees C averaged 0.346 g coke/g oil, which was roughly 4.2 times higher than that at 120 degrees C. The oxidized oil at 160 degrees C possessed the most superior flammability at ambient temperature and atmospheric pressure in comparison to that at 80 and 120 degrees C. The surface morphologies of oxidized oil at 160 degrees C and its formed coke were quite rough, which boosted the subsequent combustion reactions. The results of TG/DSC unravelled that the oxidized oils were subjected to higher mass loss and exothermic effect at the fuel deposition (FD) and high temperature oxidation (HTO) stages as compared to crude oil. After the static LTO, the activation energy in the LTO and FD stages for heavy oil was increased, while that in the HTO stage was reduced. Compared with crude oil and oxidized oils, the coke deposited during the static LTO presented the highest thermal release and reaction activity in the HTO interval. This paper can provide some new insights regarding LTO mechanisms of heavy oil to rich the ISC technology.",27,32,1
Degrees C.,Heavy Oil,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Li, Xiangfang; Li, Qian; Yang, Jian; Wu, Jiqiang",A coupled model for CO2 & superheated steam flow in full-length concentric dual-tube horizontal wells to predict the thermophysical properties of CO2 & superheated steam mixture considering condensation,Heavy oil recovery; Concentric dual-tube wells; Multi-point injection technique; CO2 coupled with superheated steam; Wellbore hydraulics,HEAT-TRANSFER CHARACTERISTICS; MASS-TRANSFER CHARACTERISTICS; MULTICOMPONENT THERMAL FLUID; 2-PHASE FLOW; NONCONDENSING GASES; NONISOTHERMAL FLOW; SUPERCRITICAL CO2; CURVE ANALYSIS; OIL-RECOVERY; INJECTION,"The mixture of CO2 and superheated steam (SHS) has been proved effective for heavy oil recovery by field practices. It has been proved that the development effect is closely related to the state parameters (temperature, pressure and superheated degree etc.) of the mixture. As a result, wellbore modeling is an important branch in the study of thermal recovery of heavy oil. In recent years, concentric dual-tube wells (CDTW) coupled with multi-point injection technique (MPIT) is proposed to overcome the fingering phenomenon, induced by serious reservoir heterogeneity, during the steam injection process. In this paper, a wellbore model is developed for simulating CO2 & SHS flow in a full-length CDTW. The model is solved with finite difference method on space. It is found that: (a) An injection pressure, higher than 4.1 MPa, in the integral joint tube (IJT) or an injection pressure, smaller than 4.1 MPa, in annuli are recommended to obtain a uniform steam absorption rate along the horizontal wellbores. (b) The mass injection rate at well-head condition should be close to each other to avoid un-uniform of steam absorption rate along the horizontal wellbores. (c) When phase change occurs in the annuli, the mixture temperature increases with increasing CO2 content. (d) The total length of wet steam flow in the horizontal section of the wellbores increases with increasing CO2 content.",27,28,0
Degrees C.,Heavy Oil,"Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Yuan, Chengdong; Pan, Jingjun; Wang, Ruyan; Chen, Long; Kan, Ni",Low-temperature oxidation of light and heavy oils via thermal analysis: Kinetic analysis and temperature zone division,Low-temperature oxidation; Light and heavy oils; Thermal analysis; Kinetic analysis; Temperature zone division,PRESSURE AIR INJECTION; CRUDE-OIL; THERMOGRAVIMETRIC ANALYSIS; COMBUSTION KINETICS; SARA FRACTIONS; PYROLYSIS; BEHAVIORS; RECOVERY; MODEL; DECOMPOSITION,"This research is intended to investigate low-temperature oxidation (LTO) behavior and kinetics of light and heavy oils and to divide their LTO intervals. Ramped thermogravimetry/derivative thermogravimetry (TG/DTG) and differential scanning calorimetry (DSC) experiments and isothermal TG experiments with different temperature intervals were used to characterize LTO behavior and to obtain kinetic parameters determined by Ozawa-Flynn-Wall (OFW) and general reaction rate models. The results indicated that there were three (two) distinct variation trends about the conversion rate versus temperature for light (heavy) oil in the LTO region, manifesting the LTO interval of light (heavy) oil should be controlled by multiple-step mechanisms and divided into at least three (two) reaction subintervals. The LTO interval of both light and heavy oils used could be subdivided into three temperature intervals inferred from the variation trend of activation energy over temperature for ramped experiments. Additionally, the LTO region of both light and heavy oils held three subzones in the aspect of isothermal tests. For light oil, the reaction rate augmented from 50 to 250 degrees C where the activation energy was positive, while it reduced from 250 to 350 degrees C coupled with negative activation energy. As for heavy oil, the reaction rate presented an increasing trend in the first and third subintervals (50-150 degrees C and 250 350 degrees C) with positive activation energy and a declining trend in the second subinterval (150 250 degrees C) with negative activation energy. It is believed that this research can add new insights to the LTO interval division of crude oil regarding to the isothermal and non-isothermal conditions, which are of significance for understanding LTO reaction pathways and mechanisms.",26,27,1
Degrees C.,Heavy Oil,"Sepehri, Sanam; Soleyman, Rouhollah; Varamesh, Akbar; Valizadeh, Majid; Nasiri, Alireza",Effect of synthetic water-soluble polymers on the properties of the heavy water-based drilling fluid at high pressure-high temperature (HPHT) conditions,Water-based drilling fluid; Fluid loss; Synthetic polymer; High temperature-high pressure conditions,ACRYLAMIDE,"Nowadays, by rising age of oil wells, the utilization of high pressure-high temperature (HPHT) additives in deep well drilling is unavoidable. In this study, a terpolymer of acrylamide/2-acrylamido-2-methyl propane sulfonic acid/N-vinyl caprolactam and a tetrapolymer of acrylamide/2-acrylamido-2-methyl propane sulfonic acid/3-allyl Oxy-2-hydroxy-1-propane sulfonic acid/acrylic acid were synthesized by solution polymerization and characterized by Fourier transform-infrared (FTIR) spectroscopy, thermal gravimetric analysis (TGA) and hydrogen nuclear magnetic resonance ((HNMR)-H-1) techniques. The effect of crosslinking agent, transfer agent and comonomer contents of the synthesized polymers on the fluid loss and the rheological properties of the heavy drilling fluid containing these synthesized products were studied. The stability and performance of the tetrapolymer were better in the heavy drilling fluid at high temperature and high salt concentration. The fluid losses of the prepared heavy drilling fluid by tetrapolymer were 1.9 and 2.1 cc/30 min in NaCl saturated water and formation water of Iran reservoirs at 150 degrees C, respectively.",24,28,2
Degrees C.,Heavy Oil,"Gu, Xuefan; Zhang, Fan; Li, Yongfei; Zhang, Jie; Chen, Shijun; Qu, Chengtun; Chen, Gang",Investigation of cationic surfactants as clean flow improvers for crude oil and a mechanism study,Cationic surfactants; Crude oil; Flow improver; Viscosity; Pour point,RELATIVELY LOW-TEMPERATURE; HEAVY OIL; CANOLA OIL; AQUATHERMOLYSIS; COMPLEX; COPOLYMER,"Cetyl trimethyl ammonium chloride (CTAC), cetyl trimethyl ammonium bromide (CTAB), and octadecyl trimethylammonium chloride (OTAC) were evaluated as clean flow improvers for crude oil. The results showed that all of them have some effect on the viscosity of crude oil in a certain temperature range, and can depress the pour point, among which CTAC is the most potent one. The viscosity was reduced to below 540 mPa s under different concentration at 35 degrees C by CTAC, and it can depress the pour points by 7.5 degrees C with the concentration of 0.03%. DSC analysis and microscopic morphology analysis discovered the interaction of CTAC and saturated hydrocarbon component of the crude oil, which can reduce the wax peak temperature and wax precipitation point of crude oil. CTAC may precipitate and pack with the long-chain alkane to form the crystal nucleus, while the cationic part and the corresponding Cl- anion can act as a wax crystal modifier and block the wax crystal to grow up, thereby reduce the risk to form three-dimensional networks.",23,24,2
Degrees C.,Heavy Oil,"Wang, Chao; Liu, Pengcheng; Wang, Fushun; Atadurdyyev, Bayramberdi; Ovluyagulyyev, Mergen",Experimental study on effects of CO2 and improving oil recovery for CO2 assisted SAGD in super-heavy-oil reservoirs,Super-heavy oil reservoir; Steam assisted gravity drainage (SAGD); Reduce viscosity; Carbon dioxide; Thermal oil recovery,GRAVITY DRAINAGE; STEAM; EOR; PERFORMANCE; INJECTION; SEQUESTRATION; MECHANISM; PRESSURE; BEHAVIOR; SOLVENT,"When developing heavy-oil reservoirs using steam-assisted gravity drainage (SAGD) technology, CO2 is often used to reduce the viscosity of heavy oil and the heat loss of the steam chamber, thereby enhancing oil recovery. The limitation of experimental apparatuses, results in a maximum temperature of the reaction kettle of no more than 150 degrees C. Thus, the solubility of CO2 in super-heavy oil and its impact on decreasing viscosity beyond 150 degrees C requires further discussion. Considering these issues, a high-temperature-resistant heavy-oil mixing apparatus was designed to measure the solubility of CO2 in super-heavy oil and the relative density and viscosity of super-heavy oil under high temperatures and pressures. Core flooding experiments under 200 degrees C were conducted to explore the effects of CO2 on oil displacement efficiency. The results indicated that solubility of CO2 became significantly lower at 200 degrees C, when the viscosity and relative density of super-heavy oil decreased as pressure increased. The viscosity of super-heavy oil saturated with CO2 decreased by 71.2%, and relative density decreased by 10.1% at 200 degrees C compared to those of degassed crude. At temperatures of 120 degrees C, 150 degrees C and 200 degrees C, the ultimate displacement efficiency of super-heavy oil increased by 6.6%, 19.2% and 21.4%, respectively, compared to a temperature of 60 degrees C. At pressures of 1.0 MPa, 2.0 MPa and 4.0 MPa, the ultimate displacement efficiency (46.7%) of super-heavy oil increased by 5.2%, 4.0% and 5.9%, respectively, compared to a pressure of 0.5 MPa. The experiments showed that CO2 injection can effectively reduce the relative density and viscosity of super-heavy oil and improve oil recovery under high temperatures and pressures. CO2 has good potential to improve SAGD efficiency in developing super-heavy-oil reservoirs.",20,21,4
Degrees C.,Heavy Oil,"Lashkarbolooki, Mostafa; Riazi, Masoud; Ayatollahi, Shahab",Effect of CO2 and crude oil type on the dynamic interfacial tension of crude oil/carbonated water at different operational conditions,Dynamic IFT; Carbonated water; CO2; Adsorption time; Temperature; Pressure,CARBONATED WATER; AQUEOUS-SOLUTIONS; INJECTION; RECOVERY; PH; EQUILIBRIUM; TEMPERATURE; PERFORMANCE; ASPHALTENE; ADSORPTION,"Concerns about climate change have persuaded the researchers to examine CO2 injection in the form of carbonated water (CW) into oil reservoir as a safe and effective CO2 storage and enhanced oil recovery process. Although interfacial tension (IFT) between crude oil and injected fluid has a vital role on the displacement of fluids in porous media, the effect of CO2 and crude oil type on the dynamic IFT of crude oil under different operational conditions is not well understood. Accordingly, this study was carried out to assess the effects of temperature, pressure, crude oil type and CO2 on the dynamic IFT of crude oil/CW. To achieve this goal, two types of crude oil were provided from southern Iranian oil reservoirs and dynamic IFTs with CW were measured in a wide range of temperatures and pressures (i.e. temperature range of 30-80 degrees C and pressure range of 500-4000 psi); the obtained results were compared with the system without CO2. In addition, the adsorption time of carbonated aqueous phase/crude oil, obtained based on the mono exponential decay model, was also compared with unadulterated water/crude oil system. The outcome of this study showed that crude oil type has the most significant effect on the IFT of crude oil/CW compared to pressure, temperature and CO2 content. In more details, the IFT of crude oil/CW can be affected by the amount and type of acidic/basic components in the crude oil as well as pH of the aqueous solution. Besides, the obtained results revealed that the effect of temperature was more considerable on the IFT of the heavy crude oil compared with the light crude oil in both studied aqueous solutions (i.e. unadulterated water and CW). Although the inversion phase temperature was obtained for unadulterated water/studied crude oils at all studied pressures, this phenomenon was not observed for crude oil/CW at elevated pressure, due to the high amount of CO2 at this condition.",17,17,3
Degrees C.,Heavy Oil,"Nasri, Zarrin; Mozafari, Motahareh",Multivariable statistical analysis and optimization of Iranian heavy crude oil upgrading using microwave technology by response surface methodology (RSM),Heavy crude oil; Upgrading; Microwaves; Response surface methodology,ULTRASONIC IRRADIATION; HORIZONTAL WELL; DEMULSIFICATION; EMULSIONS; PERFORMANCE; PYROLYSIS; RECOVERY,"Conventional methods to upgrade heavy oil due to high pressure, low production efficiency, and low product quality have not been recognized as profitable methods. These complications resulted in using innovative technologies in this area. In this paper, the statistical analysis and process conditions optimization of Iranian heavy crude oil upgrading have been performed using microwave technology, for the first time. The heavy crude oil is from Iranian west Paydar field, with specifications including API 18.53, viscosity 78.76 cSt (at 20 degrees C). In order to optimize process conditions for upgrading heavy crude oil, independent variables include power level (40-70-100%), process time (5-12.5-20) (min), activated carbon as sensitizer (0-5-10) (wt%), and Fe as catalyst (0-3-6) (wt%). Surface temperature, API ratio, viscosity ratio, and asphaltene reduction have been considered as response variables. The Box-Behnken design and response surface methodology (RSM) have been applied to determine parameters levels and to model the responses, respectively. The results show that the optimal conditions to maximize surface temperature, API ratio, and asphaltene reduction, and to minimize viscosity ratio involve power level of 100%, process time of 20 min, activated carbon of 10 wt%, Fe catalyst of 4.06 wt% which leads to 23.31API ratio, 31.6% asphaltene reduction, and 43.37% viscosity reduction. The predicted conditions agreed with the experimental values, representing the models accuracy.",16,17,3
Degrees C.,Heavy Oil,"Foss, Lev; Petrukhina, Natalia; Kayukova, Galina; Amerkhanov, Marat; Romanov, Gennady; Ganeeva, Yulia","Changes in hydrocarbon content of heavy oil during hydrothermal process with nickel, cobalt, and iron carboxylates",Heavy oil; Catalyst precursors; Changes in oil content; Heavy oil upgrading; Hydrothermal process (aquathermolysis); Hydrogen donor,HIGH-TEMPERATURE HYDROLYSIS; AQUEOUS ORGANIC-CHEMISTRY; CATALYTIC AQUATHERMOLYSIS; CRUDE-OIL; ATHABASCA BITUMEN; SANDS; WATER; TETRAHYDROTHIOPHENE; NANOCATALYSTS; NANOPARTICLES,"We conducted autoclave modeling experiments to study the process of upgrading heavy oil in the reservoir conditions and used carboxylates of transition metals (Ni, Co, Fe) as catalyst precursors. The process was carried out at temperatures of 250, 300, and 350 degrees C in the presence of a naphthenoaromatic hydrogen donor. We found that significant content changes of oil occur at temperatures of 300 and 350 degrees C accompanied by an increase of light fractions and a decrease of high molecular weight hydrocarbons. We studied the hydrocarbon composition of the initial oil and the products of the hydrothermal process as well as tetralin (proton donor) transformations to determine the patterns of influence of the process conditions and catalyst precursors.",15,16,3
Degrees C.,Heavy Oil,"Taheri-Shakib, Jaber; Shekarifard, Ali; Naderi, Hassan",The study of influence of electromagnetic waves on the wettability alteration of oil-wet calcite: Imprints in surface properties,Wettability; Heavy oil; Microwave; Calcite; Polar,APPEARANCE TEMPERATURE WAT; CONTACT-ANGLE; RECOVERY; MICROWAVE; SALINITY; CARBONATE; ROUGHNESS; IMPACT; TIME; GAS,"The wettability of reservoir rock is one of the fundamental parameters determining the flow of fluid in the porous media. This study has investigated the effect of microwaves on the wettability of calcite reservoir rock from Yaran, Iran, as the time interval of microwave radiation is one of the most important parameters affecting wettability. The reservoir rock samples were placed in a microwave oven filled with helium gas and subjected to microwave radiation at 5-min intervals from 5 to 35 min. Measurements of the contact angle between the oil and the rock indicated that the microwaves brought the angle from about 120 degrees primary state to 93 degrees at 35 min. At intervals of 5-15 min, no change in the wettability of the oil-wet rock was observed. Sulfur components had high absorption coefficients of microwaves, so initially reduced the amount of sulfur (S) on the surface of the oil-wet rock. Next, the nitrogen (N) and oxygen (O) elements were reduced, and eventually the carbon (C) levels began to decrease. This trend was observed in the zeta potential by changing the surface charge of the rock. Indeed, eliminating SNO polar compounds with a high potential for absorbing microwave caused the rock to become water-wet. Microwave radiation initially produced no change in the Fourier-transform infrared spectroscopy (FTIR) spectrum, as it continued, the peak intensity of the corresponding oil, such as the carboxylic acid functional group, declined, and the corresponding peaks of the rock became more intense, indicating a gradual change in the wettability. It can be interpreted that the aromatic compounds exist in oil and act as surface agent components. The results of this study can be used as a representation of the use of microwave radiation in hydrocarbon reservoirs to change the wettability and increase the production rate of reservoirs.",15,15,0
Degrees C.,Heavy Oil,"Mehrabi-Kalajahi, Seyed Saeed; Varfolomeev, Mikhail A.; Yuan, Chengdong; Emelianov, Dmitrii A.; Khayarov, Khasan R.; Klimovitskii, Alexander I.; Rodionov, Alexander A.; Orlinskii, Sergei B.; Gafurov, Marat R.; Afanasiev, Igor S.; Fedorchenko, Gennadii D.; Lubnina, Elena V.",EPR as a complementary tool for the analysis of low-temperature oxidation reactions of crude oils,Crude oil; In-situ combustion; Air injection; Oxidation; EPR; Free radical concentration,IN-SITU COMBUSTION; VANADYL-PORPHYRIN COMPLEXES; SARA FRACTIONS; PARAMAGNETIC-RESONANCE; KINETIC-ANALYSIS; AIR INJECTION; HEAVY OIL; LIGHT; ASPHALTENES; BEHAVIOR,"Air injection is a promising method for enhanced oil recovery (EOR) in both conventional and unconventional oil sources. It is widely accepted that oxidation reactions between oil and injected air determine the success of an air injection process. In this study, electron paramagnetic resonance (EPR) was introduced as a new route to investigate the occurrence of low-temperature oxidation (LTO) and its behavior by monitoring the signals of free radicals. The EPR experiments were conducted for the different crude oil samples (light, medium and heavy) heated in both static air and flow air (air-bubbling) conditions under different temperatures from 25 degrees C to 180 degrees C. The results showed that the free-radical concentrations exhibited a good correspondence on the heating temperature. Furthermore, nuclear magnetic resonance (NMR), Fourier-transform infrared spectroscopy (FTIR) and differential scanning calorimetry (DSC) experiments were carried out to help to analyze the oxidation process and verify the EPR results. It turned out that the EPR results can be well supported by NMR, FTIR and DSC data, which indicates that proposed EPR monitoring method can be applied as a fast and low-cost technique to investigate LTO under mild reaction conditions. Simultaneously, the combination of EPR, NMR, FTIR and DSC can help to better understand the LTO mechanism and to monitor the application of in-situ combustion technique in the field.",14,14,1
Degrees C.,Enhanced Oil-recovery,"Da, Chang; Alzobaidi, Shehab; Jian, Guoqing; Zhang, Leilei; Biswal, Sibani L.; Hirasaki, George J.; Johnston, Keith P.",Carbon dioxide/water foams stabilized with a zwitterionic surfactant at temperatures up to 150 degrees C in high salinity brine,CO2-in-water foam; Zwitterionic surfactant; Porous media; EOR,ENHANCED OIL-RECOVERY; WORMLIKE MICELLES; CONCENTRATED EMULSIONS; SUPERCRITICAL FLUIDS; MOBILITY CONTROL; MIXED-SOLUTIONS; AQUEOUS-PHASE; POROUS-MEDIA; YIELD-STRESS; ADSORPTION,"Stabilization of CO2-in-water (C/W) foams with surfactants at high temperature and high salinity conditions is challenging given limitations in the solubility and thermal stability of surfactants, particularly for surfactants other than anionic ones. Here we show that a single zwitterionic surfactant, cetyl betaine (CH3(CH2)(15)N+(CH3)(2)CH2COO-), stabilizes viscous C/W foam (> 15 cP) in crushed limestone (76-Darcy) at a temperature up to 150 degrees C and over a wide range in salinity up to 22% total dissolved solids (TDS) at superficial velocity of 940 ft/day. According to liquid chromatography mass spectrometry (LC/MS), cetyl betaine has high thermal stability with negligible chemical degradation after incubation at 135 degrees C for 30 days. Interfacial tension (IFT) at the C/W interface was reduced significantly from similar to 37 mN/m to < 5 mN/m with the addition of 0.08 mmol/L of cetyl betaine. Relative to ionic surfactants, the relatively weak electrostatic repulsion between the local charges in the headgroup is shown to produce strong adsorption at the C/W interface (similar to 134 angstrom(2)/molecule), resulting in generation of viscous foam (similar to 6 cP) even in pure water without added salt. At a low superficial velocity of 6 ft/day (shear rate 45 s(-1)) in a beadpack, foam was still formed with cetyl betaine. Static adsorption of cetyl betaine on carbonates was on the order of 1 mg/m(2), and core flood test also proved that cetyl betaine could stabilize viscous C/W foam (> 20 cP) within 6 pore volumes of injection at 120 degrees C. The surfactant stabilized viscous C/W foam at low oil fractions and broke in the presence of large fractions of oil, both of which are desirable in CO2 mobility control and oil displacement. The ability to form foams at high temperatures and over a wide range in salinity is important for various practical applications including CO2 enhanced oil recovery, fracturing with energized fluids and CO2 sequestration.",46,48,19
Degrees C.,Enhanced Oil-recovery,"Goswami, Rishiraj; Chaturvedi, Krishna Raghav; Kumar, Ravi Shankar; Chon, Bo Hyun; Sharma, Tushar",Effect of ionic strength on crude emulsification and EOR potential of micellar flood for oil recovery applications in high saline environment,Crude oil; Emulsion; Micellar flood; Rheology; SDS; Salt,NANOPARTICLE-SURFACTANT-POLYMER; IN-WATER EMULSIONS; INTERFACIAL-TENSION; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; HIGH-TEMPERATURE; SYSTEM; BEHAVIOR; CALCIUM; STABILITY,"Micellar flooding is one of the chemical oil recovery techniques in which micelle action emulsifies the crude oil to be mobilized in form of emulsion from a subsurface porous media. However, the subsurface conditions such as high ionic strength and temperature are challenges to the successful use of micellar flood owing to the deterioration of micelle action suggesting no crude emulsification. The ionic compounds dissociate into different ions that may further affect micelle action via loss in viscosity and pressure drop, increased water cut, and mobility contrast between micellar flood and displaced oil. Thus, investigation leading to the successful use of micellar flood, context to crude emulsion, in extreme salinity and temperature is vital to extend the use of chemical methods in new reservoirs. In this work, a typical surfactant sodium dodecyl sulfate (SDS) solution with critical micelle concentration (0.8 wt%) was tested to emulsify a fresh crude oil in the presence of varying ionic strength (0-4 wt%, NaCl/CaCl2 and temperature (40-98 degrees C). The efficacy of SDS micelles to produce crude emulsion significantly reduced with increasing salt concentration as reported through microscopic, rheological, and flooding experiments, particularly for divalent salt (CaCl2) than monovalent salt (NaCl). The increase in temperature (> 40 degrees C) further curtailed the growth of crude emulsion, mainly due to enhanced droplet coalescence; thus the use of micellar flood is critical in a reservoir enriched with high salinity and high temperature. Salinity effect on emulsion viscosity is reported through rheological measurements. The study highlighted important aspects of surfactant flooding and is a forward step towards the use of SDS based micellar flood at complex reservoir conditions.",29,28,1
Degrees C.,Enhanced Oil-recovery,"Xie, Binqiang; Ting, Li; Zhang, Yan; Liu, Chen",Rheological properties of bentonite-free water-based drilling fluids with novel polymer viscosifier,Water-soluble polymers; Viscosifier; Thermo-thickening; Rheology; Bentonite-free drilling fluid,ACRYLAMIDE-BASED TERPOLYMER; ENHANCED OIL-RECOVERY; AQUEOUS-SOLUTION; GRAFT-COPOLYMERS; THERMOASSOCIATIVE COPOLYMERS; CELLULOSE NANOPARTICLES; FORMATION DAMAGE; PERFORMANCE; BEHAVIOR; ADDITIVES,"Water-based drilling fluids with no bentonite content was particularly advantageous in oil and natural gas exploration due to the excellent characteristics including faster rates of penetration, enhanced hole cleaning, less formation damage, etc. However, how to keep the excellent rheological regulation of bentonite-free drilling fluids was still one of the most serious issues for the mud designers. In this study, novel polymer viscosifier (SDKP) was prepared under optimal synthesis conditions through the copolymerization of N-vinylcaprolactam and sodium 2-acrylamido-2-methylpropane sulfonate. The effect of SDKP on rheological behavior of bentonite-free fluids was studied according to American Petroleum Institute standard. Results showed that SDKP could improve the rheological properties of bentonite-free fluids. In addition, the good thermal stability and salt stability in improving rheological behavior of fluids made SDKP more attractive. Rheological behavior of SDKP based bentonite-free fluids at different temperatures was also evaluated. Results showed that SDKP based bentonite-free fluids showed certain thermo-viscosifying behavior in the temperature range of 80-140 degrees C even in high salinity, which was benefit for carrying cuttings. Shear test showed that the magnitude of the thermo-thickening viscosity was very sensitive to shear rate, and SDKP containing fluids became better shear-thinning upon heating, which could be more easily pumped into the well. In addition, the mechanism of SDKP in improving rheological behavior of bentonite-free fluids was revealed based on the investigation of morphology of SDKP through Environmental Scanning Electron Microscopy experiment.",24,25,3
Degrees C.,Enhanced Oil-recovery,"Hanamertani, Alvinda Sri; Pilus, Rashidah M.; Manan, Ninie A.; Mutalib, M. Ibrahim A.",The use of ionic liquids as additive to stabilize surfactant foam for mobility control application,Surfactant; Foam additive; Ionic liquid; Foam stability; Foamscan,DEEP EUTECTIC SOLVENTS; ALKYL CHAIN-LENGTH; INTERFACIAL-TENSION; PHYSICOCHEMICAL PROPERTIES; PHASE-BEHAVIOR; OIL; IMIDAZOLIUM; FILMS; CHLORIDE; AGGREGATION,"Foam application has been introduced in enhanced oil recovery processes for mobility control to overcome some issues occurred during gas injection. The stability of foam has become the main concern as it dictates the effectiveness of foam mobility control. Many attempts at enhancing foam stability under reservoir conditions involve the application of chemical additives which can produce synergistic effect in combination with surfactant. Ionic liquids (ILs), salts melting below 100 degrees C, are considered to be able to alter surface behavior of surfactant molecules, hence supporting the surfactant performance at the interface. Their alteration is expected to be favorable in improving surface properties of foam. This research has introduced ionic liquid based additives for the first time to improve surfactant foam stability. Identification of the effect of ILs was performed by conducting bulk foam experiments at ambient conditions and also at high temperature using Foamscan. The foaming properties of in-house surfactant (MFOMAX) were evaluated in the absence and presence of ILs at different mixture ratios. The results show that imidazolium-and eutectic-based ILs were able to improve surfactant foam stability to different extent at high temperature and their effect on foam stabilization was more pronounced at surfactant/IL mixture ratio of 60:40. The highest foam stability increment exhibited by the best formulation reached 136% of that achieved by the formulation without IL. This study has indicated that ionic liquid has a promising potential for improving surfactant-stabilized foam mobility control during EOR processes.",24,24,3
Degrees C.,Enhanced Oil-recovery,"Lenji, Majid Abedi; Haghshenasfard, Masoud; Sefti, Mohsen Vafaie; Salehi, Mahsa Baghban; Heidari, Aghdas",Experimental study of swelling and rheological behavior of preformed particle gel used in water shutoff treatment,Preformed particle gel; Swelling ratio; PPG strength; Core flooding; Water cut reduction,ENHANCED OIL-RECOVERY; CONFORMANCE CONTROL; NUMERICAL-SIMULATION; PHENOLIC RESIN; HYDROGELS; POLYMER; POLYACRYLAMIDE; PERMEABILITY; PH; TRANSPORT,"Production of water effluents in mature reservoirs subjected to water flooding face many difficulties that might, ultimately, lead to their abandonment. Gel shutoff treatment of such reservoirs using preformed particle gel (PPG) is a technique used to block fracture channels and to insulate highly permeable zones. The technique not only reduces water production but leads also to successful conformance control. The present study introduces a novel type of PPG with an extremely high swelling ratio. The PPG is made up of polyacrylamide and Aluminum nitrate nanohydrate, which acts like a superabsorbent to absorb water equivalent in weight to 1000-2000 times the dry weight of the gel. Tests were conducted in the present experiment to investigate the effects of polymer and crosslinker concentrations, temperature, salinity, and pH on the swelling of PPG. Results showed that increasing polymer and crosslinker concentrations as well as enhanced salinity led to declining PPG swelling ratio. While PPG swelling ratio was not considerable outside the pH range of 5-9, its rate within this range was relatively high. Moreover, PPG swelling ratio increased only slightly with increasing temperature by up to 100 degrees C, beyond which the 3D network structure of PPG collapsed. Rheological tests were performed to determine PPG strength in three samples selected based on least salt sensitivity factor values. In addition, the core flooding test was performed to evaluate the blocking efficiency and the performance of the three samples in reducing water production in sandpacks. The test results revealed that PPG reduced water effluents in the sandpack by 30%-65%.",22,22,3
Degrees C.,Enhanced Oil-recovery,"Wang, Chao; Liu, Pengcheng; Wang, Fushun; Atadurdyyev, Bayramberdi; Ovluyagulyyev, Mergen",Experimental study on effects of CO2 and improving oil recovery for CO2 assisted SAGD in super-heavy-oil reservoirs,Super-heavy oil reservoir; Steam assisted gravity drainage (SAGD); Reduce viscosity; Carbon dioxide; Thermal oil recovery,GRAVITY DRAINAGE; STEAM; EOR; PERFORMANCE; INJECTION; SEQUESTRATION; MECHANISM; PRESSURE; BEHAVIOR; SOLVENT,"When developing heavy-oil reservoirs using steam-assisted gravity drainage (SAGD) technology, CO2 is often used to reduce the viscosity of heavy oil and the heat loss of the steam chamber, thereby enhancing oil recovery. The limitation of experimental apparatuses, results in a maximum temperature of the reaction kettle of no more than 150 degrees C. Thus, the solubility of CO2 in super-heavy oil and its impact on decreasing viscosity beyond 150 degrees C requires further discussion. Considering these issues, a high-temperature-resistant heavy-oil mixing apparatus was designed to measure the solubility of CO2 in super-heavy oil and the relative density and viscosity of super-heavy oil under high temperatures and pressures. Core flooding experiments under 200 degrees C were conducted to explore the effects of CO2 on oil displacement efficiency. The results indicated that solubility of CO2 became significantly lower at 200 degrees C, when the viscosity and relative density of super-heavy oil decreased as pressure increased. The viscosity of super-heavy oil saturated with CO2 decreased by 71.2%, and relative density decreased by 10.1% at 200 degrees C compared to those of degassed crude. At temperatures of 120 degrees C, 150 degrees C and 200 degrees C, the ultimate displacement efficiency of super-heavy oil increased by 6.6%, 19.2% and 21.4%, respectively, compared to a temperature of 60 degrees C. At pressures of 1.0 MPa, 2.0 MPa and 4.0 MPa, the ultimate displacement efficiency (46.7%) of super-heavy oil increased by 5.2%, 4.0% and 5.9%, respectively, compared to a pressure of 0.5 MPa. The experiments showed that CO2 injection can effectively reduce the relative density and viscosity of super-heavy oil and improve oil recovery under high temperatures and pressures. CO2 has good potential to improve SAGD efficiency in developing super-heavy-oil reservoirs.",20,21,4
Degrees C.,Enhanced Oil-recovery,"Lashkarbolooki, Mostafa; Riazi, Masoud; Ayatollahi, Shahab",Effect of CO2 and crude oil type on the dynamic interfacial tension of crude oil/carbonated water at different operational conditions,Dynamic IFT; Carbonated water; CO2; Adsorption time; Temperature; Pressure,CARBONATED WATER; AQUEOUS-SOLUTIONS; INJECTION; RECOVERY; PH; EQUILIBRIUM; TEMPERATURE; PERFORMANCE; ASPHALTENE; ADSORPTION,"Concerns about climate change have persuaded the researchers to examine CO2 injection in the form of carbonated water (CW) into oil reservoir as a safe and effective CO2 storage and enhanced oil recovery process. Although interfacial tension (IFT) between crude oil and injected fluid has a vital role on the displacement of fluids in porous media, the effect of CO2 and crude oil type on the dynamic IFT of crude oil under different operational conditions is not well understood. Accordingly, this study was carried out to assess the effects of temperature, pressure, crude oil type and CO2 on the dynamic IFT of crude oil/CW. To achieve this goal, two types of crude oil were provided from southern Iranian oil reservoirs and dynamic IFTs with CW were measured in a wide range of temperatures and pressures (i.e. temperature range of 30-80 degrees C and pressure range of 500-4000 psi); the obtained results were compared with the system without CO2. In addition, the adsorption time of carbonated aqueous phase/crude oil, obtained based on the mono exponential decay model, was also compared with unadulterated water/crude oil system. The outcome of this study showed that crude oil type has the most significant effect on the IFT of crude oil/CW compared to pressure, temperature and CO2 content. In more details, the IFT of crude oil/CW can be affected by the amount and type of acidic/basic components in the crude oil as well as pH of the aqueous solution. Besides, the obtained results revealed that the effect of temperature was more considerable on the IFT of the heavy crude oil compared with the light crude oil in both studied aqueous solutions (i.e. unadulterated water and CW). Although the inversion phase temperature was obtained for unadulterated water/studied crude oils at all studied pressures, this phenomenon was not observed for crude oil/CW at elevated pressure, due to the high amount of CO2 at this condition.",17,17,3
Degrees C.,Enhanced Oil-recovery,"Silva, Ivonete P. G.; Aguiar, Amaury A.; Rezende, Viviane P.; Monsores, Andre L. M.; Lucas, Elizabete F.",A polymer flooding mechanism for mature oil fields: Laboratory measurements and field results interpretation,Enhanced oil recovery; Polymer flooding; Mobility; Rheology; Particle size,LIGHT-SCATTERING; MOLECULAR-WEIGHT; POLYACRYLAMIDE; FLOW; DEPENDENCE; RECOVERY; POLYELECTROLYTE; TEMPERATURE; COPOLYMERS; RETENTION,"Although polymer flooding has been widely studied in the literature on oil recovery, many questions remain about the technique's action mechanisms. It is widely accepted that the process is based on increasing viscosity of the aqueous phase (injected fluid). The polymer can also act secondarily by reducing the relative permeability to water. Fields that are markedly heterogeneous, highly depleted or that contain fluids with strong salinity are not good candidates for the process. To overcome these restrictions, the most recent applications have used more resistant polymers, with higher molar masses, injected in larger quantities, to preserve the level of viscosity under these adverse conditions. However, a pilot test in a field under adverse conditions showed surprising results and unexpected pressure abnormality, even with small quantities of partially hydrolyzed polyacrylamide (HPAM) with relatively low molar mass (6 x 10(6) g/mol). This paper reports the investigation of the prevailing mechanism responsible for these unexpected results, by means of laboratory tests of flow in porous media and rheological analysis of fluids and hydrodynamic diameter of polymer molecules. The Salt effect (NaCl) on polymer solutions was researched by rheology and particle size analysis at 25 and 50 degrees C. The results showed that mechanical/hydrodynamic retention prevails over polymer adsorption at the rock, with the former being caused by the increase in the polymeric hydrodynamic volume in fluid dilution processes. Besides this, increased temperature was found to favor greater hydrodynamic volume under tested conditions, while salinity had little influence. The results also shed new light on the flow behavior of polymer solutions in porous media, particularly in polymer injection for enhanced oil recovery from mature fields.",15,15,3
Degrees C.,Enhanced Oil-recovery,"Derguine-Mecheri, Louiza; Kebbouche-Gana, Salima; Khemili-Talbi, Souad; Djenane, Djamel",Screening and biosurfactant/bioemulsifier production from a high-salt-tolerant halophilic Cryptococcus strain YLF isolated from crude oil,Yeasts; Biosurfactant; Cryptococcus sp YLF; Agro industrial wastes; EOR,BIOSURFACTANT PRODUCTION; LIPOPEPTIDE BIOSURFACTANT; SURFACE-PROPERTIES; WASTE-WATER; CANDIDA; BOMBICOLA; YEAST; SOPHOROLIPIDS; BIOEMULSIFIER; QUANTITATION,"Biosurfactant-producing yeasts were isolated from different biotopes including food samples, waste and sand samples collected from areas contaminated with hydrocarbons in Algeria. Isolates were screened for biosurfactant/bioemulsifier production in mineral salt medium and in high salinity using emulsification index (E24), drop-collapse test, spread oil technique and hemolytic activity. Fifty of one hundred isolates were positive for almost all the qualitative tests, four of them were the best strains for biosurfactants production with emulsions over than 60%. More interestingly, one high-salt-tolerant yeast isolate was the most potent biosurfactants producing yeast with an emulsification index of 69.50 +/- 0.70. It was identified by morphological, physiological and biochemical tests and by 5.8s-rDNA Analysis as Cryptococcus sp. YLF. This strain produced biosurfactant using different carbon and nitrogen sources and when grown in low-cost fermentative media based on agro industrial by-products and wastes like whey, molasses, corn steep liquor, date syrup and olive mill wastewater (OMW) supplemented with NaCl (2.5 M). The biosurfactant produced by Cryptococcus sp. YLF was partially characterized as glycolipid based on the estimation of macromolecules, TLC and IR analysis. The crude biosurfactant demonstrated stability regarding surface tension reduction and emulsification activity in a range of temperatures (5-100 degrees C), pH (2-12) and high salinities (1-10%). The partially purified biosurfactant showed promising potential for application in enhanced oil recovery (EOR).",14,14,4
Degrees C.,Enhanced Oil-recovery,"Aurepatipan, Nathapat; Champreda, Verawat; Kanokratana, Pattanop; Chitov, Thararat; Bovonsombut, Sakunnee",Assessment of bacterial communities and activities of thermotolerant enzymes produced by bacteria indigenous to oil-bearing sandstone cores for potential application in Enhanced Oil Recovery,Enhanced Oil Recovery; Lipase; Esterase; Bacterial communities,BIOSURFACTANT PRODUCTION; PETROLEUM RESERVOIRS; MOLECULAR ANALYSIS; BACILLUS-SUBTILIS; HIGH-TEMPERATURE; ALKALINE LIPASE; WATER; MICROORGANISMS; DIVERSITY; BIODEGRADATION,"Enhanced Oil Recovery (EOR) is a potential approach to improve oil yield in petroleum production. In this research, indigenous bacterial communities residing in oil-bearing sandstone cores, taken from oil wells in Fang oil field in Northern Thailand, were investigated using the Ion Torrent PGM sequencing method. Based on 16rRNA gene sequences, Proteobacteria and Firmicutes were found to be the predominant phyla, and Bacillus, Sinomonas, Paenibacillus and Hydrogenophaga were the major genera. Thermotolerant lipase-esterase and urease producing bacteria were also isolated from the oil-bearing sandstone core samples. One lipase-esterase producing isolate, Bacillus licheniformis L3-2, produced the enzyme with highest activity at 80 degrees C. The enzyme retained up to 50% of its activity after incubation at 60 degrees C for 4 h. The results suggest the possibility of applying an in situ EOR approach using a combination of Enzyme Enhanced Oil Recovery (EEOR) and Microbial Enhanced Oil Recovery (MEOR) methods, with this lipase-esterase producing Bacillus licheniformis isolate, which is indigenous to one of the wells in this oil field.",14,14,3
Degrees C.,Enhanced Oil-recovery,"Mehrabi-Kalajahi, Seyed Saeed; Varfolomeev, Mikhail A.; Yuan, Chengdong; Emelianov, Dmitrii A.; Khayarov, Khasan R.; Klimovitskii, Alexander I.; Rodionov, Alexander A.; Orlinskii, Sergei B.; Gafurov, Marat R.; Afanasiev, Igor S.; Fedorchenko, Gennadii D.; Lubnina, Elena V.",EPR as a complementary tool for the analysis of low-temperature oxidation reactions of crude oils,Crude oil; In-situ combustion; Air injection; Oxidation; EPR; Free radical concentration,IN-SITU COMBUSTION; VANADYL-PORPHYRIN COMPLEXES; SARA FRACTIONS; PARAMAGNETIC-RESONANCE; KINETIC-ANALYSIS; AIR INJECTION; HEAVY OIL; LIGHT; ASPHALTENES; BEHAVIOR,"Air injection is a promising method for enhanced oil recovery (EOR) in both conventional and unconventional oil sources. It is widely accepted that oxidation reactions between oil and injected air determine the success of an air injection process. In this study, electron paramagnetic resonance (EPR) was introduced as a new route to investigate the occurrence of low-temperature oxidation (LTO) and its behavior by monitoring the signals of free radicals. The EPR experiments were conducted for the different crude oil samples (light, medium and heavy) heated in both static air and flow air (air-bubbling) conditions under different temperatures from 25 degrees C to 180 degrees C. The results showed that the free-radical concentrations exhibited a good correspondence on the heating temperature. Furthermore, nuclear magnetic resonance (NMR), Fourier-transform infrared spectroscopy (FTIR) and differential scanning calorimetry (DSC) experiments were carried out to help to analyze the oxidation process and verify the EPR results. It turned out that the EPR results can be well supported by NMR, FTIR and DSC data, which indicates that proposed EPR monitoring method can be applied as a fast and low-cost technique to investigate LTO under mild reaction conditions. Simultaneously, the combination of EPR, NMR, FTIR and DSC can help to better understand the LTO mechanism and to monitor the application of in-situ combustion technique in the field.",14,14,1
Degrees C.,Enhanced Oil-recovery,"Ashish; Debnath (Das), Mira",Application of biosurfactant produced by an adaptive strain of C-tropicalis MTCC230 in microbial enhanced oil recovery (MEOR) and removal of motor oil from contaminated sand and water,Biosurfactant; Candida tropicalis; Surfactin; Critical micelle concentration; MEOR,WASTE-WATER; SURFACTIN; BACTERIA; PURIFICATION; HYDROCARBON; SUBSTRATE; GLYCEROL; SOIL,"Microbial enhanced oil recovery (MEOR) represents the use of microorganisms or their products to recover remaining oil trapped up in oil reservoirs. In this study adaptive strain C. tropicalis MTCC230 was used to determine its suitability in MEOR. Biosurfactant produced from an adaptive strain C. tropicalis MTCC230 was characterized as lipopeptide surfactin by Near IR, FTIR spectrum and HPLC and mass spectroscopy analysis. It can significantly reduce the surface tension 72 mN/m to 32 mN/m, with the critical micelle concentration (CMC) of 32.5 mg/l and B. subtilis MTCC2423 used as a standard surfactin (Biosurfactant) producing strain for comparative study. It shows stable Physiochemical properties under the extreme pH(2-12), temperature(30 degrees C - 90 degrees C) and salinity(2%-10%) that promote its potential use in enhanced oil recovery. Oil spreading method and soil washing analysis confirmed it suitability to remove the hydrocarbon contaminants from water and soil. Laboratory scale sand pack column saturated with four stroke engine oil resulted similar to 39.80% additional oil recovery (AOR), suggesting its suitability for commercial use in microbial enhanced oil recovery (MEOR) in oil reservoirs.",14,15,1
Degrees C.,Surfactant,"Da, Chang; Alzobaidi, Shehab; Jian, Guoqing; Zhang, Leilei; Biswal, Sibani L.; Hirasaki, George J.; Johnston, Keith P.",Carbon dioxide/water foams stabilized with a zwitterionic surfactant at temperatures up to 150 degrees C in high salinity brine,CO2-in-water foam; Zwitterionic surfactant; Porous media; EOR,ENHANCED OIL-RECOVERY; WORMLIKE MICELLES; CONCENTRATED EMULSIONS; SUPERCRITICAL FLUIDS; MOBILITY CONTROL; MIXED-SOLUTIONS; AQUEOUS-PHASE; POROUS-MEDIA; YIELD-STRESS; ADSORPTION,"Stabilization of CO2-in-water (C/W) foams with surfactants at high temperature and high salinity conditions is challenging given limitations in the solubility and thermal stability of surfactants, particularly for surfactants other than anionic ones. Here we show that a single zwitterionic surfactant, cetyl betaine (CH3(CH2)(15)N+(CH3)(2)CH2COO-), stabilizes viscous C/W foam (> 15 cP) in crushed limestone (76-Darcy) at a temperature up to 150 degrees C and over a wide range in salinity up to 22% total dissolved solids (TDS) at superficial velocity of 940 ft/day. According to liquid chromatography mass spectrometry (LC/MS), cetyl betaine has high thermal stability with negligible chemical degradation after incubation at 135 degrees C for 30 days. Interfacial tension (IFT) at the C/W interface was reduced significantly from similar to 37 mN/m to < 5 mN/m with the addition of 0.08 mmol/L of cetyl betaine. Relative to ionic surfactants, the relatively weak electrostatic repulsion between the local charges in the headgroup is shown to produce strong adsorption at the C/W interface (similar to 134 angstrom(2)/molecule), resulting in generation of viscous foam (similar to 6 cP) even in pure water without added salt. At a low superficial velocity of 6 ft/day (shear rate 45 s(-1)) in a beadpack, foam was still formed with cetyl betaine. Static adsorption of cetyl betaine on carbonates was on the order of 1 mg/m(2), and core flood test also proved that cetyl betaine could stabilize viscous C/W foam (> 20 cP) within 6 pore volumes of injection at 120 degrees C. The surfactant stabilized viscous C/W foam at low oil fractions and broke in the presence of large fractions of oil, both of which are desirable in CO2 mobility control and oil displacement. The ability to form foams at high temperatures and over a wide range in salinity is important for various practical applications including CO2 enhanced oil recovery, fracturing with energized fluids and CO2 sequestration.",46,48,19
Degrees C.,Surfactant,"Yue, Ye; Chen, Shuya; Wang, Ziqi; Yang, Xianyu; Peng, Yangdong; Cai, Jihua; Nasr-El-Din, Hisham A.",Improving wellbore stability of shale by adjusting its wettability,Shale Water-based mud (WBM); Wellbore stability; Wettability; Contact angle; Pressure transmission test (PTT),WATER; ADSORPTION; PRESSURE; MODEL; MUD,"The possibility of improving wellbore stability of shale by adjusting its wettability was investigated. First, an optimized surfactants combination (0.2 wt% cetyltrimethylammonium bromide (CTAB) plus 0.1 wt% sodium dodecyl benzene sulfonate (SDBS)) was screened out that could effectively reduce the surface tension of the water-based mud (WBM) or fresh water, and increase the contact angle with shale. Then, regular tests on viscosity, filtration, lubrication, water activity, and special tests on linear swelling, rolling recovery rate, temperature tolerance, salts, and active cuttings tolerance, along with pressure transmission test (PTT) of shale were conducted to evaluate the performance of the optimized surfactants combination. Results show that the WBM's surface tension could be decreased from 45.1 to 20.0 mN/m and the contact angle on the shale could be increased from 34.5 to 63.5 degrees. The optimized surfactants combination could also improve the WBM's performance to inhibit shale hydration. The WBM in the presence of the optimized surfactants combination had good tolerance to a pollutants complex (0.8 wt% CaCl2, 0.8 wt% MgCl2, 5 wt% sodium bentonite, and 10 wt% NaCl) and could withstand a high temperature of 130 degrees C. Foaming phenomenon could be avoided by adding surfactants in the last step. PTT results show that compared with 4 wt% NaCl, the optimized surfactants combination could effectively retard the pore pressure transmission in shale and reduce its permeability by 98.6%. The addition of CTAB to the WBM or fresh water, hydrolyzed CTA(+) cation adsorbs on the surface of shale via an ionic bond, forming a hydrophilic base toward shale and a lipophilic base toward the WBM or water, thus, increasing the contact angle with shale and improve wellbore stability in shale. This paper paves a new way to address wellbore stability issues in troublesome shale formations.",30,31,0
Degrees C.,Surfactant,"Goswami, Rishiraj; Chaturvedi, Krishna Raghav; Kumar, Ravi Shankar; Chon, Bo Hyun; Sharma, Tushar",Effect of ionic strength on crude emulsification and EOR potential of micellar flood for oil recovery applications in high saline environment,Crude oil; Emulsion; Micellar flood; Rheology; SDS; Salt,NANOPARTICLE-SURFACTANT-POLYMER; IN-WATER EMULSIONS; INTERFACIAL-TENSION; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; HIGH-TEMPERATURE; SYSTEM; BEHAVIOR; CALCIUM; STABILITY,"Micellar flooding is one of the chemical oil recovery techniques in which micelle action emulsifies the crude oil to be mobilized in form of emulsion from a subsurface porous media. However, the subsurface conditions such as high ionic strength and temperature are challenges to the successful use of micellar flood owing to the deterioration of micelle action suggesting no crude emulsification. The ionic compounds dissociate into different ions that may further affect micelle action via loss in viscosity and pressure drop, increased water cut, and mobility contrast between micellar flood and displaced oil. Thus, investigation leading to the successful use of micellar flood, context to crude emulsion, in extreme salinity and temperature is vital to extend the use of chemical methods in new reservoirs. In this work, a typical surfactant sodium dodecyl sulfate (SDS) solution with critical micelle concentration (0.8 wt%) was tested to emulsify a fresh crude oil in the presence of varying ionic strength (0-4 wt%, NaCl/CaCl2 and temperature (40-98 degrees C). The efficacy of SDS micelles to produce crude emulsion significantly reduced with increasing salt concentration as reported through microscopic, rheological, and flooding experiments, particularly for divalent salt (CaCl2) than monovalent salt (NaCl). The increase in temperature (> 40 degrees C) further curtailed the growth of crude emulsion, mainly due to enhanced droplet coalescence; thus the use of micellar flood is critical in a reservoir enriched with high salinity and high temperature. Salinity effect on emulsion viscosity is reported through rheological measurements. The study highlighted important aspects of surfactant flooding and is a forward step towards the use of SDS based micellar flood at complex reservoir conditions.",29,28,1
Degrees C.,Surfactant,"Mao, Jincheng; Yang, Xiaojiang; Chen, Yanan; Zhang, Zhaoyang; Zhang, Chong; Yang, Bo; Zhao, Jinzhou",Viscosity reduction mechanism in high temperature of a Gemini viscoelastic surfactant (VES) fracturing fluid and effect of counter-ion salt (KCl) on its heat resistance,Clear fracturing fluid; Molecular characterization; Viscosity reduction; Micelle aggregation,MICELLES; NANOCOMPOSITES; SCATTERING,"In the past several decades, Gemini viscoelastic surfactant has been applied for many cases due to its specific properties, including clean fracturing fluid. As we know that counter-ions can greatly promote the micelle aggregation of VES and show important effect on its heat resistance. Potassium chloride, as a normal additive for fracturing fluids to control the clay swelling, was investigated as such counter-ions in the context. Thus, a clean fracturing fluid with good heat resistance could be obtained by studying the viscosity reduction of the fluid prepared from a novel Gemini VES. The results of molecular structure characterization showed that potassium chloride has no effect on the surfactant molecular structure in rheological tests at high temperature. Based on the rheological tests, it can be concluded that the viscosity reduction at the test conditions is mainly of the micelle dissociation. Analysis results, such as microstructure comparison and the dynamic light scattering, suggested that potassium chloride can facilitate the micelles aggregation and entanglement, especially making the micelles tighter. In this way, the fluid could keep higher viscoelasticity at higher temperature and certain shear rate. Based on this mechanism, an improved VES fracturing fluid could be achieved via iterative formation adjustment, whose final viscosity could be maintained about 40 mPa s at 160 degrees C during 120 min.",26,26,8
Degrees C.,Surfactant,"Hanamertani, Alvinda Sri; Pilus, Rashidah M.; Manan, Ninie A.; Mutalib, M. Ibrahim A.",The use of ionic liquids as additive to stabilize surfactant foam for mobility control application,Surfactant; Foam additive; Ionic liquid; Foam stability; Foamscan,DEEP EUTECTIC SOLVENTS; ALKYL CHAIN-LENGTH; INTERFACIAL-TENSION; PHYSICOCHEMICAL PROPERTIES; PHASE-BEHAVIOR; OIL; IMIDAZOLIUM; FILMS; CHLORIDE; AGGREGATION,"Foam application has been introduced in enhanced oil recovery processes for mobility control to overcome some issues occurred during gas injection. The stability of foam has become the main concern as it dictates the effectiveness of foam mobility control. Many attempts at enhancing foam stability under reservoir conditions involve the application of chemical additives which can produce synergistic effect in combination with surfactant. Ionic liquids (ILs), salts melting below 100 degrees C, are considered to be able to alter surface behavior of surfactant molecules, hence supporting the surfactant performance at the interface. Their alteration is expected to be favorable in improving surface properties of foam. This research has introduced ionic liquid based additives for the first time to improve surfactant foam stability. Identification of the effect of ILs was performed by conducting bulk foam experiments at ambient conditions and also at high temperature using Foamscan. The foaming properties of in-house surfactant (MFOMAX) were evaluated in the absence and presence of ILs at different mixture ratios. The results show that imidazolium-and eutectic-based ILs were able to improve surfactant foam stability to different extent at high temperature and their effect on foam stabilization was more pronounced at surfactant/IL mixture ratio of 60:40. The highest foam stability increment exhibited by the best formulation reached 136% of that achieved by the formulation without IL. This study has indicated that ionic liquid has a promising potential for improving surfactant-stabilized foam mobility control during EOR processes.",24,24,3
Degrees C.,Surfactant,"Gu, Xuefan; Zhang, Fan; Li, Yongfei; Zhang, Jie; Chen, Shijun; Qu, Chengtun; Chen, Gang",Investigation of cationic surfactants as clean flow improvers for crude oil and a mechanism study,Cationic surfactants; Crude oil; Flow improver; Viscosity; Pour point,RELATIVELY LOW-TEMPERATURE; HEAVY OIL; CANOLA OIL; AQUATHERMOLYSIS; COMPLEX; COPOLYMER,"Cetyl trimethyl ammonium chloride (CTAC), cetyl trimethyl ammonium bromide (CTAB), and octadecyl trimethylammonium chloride (OTAC) were evaluated as clean flow improvers for crude oil. The results showed that all of them have some effect on the viscosity of crude oil in a certain temperature range, and can depress the pour point, among which CTAC is the most potent one. The viscosity was reduced to below 540 mPa s under different concentration at 35 degrees C by CTAC, and it can depress the pour points by 7.5 degrees C with the concentration of 0.03%. DSC analysis and microscopic morphology analysis discovered the interaction of CTAC and saturated hydrocarbon component of the crude oil, which can reduce the wax peak temperature and wax precipitation point of crude oil. CTAC may precipitate and pack with the long-chain alkane to form the crystal nucleus, while the cationic part and the corresponding Cl- anion can act as a wax crystal modifier and block the wax crystal to grow up, thereby reduce the risk to form three-dimensional networks.",23,24,2
Degrees C.,Surfactant,"Mohamed, Abdelhalim I. A.; Hussein, Ibnelwaleed A.; Sultan, Abdullah S.; Al-Muntasheri, Ghaithan A.",Use of organoclay as a stabilizer for water-in-oil emulsions under high-temperature high-salinity conditions,W/O emulsion; Pickering emulsion; Emulsion stability; Organoclay; High-temperature high-salinity; Chelating agent,INTERFACIAL-TENSIONS; NANOCOMPOSITES; SURFACTANT; FLOW,"Emulsified polymer gels are used in near wellbore applications for water shut-off treatment to control produced water in oil and gas reservoirs. The emulsified gels are expected to separate into oil and water phases at reservoir conditions. The stability of emulsified gels, as measured by the separation time, is influenced by the emulsifier type, salinity of the mixing water, and temperature. Although a range of commercial surfactants is used as emulsifiers, their toxicity and high cost are significant drawbacks. Nowadays, various nanomaterials have been developed for quite a few applications in different fields of endeavors, due to their low cost, availability, high surface area, and most prominently environmental-friendly. The proposed alternative organoclay (OC) has been shown to enhance emulsion stability with increasing OC concentration. The total separated volume reduced by a factor of 4.8, due to the decrease in the interfacial tension, when the OC (Cloisite 15A) concentration was increased from 600 to 1000 ppm. The stability of an emulsion prepared using a 6 vol% polyethylene glycol-2 ether (PEG-2E) enhanced by a factor of similar to 2 when the concentration of Cloisite 15A was increased from 300 to 1000 ppm. The separation time can be controlled by controlling the OC dose, depending on the application. A chelating agent can be used to reduce the effect of salts on emulsion stability. The OC materials have the potential to be used as cost-effective emulsifiers for PAM/PEI at high temperature (>100 degrees C) and high salinity (>200,000 ppm). The OC materials can be used as standalone emulsifiers or co-surfactants to enhance the performance of commercial emulsifiers.",21,22,5
Degrees C.,Surfactant,"Ren, Guangwei; Nguyen, Quoc P.; Hon Chung Lau",Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants,CO2 soluble surfactants; Partition coefficient; CO2 foam; Fractured carbonate reservoir; EOR,INTERFACIAL-TENSION; GRAVITY DRAINAGE; MOBILITY CONTROL; CRUDE-OIL; DISPLACEMENT; EOR; MICROEMULSIONS; WETTABILITY; SOLUBILITY; REDUCTION,"Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions. A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 degrees C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water. RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam. These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.",19,20,2
Degrees C.,Surfactant,"Fakoya, Muili F.; Ahmed, Ramadan M.",A generalized model for apparent viscosity of oil-based muds,Invert-emulsion mud; Shear thinning; Temperature; Oil-water ratio; Clay content; Apparent viscosity,DRILLING-FLUIDS; RHEOLOGY; TEMPERATURE; SUSPENSIONS; EMULSIONS,"Oil-based drilling fluid, typically called oil-based mud (OBM), is an invert emulsion that finds application in drilling operations owing to its outstanding performance, especially in high pressure and high temperature (HPHT) wells. Besides, OBM promotes a better lubricity, ensures wellbore stability, increases the rate of penetration, and facilitates the achievement of low fluid loss and a thin filter-cake. Due to environmental concerns, the use of low-toxicity mineral oils as the base fluid or continuous phase for OBM is preferable. The flow behavior of OBM mainly depends on rheological properties of its continuous phase, and the volume fraction of the dispersed phase. Besides this, other imposed conditions like shear rate and temperature play a significant role. The availability of rheological models that show this connection is necessary for predicting rheology of OBM based on its formulation and borehole condition. This work presents an experimental investigation of the apparent viscosity of OBM within a temperature range of 24-87 degrees C. The continuous phase was prepared with mineral oil, surfactants (emulsifier and wetting agent), organophilic clay, lime, and calcium chloride. Organophilic clay concentrations and oil/water ratio (OWR) were varied. Apparent viscosity measurements are gathered and analyzed. OBM displayed shear-thinning behavior that best fits the Herschel-Bulkley model. The results reveal notable trends of apparent viscosity and rheological parameters with increasing temperature, organophilic clay concentration, and OWR. Generalized empirical models that link the apparent viscosity of the continuous phase to that of OBM are developed by applying nonlinear regression analysis. The prediction of OBM rheological parameters requires the knowledge of continuous phase apparent viscosity at ambient temperature, dispersed phase volume fraction, and temperature. The models give a reasonable prediction of OBM apparent viscosity. The comparison of normalized or reduced rheological parameters and apparent viscosity of OBM and water-based mud (WBM) revealed the sensitivity of viscous properties of OBM to temperature as compared to that of WBM. This revelation shows why OBM is more susceptible to barite sag phenomenon than WBM.",16,16,0
Degrees C.,Rock,"Kumari, W. G. P.; Ranjith, P. G.; Perera, M. S. A.; Chen, B. K.","Experimental investigation of quenching effect on mechanical, microstructural and flow characteristics of reservoir rocks: Thermal stimulation method for geothermal energy extraction",Geothermal; Granite; Permeability; Quenching; Thermal cracks; Thermal stimulation,AUSTRALIAN STRATHBOGIE GRANITE; FRACTURE PERMEABILITY; HEAT-TRANSFER; BEHAVIOR; STRESS; TEMPERATURES; EVOLUTION; TRANSPORT; POROSITY; CRACKING,"Thermal stimulation method can be effectively utilized to enhance the flow performance in the tight porous media with an induced thermal shock. This approach can be applied to many deep geo-engineering applications including geothermal energy extraction. In this regard, understanding the flow-mechanical behaviour of reservoir rock during and after thermal stimulation is necessary for safe and effective stimulation process. The aim of this study is, therefore to investigate the quenching effect on mechanical and flow behaviour of Australian Strathbogie granite by conducting a series of micro and macro-experiments. Experiments were conducted by profiling the micro-structure of rock with CT scanning, microscopic imaging and, quantifying the thermally induced damage due to quenching treatment. In order to understand mechanical response of rock due to quenching, strength tests were conducted under the unconfined condition, and the corresponding fracture propagation patterns were investigated using an acoustic emission (AE) system. In addition, flow performance of thermally treated rock was studied under a wide range of coupled high temperature and high-pressure conditions (temperatures 20-300 degrees C, confining pressure up to 45 MPa and injection pressure up to 40 MPa), simulating different geothermal temperatures and depths. According to the findings, thermal treatment resulted in around 70% of reduction of strength and elastic properties respectively due to the thermally induced damage caused by induction of both inter and intra-crystalline cracks. Further, increased porosity and crack density significantly enhanced the permeability of the rock compared to the intact rock (from approximately 1 x 10(-19)m(2) to 6 x 10(-15)m(2) under 10 MPa confining pressure). However with the increasing of normal stresses, permeability decreased non-linearly and further, increasing temperature resulted in significant reductions in permeability of granite (approximately 95% of reduction from room temperature to 300 degrees C) due to the thermally induced volumetric expansion which leads to enhancement of interlock effect.",60,68,12
Degrees C.,Rock,"Sharma, Himanshu; Mohanty, Kishore K.",An experimental and modeling study to investigate brine-rock interactions during low salinity water flooding in carbonates,Low salinity; Wettability alteration; Brine-rock interactions; IPHREEQC; Carbonates; Mechanistic model; Surface complexation,WETTABILITY ALTERATION; OIL-RECOVERY; CHALK,"Injection of brines with carefully designed ionic compositions into oil-wet carbonate rocks at high temperatures has shown to alter their wettability towards a water-wet state and improve oil recovery. Various mechanisms have been postulated for this wettability alteration such as mineral dissolution and interaction of potential determining ions, such as Ca2+, Mg2+ and SO42-, with the carbonate surface. In this study, experimental and modeling work was performed to gain further insights into the geochemical interactions between carbonate rocks and modified brines. Single-phase static (equilibrium) and transport experiments were performed with various brines in limestone cores at 120 degrees C. The ionic compositions of the effluent samples were monitored using ion chromatography. A mechanistic model for the wettability alteration process was developed in UTCHEM-IPHREEQC based on key geochemical interactions. The calcite surface was assumed to consist of positive and negative sites and their interactions with potential determining ions were considered assuming local equilibrium. The model assumed the degree of oil-wetness to depend on the amount of organic acid attached on the surface, which in-turn was dependent on the geochemistry of the system. Results of static experiments performed with crushed limestones and brines showed an increase in calcium concentration and a decrease in magnesium concentration in the supernatant brines. The effluent concentrations from single-phase brine corefloods in limestone cores showed an increase in calcium concentration, a decrease in magnesium concentration and a delay in sulfate concentration. Three key geochemical interactions were identified based on these results: mineral dissolution, surface dolomitization and sulfate adsorption. A good qualitative agreement was observed between single-phase experiments and simulations, suggesting that the model was able to accurately capture the geochemistry. The simulation results showed good agreement with zeta potential and oil recovery results reported in the literature.",55,57,3
Degrees C.,Rock,"Khormali, Azizollah; Sharifov, Anar R.; Torba, Dmitry I.",Increasing efficiency of calcium sulfate scale prevention using a new mixture of phosphonate scale inhibitors during waterflooding,Calcium sulfate; Formation damage; Scale inhibitor; Synergistic inhibition effect; Waterflooding,POROUS-MEDIA; WATER INJECTION; SQUEEZE TREATMENT; OIL-RESERVOIRS; PRECIPITATION; CARBONATE; PREDICTION; DEPOSITION; TECHNOLOGY; KINETICS,"Inorganic salt precipitation is one of the main problems in oilfield operations. Different factors affect scale formation and inhibition. Calcium sulfate scale formation occurs during waterflooding due to incompatibility of injection and formation waters. In this work, synthetic formation and injection waters were prepared to determine the influence of reservoir conditions (temperature and pressure), and mixing ratio of the waters on calcium sulfate scale deposition during waterflooding. A new mixture of phosphonate scale inhibitors (SI) was developed for increasing the inhibition efficiency of calcium sulfate scale formation in oil reservoirs. The developed mixture consists of three different industrial phosphonate SI and some additives. The concentrations of components of the developed mixture of phosphonate SI were determined on the basis of a synergistic inhibition effect. The maximum value of the synergistic inhibition effect was about 1.091. Performance of the developed mixture and four different industrial SI (HEDP, ATMP, PPCA and DTPMP) was determined by jar test. The experimental results showed that the developed mixture of phosphonate SI has a better inhibition performance than the industrial inhibitors under any conditions. Its effectiveness was more than 90% at any reservoir temperature (60-120 degrees C) and content of formation water in the solution (10-90%). Furthermore, a minimum inhibitory concentration of the developed mixture of phosphonate SI was about 25 mg/L. Moreover, formation damage due to calcium sulfate precipitation in carbonate rock samples with and without the use of scale inhibitors was investigated. Without the addition of any SI, the damaged permeability was about 58% of the initial rock permeability. The damaged permeability in the presence of the developed mixture of phosphonate SI was about 93.5% of the initial permeability of the used rock samples. Also, a new correlation was developed for predicting a permeability reduction of the rock samples due to calcium sulfate precipitation. The coefficient of determination between experimental and predicted (form correlation) data was 0.99. In addition, the developed mixture of phosphonate SI had the enhanced adsorption/desorption capacities. Its squeeze lifetime was longer up to 22.6% than other inhibitors. The corrosion rate in the solution of the developed mixture of phosphonate SI was lower than 0.063 mm/y at any concentration.",25,29,1
Degrees C.,Rock,"Bakshi, Tuli; Prusty, B. K.; Pathak, K.; Pal, S. K.",Pore characteristics of Damodar valley shale and their effect on gas storage potential,Organic matter; Mineralogy; Pore characteristics; Microporosity; Sorption; Shale gas reservoirs,FORT-WORTH BASIN; NORTHEASTERN BRITISH-COLUMBIA; MISSISSIPPIAN BARNETT SHALE; METHANE SORPTION CAPACITY; NORTH-CENTRAL TEXAS; COALBED METHANE; HYDROCARBON GENERATION; SIZE DISTRIBUTION; THERMAL MATURITY; BOWEN BASIN,"The current global interest in fine grained sedimentary shale rock is driven by its ability to store gas in the pore spaces in them. The current study focuses on the understanding of the gas storage capacity of less explored Damodar Valley shales of India, in light of pore characteristics of organic matter and clay minerals. In this study, four samples were collected from different parts of Damodar valley basin and their geochemical composition, pore structure and adsorption capacity were investigated by XRD studies, rock-eval analyses, low-pressure N-2-CO2 adsorption analyses and high-pressure methane adsorption experiment. The samples were also studied to know their hydrocarbon potential. The relationship between mineralogy, organic matter, and pore-structure was analyzed and finally, their effect on methane sorption capacity was discussed. The shale samples are found to be clay rich. The average clay content of the shale samples is 50.69% and average quartz content is 31.65%. Presence of excellent TOC content (4.8%-37.36%) with a predominance of type III organic matter and Tmax varying from 440 degrees C to 465 degrees C suggests a very good to excellent hydrocarbon generation potential in all the samples. The correlation between the TOC and V-L was found to be positive indicating a positive influence of organic matter on methane sorption capacity of the studied samples. However, a lack of correlation between total clay and CH4-V-L indicates that the role of clay minerals on methane sorption behavior of these shales are inconclusive. A positive correlation between CO2 micropore volume, CH4-V-L and TOC suggest microporous nature of organic matter within the shale samples and their positive control on methane sorption potential. The negative correlation of clay mineral with CO2 micropore volume suggests a lack of microporosity in the clay minerals of the collected shale samples. It was also observed that thermally mature shale samples have higher micropore volume and surface area, and are prone to higher methane sorption capacity compared to that of less mature shales.",23,23,2
Degrees C.,Rock,"Minde, Mona W.; Wang, Wenxia; Madland, Merete, V; Zimmermann, Udo; Korsnes, Reidar, I; Bertolino, Silvana R. A.; Andersen, Pal O.",Temperature effects on rock engineering properties and rock-fluid chemistry in opal-CT-bearing chalk,Chalk; Compaction; Dissolution/precipitation; Permeability; Opal-CT; Mineralogical changes,NORTH-SEA; POROSITY; PRECIPITATION; SEDIMENTS; MODEL; COMPACTION; SEAWATER; BEHAVIOR; DENMARK; EKOFISK,"In this study, eight tri-axial tests on Cretaceous age outcrop chalk from Aalborg have been performed systematically by injecting MgCl2 for the first time at different temperatures (25, 60, 92, 110 and 130 degrees C) and for comparison, NaCl at 130 degrees C. Whole-rock geochemistry, stable isotope measurements, pycnometry, Field Emission Gun Scanning Electron Microscopy with Energy-Dispersive X-ray Spectroscopy, X-Ray Diffraction (XRD) and measurements of Specific Surface Area (Brunauer-Emmett-Teller theory (N-2)) were applied to analyse unflooded and flooded cores. Based on analyses of changes in brine composition, mineralogy, specific surface area, solid density, porosity and permeability some conclusions can be drawn on temperature effects on rock engineering properties and rock-fluid chemistry. The MgCl2 flooded cores show systematically higher creep rates at higher temperature and the cores tested at 25 and 60 degrees C show similar creep rates as the two NaCl flooded cores at 130 degrees C. All fluid-rock interactions were more pronounced at higher temperature. After flooding with MgCl2 at 110 and 130 degrees C newly formed magnesite is observed. In the cores tested at 25, 60 and 92 degrees C magnesite crystals have not been positively identified, but minute increases in MgO in whole-rock geochemistry analyses are seen. Si4+ originating from the dissolution of silica bearing phases (mainly diagenetic opal-CT), has taken part in the re-precipitation of Si-Mg-bearing minerals during MgCl2 injection from 25 to 130 degrees C, leading to an increase of the specific surface area. This is partly balanced by opal-CT dissolution, which should lower the specific surface area. The flaky Si-Mg-bearing minerals, covering significant portions of the pore surfaces and throats are the main drivers to reduce permeability in cores flooded at high temperatures. Additionally, in NaCl flooded cores where mineralogical changes are minute, the dissolution of parts of the existing opal-CT has lowered the SSA. At high temperatures, the following chemical changes must be carefully acknowledged when porosity reduction is calculated: calcite and opal-CT dissolution and precipitation of new minerals, particularly Mg-bearing minerals. The presence of opal-CT strongly influences the mineralogical alterations in flooded cores, hence the geo-mechanical evolution.",20,20,0
Degrees C.,Rock,"Silva, Ivonete P. G.; Aguiar, Amaury A.; Rezende, Viviane P.; Monsores, Andre L. M.; Lucas, Elizabete F.",A polymer flooding mechanism for mature oil fields: Laboratory measurements and field results interpretation,Enhanced oil recovery; Polymer flooding; Mobility; Rheology; Particle size,LIGHT-SCATTERING; MOLECULAR-WEIGHT; POLYACRYLAMIDE; FLOW; DEPENDENCE; RECOVERY; POLYELECTROLYTE; TEMPERATURE; COPOLYMERS; RETENTION,"Although polymer flooding has been widely studied in the literature on oil recovery, many questions remain about the technique's action mechanisms. It is widely accepted that the process is based on increasing viscosity of the aqueous phase (injected fluid). The polymer can also act secondarily by reducing the relative permeability to water. Fields that are markedly heterogeneous, highly depleted or that contain fluids with strong salinity are not good candidates for the process. To overcome these restrictions, the most recent applications have used more resistant polymers, with higher molar masses, injected in larger quantities, to preserve the level of viscosity under these adverse conditions. However, a pilot test in a field under adverse conditions showed surprising results and unexpected pressure abnormality, even with small quantities of partially hydrolyzed polyacrylamide (HPAM) with relatively low molar mass (6 x 10(6) g/mol). This paper reports the investigation of the prevailing mechanism responsible for these unexpected results, by means of laboratory tests of flow in porous media and rheological analysis of fluids and hydrodynamic diameter of polymer molecules. The Salt effect (NaCl) on polymer solutions was researched by rheology and particle size analysis at 25 and 50 degrees C. The results showed that mechanical/hydrodynamic retention prevails over polymer adsorption at the rock, with the former being caused by the increase in the polymeric hydrodynamic volume in fluid dilution processes. Besides this, increased temperature was found to favor greater hydrodynamic volume under tested conditions, while salinity had little influence. The results also shed new light on the flow behavior of polymer solutions in porous media, particularly in polymer injection for enhanced oil recovery from mature fields.",15,15,3
Degrees C.,Rock,"Taheri-Shakib, Jaber; Shekarifard, Ali; Naderi, Hassan",The study of influence of electromagnetic waves on the wettability alteration of oil-wet calcite: Imprints in surface properties,Wettability; Heavy oil; Microwave; Calcite; Polar,APPEARANCE TEMPERATURE WAT; CONTACT-ANGLE; RECOVERY; MICROWAVE; SALINITY; CARBONATE; ROUGHNESS; IMPACT; TIME; GAS,"The wettability of reservoir rock is one of the fundamental parameters determining the flow of fluid in the porous media. This study has investigated the effect of microwaves on the wettability of calcite reservoir rock from Yaran, Iran, as the time interval of microwave radiation is one of the most important parameters affecting wettability. The reservoir rock samples were placed in a microwave oven filled with helium gas and subjected to microwave radiation at 5-min intervals from 5 to 35 min. Measurements of the contact angle between the oil and the rock indicated that the microwaves brought the angle from about 120 degrees primary state to 93 degrees at 35 min. At intervals of 5-15 min, no change in the wettability of the oil-wet rock was observed. Sulfur components had high absorption coefficients of microwaves, so initially reduced the amount of sulfur (S) on the surface of the oil-wet rock. Next, the nitrogen (N) and oxygen (O) elements were reduced, and eventually the carbon (C) levels began to decrease. This trend was observed in the zeta potential by changing the surface charge of the rock. Indeed, eliminating SNO polar compounds with a high potential for absorbing microwave caused the rock to become water-wet. Microwave radiation initially produced no change in the Fourier-transform infrared spectroscopy (FTIR) spectrum, as it continued, the peak intensity of the corresponding oil, such as the carboxylic acid functional group, declined, and the corresponding peaks of the rock became more intense, indicating a gradual change in the wettability. It can be interpreted that the aromatic compounds exist in oil and act as surface agent components. The results of this study can be used as a representation of the use of microwave radiation in hydrocarbon reservoirs to change the wettability and increase the production rate of reservoirs.",15,15,0
Degrees C.,Rock,"Geng, Jishi; Sun, Qiang; Zhang, Yuchun; Cao, Liwen; Lu, Chao; Zhang, Yuliang",Temperature dependence of the thermal diffusivity of sandstone,Geothermic; Thermal diffusivity; Sandstone; High temperature,TRANSPORT-PROPERTIES; ELEVATED-TEMPERATURE; PHYSICAL-PROPERTIES; HEAT CAPACITY; ROCKS; CONDUCTIVITY; CRYSTALS; MINERALS; GRANITE; COAL,"High temperature causes a significant impact on the thermal diffusivity of rocks. The deterioration of the thermal properties of rocks, would seriously threaten many applications in engineering and geosciences, such as petroleum engineering, geothermal energy. This paper emphasizes on the variations of thermal diffusivity of sandstone after high-temperature heating. The results indicate that there are two main reasons for the decrease of thermal diffusivity: the variation of mineralogical composition, the physical and chemical reactions caused by thermal stress. The thermal diffusivity of sandstone decreases with temperature and it tends to be constant once the temperature exceeds a critical value. From 25 degrees C to 300 degrees C, the decrease is mainly due to the escaping of the adhered water, bound water and structural water. Between 300 degrees C and 600 degrees C, the thermal response of minerals in sandstone increases the development of microcracks and weakens the thermal diffusivity of sandstone.",14,14,2
Degrees C.,Shale,"An, Yuxiu; Yu, Peizhi",A strong inhibition of polyethyleneimine as shale inhibitor in drilling fluid,Swelling; Inhibition; Mechanism; Polyethyleneimine; Shale,WELLBORE INSTABILITY; STABILITY; DESIGN; MODEL,"In this paper, the inhibition property of polyethyleneimine (PEI) in montmorillonite solution was studied. The inhibition property was evaluated by linear swelling test and rolling recovery test. Compared with other inhibitors, the addition of PEI resulted in the lowest swelling height in drilling fluid. In rolling recovery rate study, the addition of PEI resulted in the highest recovery rate after rolled at 120 degrees C. More importantly, PEI was environmental friendly inhibitor. The inhibition mechanism was investigated by Fourier transform infrared spectroscopy, X-ray diffraction, Transmission electron microscope, Scanning electron microscopy, Atomic force microscope, Zeta potential and Particle-size analyzer. The spectrums and images showed that the negative charge in the surface of montmorillonite (MMT) was neutralized by the positive charge in amino group of PEI. PEI was adsorbed in the surface and intercalated into interlayer of MMT, which reduced the hydration repulsion of diffuse electric double layer and prevented the invasion of water. Hydrogen bonding between hydroxyl in the surface of clay and amino groups in the backbone and side chain of PEI can be formed in the process. The adsorption and intercalation of PEI in the surface and interlayer of MMT was the major factor to prevent water molecules from invading into the gallery of clay. There were a quantity of positive ions in solution because of the protonation of nitrogen in water. More positive ions resulted in the stronger force between inhibitor and clay.",45,49,1
Degrees C.,Shale,"Yue, Ye; Chen, Shuya; Wang, Ziqi; Yang, Xianyu; Peng, Yangdong; Cai, Jihua; Nasr-El-Din, Hisham A.",Improving wellbore stability of shale by adjusting its wettability,Shale Water-based mud (WBM); Wellbore stability; Wettability; Contact angle; Pressure transmission test (PTT),WATER; ADSORPTION; PRESSURE; MODEL; MUD,"The possibility of improving wellbore stability of shale by adjusting its wettability was investigated. First, an optimized surfactants combination (0.2 wt% cetyltrimethylammonium bromide (CTAB) plus 0.1 wt% sodium dodecyl benzene sulfonate (SDBS)) was screened out that could effectively reduce the surface tension of the water-based mud (WBM) or fresh water, and increase the contact angle with shale. Then, regular tests on viscosity, filtration, lubrication, water activity, and special tests on linear swelling, rolling recovery rate, temperature tolerance, salts, and active cuttings tolerance, along with pressure transmission test (PTT) of shale were conducted to evaluate the performance of the optimized surfactants combination. Results show that the WBM's surface tension could be decreased from 45.1 to 20.0 mN/m and the contact angle on the shale could be increased from 34.5 to 63.5 degrees. The optimized surfactants combination could also improve the WBM's performance to inhibit shale hydration. The WBM in the presence of the optimized surfactants combination had good tolerance to a pollutants complex (0.8 wt% CaCl2, 0.8 wt% MgCl2, 5 wt% sodium bentonite, and 10 wt% NaCl) and could withstand a high temperature of 130 degrees C. Foaming phenomenon could be avoided by adding surfactants in the last step. PTT results show that compared with 4 wt% NaCl, the optimized surfactants combination could effectively retard the pore pressure transmission in shale and reduce its permeability by 98.6%. The addition of CTAB to the WBM or fresh water, hydrolyzed CTA(+) cation adsorbs on the surface of shale via an ionic bond, forming a hydrophilic base toward shale and a lipophilic base toward the WBM or water, thus, increasing the contact angle with shale and improve wellbore stability in shale. This paper paves a new way to address wellbore stability issues in troublesome shale formations.",30,31,0
Degrees C.,Shale,"Bakshi, Tuli; Prusty, B. K.; Pathak, K.; Pal, S. K.",Pore characteristics of Damodar valley shale and their effect on gas storage potential,Organic matter; Mineralogy; Pore characteristics; Microporosity; Sorption; Shale gas reservoirs,FORT-WORTH BASIN; NORTHEASTERN BRITISH-COLUMBIA; MISSISSIPPIAN BARNETT SHALE; METHANE SORPTION CAPACITY; NORTH-CENTRAL TEXAS; COALBED METHANE; HYDROCARBON GENERATION; SIZE DISTRIBUTION; THERMAL MATURITY; BOWEN BASIN,"The current global interest in fine grained sedimentary shale rock is driven by its ability to store gas in the pore spaces in them. The current study focuses on the understanding of the gas storage capacity of less explored Damodar Valley shales of India, in light of pore characteristics of organic matter and clay minerals. In this study, four samples were collected from different parts of Damodar valley basin and their geochemical composition, pore structure and adsorption capacity were investigated by XRD studies, rock-eval analyses, low-pressure N-2-CO2 adsorption analyses and high-pressure methane adsorption experiment. The samples were also studied to know their hydrocarbon potential. The relationship between mineralogy, organic matter, and pore-structure was analyzed and finally, their effect on methane sorption capacity was discussed. The shale samples are found to be clay rich. The average clay content of the shale samples is 50.69% and average quartz content is 31.65%. Presence of excellent TOC content (4.8%-37.36%) with a predominance of type III organic matter and Tmax varying from 440 degrees C to 465 degrees C suggests a very good to excellent hydrocarbon generation potential in all the samples. The correlation between the TOC and V-L was found to be positive indicating a positive influence of organic matter on methane sorption capacity of the studied samples. However, a lack of correlation between total clay and CH4-V-L indicates that the role of clay minerals on methane sorption behavior of these shales are inconclusive. A positive correlation between CO2 micropore volume, CH4-V-L and TOC suggest microporous nature of organic matter within the shale samples and their positive control on methane sorption potential. The negative correlation of clay mineral with CO2 micropore volume suggests a lack of microporosity in the clay minerals of the collected shale samples. It was also observed that thermally mature shale samples have higher micropore volume and surface area, and are prone to higher methane sorption capacity compared to that of less mature shales.",23,23,2
Degrees C.,Shale,"Zhang, Xianmin; Jiang, Guancheng; Dong, Tengfei; Wang, Le; Li, Xinliang; Wang, Guoshuai",An amphoteric polymer as a shale borehole stabilizer in water-based drilling fluids,Borehole stabilizer; Amphoteric polymers; Shale hydration; Micro-nanometer plugging; Water-based drilling fluid,ELEVATED-TEMPERATURE; WELLBORE INSTABILITY; POLYACRYLAMIDE; NANOPARTICLES; SPECTROSCOPY; WELLS; MUDS,"An amphoteric polymer P (acrylamide-styrene-butyl acrylate) (ASBA) was evaluated for use as a shale borehole stabilizer and for its ability to counter the problem of well instability during shale gas exploration and development. The hydrophilic groups in the ASBA increased the adsorption between the ASBA and the shale formation and the hydrophobic groups reduced the hydrophilicity of the sodium bentonite (BT). The addition of 1.6 wt% ASBA resulted in a water contact angle of the BT/ASBA that was more than 40 degrees larger than that of the BT. The amount of linear swelling decreased by 37.81% and the hot-rolling recovery rate of the shale cuttings was more than 60% higher in the 1.6 wt% ASBA solution than in deionized water. The ASBA exhibited micro/nanometer globules with an average diameter of 250.4 nm in aqueous solution. This was in agreement with the results of the morphology tests (scanning electron microscopy (SEM) and transmission electron microscopy (TEM)). The morphology tests, elemental analysis, and thermogravimetric analysis showed that the polymer was evenly dispersed in the aqueous solution and effectively adsorbed onto the BT instead of the free water. The soft globules changed under pressure and effectively plugged the various pores in the formation. Due to the hydrophobicity and the plugging effect, the ASBA prevented the BT aggregation and reduced the filtration loss; the American Petroleum Institute (API) filtration loss of the basic mud containing 1.6 wt% ASBA was reduced by 56.67% compared to the basic mud without ASBA after aging at 150 degrees C. Due to the excellent inhibition of the shale hydration and the micro/nanometer plugging performance, the ASBA has a potential application as a borehole stabilizer in drilling fluids.",19,20,4
Degrees C.,Formation Damage,"Khormali, Azizollah; Sharifov, Anar R.; Torba, Dmitry I.",Increasing efficiency of calcium sulfate scale prevention using a new mixture of phosphonate scale inhibitors during waterflooding,Calcium sulfate; Formation damage; Scale inhibitor; Synergistic inhibition effect; Waterflooding,POROUS-MEDIA; WATER INJECTION; SQUEEZE TREATMENT; OIL-RESERVOIRS; PRECIPITATION; CARBONATE; PREDICTION; DEPOSITION; TECHNOLOGY; KINETICS,"Inorganic salt precipitation is one of the main problems in oilfield operations. Different factors affect scale formation and inhibition. Calcium sulfate scale formation occurs during waterflooding due to incompatibility of injection and formation waters. In this work, synthetic formation and injection waters were prepared to determine the influence of reservoir conditions (temperature and pressure), and mixing ratio of the waters on calcium sulfate scale deposition during waterflooding. A new mixture of phosphonate scale inhibitors (SI) was developed for increasing the inhibition efficiency of calcium sulfate scale formation in oil reservoirs. The developed mixture consists of three different industrial phosphonate SI and some additives. The concentrations of components of the developed mixture of phosphonate SI were determined on the basis of a synergistic inhibition effect. The maximum value of the synergistic inhibition effect was about 1.091. Performance of the developed mixture and four different industrial SI (HEDP, ATMP, PPCA and DTPMP) was determined by jar test. The experimental results showed that the developed mixture of phosphonate SI has a better inhibition performance than the industrial inhibitors under any conditions. Its effectiveness was more than 90% at any reservoir temperature (60-120 degrees C) and content of formation water in the solution (10-90%). Furthermore, a minimum inhibitory concentration of the developed mixture of phosphonate SI was about 25 mg/L. Moreover, formation damage due to calcium sulfate precipitation in carbonate rock samples with and without the use of scale inhibitors was investigated. Without the addition of any SI, the damaged permeability was about 58% of the initial rock permeability. The damaged permeability in the presence of the developed mixture of phosphonate SI was about 93.5% of the initial permeability of the used rock samples. Also, a new correlation was developed for predicting a permeability reduction of the rock samples due to calcium sulfate precipitation. The coefficient of determination between experimental and predicted (form correlation) data was 0.99. In addition, the developed mixture of phosphonate SI had the enhanced adsorption/desorption capacities. Its squeeze lifetime was longer up to 22.6% than other inhibitors. The corrosion rate in the solution of the developed mixture of phosphonate SI was lower than 0.063 mm/y at any concentration.",25,29,1
Degrees C.,Formation Damage,"Xie, Binqiang; Ting, Li; Zhang, Yan; Liu, Chen",Rheological properties of bentonite-free water-based drilling fluids with novel polymer viscosifier,Water-soluble polymers; Viscosifier; Thermo-thickening; Rheology; Bentonite-free drilling fluid,ACRYLAMIDE-BASED TERPOLYMER; ENHANCED OIL-RECOVERY; AQUEOUS-SOLUTION; GRAFT-COPOLYMERS; THERMOASSOCIATIVE COPOLYMERS; CELLULOSE NANOPARTICLES; FORMATION DAMAGE; PERFORMANCE; BEHAVIOR; ADDITIVES,"Water-based drilling fluids with no bentonite content was particularly advantageous in oil and natural gas exploration due to the excellent characteristics including faster rates of penetration, enhanced hole cleaning, less formation damage, etc. However, how to keep the excellent rheological regulation of bentonite-free drilling fluids was still one of the most serious issues for the mud designers. In this study, novel polymer viscosifier (SDKP) was prepared under optimal synthesis conditions through the copolymerization of N-vinylcaprolactam and sodium 2-acrylamido-2-methylpropane sulfonate. The effect of SDKP on rheological behavior of bentonite-free fluids was studied according to American Petroleum Institute standard. Results showed that SDKP could improve the rheological properties of bentonite-free fluids. In addition, the good thermal stability and salt stability in improving rheological behavior of fluids made SDKP more attractive. Rheological behavior of SDKP based bentonite-free fluids at different temperatures was also evaluated. Results showed that SDKP based bentonite-free fluids showed certain thermo-viscosifying behavior in the temperature range of 80-140 degrees C even in high salinity, which was benefit for carrying cuttings. Shear test showed that the magnitude of the thermo-thickening viscosity was very sensitive to shear rate, and SDKP containing fluids became better shear-thinning upon heating, which could be more easily pumped into the well. In addition, the mechanism of SDKP in improving rheological behavior of bentonite-free fluids was revealed based on the investigation of morphology of SDKP through Environmental Scanning Electron Microscopy experiment.",24,25,3
Degrees C.,Formation Damage,"Franco-Aguirre, Maribel; Zabala, Richard D.; Lopera, Sergio H.; Franco, Camilo A.; Cortes, Farid B.",Ca-DTPMP nanoparticles-based nanofluids for the inhibition and remediation of formation damage due to CaCO3 scaling in tight gas-condensate reservoirs,Calcium carbonate; Formation damage; Inhibition; Nanofluid; Phosphonate; Remediation,CALCIUM-CARBONATE PRECIPITATION; PHOSPHONATE; ADSORPTION; MEDIA; OIL,"The oil productivity of tight gas-condensate reservoirs can be affected by the precipitation/deposition of inorganic scales such calcium carbonate (CaCO3), which leads to a reduction mainly in permeability and porosity of the porous media. Therefore, the main objective of this study is to develop for the first time a nanofluid based on the interaction between active nanoparticles such as Ca-diethylenetriamine pentamethylene phosphonic (Ca-DTPMP) and remaining synthesis fluid (RSF) obtained from the synthesis process, to simultaneously inhibit and remove the formation damage due to the precipitation/deposition of CaCO3 scales. The synthesis of the Ca-DTPMP nanoparticles was performed varying the phosphonate concentration between 0.01 and 0.5 M. The obtained nanoparticles were characterized through N-2 physisorption at - 196 degrees C for obtaining the surface area (S-BET), field emission scanning electron microscopy (FESEM), and dynamic light scattering (DLS) measurements. The mean nanoparticles size of the obtained materials ranged between 36 and 69 nm and was lower for the nanoparticles synthesized with a lower concentration of DTPMP. Nanofluids containing the synthesized nanoparticles of Ca-DTPMP were prepared with RSF solutions in deionized water as a carrier fluid for different Ca-DTPMP/RSF ratios of 10, 50, 200 and 500. The ability of the nanoparticles and nanofluids to inhibit the CaCO3 scaling was evaluated in batch-mode experiments at 70 degrees C by measuring changes in the calcium ion (Ca2+) concentration in the solution. The nanofluid with better performance was that prepared with 50 mg/L of Ca-DTPMP/0.3 nanoparticles and a Ca-DTPMP/RSF ratio of 10, with an inhibition efficiency of 67%. Further, coreflooding tests were carried out using the nanofluid with better performance from the batch-mode experiments. Displacement tests were conducted under tight gas-condensate reservoir conditions at a temperature of 110 degrees C (230 degrees F) and confining and pore pressures of 34.47 MPa (5000 Psi) and 6.89 MPa (1000 Psi), respectively. Inhibition and remediation of CaCO3 scaling were evaluated. The nanofluid was soaked in the porous media for 8 h. Based on the results of the relative permeability and oil recovery curves, it is possible to conclude that the synthesized nanofluid promotes the inhibition and removal of the formation damage due to CaCO3 inorganic scales. The nanofluid injection leads to an increase of the oil permeability of 57% in comparison with the base system, suggesting that the nanofluid acts as inhibitor agent, as remediation treatment, and as stimulation product of oil wells. Also, the treatment showed a perdurability of more than 60 pore volumes and increasing of oil recovery of 4 and 24% regarding the base and the damaged systems, respectively.",16,16,1
Degrees C.,Displacement Efficiency,"Wang, Chao; Liu, Pengcheng; Wang, Fushun; Atadurdyyev, Bayramberdi; Ovluyagulyyev, Mergen",Experimental study on effects of CO2 and improving oil recovery for CO2 assisted SAGD in super-heavy-oil reservoirs,Super-heavy oil reservoir; Steam assisted gravity drainage (SAGD); Reduce viscosity; Carbon dioxide; Thermal oil recovery,GRAVITY DRAINAGE; STEAM; EOR; PERFORMANCE; INJECTION; SEQUESTRATION; MECHANISM; PRESSURE; BEHAVIOR; SOLVENT,"When developing heavy-oil reservoirs using steam-assisted gravity drainage (SAGD) technology, CO2 is often used to reduce the viscosity of heavy oil and the heat loss of the steam chamber, thereby enhancing oil recovery. The limitation of experimental apparatuses, results in a maximum temperature of the reaction kettle of no more than 150 degrees C. Thus, the solubility of CO2 in super-heavy oil and its impact on decreasing viscosity beyond 150 degrees C requires further discussion. Considering these issues, a high-temperature-resistant heavy-oil mixing apparatus was designed to measure the solubility of CO2 in super-heavy oil and the relative density and viscosity of super-heavy oil under high temperatures and pressures. Core flooding experiments under 200 degrees C were conducted to explore the effects of CO2 on oil displacement efficiency. The results indicated that solubility of CO2 became significantly lower at 200 degrees C, when the viscosity and relative density of super-heavy oil decreased as pressure increased. The viscosity of super-heavy oil saturated with CO2 decreased by 71.2%, and relative density decreased by 10.1% at 200 degrees C compared to those of degassed crude. At temperatures of 120 degrees C, 150 degrees C and 200 degrees C, the ultimate displacement efficiency of super-heavy oil increased by 6.6%, 19.2% and 21.4%, respectively, compared to a temperature of 60 degrees C. At pressures of 1.0 MPa, 2.0 MPa and 4.0 MPa, the ultimate displacement efficiency (46.7%) of super-heavy oil increased by 5.2%, 4.0% and 5.9%, respectively, compared to a pressure of 0.5 MPa. The experiments showed that CO2 injection can effectively reduce the relative density and viscosity of super-heavy oil and improve oil recovery under high temperatures and pressures. CO2 has good potential to improve SAGD efficiency in developing super-heavy-oil reservoirs.",20,21,4
Degrees C.,Displacement Efficiency,"Li, Xiuluan; Shi, Lanxiang; Li, Haozhe; Liu, Pengcheng; Luo, Jian; Yuan, Zhe",Experimental study on viscosity reducers for SAGD in developing extra-heavy oil reservoirs,Steam assisted gravity drainage (SAGD); Viscosity reducer; Extra-heavy oil; Thermal stability; Displacement efficiency,ASSISTED GRAVITY DRAINAGE; ES-SAGD; PHASE-BEHAVIOR; SOLVENT; STEAM; BITUMEN; WELLS; PERFORMANCE; RECOVERY,"Steam assisted gravity drainage (SAGD) is an effective in situ oil recovery technology in developing extra-heavy oil reservoirs. Large volumes of steam are needed, however, to heat the extra-heavy oil because of its high viscosity. Steam generation consumes large amounts of natural gas, which adversely affects the economics of SAGD, especially when oil prices are low. Moreover, environmental concerns arise because of excessive freshwater use and greenhouse gas emissions from the burning of the fossil fuels to generate steam. Considering these limitations and concerns, this paper evaluates the effectiveness of different viscosity reducers to decrease the steam consumption and improve SAGD performance. We conducted a series of screening experiments, including viscosity-reduction ratio, thermal stability, and core flooding, for nine types of viscosity reducers, based on an extra-heavy oil sample from a commercial SAGD project in China. The results indicate that water-soluble viscosity reducer #8, a nanoemulsion, is suitable for SAGD. It has a viscosity-reduction ratio of 98.0% at 50 degrees C and is still effective after high-temperature and high-pressure (200 degrees C, 4.0 MPa) treatment, with a viscosity-reduction ratio of 92.6%. The displacement efficiency is improved by 29.1%, and the cumulative steam-to-oil-ratio is reduced by 45.3% compared with pure steam flooding. Despite viscosity-reduction, the effect of interfacial tension reduction plays an important role in improving displacement efficiency during the coinjection of steam and viscosity reducer #8 has good potential to improve SAGD performance in developing extra-heavy oil reservoirs.",18,21,4
Degrees C.,Displacement Efficiency,"Franco-Aguirre, Maribel; Zabala, Richard D.; Lopera, Sergio H.; Franco, Camilo A.; Cortes, Farid B.",Ca-DTPMP nanoparticles-based nanofluids for the inhibition and remediation of formation damage due to CaCO3 scaling in tight gas-condensate reservoirs,Calcium carbonate; Formation damage; Inhibition; Nanofluid; Phosphonate; Remediation,CALCIUM-CARBONATE PRECIPITATION; PHOSPHONATE; ADSORPTION; MEDIA; OIL,"The oil productivity of tight gas-condensate reservoirs can be affected by the precipitation/deposition of inorganic scales such calcium carbonate (CaCO3), which leads to a reduction mainly in permeability and porosity of the porous media. Therefore, the main objective of this study is to develop for the first time a nanofluid based on the interaction between active nanoparticles such as Ca-diethylenetriamine pentamethylene phosphonic (Ca-DTPMP) and remaining synthesis fluid (RSF) obtained from the synthesis process, to simultaneously inhibit and remove the formation damage due to the precipitation/deposition of CaCO3 scales. The synthesis of the Ca-DTPMP nanoparticles was performed varying the phosphonate concentration between 0.01 and 0.5 M. The obtained nanoparticles were characterized through N-2 physisorption at - 196 degrees C for obtaining the surface area (S-BET), field emission scanning electron microscopy (FESEM), and dynamic light scattering (DLS) measurements. The mean nanoparticles size of the obtained materials ranged between 36 and 69 nm and was lower for the nanoparticles synthesized with a lower concentration of DTPMP. Nanofluids containing the synthesized nanoparticles of Ca-DTPMP were prepared with RSF solutions in deionized water as a carrier fluid for different Ca-DTPMP/RSF ratios of 10, 50, 200 and 500. The ability of the nanoparticles and nanofluids to inhibit the CaCO3 scaling was evaluated in batch-mode experiments at 70 degrees C by measuring changes in the calcium ion (Ca2+) concentration in the solution. The nanofluid with better performance was that prepared with 50 mg/L of Ca-DTPMP/0.3 nanoparticles and a Ca-DTPMP/RSF ratio of 10, with an inhibition efficiency of 67%. Further, coreflooding tests were carried out using the nanofluid with better performance from the batch-mode experiments. Displacement tests were conducted under tight gas-condensate reservoir conditions at a temperature of 110 degrees C (230 degrees F) and confining and pore pressures of 34.47 MPa (5000 Psi) and 6.89 MPa (1000 Psi), respectively. Inhibition and remediation of CaCO3 scaling were evaluated. The nanofluid was soaked in the porous media for 8 h. Based on the results of the relative permeability and oil recovery curves, it is possible to conclude that the synthesized nanofluid promotes the inhibition and removal of the formation damage due to CaCO3 inorganic scales. The nanofluid injection leads to an increase of the oil permeability of 57% in comparison with the base system, suggesting that the nanofluid acts as inhibitor agent, as remediation treatment, and as stimulation product of oil wells. Also, the treatment showed a perdurability of more than 60 pore volumes and increasing of oil recovery of 4 and 24% regarding the base and the damaged systems, respectively.",16,16,1
Degrees C.,Scale,"Khormali, Azizollah; Sharifov, Anar R.; Torba, Dmitry I.",Increasing efficiency of calcium sulfate scale prevention using a new mixture of phosphonate scale inhibitors during waterflooding,Calcium sulfate; Formation damage; Scale inhibitor; Synergistic inhibition effect; Waterflooding,POROUS-MEDIA; WATER INJECTION; SQUEEZE TREATMENT; OIL-RESERVOIRS; PRECIPITATION; CARBONATE; PREDICTION; DEPOSITION; TECHNOLOGY; KINETICS,"Inorganic salt precipitation is one of the main problems in oilfield operations. Different factors affect scale formation and inhibition. Calcium sulfate scale formation occurs during waterflooding due to incompatibility of injection and formation waters. In this work, synthetic formation and injection waters were prepared to determine the influence of reservoir conditions (temperature and pressure), and mixing ratio of the waters on calcium sulfate scale deposition during waterflooding. A new mixture of phosphonate scale inhibitors (SI) was developed for increasing the inhibition efficiency of calcium sulfate scale formation in oil reservoirs. The developed mixture consists of three different industrial phosphonate SI and some additives. The concentrations of components of the developed mixture of phosphonate SI were determined on the basis of a synergistic inhibition effect. The maximum value of the synergistic inhibition effect was about 1.091. Performance of the developed mixture and four different industrial SI (HEDP, ATMP, PPCA and DTPMP) was determined by jar test. The experimental results showed that the developed mixture of phosphonate SI has a better inhibition performance than the industrial inhibitors under any conditions. Its effectiveness was more than 90% at any reservoir temperature (60-120 degrees C) and content of formation water in the solution (10-90%). Furthermore, a minimum inhibitory concentration of the developed mixture of phosphonate SI was about 25 mg/L. Moreover, formation damage due to calcium sulfate precipitation in carbonate rock samples with and without the use of scale inhibitors was investigated. Without the addition of any SI, the damaged permeability was about 58% of the initial rock permeability. The damaged permeability in the presence of the developed mixture of phosphonate SI was about 93.5% of the initial permeability of the used rock samples. Also, a new correlation was developed for predicting a permeability reduction of the rock samples due to calcium sulfate precipitation. The coefficient of determination between experimental and predicted (form correlation) data was 0.99. In addition, the developed mixture of phosphonate SI had the enhanced adsorption/desorption capacities. Its squeeze lifetime was longer up to 22.6% than other inhibitors. The corrosion rate in the solution of the developed mixture of phosphonate SI was lower than 0.063 mm/y at any concentration.",25,29,1
Degrees C.,Scale,"Franco-Aguirre, Maribel; Zabala, Richard D.; Lopera, Sergio H.; Franco, Camilo A.; Cortes, Farid B.",Ca-DTPMP nanoparticles-based nanofluids for the inhibition and remediation of formation damage due to CaCO3 scaling in tight gas-condensate reservoirs,Calcium carbonate; Formation damage; Inhibition; Nanofluid; Phosphonate; Remediation,CALCIUM-CARBONATE PRECIPITATION; PHOSPHONATE; ADSORPTION; MEDIA; OIL,"The oil productivity of tight gas-condensate reservoirs can be affected by the precipitation/deposition of inorganic scales such calcium carbonate (CaCO3), which leads to a reduction mainly in permeability and porosity of the porous media. Therefore, the main objective of this study is to develop for the first time a nanofluid based on the interaction between active nanoparticles such as Ca-diethylenetriamine pentamethylene phosphonic (Ca-DTPMP) and remaining synthesis fluid (RSF) obtained from the synthesis process, to simultaneously inhibit and remove the formation damage due to the precipitation/deposition of CaCO3 scales. The synthesis of the Ca-DTPMP nanoparticles was performed varying the phosphonate concentration between 0.01 and 0.5 M. The obtained nanoparticles were characterized through N-2 physisorption at - 196 degrees C for obtaining the surface area (S-BET), field emission scanning electron microscopy (FESEM), and dynamic light scattering (DLS) measurements. The mean nanoparticles size of the obtained materials ranged between 36 and 69 nm and was lower for the nanoparticles synthesized with a lower concentration of DTPMP. Nanofluids containing the synthesized nanoparticles of Ca-DTPMP were prepared with RSF solutions in deionized water as a carrier fluid for different Ca-DTPMP/RSF ratios of 10, 50, 200 and 500. The ability of the nanoparticles and nanofluids to inhibit the CaCO3 scaling was evaluated in batch-mode experiments at 70 degrees C by measuring changes in the calcium ion (Ca2+) concentration in the solution. The nanofluid with better performance was that prepared with 50 mg/L of Ca-DTPMP/0.3 nanoparticles and a Ca-DTPMP/RSF ratio of 10, with an inhibition efficiency of 67%. Further, coreflooding tests were carried out using the nanofluid with better performance from the batch-mode experiments. Displacement tests were conducted under tight gas-condensate reservoir conditions at a temperature of 110 degrees C (230 degrees F) and confining and pore pressures of 34.47 MPa (5000 Psi) and 6.89 MPa (1000 Psi), respectively. Inhibition and remediation of CaCO3 scaling were evaluated. The nanofluid was soaked in the porous media for 8 h. Based on the results of the relative permeability and oil recovery curves, it is possible to conclude that the synthesized nanofluid promotes the inhibition and removal of the formation damage due to CaCO3 inorganic scales. The nanofluid injection leads to an increase of the oil permeability of 57% in comparison with the base system, suggesting that the nanofluid acts as inhibitor agent, as remediation treatment, and as stimulation product of oil wells. Also, the treatment showed a perdurability of more than 60 pore volumes and increasing of oil recovery of 4 and 24% regarding the base and the damaged systems, respectively.",16,16,1
Degrees C.,Scale,"Ashish; Debnath (Das), Mira",Application of biosurfactant produced by an adaptive strain of C-tropicalis MTCC230 in microbial enhanced oil recovery (MEOR) and removal of motor oil from contaminated sand and water,Biosurfactant; Candida tropicalis; Surfactin; Critical micelle concentration; MEOR,WASTE-WATER; SURFACTIN; BACTERIA; PURIFICATION; HYDROCARBON; SUBSTRATE; GLYCEROL; SOIL,"Microbial enhanced oil recovery (MEOR) represents the use of microorganisms or their products to recover remaining oil trapped up in oil reservoirs. In this study adaptive strain C. tropicalis MTCC230 was used to determine its suitability in MEOR. Biosurfactant produced from an adaptive strain C. tropicalis MTCC230 was characterized as lipopeptide surfactin by Near IR, FTIR spectrum and HPLC and mass spectroscopy analysis. It can significantly reduce the surface tension 72 mN/m to 32 mN/m, with the critical micelle concentration (CMC) of 32.5 mg/l and B. subtilis MTCC2423 used as a standard surfactin (Biosurfactant) producing strain for comparative study. It shows stable Physiochemical properties under the extreme pH(2-12), temperature(30 degrees C - 90 degrees C) and salinity(2%-10%) that promote its potential use in enhanced oil recovery. Oil spreading method and soil washing analysis confirmed it suitability to remove the hydrocarbon contaminants from water and soil. Laboratory scale sand pack column saturated with four stroke engine oil resulted similar to 39.80% additional oil recovery (AOR), suggesting its suitability for commercial use in microbial enhanced oil recovery (MEOR) in oil reservoirs.",14,15,1
Degrees C.,"Methane Adsorption,Adsorption Capacity","Liu, Yu; Zhu, Yanming; Liu, Shimin; Li, Wu; Tang, Xin",Temperature effect on gas adsorption capacity in different sized pores of coal: Experiment and numerical modeling,Coalbed methane; Temperature effect; Methane adsorption; Pore structure; GCMC,CANONICAL MONTE-CARLO; SCANNING-ELECTRON-MICROSCOPY; MOLECULAR SIMULATION; METHANE ADSORPTION; MESOPOROUS CARBONS; ACTIVATED CARBON; PURE GASES; RESERVOIR; DISTRIBUTIONS; MICROPORES,"Accurate methane gas adsorption capacity estimation is key for the coalbed methane (CBM) reservoir gas-in-place assessment. As in situ, the reservoir pressure and temperature vary from one location to another. The temperature induced gas sorption capacity evaluation is important for the CBM and mining industry. In this study, grand canonical Monte Carlo (GCMC) simulation was used to investigate temperature effect on methane adsorption capacity and adsorbed methane density for different sized pores. Methane adsorption experiments were performed to show realistic temperature effect on methane adsorption capacity and the experimental data were used directly to validate the numerical model. The pore structure of coal was characterized by high-pressure mercury injection, low-pressure N-2 gas adsorption, low-pressure CO2 gas adsorption. The simulation results revealed that, first, temperature influence on methane adsorption was more obvious in smaller pores than that in larger pores. Based on the characteristics of the temperature influence on methane adsorption, pores can be divided into three categories: 0.7-0.9 nm pores, 1.0-1.3 nm pores and pores larger than 1.4 nm. In the 0.7-0.9 nm group, methane adsorption capacity decreased by approximately 19% at 3 MPa from 20 degrees C to 100 degrees C. In contrast, in the 1.0-1.3 nm pores and pores larger than 1.4 nm, methane adsorption capacity decreased by approximately 32% and 45%. Second, in 0.7 nm and 1.0 nm pores, methane adsorption capacity decreased linearly with an increase in temperature. In 4.0 nm pores methane adsorption capacity exhibited a negative exponential decrease with increasing temperature at low pressure (<3 MPa). Third, when the pore size was the same, the temperature effect was more obvious at a lower pressure than that at a higher pressure. The experimental results indicated that methane adsorption capacity in the coal sample decreased linearly with temperature increasing, and temperature effect on reducing methane adsorption capacity was greater at low pressure. These experimental results were consistent with the simulation results. Based on simulation and experimental data, it was obvious that temperature-induced gas adsorption capacity variation was both pore size dependent and pressure dependent.",26,27,9
Degrees C.,"Methane Adsorption,Adsorption Capacity","Bakshi, Tuli; Prusty, B. K.; Pathak, K.; Pal, S. K.",Pore characteristics of Damodar valley shale and their effect on gas storage potential,Organic matter; Mineralogy; Pore characteristics; Microporosity; Sorption; Shale gas reservoirs,FORT-WORTH BASIN; NORTHEASTERN BRITISH-COLUMBIA; MISSISSIPPIAN BARNETT SHALE; METHANE SORPTION CAPACITY; NORTH-CENTRAL TEXAS; COALBED METHANE; HYDROCARBON GENERATION; SIZE DISTRIBUTION; THERMAL MATURITY; BOWEN BASIN,"The current global interest in fine grained sedimentary shale rock is driven by its ability to store gas in the pore spaces in them. The current study focuses on the understanding of the gas storage capacity of less explored Damodar Valley shales of India, in light of pore characteristics of organic matter and clay minerals. In this study, four samples were collected from different parts of Damodar valley basin and their geochemical composition, pore structure and adsorption capacity were investigated by XRD studies, rock-eval analyses, low-pressure N-2-CO2 adsorption analyses and high-pressure methane adsorption experiment. The samples were also studied to know their hydrocarbon potential. The relationship between mineralogy, organic matter, and pore-structure was analyzed and finally, their effect on methane sorption capacity was discussed. The shale samples are found to be clay rich. The average clay content of the shale samples is 50.69% and average quartz content is 31.65%. Presence of excellent TOC content (4.8%-37.36%) with a predominance of type III organic matter and Tmax varying from 440 degrees C to 465 degrees C suggests a very good to excellent hydrocarbon generation potential in all the samples. The correlation between the TOC and V-L was found to be positive indicating a positive influence of organic matter on methane sorption capacity of the studied samples. However, a lack of correlation between total clay and CH4-V-L indicates that the role of clay minerals on methane sorption behavior of these shales are inconclusive. A positive correlation between CO2 micropore volume, CH4-V-L and TOC suggest microporous nature of organic matter within the shale samples and their positive control on methane sorption potential. The negative correlation of clay mineral with CO2 micropore volume suggests a lack of microporosity in the clay minerals of the collected shale samples. It was also observed that thermally mature shale samples have higher micropore volume and surface area, and are prone to higher methane sorption capacity compared to that of less mature shales.",23,23,2
Degrees C.,Apparent Viscosity,"Perween, Shama; Beg, Mukarram; Shankar, Ravi; Sharma, Shivanjali; Ranjan, Amit",Effect of zinc titanate nanoparticles on rheological and filtration properties of water based drilling fluids,Electrospun ZnTiO3 nanoparticles; Nanoenhanced drilling fluid; Rheology and filtration properties,XANTHAN GUM; NANOCOMPOSITE; GAS,"The aim of this work is to evaluate the effect of laboratory synthesized ZnTiO3 nanoparticles on rheological and filtration characteristics and their response to heating in a drilling fluid. This work is the first study where the use of zinc titanate (ZnTiO3) nanoparticles is reported to improve the rheological and filtrate loss properties of water based drilling fluid (WBDF). The role of nanoparticles is examined by performing a comparative study on drilling fluid properties by incorporating the ZnTiO3 nanoparticles from 0.05 to 0.30 w/v% in mud formulations. The nanoparticles are obtained by two different synthesis approaches: (a) sol-gel bulk polymerization method (SNP), and (b) sol-electrospinning technique (ENP). These two methods yield nanoparticles with different mean sizes and size distributions. The experimental work has been carried out to investigate the influence of concentration of ZnTiO3 nanoparticles on fluid rheology at 20 degrees C and 70 degrees C and API filtrate at normal temperature and 100 psi pressure according to American Petroleum Institute (API) methodology. The mud samples are subjected to ageing process in hot rolling oven at 110 degrees C for 16 h to study thermal stability and the effect of ageing on rheological and filtration properties. The experimental results show that ZnTiO3 nanoparticles significantly affect to the drilling fluid properties and considerably decrease the filtrate loss and improve thermal stability and rheological properties. Apparent viscosity (AV) for base mud indicated similar to 27% decrease on heating up to 70 degrees C, however, this decrease due to temperature rise is reduced by the addition of 0.30 w/v% nanoparticles (only 6% for SNP and 10% for ENP). It is also found that ageing of base mud at 110 degrees C caused similar to 17.3% reduction in AV at 20 degrees C and similar to 31.5% reduction at 70 degrees C. However, this decrease in AV due to hot rolling ageing was reduced by addition of 0.30w/v% nanoparticles (similar to 6% for SNP and similar to 12% for ENP) at 20 degrees C. AV was found to initially decrease and then increase with increasing concentration of nanoparticles. On addition of 0.30 w/v% nanoparticles, the AV of the hot rolled base mud increased by similar to 9.3% (21.5-23.5) for SNP, and by similar to 20.9% (21.5-26) for ENP. API filtrate of base mud, after hot rolling, reduced by 33% and 35.86% on using 0.30% (w/v) nanoparticle concentration of SNP and ENP, respectively which is a remarkable influence of NP as a fluid loss reducer. This effect can arise due to size, shape and surface area of the added nanoparticles.",33,33,1
Degrees C.,Apparent Viscosity,"Fakoya, Muili F.; Ahmed, Ramadan M.",A generalized model for apparent viscosity of oil-based muds,Invert-emulsion mud; Shear thinning; Temperature; Oil-water ratio; Clay content; Apparent viscosity,DRILLING-FLUIDS; RHEOLOGY; TEMPERATURE; SUSPENSIONS; EMULSIONS,"Oil-based drilling fluid, typically called oil-based mud (OBM), is an invert emulsion that finds application in drilling operations owing to its outstanding performance, especially in high pressure and high temperature (HPHT) wells. Besides, OBM promotes a better lubricity, ensures wellbore stability, increases the rate of penetration, and facilitates the achievement of low fluid loss and a thin filter-cake. Due to environmental concerns, the use of low-toxicity mineral oils as the base fluid or continuous phase for OBM is preferable. The flow behavior of OBM mainly depends on rheological properties of its continuous phase, and the volume fraction of the dispersed phase. Besides this, other imposed conditions like shear rate and temperature play a significant role. The availability of rheological models that show this connection is necessary for predicting rheology of OBM based on its formulation and borehole condition. This work presents an experimental investigation of the apparent viscosity of OBM within a temperature range of 24-87 degrees C. The continuous phase was prepared with mineral oil, surfactants (emulsifier and wetting agent), organophilic clay, lime, and calcium chloride. Organophilic clay concentrations and oil/water ratio (OWR) were varied. Apparent viscosity measurements are gathered and analyzed. OBM displayed shear-thinning behavior that best fits the Herschel-Bulkley model. The results reveal notable trends of apparent viscosity and rheological parameters with increasing temperature, organophilic clay concentration, and OWR. Generalized empirical models that link the apparent viscosity of the continuous phase to that of OBM are developed by applying nonlinear regression analysis. The prediction of OBM rheological parameters requires the knowledge of continuous phase apparent viscosity at ambient temperature, dispersed phase volume fraction, and temperature. The models give a reasonable prediction of OBM apparent viscosity. The comparison of normalized or reduced rheological parameters and apparent viscosity of OBM and water-based mud (WBM) revealed the sensitivity of viscous properties of OBM to temperature as compared to that of WBM. This revelation shows why OBM is more susceptible to barite sag phenomenon than WBM.",16,16,0
Degrees C.,Phenolic Resin,"Lenji, Majid Abedi; Haghshenasfard, Masoud; Sefti, Mohsen Vafaie; Salehi, Mahsa Baghban; Heidari, Aghdas",Experimental study of swelling and rheological behavior of preformed particle gel used in water shutoff treatment,Preformed particle gel; Swelling ratio; PPG strength; Core flooding; Water cut reduction,ENHANCED OIL-RECOVERY; CONFORMANCE CONTROL; NUMERICAL-SIMULATION; PHENOLIC RESIN; HYDROGELS; POLYMER; POLYACRYLAMIDE; PERMEABILITY; PH; TRANSPORT,"Production of water effluents in mature reservoirs subjected to water flooding face many difficulties that might, ultimately, lead to their abandonment. Gel shutoff treatment of such reservoirs using preformed particle gel (PPG) is a technique used to block fracture channels and to insulate highly permeable zones. The technique not only reduces water production but leads also to successful conformance control. The present study introduces a novel type of PPG with an extremely high swelling ratio. The PPG is made up of polyacrylamide and Aluminum nitrate nanohydrate, which acts like a superabsorbent to absorb water equivalent in weight to 1000-2000 times the dry weight of the gel. Tests were conducted in the present experiment to investigate the effects of polymer and crosslinker concentrations, temperature, salinity, and pH on the swelling of PPG. Results showed that increasing polymer and crosslinker concentrations as well as enhanced salinity led to declining PPG swelling ratio. While PPG swelling ratio was not considerable outside the pH range of 5-9, its rate within this range was relatively high. Moreover, PPG swelling ratio increased only slightly with increasing temperature by up to 100 degrees C, beyond which the 3D network structure of PPG collapsed. Rheological tests were performed to determine PPG strength in three samples selected based on least salt sensitivity factor values. In addition, the core flooding test was performed to evaluate the blocking efficiency and the performance of the three samples in reducing water production in sandpacks. The test results revealed that PPG reduced water effluents in the sandpack by 30%-65%.",22,22,3
Degrees C.,Phenolic Resin,"Gu, Chenglin; Lv, Yahui; Fan, Xiqun; Zhao, Changxi; Dai, Caili; Zhao, Guang",Study on rheology and microstructure of phenolic resin cross-linked nonionic polyacrylamide (NPAM) gel for profile control and water shutoff treatments,Gel; Microstructure; Rheology; Phenolic resin; Plugging agent,GELATION PROCESS; POLYMER; SYSTEM; RESERVOIRS,"Phenolic resin cross-linked polymer gel as a plugging agent for profile control and water shutoff has wide industrial applications. There have been many studies on the gel, but research on the rheology and microstructure has not been systematic. In this study, the rheological properties and microstructure of phenolic resin gel were measured by using a Haake Mars 60 rheometer and a Carl Zeiss Jena cryo-etching electron microscope. Viscosity and viscoelastic moduli of the gel rose constantly and the structure became denser during the gelation process. An increasing polymer or cross-linker concentration increased the viscosity and viscoelastic moduli of the gel. This increase is attributed to a higher polymer concentration contributing to form a stronger membrane structure and a higher cross-linker concentration making the density of the spherical particles higher. The addition of salt and acid affected the stability of the gel. As salinity increased or pH decreased, both the viscosity and viscoelastic moduli of the gel decreased. Combined with the microstructures of the gel systems, this outcome confirmed that salt and acid made the structure of the gel fragile and easily dehydrated. The results showed that phenolic resin gel (gelation temperature: 95 degrees C; aging time: 8 h) can maintain good stability under a salinity of less than 30,000 mg/L or alkaline conditions with pH > 7. This study can help to understand the gelation mechanism of phenolic resin gel and the impact mechanism of various factors.",16,20,13
Degrees C.,Hot Rolling,"Perween, Shama; Beg, Mukarram; Shankar, Ravi; Sharma, Shivanjali; Ranjan, Amit",Effect of zinc titanate nanoparticles on rheological and filtration properties of water based drilling fluids,Electrospun ZnTiO3 nanoparticles; Nanoenhanced drilling fluid; Rheology and filtration properties,XANTHAN GUM; NANOCOMPOSITE; GAS,"The aim of this work is to evaluate the effect of laboratory synthesized ZnTiO3 nanoparticles on rheological and filtration characteristics and their response to heating in a drilling fluid. This work is the first study where the use of zinc titanate (ZnTiO3) nanoparticles is reported to improve the rheological and filtrate loss properties of water based drilling fluid (WBDF). The role of nanoparticles is examined by performing a comparative study on drilling fluid properties by incorporating the ZnTiO3 nanoparticles from 0.05 to 0.30 w/v% in mud formulations. The nanoparticles are obtained by two different synthesis approaches: (a) sol-gel bulk polymerization method (SNP), and (b) sol-electrospinning technique (ENP). These two methods yield nanoparticles with different mean sizes and size distributions. The experimental work has been carried out to investigate the influence of concentration of ZnTiO3 nanoparticles on fluid rheology at 20 degrees C and 70 degrees C and API filtrate at normal temperature and 100 psi pressure according to American Petroleum Institute (API) methodology. The mud samples are subjected to ageing process in hot rolling oven at 110 degrees C for 16 h to study thermal stability and the effect of ageing on rheological and filtration properties. The experimental results show that ZnTiO3 nanoparticles significantly affect to the drilling fluid properties and considerably decrease the filtrate loss and improve thermal stability and rheological properties. Apparent viscosity (AV) for base mud indicated similar to 27% decrease on heating up to 70 degrees C, however, this decrease due to temperature rise is reduced by the addition of 0.30 w/v% nanoparticles (only 6% for SNP and 10% for ENP). It is also found that ageing of base mud at 110 degrees C caused similar to 17.3% reduction in AV at 20 degrees C and similar to 31.5% reduction at 70 degrees C. However, this decrease in AV due to hot rolling ageing was reduced by addition of 0.30w/v% nanoparticles (similar to 6% for SNP and similar to 12% for ENP) at 20 degrees C. AV was found to initially decrease and then increase with increasing concentration of nanoparticles. On addition of 0.30 w/v% nanoparticles, the AV of the hot rolled base mud increased by similar to 9.3% (21.5-23.5) for SNP, and by similar to 20.9% (21.5-26) for ENP. API filtrate of base mud, after hot rolling, reduced by 33% and 35.86% on using 0.30% (w/v) nanoparticle concentration of SNP and ENP, respectively which is a remarkable influence of NP as a fluid loss reducer. This effect can arise due to size, shape and surface area of the added nanoparticles.",33,33,1
Degrees C.,Hot Rolling,"Abdollahi, Mahdi; Pourmahdi, Maryam; Nasiri, Ali Reza",Synthesis and characterization of lignosulfonate/acrylamide graft copolymers and their application in environmentally friendly water-based drilling fluid,Bio-based graft copolymer; Drilling fluid; Rheology; Fluid loss; Structure-property relationship,LIGNIN; ACRYLAMIDE; AGENT; FIBER,"Acrylamide (AAm) was grafted onto lignosulfonate (LS) in the aqueous medium using two different H2O2/CaCl2 redox and potassium persulfate (KPS) thermal initiating systems at 30 and 55 degrees C, respectively. Resulting LS-g-PAAm graft copolymers were characterized by gravimetric, FT-IR and H-1 NMR methods, from which initiator type and AAm concentration dependency of the AAm conversion (X-AAm), grafting percentage (G(%)), grafting efficiency (GE) and copolymer structure were systematically evaluated. It was found that X-AAm and G(%) can be affected significantly by the initiator type and AAm concentration while GE can mostly be affected only by the initiator type. Highest GE of 100% and grafting length of the PAAm chains onto LS was observed in the reaction LA-2 performed using redox initiator at 30 degrees C and initial weight ratio of AAm to LS of 20 while highest XAAm was observed in the reaction LA-3 performed using KPS initiator at 55 degrees C. Graft copolymers as well as LS with different amounts were used to prepare bentonite-based tap water (TWF), sea water (SWF) and NaCl salt saturated water (SSWF) fluids. Rheological and fluid loss (FL) properties of the above fluids were evaluated before and after hot rolling at 250 degrees F for 4 h. It was found that when an amount of 2.45-3.5 g/350 ml water is used; graft copolymers obtained from reactions LA-2 and LA-3 are able to improve rheological properties and to control FL and pH values in the TWF and SSWF, respectively, at low and high temperatures. All fluids showed shear thinning behavior with a gel-like structure under static conditions. Results revealed that thermal stability and salt resistance of the graft copolymers are high enough to be used as an effective additive in the high temperature and high salty water-based drilling fluids (WBDFs). An attempt was made to establish a relationship between the graft copolymer structure and its aqueous solution properties in the various water-based fluids. It was found that simultaneous higher GE (preferentially as high as 100%) and XAAm (as high as possible) in the graft polymers can results in a structure with the best performance in the WBDFs.",21,22,7
Drilling Fluid,Nanoparticles,"Perween, Shama; Beg, Mukarram; Shankar, Ravi; Sharma, Shivanjali; Ranjan, Amit",Effect of zinc titanate nanoparticles on rheological and filtration properties of water based drilling fluids,Electrospun ZnTiO3 nanoparticles; Nanoenhanced drilling fluid; Rheology and filtration properties,XANTHAN GUM; NANOCOMPOSITE; GAS,"The aim of this work is to evaluate the effect of laboratory synthesized ZnTiO3 nanoparticles on rheological and filtration characteristics and their response to heating in a drilling fluid. This work is the first study where the use of zinc titanate (ZnTiO3) nanoparticles is reported to improve the rheological and filtrate loss properties of water based drilling fluid (WBDF). The role of nanoparticles is examined by performing a comparative study on drilling fluid properties by incorporating the ZnTiO3 nanoparticles from 0.05 to 0.30 w/v% in mud formulations. The nanoparticles are obtained by two different synthesis approaches: (a) sol-gel bulk polymerization method (SNP), and (b) sol-electrospinning technique (ENP). These two methods yield nanoparticles with different mean sizes and size distributions. The experimental work has been carried out to investigate the influence of concentration of ZnTiO3 nanoparticles on fluid rheology at 20 degrees C and 70 degrees C and API filtrate at normal temperature and 100 psi pressure according to American Petroleum Institute (API) methodology. The mud samples are subjected to ageing process in hot rolling oven at 110 degrees C for 16 h to study thermal stability and the effect of ageing on rheological and filtration properties. The experimental results show that ZnTiO3 nanoparticles significantly affect to the drilling fluid properties and considerably decrease the filtrate loss and improve thermal stability and rheological properties. Apparent viscosity (AV) for base mud indicated similar to 27% decrease on heating up to 70 degrees C, however, this decrease due to temperature rise is reduced by the addition of 0.30 w/v% nanoparticles (only 6% for SNP and 10% for ENP). It is also found that ageing of base mud at 110 degrees C caused similar to 17.3% reduction in AV at 20 degrees C and similar to 31.5% reduction at 70 degrees C. However, this decrease in AV due to hot rolling ageing was reduced by addition of 0.30w/v% nanoparticles (similar to 6% for SNP and similar to 12% for ENP) at 20 degrees C. AV was found to initially decrease and then increase with increasing concentration of nanoparticles. On addition of 0.30 w/v% nanoparticles, the AV of the hot rolled base mud increased by similar to 9.3% (21.5-23.5) for SNP, and by similar to 20.9% (21.5-26) for ENP. API filtrate of base mud, after hot rolling, reduced by 33% and 35.86% on using 0.30% (w/v) nanoparticle concentration of SNP and ENP, respectively which is a remarkable influence of NP as a fluid loss reducer. This effect can arise due to size, shape and surface area of the added nanoparticles.",33,33,1
Drilling Fluid,Nanoparticles,"Parizad, Amirhossein; Shahbazi, Khalil; Tanha, Abbas Ayatizadeh",Enhancement of polymeric water-based drilling fluid properties using nanoparticles,Drilling fluid; TiO2 nanofluid viscosity; Nanofluid thermal and electrical conductivities; Nanofluid filtration; Nanofluid thermal resistance: nanofluid shale; recovery,SIZE; NANOFLUIDS; VISCOSITY; BEHAVIOR; STABILITY,"The maturity of shallow depth and conventional petroleum reserves together with growing demand for energy have forced the oil industry to drill harsh and deep reserves. Nanotechnology has the ability to improve drilling fluid performance for drilling deeper and harsher environments. In this study, a water-based drilling fluid containing polymers was set as the base fluid. TiO2 nanoparticle was employed to improve rheology, electrical and thermal conductivities of the resultant drilling fluids. The test fluids were made by addition of different concentrations of TiO2 nanoparticle and KCl salt to the base fluid. The resultant samples were examined at different temperatures and 19 different shear rates. Presence of TiO2 particles enhanced not only the rheological behavior but also thermal and electrical conductivities of the drilling fluids up to 25% and 41%, respectively. Moreover, the addition of TiO2 particles increased thermal resistance, shale recovery up to 97.2% and also decreased the filtration volume up to 27%. Moreover, the viscosities of aqueous TiO2 dispersions at different temperatures and TiO2 and KCl concentrations were measured. The TiO2 nanoparticle has good soloubility in hot HCl and HF acids. It was found that the base aqueous fluid viscosity directly affects the resultant drilling fluid viscosity. In this regard, an analysis was performed and a model was proposed.",30,30,2
Drilling Fluid,Nanoparticles,"Xie, Binqiang; Ting, Li; Zhang, Yan; Liu, Chen",Rheological properties of bentonite-free water-based drilling fluids with novel polymer viscosifier,Water-soluble polymers; Viscosifier; Thermo-thickening; Rheology; Bentonite-free drilling fluid,ACRYLAMIDE-BASED TERPOLYMER; ENHANCED OIL-RECOVERY; AQUEOUS-SOLUTION; GRAFT-COPOLYMERS; THERMOASSOCIATIVE COPOLYMERS; CELLULOSE NANOPARTICLES; FORMATION DAMAGE; PERFORMANCE; BEHAVIOR; ADDITIVES,"Water-based drilling fluids with no bentonite content was particularly advantageous in oil and natural gas exploration due to the excellent characteristics including faster rates of penetration, enhanced hole cleaning, less formation damage, etc. However, how to keep the excellent rheological regulation of bentonite-free drilling fluids was still one of the most serious issues for the mud designers. In this study, novel polymer viscosifier (SDKP) was prepared under optimal synthesis conditions through the copolymerization of N-vinylcaprolactam and sodium 2-acrylamido-2-methylpropane sulfonate. The effect of SDKP on rheological behavior of bentonite-free fluids was studied according to American Petroleum Institute standard. Results showed that SDKP could improve the rheological properties of bentonite-free fluids. In addition, the good thermal stability and salt stability in improving rheological behavior of fluids made SDKP more attractive. Rheological behavior of SDKP based bentonite-free fluids at different temperatures was also evaluated. Results showed that SDKP based bentonite-free fluids showed certain thermo-viscosifying behavior in the temperature range of 80-140 degrees C even in high salinity, which was benefit for carrying cuttings. Shear test showed that the magnitude of the thermo-thickening viscosity was very sensitive to shear rate, and SDKP containing fluids became better shear-thinning upon heating, which could be more easily pumped into the well. In addition, the mechanism of SDKP in improving rheological behavior of bentonite-free fluids was revealed based on the investigation of morphology of SDKP through Environmental Scanning Electron Microscopy experiment.",24,25,3
Drilling Fluid,Nanoparticles,"Huo, Jin-hua; Peng, Zhi-gang; Ye, Zhong-bin; Feng, Qian; Zheng, Yong; Zhang, Jian; Liu, Xianjie",Investigation of synthesized polymer on the rheological and filtration performance of water-based drilling fluid system,Water-based drilling fluid system; Poly(SSS/AM/AMPS); Inverse emulsion polymerization; Molecular structure; Rheological and filtration performance; Filtration mechanism,HIGH-TEMPERATURE; CELLULOSE NANOPARTICLES; BEHAVIOR,"Based on the molecular structure requirement of the synthesized polymer resistant to higher temperature and the lower cost demand of water-based drilling fluid system, a kind of synthesized polymer Poly(SSS/AM/AMPS) was prepared by using 2-acrylamido-2-methylpropanesulfonic acid (AMPS), acrylamide (AM) and sodium p-styrenesulfonate (SSS) through inverse emulsion polymerization. Firstly, the molecular structure, molecular weight distribution and thermal stability were studied. Secondly, the Poly(SSS/AM/AMPS) was introduced into water-based drilling fluid system. As a result, when adding amount is 1.2 wt%, it was found that the water drilling fluids is more fitted to the Herschel-Bulkley flow model. Besides, before and after thermal aging test, the FLAPI of drilling fluid system is 9.20 and 9.40 mL, respectively. Moreover, it was shown that the higher temperature resistance of drilling fluid system was also improved, and the operation cost was decreased. Furthermore, the results of adsorption analysis, zeta potential method and morphology analysis shows that Poly(SSS/AM/AMPS) improves the filtration properties of drilling fluid system by absorption and physical plugging.",23,25,7
Drilling Fluid,Nanoparticles,"Saffari, H. R. M.; Soltani, R.; Alaei, M.; Soleymani, M.",Tribological properties of water-based drilling fluids with borate nanoparticles as lubricant additives,Drilling fluids; Nano-additives; Borates; Tribological properties,ZINC BORATE; MAGNESIUM BORATE; LIQUID PARAFFIN; ANTIWEAR,"In this work, several nanostructured borates such as magnesium, zinc, aluminum and titanium borates were synthesized. These borates were added to drilling muds and their ability to improve tribological properties of water-based drilling fluids, was investigated. The tribological properties of the fluids containing these nano-additives were compared with those of a typical mud (containing bentonite and water) with and without a commercial lubricant additive (BitcLub, M-I SWACO) as reference samples. The results indicated that adding nano-additives to the drilling mud increased its extreme pressure property by more than five times compared to the reference samples. At the same time, these nano-additives decreased the coefficient of friction due to their good ability in producing a strong protective film (tribo-film) on the contacting surfaces being stable at extremely high pressure and temperature conditions. Among all the prepared nano-additives, titanium borate, which is biodegradable, showed a significant improvement in tribological properties of drilling fluid as compared to the other borates.",22,25,8
Drilling Fluid,Nanoparticles,"Wang, Zhihao; Wu, Yuanpeng; Luo, Pingya; Tian, Yingpei; Lin, Yuanhua; Guo, Qipeng",Poly (sodium p-styrene sulfonate) modified Fe3O4 nanoparticles as effective additives in water-based drilling fluids,Water-based drilling fluids; Fe3O4 nanoparticles; Poly (sodium p-styrene sulfonate); Rheology; Fluid loss,CONTROLLING FILTRATION PROPERTIES; RHEOLOGICAL PROPERTIES; BENTONITE SUSPENSIONS; HIGH-TEMPERATURES; HIGH-PRESSURE; LOSS AGENT; BEHAVIOR; PERFORMANCE; SHALE; STABILIZATION,"In this work, a series of low solid phase, economic and excellent performance water-based drilling fluids (WBDFs) were obtained by introducing nanoparticles into conventional WBDFs. Fe3O4 nanoparticles which were surface modified by poly (sodium p-styrene sulfonate) (PSSS) through 3-(trimethoxysilyl) proryl methacrylate (TMSPMA) were adopted in low solid WBDFs containing 4 wt % bentonite (BT). The effect of temperature on rheological property and fluid filtration was investigated. When the concentration of Fe3O4/PSSS nanoparticles reached 0.1 wt %, shear thinning of WBDFs will be perfect at different temperatures. When the concentration of Fe3O4/PSSS nanoparticles reached 0.25 wt %, the WBDFs had superior rheological properties, as compared to other concentrations of the particles in salt environment. Rheological curves provide a closely fit for the Bingham model at low temperature, however, the curves fit Herschel-Bulkley model at higher temperature. Rheological tests indicated that higher concentration of Fe3O4/PSSS nanoparticles can effectively improve salt (KCl) tolerance. Under high temperature and high press (HTHP) filtration test, WBDFs with Fe3O4/PSSS nanoparticles exhibited minimum filtration loss volume with the concentration of Fe3O4/PSSS nanoparticles as low as 0.1 wt % at different temperatures. For salt tolerance test, the higher concentration of the Fe3O4/PSSS nanoparticles leads to the lower the amount of fluid loss at the same concentration of KCl. With the concentration of nanoparticles grows to 0.1 wt %, the amount of fluid loss volume was minimum, indicating that Fe3O4/PSSS nanoparticles in WBDFs improve the filtration. The WBDFs with performance improved by Fe3O4/PSSS nanoparticles can be used as effective drilling fluids even under high temperature and high salinity, demonstrating that the modified fluids are potential candidates for drilling in deep and salty formation.",19,20,8
Drilling Fluid,Nanoparticles,"Zhang, Xianmin; Jiang, Guancheng; Dong, Tengfei; Wang, Le; Li, Xinliang; Wang, Guoshuai",An amphoteric polymer as a shale borehole stabilizer in water-based drilling fluids,Borehole stabilizer; Amphoteric polymers; Shale hydration; Micro-nanometer plugging; Water-based drilling fluid,ELEVATED-TEMPERATURE; WELLBORE INSTABILITY; POLYACRYLAMIDE; NANOPARTICLES; SPECTROSCOPY; WELLS; MUDS,"An amphoteric polymer P (acrylamide-styrene-butyl acrylate) (ASBA) was evaluated for use as a shale borehole stabilizer and for its ability to counter the problem of well instability during shale gas exploration and development. The hydrophilic groups in the ASBA increased the adsorption between the ASBA and the shale formation and the hydrophobic groups reduced the hydrophilicity of the sodium bentonite (BT). The addition of 1.6 wt% ASBA resulted in a water contact angle of the BT/ASBA that was more than 40 degrees larger than that of the BT. The amount of linear swelling decreased by 37.81% and the hot-rolling recovery rate of the shale cuttings was more than 60% higher in the 1.6 wt% ASBA solution than in deionized water. The ASBA exhibited micro/nanometer globules with an average diameter of 250.4 nm in aqueous solution. This was in agreement with the results of the morphology tests (scanning electron microscopy (SEM) and transmission electron microscopy (TEM)). The morphology tests, elemental analysis, and thermogravimetric analysis showed that the polymer was evenly dispersed in the aqueous solution and effectively adsorbed onto the BT instead of the free water. The soft globules changed under pressure and effectively plugged the various pores in the formation. Due to the hydrophobicity and the plugging effect, the ASBA prevented the BT aggregation and reduced the filtration loss; the American Petroleum Institute (API) filtration loss of the basic mud containing 1.6 wt% ASBA was reduced by 56.67% compared to the basic mud without ASBA after aging at 150 degrees C. Due to the excellent inhibition of the shale hydration and the micro/nanometer plugging performance, the ASBA has a potential application as a borehole stabilizer in drilling fluids.",19,20,4
Drilling Fluid,Nanoparticles,"Minakov, A. V.; Zhigarev, V. A.; Mikhienkova, E. I.; Neverov, A. L.; Buryukin, F. A.; Guzei, D. V.",The effect of nanoparticles additives in the drilling fluid on pressure loss and cutting transport efficiency in the vertical boreholes,Non-Newtonian fluids; Drilling fluid; Nanoparticles; Rheology; Annular channel; Pressure loss; Herschel-bulkley model; Cutting transport; Vertical borehole; Laminar flow,GRANULAR FLOW; KINETIC-THEORY; HEAT-TRANSFER; COUETTE-FLOW; NANOFLUIDS; PARTICLES; NANOCOMPOSITE; CONVECTION; VISCOSITY; CHANNEL,"The effect of nanoparticles of various chemical components and sizes on the rheological behaviour of drilling fluids, pressure loss and cuttings transport in the vertical borehole for a laminar flow regime is considered in the paper. The results of numerical and experimental studies are presented. Silicon, aluminium and titanium oxides nanoparticles are considered. A drilling fluid is Bentonite-water solution with a mass fraction of 5%. The particles concentration in the solution was varied from 0.25 to 2 wt percentages and the particles sizes ranged from 5 to 50 nm. The dependences of the effective viscosity and rheological parameters of the solutions on the nanoparticles concentrations, sizes and materials were obtained. It was shown that nanoparticles in drilling fluid increase cuttings transport by 17% and decrease the average slip velocity of the sludge particles in 1.7-2.0 times, but the pressure losses when pumping the drilling fluid increase in 2.5 times.",18,18,4
Drilling Fluid,Field,"Mirzaei-Paiaman, Abouzar; Ostadhassan, Mehdi; Rezaee, Reza; Saboorian-Jooybari, Hadi; Chen, Zhangxin",A new approach in petrophysical rock typing,Petrophyisics; Rock typing; Hydraulic flow unit; Kozeny-carman; Reservoir characterization; FZI-Star; PSRTI,HYDRAULIC FLOW UNITS; SPONTANEOUS IMBIBITION; CAPILLARY-PRESSURE; PERMEABILITY; RESERVOIR; CENTRALITY; SELECTION,"Petrophysical rock typing in reservoir characterization is an important input for successful drilling, production, injection, reservoir studies and simulation. In this study petrophysical rock typing is divided into two major categories: 1) a petrophysical static rock type (PSRT): a collection of rocks having the same primary drainage capillary pressure curves or unique water saturation for a given height above the free water level, 2) a petrophysical dynamic rock type (PDRT): a set of rocks with a similar fluid flow behavior. It was shown that static and dynamic rock types do not necessarily overlap or share petrophysical properties, regardless of wettability. In addition, a new index is developed to define PDRTs via the Kozeny-Carman equation and Darcy's law. We also proposed a different index for delineation of PSRTs by combining the Young-Laplace capillary pressure expression and the Kozeny-Carman equation. These new indices were compared with the existing theoretical and empirical indices. Results showed that our indices are representatives of previously developed models which were also tested with mercury injection capillary pressure, water-oil primary drainage capillary pressure, and water-oil relative permeability data on core plugs from a highly heterogeneous carbonate reservoir in an Iranian oil field. This study enabled us to modify the conventional J-function to enhance its capability of normalizing capillary pressure data universally.",62,62,1
Drilling Fluid,Field,"Sun, Jiaxin; Ning, Fulong; Lei, Hongwu; Gai, Xuerui; Sanchez, Marcelo; Lu, Jingan; Li, Yanlong; Liu, Lele; Liu, Changling; Wu, Nengyou; He, Yong; Wu, Min",Wellbore stability analysis during drilling through marine gas hydrate-bearing sediments in Shenhu area: A case study,Natural gas hydrates; Drilling mud invasion; Wellbore stability; Drilling mud property; Reservoir physical property,METHANE HYDRATE; NUMERICAL-SIMULATION; RESERVOIR DISSOCIATION; MECHANICAL-BEHAVIOR; EAST-COAST; TEST-SITE; MODEL; FLUID; TEMPERATURE; INVASION,"Because of the metastable character of natural gas hydrate-bearing sediments (GHBS), they can be easily affected by drilling operations, thereby inducing the wellbore instability risk. This issue is studied in this paper by means of numerical simulations based on the first exploration well performed in the Shenhu area of the South China Sea in 2007. The corresponding simulated results were compared against the field caliper logging curve. Besides this analysis, the effects of both drilling mud properties (i.e., temperature, density, and salinity) and initial reservoir conditions (i.e., permeability, and saturation) on the wellbore stability were further investigated under the condition of drilling mud invasion into the GHBS. It is anticipated that the coupled multiphysics phenomena triggered under operation conditions can lead to wellbore instability and may also trigger the formation of fractures. The simulation results show that the predicted yield region around the borehole of well SH2 conforms to the borehole enlargement observed in the field. The sensitivity analyses indicate that a local increase in the pore pressure is likely to be generated in the wellbore vicinity, triggered by the large amount of free gas to be released during hydrate dissociation, which is in turn induced by heating (i.e., coming from the drilling-friction effects) and the high salinity of the drilling muds typically used. This study shows that by engineering the salinity of the drilling mud, the amount of free gas to be produced from marine GHBS can be controlled, preventing in this way further wellbore instability issues. This research also shows that an increase in the drilling-mud density not only impact on the development of pore pressures near the borehole, but it also affects the extent of drilling-mud invasion. This effect will extend the hydrate dissociation to a wider area and will also reduce the resistance of the formation, leading to further deformation and potential failure. The analyses also show that the increase in the initial hydrate saturation is associated with a stronger sediment and a more stable wellbore. The model also predicts that GHBS with higher absolute permeability will dissipate faster the excess of pore pressure in the surrounding sediment, contributing to wellbore stability; however, the extent of the hydrate dissociation zone will expand and thereby will increase the yield region.",49,54,11
Drilling Fluid,Field,"Davoodi, Shadfar; Ramazani, Ahmad S. A.; Jamshidi, Saied; Jahromi, Arash Fellah",A novel field applicable mud formula with enhanced fluid loss properties in High Pressure-High Temperature well condition containing pistachio shell powder,Pistachio shell powder; Gel strength; Mud cake thickness; High pressure -high temperature; Fluid loss; Polyanionic cellulose; Filter cake,DRILLING-FLUIDS; PERFORMANCE,"Sustainable technologies are the main concerns of the 21st century modified oilfield industries. The insufficiency of conventional drilling fluid formulations with a combination of hardly degradable hazardous chemicals as additives raise the demands of field-applicable innovative and environmentally friendly methods. Pistachio Shell discards as degradable wastes, which can intellectually apply in drilling fluid formulation. The experimental oilfield investigations of utilizing pistachio shell powder prove the significant enhancement of rheological properties, reduction of fluid loss and mud cake thickness in both API (Low Pressure - Low Temperature) and High Pressure - High Temperature (HPHT) conditions. The main point of concern is substituting polyanionic cellulose polymer, which frequently used in water-based conventional mud formulations with pistachio shell in the form of two distinct fine particle sizes. Both particle sizes prove their ultra practical properties to be used as fluid loss control agent. Also producing thin and high-quality mud cakes demonstrate their applicative field attribute. The relatively fine particle size (less than 75 mu m) shows the maximum efficiency with % 44 fluid loss reduction and the highest value of plastic viscosity, yield point, and gel strength, which are indicators of very appropriate rheology. Moreover, the cost analysis shows 13% reduction in the cost of preparing drilling fluid in compared to the fluid with polyanionic cellulose. The lab to field approach of the experiments increases the certainty of the field scaling practices and eliminates the demands of intermediate upscaling stages. The presented method successfully apply in one of the Iranian oil fields.",28,29,2
Drilling Fluid,Field,"Beg, Mukarram; Sharma, Shivanjali; Ojha, Umaprasana",Effect of cationic copolyelectrolyte additives on drilling fluids for shales,Copolyelectrolytes; Shale retention; Borehole instability; Phase segregation; Drilling fluids,OPTIMIZATION; FIELD; MUD,"Wellbore instability remains one of the major challenges in terms of both time and economy during drilling. The issue is more pronounced in reactive shale formations. A set of polytertiary amines (PTA)-ran-polyquaternary amines (PQA) polymers possessing different ratios of tertiary amine to quaternary amine (0: 100, 40: 60, 60: 40, mol: mol) segments were synthesized and their efficacy towards the wellbore stability of shale reservoirs were ascertained. When added in similar weight proportions, the copolymer possessing 60: 40 (mol: mol) ratio of tertiary to quaternary amine moieties (PTA-ran-PQA-64) enhanced the apparent (>= 58%) and plastic (>= 71%) viscosities of silicate drilling fluid to maximum extent. The amount of API filtrate reduced with increasing concentration of the copolymers and filtrate loss in case of the mud containing polyelectrolyte PTA-ran-PQA-64 was lower compared to the other two polyelectrolytes. Hot rolling shale dispersion test showed that the shale recovery improved from 91 to 97% on inclusion of minimum amounts (0.25 wt%) of these polyelectrolytes in the drilling fluid. The Linear Swell Meter (LSM) data demonstrated, the swelling in shale pallet is 11% in absence of polyelectrolytes and gets reduced to 4.3% in presence of PTA-ran-PQA-64. The above studies revealed that, these copolymers are viable candidates as drilling fluid additives to possibly enhance the wellbore stability.",27,27,0
Drilling Fluid,Field,"Yang, Zhao-Zhong; Yi, Liang-Ping; Li, Xiao-Gang; He, Wei",Pseudo-three-dimensional numerical model and investigation of multi-cluster fracturing within a stage in a horizontal well,Displacement discontinuity method; Multi-cluster fracturing; Horizontal well; Three-dimensional fracture,HYDRAULIC FRACTURES; PROPAGATION,"Multi-cluster fracturing and horizontal drilling are the key techniques used to exploit unconventional reservoirs. However, field production has revealed that certain perforation clusters are invalid. In order to find the most effective approaches to improve the uniformity of multiple-fracture growth, a pseudo-3D multi-cluster fracturing model is established in this study. In our model, complex in-situ stress distributions are considered and the stress interactions between fractures are calculated using the displacement discontinuity method (DDM). Fluid dynamic flow distributions into different clusters are calculated using Kirchhoff's second law. Fracture height and length extension velocities are determined based on the fracture edge energy release rate. The effectiveness of our model is verified by comparing the single fracture extension results obtained by our model to those obtained by a semi-analytical model. Based on our numerical model, possible approaches to promoting the uniform growth of multiple fractures are discussed. The results indicate that adjusting spacing is an inefficient method to promote multiple-fracture uniform growth under the condition of four clusters fracturing within a stage. However, regulating perforation friction, reducing fracturing fluid viscosity, and increasing injection rate are useful ways to improve the uniformity of multiple-fracture propagation.",20,24,4
Drilling Fluid,Field,"Tian, Jialin; Li, Jurui; Cheng, Wenming; Zhu, Zhi; Yang, Lin; Yang, Yi; Zhang, Tangjia",Working mechanism and rock-breaking characteristics of coring drill bit,Drilling; Coring drill bit; Drillability; ROP(rate of penetration); Mechanism; Cores,,"For improving the rate of penetration of the complex well structure and performance of the coring drill bit, this paper is to investigate a new type of coring drill bit that generates small-diameter core samples during the drilling process. A special jet channel is designed inside the drill bit body, and the high-pressure drilling fluid flows through the special jet channel to the coring channel, then the cored rock is taken out of the downhole from the drill bit under the negative pressure. Based on the hydrodynamics theory, rock breaking mechanics and actual drilling conditions, the rock breaking mechanism model of the coring drill bit is established. The difference of rock breaking performance between the new drill bit and the existing drill bit is analyzed based on the analysis of numerical example, laboratory and field test. The research results indicate that the special structure design in the new drill bit has the effect of 'absorbing the bottom rock cuttings and pushing the upper rock cuttings' during the process of rock breaking. The effect can reduce the repeated cutting of cores at the bottom hole and improve the ROP(rate of penetration). Field tests show that when the flow rate of drill pump is 25L/s, the result of ROP can be increased by 15%-40%. The new design drill bit can present innovative ideas for improving the efficiency of coring and the quality of geological logging during the drilling process. Moreover, the analysis models can provide references for the new research of improving ROP and drilling efficiency, especially under the conditions of complex structure or large displacement wells.",19,22,3
Drilling Fluid,Field,"Said, Mohammed Mokhtar; El-Sayed, Abdel-Alim Hashim",The use of palm oil fatty acid methyl ester as a base fluid for a flat rheology high-performance drilling fluid,Deepwater drilling; Vegetable oil mud; HTHP drilling fluid; Environmentally friendly drilling fluid,MUD,"Exploration for oil and gas in increasingly difficult environments is constantly fueled by rising world energy demand. Exploration is now extending into environmentally-sensitive regions, particularly in offshore fields. Oil and synthetic-based muds have always performed better with hostile drilling cases. However, they are also a cause for environmental concern and potential long-term liabilities for damage caused by mud spills, and are associated with problems in disposing of oil-contaminated drill cuttings. In response to these concerns, the oil industry has been replacing high-aromatic oils (e.g., diesel) with low-aromatic mineral oils as well as synthetic oils. One of the possibilities in avoiding these problems, while keeping the advantages of oil-based muds, is to substitute mineral oils with biodegradable vegetable oils. In this paper, it is shown that palm oil fatty acid methyl ester is successfully used as a base fluid for a high-performance, oil-based flat rheology drilling fluid. The performance of this newly formulated vegetable oil-based drilling fluid is compared to that of commercially available oil-based drilling fluids to evaluate the potential of their use. Fluid samples were formulated up to 18 ppg density and passed contamination tests. The formulated fluid was also statically aged and hot rolled for performance tests. The resulting drilling fluid is an environmentally-friendly fluid suitable for environmentally sensitive areas. The fluid testing results are then used to perform hydraulic simulations to estimate the fluid performance in the field.",16,18,4
Drilling Fluid,Field,"Al Saedi, A. Q.; Flori, R. E.; Kabir, C. S.","New analytical solutions of wellbore fluid temperature profiles during drilling, circulating, and cementing operations",,HEAT-TRANSFER; INJECTION; PREDICT; WELLS; MODEL; FLOW,"Historically, the formulation of the wellbore temperature profiles during drilling, circulating, and cementing operations relied upon the boundary condition or BC at the bottomhole location, wherein the tubular and annular temperatures become equal. This study presents two other formulations to explore alternative to bottomhole BC's that may potentially occur in wellbores. Application of the energy balance in the wellbore for both forward and reverse circulations underpins all three formulations. The wellbore temperature profiles generated by implementing the energy balance in the system depends on the type of the boundary condition used. Initially, we generated various temperature profiles using these models. In general, we observed that the maximum temperature occurs at the end of the tubular or some distance away from the bottom. For open and cased-hole sections, the difference in heat-transfer coefficients triggers different magnitudes of heat transfer and affects the corresponding temperature profiles. We compared the performance of our models with those presented in the literature. Thereafter, we sought to validate the models with diverse set of field data. Given the ability of all three models to handle changes in the geothermal gradient due to the characteristics of the sediments, salt domes, and gas hydrates, we explored their performance in situations where there is significant heat transfer. The holistic approach pursued here provided the necessary insights into various temperature profiles in a given situation.",15,15,1
Drilling Fluid,Field,"Akhtar, Tarek Firoze; Ahmed, Ramadan; Elgaddafi, Rida; Shah, Subhash; Amani, Mahmmod",Rheological behavior of aqueous foams at high pressure,Foam; Rheology; Yield stress; Non-Newtonian fluid; Friction pressure loss; Wall-slip,CONSTITUTIVE EQUATION; SHEAR; FLOW,"Aqueous foams are used in many oil field applications including drilling, fracturing, and enhanced oil recovery operations. The success of all these operations strongly depends on viscosity and stability of foam. Rheology of foams is a function of foam quality (i.e. gas volume fraction), liquid phase viscosity, pressure, and temperature. Besides, foam generation method and stability are factors that influence its rheology. This article presents results of an experimental study performed to investigate the effects of foam quality, pressure, and wall slip on aqueous-foam rheology. Extensive tests were conducted using a foam recirculating flow loop consisting of three pipe viscometers. Experiments were performed at ambient temperature, and varying pressure (6.89-20.68 MPa), foam quality (40-80%), and pipe diameter (3.06, 6.22 and 12.67 mm). The foam was generated by passing a mixture of water containing 2% surfactant solution and gas phase (nitrogen) through a needle valve. To minimize degradation while testing, the foam was regenerated by circulating at the maximum flow rate (0.55 L/min) before each flow measurement was made. Results indicate strong non-Newtonian behavior of foam, which closely fits the power law model. For foams with more than 55% quality, measured viscosities were higher than the ones reported in the literature. Noticeable wall slip was not observed. Foam viscosity change because of pressure variation at a constant foam quality was negligible. Foams with quality higher than 70% exhibited yield pseudoplastic behavior. Their rheological behavior can be described better by Herschel-Bulkley model than power law model when the shear rate is below 20 1/s.",14,14,1
Drilling Fluid,Degrees C,"An, Yuxiu; Yu, Peizhi",A strong inhibition of polyethyleneimine as shale inhibitor in drilling fluid,Swelling; Inhibition; Mechanism; Polyethyleneimine; Shale,WELLBORE INSTABILITY; STABILITY; DESIGN; MODEL,"In this paper, the inhibition property of polyethyleneimine (PEI) in montmorillonite solution was studied. The inhibition property was evaluated by linear swelling test and rolling recovery test. Compared with other inhibitors, the addition of PEI resulted in the lowest swelling height in drilling fluid. In rolling recovery rate study, the addition of PEI resulted in the highest recovery rate after rolled at 120 degrees C. More importantly, PEI was environmental friendly inhibitor. The inhibition mechanism was investigated by Fourier transform infrared spectroscopy, X-ray diffraction, Transmission electron microscope, Scanning electron microscopy, Atomic force microscope, Zeta potential and Particle-size analyzer. The spectrums and images showed that the negative charge in the surface of montmorillonite (MMT) was neutralized by the positive charge in amino group of PEI. PEI was adsorbed in the surface and intercalated into interlayer of MMT, which reduced the hydration repulsion of diffuse electric double layer and prevented the invasion of water. Hydrogen bonding between hydroxyl in the surface of clay and amino groups in the backbone and side chain of PEI can be formed in the process. The adsorption and intercalation of PEI in the surface and interlayer of MMT was the major factor to prevent water molecules from invading into the gallery of clay. There were a quantity of positive ions in solution because of the protonation of nitrogen in water. More positive ions resulted in the stronger force between inhibitor and clay.",45,49,1
Drilling Fluid,Degrees C,"Perween, Shama; Beg, Mukarram; Shankar, Ravi; Sharma, Shivanjali; Ranjan, Amit",Effect of zinc titanate nanoparticles on rheological and filtration properties of water based drilling fluids,Electrospun ZnTiO3 nanoparticles; Nanoenhanced drilling fluid; Rheology and filtration properties,XANTHAN GUM; NANOCOMPOSITE; GAS,"The aim of this work is to evaluate the effect of laboratory synthesized ZnTiO3 nanoparticles on rheological and filtration characteristics and their response to heating in a drilling fluid. This work is the first study where the use of zinc titanate (ZnTiO3) nanoparticles is reported to improve the rheological and filtrate loss properties of water based drilling fluid (WBDF). The role of nanoparticles is examined by performing a comparative study on drilling fluid properties by incorporating the ZnTiO3 nanoparticles from 0.05 to 0.30 w/v% in mud formulations. The nanoparticles are obtained by two different synthesis approaches: (a) sol-gel bulk polymerization method (SNP), and (b) sol-electrospinning technique (ENP). These two methods yield nanoparticles with different mean sizes and size distributions. The experimental work has been carried out to investigate the influence of concentration of ZnTiO3 nanoparticles on fluid rheology at 20 degrees C and 70 degrees C and API filtrate at normal temperature and 100 psi pressure according to American Petroleum Institute (API) methodology. The mud samples are subjected to ageing process in hot rolling oven at 110 degrees C for 16 h to study thermal stability and the effect of ageing on rheological and filtration properties. The experimental results show that ZnTiO3 nanoparticles significantly affect to the drilling fluid properties and considerably decrease the filtrate loss and improve thermal stability and rheological properties. Apparent viscosity (AV) for base mud indicated similar to 27% decrease on heating up to 70 degrees C, however, this decrease due to temperature rise is reduced by the addition of 0.30 w/v% nanoparticles (only 6% for SNP and 10% for ENP). It is also found that ageing of base mud at 110 degrees C caused similar to 17.3% reduction in AV at 20 degrees C and similar to 31.5% reduction at 70 degrees C. However, this decrease in AV due to hot rolling ageing was reduced by addition of 0.30w/v% nanoparticles (similar to 6% for SNP and similar to 12% for ENP) at 20 degrees C. AV was found to initially decrease and then increase with increasing concentration of nanoparticles. On addition of 0.30 w/v% nanoparticles, the AV of the hot rolled base mud increased by similar to 9.3% (21.5-23.5) for SNP, and by similar to 20.9% (21.5-26) for ENP. API filtrate of base mud, after hot rolling, reduced by 33% and 35.86% on using 0.30% (w/v) nanoparticle concentration of SNP and ENP, respectively which is a remarkable influence of NP as a fluid loss reducer. This effect can arise due to size, shape and surface area of the added nanoparticles.",33,33,1
Drilling Fluid,Degrees C,"Xie, Binqiang; Ting, Li; Zhang, Yan; Liu, Chen",Rheological properties of bentonite-free water-based drilling fluids with novel polymer viscosifier,Water-soluble polymers; Viscosifier; Thermo-thickening; Rheology; Bentonite-free drilling fluid,ACRYLAMIDE-BASED TERPOLYMER; ENHANCED OIL-RECOVERY; AQUEOUS-SOLUTION; GRAFT-COPOLYMERS; THERMOASSOCIATIVE COPOLYMERS; CELLULOSE NANOPARTICLES; FORMATION DAMAGE; PERFORMANCE; BEHAVIOR; ADDITIVES,"Water-based drilling fluids with no bentonite content was particularly advantageous in oil and natural gas exploration due to the excellent characteristics including faster rates of penetration, enhanced hole cleaning, less formation damage, etc. However, how to keep the excellent rheological regulation of bentonite-free drilling fluids was still one of the most serious issues for the mud designers. In this study, novel polymer viscosifier (SDKP) was prepared under optimal synthesis conditions through the copolymerization of N-vinylcaprolactam and sodium 2-acrylamido-2-methylpropane sulfonate. The effect of SDKP on rheological behavior of bentonite-free fluids was studied according to American Petroleum Institute standard. Results showed that SDKP could improve the rheological properties of bentonite-free fluids. In addition, the good thermal stability and salt stability in improving rheological behavior of fluids made SDKP more attractive. Rheological behavior of SDKP based bentonite-free fluids at different temperatures was also evaluated. Results showed that SDKP based bentonite-free fluids showed certain thermo-viscosifying behavior in the temperature range of 80-140 degrees C even in high salinity, which was benefit for carrying cuttings. Shear test showed that the magnitude of the thermo-thickening viscosity was very sensitive to shear rate, and SDKP containing fluids became better shear-thinning upon heating, which could be more easily pumped into the well. In addition, the mechanism of SDKP in improving rheological behavior of bentonite-free fluids was revealed based on the investigation of morphology of SDKP through Environmental Scanning Electron Microscopy experiment.",24,25,3
Drilling Fluid,Degrees C,"Sepehri, Sanam; Soleyman, Rouhollah; Varamesh, Akbar; Valizadeh, Majid; Nasiri, Alireza",Effect of synthetic water-soluble polymers on the properties of the heavy water-based drilling fluid at high pressure-high temperature (HPHT) conditions,Water-based drilling fluid; Fluid loss; Synthetic polymer; High temperature-high pressure conditions,ACRYLAMIDE,"Nowadays, by rising age of oil wells, the utilization of high pressure-high temperature (HPHT) additives in deep well drilling is unavoidable. In this study, a terpolymer of acrylamide/2-acrylamido-2-methyl propane sulfonic acid/N-vinyl caprolactam and a tetrapolymer of acrylamide/2-acrylamido-2-methyl propane sulfonic acid/3-allyl Oxy-2-hydroxy-1-propane sulfonic acid/acrylic acid were synthesized by solution polymerization and characterized by Fourier transform-infrared (FTIR) spectroscopy, thermal gravimetric analysis (TGA) and hydrogen nuclear magnetic resonance ((HNMR)-H-1) techniques. The effect of crosslinking agent, transfer agent and comonomer contents of the synthesized polymers on the fluid loss and the rheological properties of the heavy drilling fluid containing these synthesized products were studied. The stability and performance of the tetrapolymer were better in the heavy drilling fluid at high temperature and high salt concentration. The fluid losses of the prepared heavy drilling fluid by tetrapolymer were 1.9 and 2.1 cc/30 min in NaCl saturated water and formation water of Iran reservoirs at 150 degrees C, respectively.",24,28,2
Drilling Fluid,Degrees C,"Abdollahi, Mahdi; Pourmahdi, Maryam; Nasiri, Ali Reza",Synthesis and characterization of lignosulfonate/acrylamide graft copolymers and their application in environmentally friendly water-based drilling fluid,Bio-based graft copolymer; Drilling fluid; Rheology; Fluid loss; Structure-property relationship,LIGNIN; ACRYLAMIDE; AGENT; FIBER,"Acrylamide (AAm) was grafted onto lignosulfonate (LS) in the aqueous medium using two different H2O2/CaCl2 redox and potassium persulfate (KPS) thermal initiating systems at 30 and 55 degrees C, respectively. Resulting LS-g-PAAm graft copolymers were characterized by gravimetric, FT-IR and H-1 NMR methods, from which initiator type and AAm concentration dependency of the AAm conversion (X-AAm), grafting percentage (G(%)), grafting efficiency (GE) and copolymer structure were systematically evaluated. It was found that X-AAm and G(%) can be affected significantly by the initiator type and AAm concentration while GE can mostly be affected only by the initiator type. Highest GE of 100% and grafting length of the PAAm chains onto LS was observed in the reaction LA-2 performed using redox initiator at 30 degrees C and initial weight ratio of AAm to LS of 20 while highest XAAm was observed in the reaction LA-3 performed using KPS initiator at 55 degrees C. Graft copolymers as well as LS with different amounts were used to prepare bentonite-based tap water (TWF), sea water (SWF) and NaCl salt saturated water (SSWF) fluids. Rheological and fluid loss (FL) properties of the above fluids were evaluated before and after hot rolling at 250 degrees F for 4 h. It was found that when an amount of 2.45-3.5 g/350 ml water is used; graft copolymers obtained from reactions LA-2 and LA-3 are able to improve rheological properties and to control FL and pH values in the TWF and SSWF, respectively, at low and high temperatures. All fluids showed shear thinning behavior with a gel-like structure under static conditions. Results revealed that thermal stability and salt resistance of the graft copolymers are high enough to be used as an effective additive in the high temperature and high salty water-based drilling fluids (WBDFs). An attempt was made to establish a relationship between the graft copolymer structure and its aqueous solution properties in the various water-based fluids. It was found that simultaneous higher GE (preferentially as high as 100%) and XAAm (as high as possible) in the graft polymers can results in a structure with the best performance in the WBDFs.",21,22,7
Drilling Fluid,Degrees C,"Zhang, Xianmin; Jiang, Guancheng; Dong, Tengfei; Wang, Le; Li, Xinliang; Wang, Guoshuai",An amphoteric polymer as a shale borehole stabilizer in water-based drilling fluids,Borehole stabilizer; Amphoteric polymers; Shale hydration; Micro-nanometer plugging; Water-based drilling fluid,ELEVATED-TEMPERATURE; WELLBORE INSTABILITY; POLYACRYLAMIDE; NANOPARTICLES; SPECTROSCOPY; WELLS; MUDS,"An amphoteric polymer P (acrylamide-styrene-butyl acrylate) (ASBA) was evaluated for use as a shale borehole stabilizer and for its ability to counter the problem of well instability during shale gas exploration and development. The hydrophilic groups in the ASBA increased the adsorption between the ASBA and the shale formation and the hydrophobic groups reduced the hydrophilicity of the sodium bentonite (BT). The addition of 1.6 wt% ASBA resulted in a water contact angle of the BT/ASBA that was more than 40 degrees larger than that of the BT. The amount of linear swelling decreased by 37.81% and the hot-rolling recovery rate of the shale cuttings was more than 60% higher in the 1.6 wt% ASBA solution than in deionized water. The ASBA exhibited micro/nanometer globules with an average diameter of 250.4 nm in aqueous solution. This was in agreement with the results of the morphology tests (scanning electron microscopy (SEM) and transmission electron microscopy (TEM)). The morphology tests, elemental analysis, and thermogravimetric analysis showed that the polymer was evenly dispersed in the aqueous solution and effectively adsorbed onto the BT instead of the free water. The soft globules changed under pressure and effectively plugged the various pores in the formation. Due to the hydrophobicity and the plugging effect, the ASBA prevented the BT aggregation and reduced the filtration loss; the American Petroleum Institute (API) filtration loss of the basic mud containing 1.6 wt% ASBA was reduced by 56.67% compared to the basic mud without ASBA after aging at 150 degrees C. Due to the excellent inhibition of the shale hydration and the micro/nanometer plugging performance, the ASBA has a potential application as a borehole stabilizer in drilling fluids.",19,20,4
Drilling Fluid,Degrees C,"Fakoya, Muili F.; Ahmed, Ramadan M.",A generalized model for apparent viscosity of oil-based muds,Invert-emulsion mud; Shear thinning; Temperature; Oil-water ratio; Clay content; Apparent viscosity,DRILLING-FLUIDS; RHEOLOGY; TEMPERATURE; SUSPENSIONS; EMULSIONS,"Oil-based drilling fluid, typically called oil-based mud (OBM), is an invert emulsion that finds application in drilling operations owing to its outstanding performance, especially in high pressure and high temperature (HPHT) wells. Besides, OBM promotes a better lubricity, ensures wellbore stability, increases the rate of penetration, and facilitates the achievement of low fluid loss and a thin filter-cake. Due to environmental concerns, the use of low-toxicity mineral oils as the base fluid or continuous phase for OBM is preferable. The flow behavior of OBM mainly depends on rheological properties of its continuous phase, and the volume fraction of the dispersed phase. Besides this, other imposed conditions like shear rate and temperature play a significant role. The availability of rheological models that show this connection is necessary for predicting rheology of OBM based on its formulation and borehole condition. This work presents an experimental investigation of the apparent viscosity of OBM within a temperature range of 24-87 degrees C. The continuous phase was prepared with mineral oil, surfactants (emulsifier and wetting agent), organophilic clay, lime, and calcium chloride. Organophilic clay concentrations and oil/water ratio (OWR) were varied. Apparent viscosity measurements are gathered and analyzed. OBM displayed shear-thinning behavior that best fits the Herschel-Bulkley model. The results reveal notable trends of apparent viscosity and rheological parameters with increasing temperature, organophilic clay concentration, and OWR. Generalized empirical models that link the apparent viscosity of the continuous phase to that of OBM are developed by applying nonlinear regression analysis. The prediction of OBM rheological parameters requires the knowledge of continuous phase apparent viscosity at ambient temperature, dispersed phase volume fraction, and temperature. The models give a reasonable prediction of OBM apparent viscosity. The comparison of normalized or reduced rheological parameters and apparent viscosity of OBM and water-based mud (WBM) revealed the sensitivity of viscous properties of OBM to temperature as compared to that of WBM. This revelation shows why OBM is more susceptible to barite sag phenomenon than WBM.",16,16,0
Drilling Fluid,Cuttings Transport,"Hakim, Hadyan; Katende, Allan; Sagala, Farad; Ismail, Issham; Nsamba, Hussein",Performance of polyethylene and polypropylene beads towards drill cuttings transportation in horizontal wellbore,Drilled cuttings; Drilling mud; Water-based mud; Polymer beads; Polyethylene beads; Polypropylene beads,,"Drilled cuttings removal is critical in drilling operations, especially in horizontal wells. These cuttings are postulated to be among the possible causes of many costly complications, such as mechanical pipe sticking, bore hole instability, drag and torque. This study proposes a new approach that uses polymer beads as a mud additive to improve cutting transportation. In this study, the effect of the concentration of polyethylene (PE) and polypropylene (PP) polymer beads on cuttings transport efficiency (CTE) in water-based mud in a horizontal wellbore was investigated. Experiments were conducted in a lab-scale flow loop equipped with a 13-ft (3.96 m) test section consisting of a concentric annulus acrylic outer casing (2 in. ID) and a static inner PVC drill string (0.79 in. OD). A total of 150 tests were conducted using 10 ppg water based mud (WBM) with 1%-5% by vol. Concentrations of polymer beads (PE and PP) were added at a range of 8-9.5 cp. Six different sizes of drilled cuttings ranging from 0.5 to 4.0mm were used as samples to determine the CTE at a constant 0.69 m/s average annular fluid velocity. The results revealed that CTE increased with the increase of polymer bead concentrations and that PP is better compared to PE overall due to its low density. The highest CTE was recorded at a 5% concentration of water-based mud polypropylene (WBMPP), which is approximately 96% for cutting sizes of 0.50mm-0.99 mm.",33,34,2
Drilling Fluid,Cuttings Transport,"Pang, Boxue; Wang, Shuyan; Wang, Qiujin; Yang, Kai; Lu, Huilin; Hassan, Muhammad; Jiang, Xiaoxue",Numerical prediction of cuttings transport behavior in well drilling using kinetic theory of granular flow,Cuttings transport; Kinetic theory of granular flow; Granular temperature; Pressure drop; Non-newtonian fluid; Drill pipe rotation,NON-NEWTONIAN FLUIDS; SOLID-LIQUID FLOW; DRILLPIPE ROTATION; PIPE ROTATION; ANNULUS; PARAMETERS; PROFILES; VELOCITY; MODEL; CFD,"The cuttings transport during well drilling was numerically simulated based on kinetic theory of granular flow in combination with sliding mesh for drill pipe rotation. The power-law model was implemented to describe the rheological behavior of drilling fluid. Numerical results were compared with available experimental data in the literature to validate the algorithm, and good agreement was found. Three distinguishable regions of cuttings flow pattern and swaying phenomenon of cuttings distribution were observed along the direction of drill pipe rotation. Increasing the fluid velocity results in a reduction in the height of cuttings bed and weakening of the swaying phenomenon. Higher apparent viscosity of drilling fluid contributes to a good performance of cuttings transport at a low annular velocity, but rising in pressure loss. There is critical inclination angle of the well.ctr for cuttings transport ratio and theta(dp) for pressure drop through the annulus. The most difficult of cuttings transport occurs in the well inclinations around 35 degrees-65 degrees. There is no additional contribution of drill pipe rotation to cuttings transport after reaching a critical rotation speed. Increasing the cutting size leads to a reduction in the cuttings transport ratio and an increase in pressure drop.",32,34,8
Drilling Fluid,Cuttings Transport,"Epelle, Emmanuel, I; Gerogiorgis, Dimitrios, I",CFD modelling and simulation of drill cuttings transport efficiency in annular bends: Effect of particle sphericity,Particle sphericity; Drag coefficient; Annular bends; Volume fraction,VERTICAL ELECTRICAL FURNACE; PERLITE GRAIN EXPANSION; NONSPHERICAL PARTICLES; FLUIDIZED-BED; FLOW; DRAG; DYNAMICS; SHAPE; COEFFICIENT; ROTATION,"Accurate prediction of the flow behaviour of drill cuttings carried by a non-Newtonian fluid in an annular geometry is important for the successful and efficient design, operation, and optimisation of drilling operations. Although it is widely recognised that practical drilling operations hardly involve perfectly spherical cuttings, the relative ease in mathematical description coupled with speedy computation are the main reasons for the prevalence of this simplifying assumption. The possibilities offered by the modification of the interphase exchange coefficient of the Syamlal-O'Brien model as well as its scarce implementation in literature have motivated the authors to delve into this area of research as far as the transport phenomena of non-spherical drill cuttings is concerned. Another aspect of this work was influenced by the need to understand the flow dynamics around bends (horizontal to inclined and inclined to vertical sections) during deviated drilling operations using two high viscosity muds (0.5% CMC and 0.5% CMC + 4% Bentonite mud). The Eulerian-Eulerian model was adopted for this study while considering particle sphericities of 0.5, 0.75 and 1 and diameters of 0.002 m, 0.003 m, 0.004 m, 0.005 m and 0.008 m respectively. It was discovered that particle deposition intensifies at the inclined-to-vertical bend compared to other locations in the flow domain. We also observe increased dispersion effects and transport velocities of non-spherical particles compared to particles of a perfectly spherical geometry. Furthermore, an improvement in the rheological properties of the drilling mud shows a remarkable increase in cuttings transport efficiency especially with the smaller particles. However, increased deposition of larger particles still poses a challenge to the wellbore cleaning process despite this rheological enhancement. The proposed CFD modelling methodology is thus capable of providing critical insight into the dynamics of cuttings transport, and the resulting computational observations are consistent with relevant experimental investigations.",31,32,4
Drilling Fluid,Cuttings Transport,"Akhshik, Siamak; Rajabi, Majid",CFD-DEM modeling of cuttings transport in underbalanced drilling considering aerated mud effects and downhole conditions,CFD-DEM; Cuttings transport; Aerated mud drilling; Downhole condition; Volume-of-fluid (VOF); Underbalanced drilling (UBD),SIMULATION; LIFT; FLOW; VISCOSITY; SPHERE; FORCE,"This paper presents a developed CFD (Computational fluid dynamics)-DEM (Discrete elements method) model to study the cuttings transportation in aerated mud drilling process for inclined annuli at downhole conditions. The model is conducted to determine the effects of liquid flow rate, air injection rate, annulus inclination angle, elevated temperature and pressure on the cuttings transport efficiency. The motion of the fluid is computed using CFD based approach with gas-liquid interface capturing provided by the volume-of-fluid (VOF) method. The dynamics of cutting phase is studied by DEM using soft sphere approach in order to take into account the particle collision phenomenon. The continuum and dispersed phases are strongly coupled via the interaction forces such as drag force, lift force and pressure gradient force, which are considered in the developed CFD-DEM model. In addition, the real gas law governs the dynamics of injected air and the gas-liquid viscosity is assumed to be temperature dependant. The predicted results have been compared with the experimental data and fair agreement has been established. The results have indicated that in addition to the liquid flow rate, the cuttings transport efficiency is affected by gas-liquid ratio, ambient temperature and injection pressure.",23,24,2
Drilling Fluid,Cuttings Transport,"Minakov, A. V.; Zhigarev, V. A.; Mikhienkova, E. I.; Neverov, A. L.; Buryukin, F. A.; Guzei, D. V.",The effect of nanoparticles additives in the drilling fluid on pressure loss and cutting transport efficiency in the vertical boreholes,Non-Newtonian fluids; Drilling fluid; Nanoparticles; Rheology; Annular channel; Pressure loss; Herschel-bulkley model; Cutting transport; Vertical borehole; Laminar flow,GRANULAR FLOW; KINETIC-THEORY; HEAT-TRANSFER; COUETTE-FLOW; NANOFLUIDS; PARTICLES; NANOCOMPOSITE; CONVECTION; VISCOSITY; CHANNEL,"The effect of nanoparticles of various chemical components and sizes on the rheological behaviour of drilling fluids, pressure loss and cuttings transport in the vertical borehole for a laminar flow regime is considered in the paper. The results of numerical and experimental studies are presented. Silicon, aluminium and titanium oxides nanoparticles are considered. A drilling fluid is Bentonite-water solution with a mass fraction of 5%. The particles concentration in the solution was varied from 0.25 to 2 wt percentages and the particles sizes ranged from 5 to 50 nm. The dependences of the effective viscosity and rheological parameters of the solutions on the nanoparticles concentrations, sizes and materials were obtained. It was shown that nanoparticles in drilling fluid increase cuttings transport by 17% and decrease the average slip velocity of the sludge particles in 1.7-2.0 times, but the pressure losses when pumping the drilling fluid increase in 2.5 times.",18,18,4
Drilling Fluid,Cuttings Transport,"Naderi, Meysam; Khamehchi, Ehsan",Cutting transport efficiency prediction using probabilistic CFD and DOE techniques,Cutting transport efficiency; Computational fluid dynamic; Design of experiment; Monte Carlo simulation,LIFT ALLOCATION OPTIMIZATION; NONLINEAR RISK OPTIMIZATION; ARTIFICIAL-INTELLIGENCE; GAS; MODEL,"Efficient cutting transport plays an important role in drilling operation. This process is controlled by many factors such as well geometry, drilling fluid properties, geological features and rate of penetration. In order to minimize the operational cost of inefficient hole cleaning, it is crucial to thoroughly investigate the simultaneous effect of various factors on the process of cutting transport. In this regard, computational fluid dynamic (CFD) and design of experiment (DOE) techniques were used to predict the cutting transport efficiency (CTE) as a function mud velocity (V-m), drilling rate of penetration (ROP), mud weight (MW), cutting weight (CW), mud viscosity (mu m), pipe rotational speed (N), and cutting size (CS). The results of study based on probabilistic CFD calculations using DOE and Monte Carlo simulation (MCS) show that respectively factors of mud velocity, cutting weight, pipe rotational speed, mud weight, cutting diameter, mud viscosity, and drilling rate of penetration have the greatest impact on transportation of drilled cuttings from bottom of the well to the surface. In addition, result of MCS based on analysis of total variance reveals that 86.3% of cutting transport efficiency variation could be controlled by three factors of mud velocity, cutting weight and pipe rotational speed. Therefore, these factors should be carefully characterized during drilling and hole cleaning to maximize the cutting transport efficiency.",16,16,3
Drilling Fluid,Shale Stabilizer,"Xu, Jian-gen; Qiu, Zheng-song; Zhao, Xin; Zhong, Han-yi; Li, Gong-rang; Huang, Wei-an",Synthesis and characterization of shale stabilizer based on polyethylene glycol grafted nano-silica composite in water-based drilling fluids,Polyethylene glycol grafted nano-silica composite (PEG-NS); Wellbore instability; Water-based drilling fluids; Shale stabilizer; Pressure transmission,WELLBORE STABILITY; PERFORMANCE; NANOCOMPOSITE; HYDRATION; MECHANISM,"In order to solve wellbore instability problems in the drilling process, high-performance shale stabilizers in waterbased drilling fluids are essential. In this paper, a novel shale stabilizer based on polyethylene glycol grafted nanosilica composite (PEG-NS) was successfully synthesized. Conventional techniques were used to characterize PEGNS including Flourier transform infrared spectroscopy (FT-IR), scanning electron microscope (SEM), transmission electron microscopy (TEM), particle size distribution (PSD) and thermogravimetric analysis (TGA). The results showed that the structure of PEG-NS was in agreement with the design objective. The particle size of PEG-NS ranged from 110 to 434 nm, and PEG-NS had good thermal stability. Pressure transmission test, pore structure characterization of shale, rolling recovery test were applied to evaluate the comprehensive performance of PEGNS as a novel shale stabilizer. The experimental data indicated that PEG-NS could effectively retard the pore pressure transmission and reduce the permeability of shale sample. PEG-NS could adsorb onto the shale surface and a dense plugging film could finally coat on it. Moreover, PEG-NS also exhibited better inhibition performance compared with that of potassium chloride (KCl) and polymeric alcohol (JHC) at the same concentration. Hence, PEG-NS could be a good shale stabilizer in water-based drilling fluids for drilling reactive shale formations.",49,52,10
Drilling Fluid,Shale Stabilizer,"An, Yuxiu; Yu, Peizhi",A strong inhibition of polyethyleneimine as shale inhibitor in drilling fluid,Swelling; Inhibition; Mechanism; Polyethyleneimine; Shale,WELLBORE INSTABILITY; STABILITY; DESIGN; MODEL,"In this paper, the inhibition property of polyethyleneimine (PEI) in montmorillonite solution was studied. The inhibition property was evaluated by linear swelling test and rolling recovery test. Compared with other inhibitors, the addition of PEI resulted in the lowest swelling height in drilling fluid. In rolling recovery rate study, the addition of PEI resulted in the highest recovery rate after rolled at 120 degrees C. More importantly, PEI was environmental friendly inhibitor. The inhibition mechanism was investigated by Fourier transform infrared spectroscopy, X-ray diffraction, Transmission electron microscope, Scanning electron microscopy, Atomic force microscope, Zeta potential and Particle-size analyzer. The spectrums and images showed that the negative charge in the surface of montmorillonite (MMT) was neutralized by the positive charge in amino group of PEI. PEI was adsorbed in the surface and intercalated into interlayer of MMT, which reduced the hydration repulsion of diffuse electric double layer and prevented the invasion of water. Hydrogen bonding between hydroxyl in the surface of clay and amino groups in the backbone and side chain of PEI can be formed in the process. The adsorption and intercalation of PEI in the surface and interlayer of MMT was the major factor to prevent water molecules from invading into the gallery of clay. There were a quantity of positive ions in solution because of the protonation of nitrogen in water. More positive ions resulted in the stronger force between inhibitor and clay.",45,49,1
Drilling Fluid,Shale Stabilizer,"Parizad, Amirhossein; Shahbazi, Khalil; Tanha, Abbas Ayatizadeh",Enhancement of polymeric water-based drilling fluid properties using nanoparticles,Drilling fluid; TiO2 nanofluid viscosity; Nanofluid thermal and electrical conductivities; Nanofluid filtration; Nanofluid thermal resistance: nanofluid shale; recovery,SIZE; NANOFLUIDS; VISCOSITY; BEHAVIOR; STABILITY,"The maturity of shallow depth and conventional petroleum reserves together with growing demand for energy have forced the oil industry to drill harsh and deep reserves. Nanotechnology has the ability to improve drilling fluid performance for drilling deeper and harsher environments. In this study, a water-based drilling fluid containing polymers was set as the base fluid. TiO2 nanoparticle was employed to improve rheology, electrical and thermal conductivities of the resultant drilling fluids. The test fluids were made by addition of different concentrations of TiO2 nanoparticle and KCl salt to the base fluid. The resultant samples were examined at different temperatures and 19 different shear rates. Presence of TiO2 particles enhanced not only the rheological behavior but also thermal and electrical conductivities of the drilling fluids up to 25% and 41%, respectively. Moreover, the addition of TiO2 particles increased thermal resistance, shale recovery up to 97.2% and also decreased the filtration volume up to 27%. Moreover, the viscosities of aqueous TiO2 dispersions at different temperatures and TiO2 and KCl concentrations were measured. The TiO2 nanoparticle has good soloubility in hot HCl and HF acids. It was found that the base aqueous fluid viscosity directly affects the resultant drilling fluid viscosity. In this regard, an analysis was performed and a model was proposed.",30,30,2
Drilling Fluid,Shale Stabilizer,"Beg, Mukarram; Sharma, Shivanjali; Ojha, Umaprasana",Effect of cationic copolyelectrolyte additives on drilling fluids for shales,Copolyelectrolytes; Shale retention; Borehole instability; Phase segregation; Drilling fluids,OPTIMIZATION; FIELD; MUD,"Wellbore instability remains one of the major challenges in terms of both time and economy during drilling. The issue is more pronounced in reactive shale formations. A set of polytertiary amines (PTA)-ran-polyquaternary amines (PQA) polymers possessing different ratios of tertiary amine to quaternary amine (0: 100, 40: 60, 60: 40, mol: mol) segments were synthesized and their efficacy towards the wellbore stability of shale reservoirs were ascertained. When added in similar weight proportions, the copolymer possessing 60: 40 (mol: mol) ratio of tertiary to quaternary amine moieties (PTA-ran-PQA-64) enhanced the apparent (>= 58%) and plastic (>= 71%) viscosities of silicate drilling fluid to maximum extent. The amount of API filtrate reduced with increasing concentration of the copolymers and filtrate loss in case of the mud containing polyelectrolyte PTA-ran-PQA-64 was lower compared to the other two polyelectrolytes. Hot rolling shale dispersion test showed that the shale recovery improved from 91 to 97% on inclusion of minimum amounts (0.25 wt%) of these polyelectrolytes in the drilling fluid. The Linear Swell Meter (LSM) data demonstrated, the swelling in shale pallet is 11% in absence of polyelectrolytes and gets reduced to 4.3% in presence of PTA-ran-PQA-64. The above studies revealed that, these copolymers are viable candidates as drilling fluid additives to possibly enhance the wellbore stability.",27,27,0
Drilling Fluid,Shale Stabilizer,"Zhong, Hanyi; Qiu, Zhengsong; Chai, Jinpeng; Guo, Baoyu; Sun, Dong; Liu, Junyi",A preliminary study of the preparation of shale stabilizer with oil sludge - From waste to resource,Oil sludge; Asphalt; Shale stabilizer; Drilling fluid; Preparation,WATER-TREATMENT; BIOREMEDIATION; FORMULATION; RECOVERY,"To convert the hazardous and waste oil sludge into shale stabilizer using in drilling fluid, a novel preparing method has been proposed in the current study. According to the characteristics of oil sludge, the preparation procedure was designed learning from conventional asphaltic-type shale stabilizer preparation method. Several additives such as gilsonite, calcium carbonate, surfactants (hexadecyltrimethylammonium chloride (CTAC) and polyoxyethylene octylphenol ether (OP-10)), polymers (polyethylene glycol (PEG-2000) and cationic polyacrylamide (CPAM)), and fluid loss reducers (sulfonated lignite and potassium humate) were incorporated into oil sludge with the assistance of melting, stirring, kneading, and drying. After the sequential steps of asphaltization, emulsification, and stabilization, a powdered shale stabilizer product (SS-OS) was obtained. The effect of SS-OS on rheology, filtration, and lubricity of drilling fluid bentonite dispersions was tested. Furthermore, the properties of stabilizing shale were evaluated. The results indicated that SS-OS could effectively inhibit shale swelling, dispersion, and exhibit excellent sealing performance. Moreover, it helped to reduce the fluid loss and significantly improve the lubricity of the drilling fluid. From the preliminary study, it was concluded that the strategy of preparing shale stabilizer with oil sludge could be employed to overcome waste, energy and environmental problems simultaneously and show promising application.",20,22,1
Drilling Fluid,Shale Stabilizer,"Wang, Zhihao; Wu, Yuanpeng; Luo, Pingya; Tian, Yingpei; Lin, Yuanhua; Guo, Qipeng",Poly (sodium p-styrene sulfonate) modified Fe3O4 nanoparticles as effective additives in water-based drilling fluids,Water-based drilling fluids; Fe3O4 nanoparticles; Poly (sodium p-styrene sulfonate); Rheology; Fluid loss,CONTROLLING FILTRATION PROPERTIES; RHEOLOGICAL PROPERTIES; BENTONITE SUSPENSIONS; HIGH-TEMPERATURES; HIGH-PRESSURE; LOSS AGENT; BEHAVIOR; PERFORMANCE; SHALE; STABILIZATION,"In this work, a series of low solid phase, economic and excellent performance water-based drilling fluids (WBDFs) were obtained by introducing nanoparticles into conventional WBDFs. Fe3O4 nanoparticles which were surface modified by poly (sodium p-styrene sulfonate) (PSSS) through 3-(trimethoxysilyl) proryl methacrylate (TMSPMA) were adopted in low solid WBDFs containing 4 wt % bentonite (BT). The effect of temperature on rheological property and fluid filtration was investigated. When the concentration of Fe3O4/PSSS nanoparticles reached 0.1 wt %, shear thinning of WBDFs will be perfect at different temperatures. When the concentration of Fe3O4/PSSS nanoparticles reached 0.25 wt %, the WBDFs had superior rheological properties, as compared to other concentrations of the particles in salt environment. Rheological curves provide a closely fit for the Bingham model at low temperature, however, the curves fit Herschel-Bulkley model at higher temperature. Rheological tests indicated that higher concentration of Fe3O4/PSSS nanoparticles can effectively improve salt (KCl) tolerance. Under high temperature and high press (HTHP) filtration test, WBDFs with Fe3O4/PSSS nanoparticles exhibited minimum filtration loss volume with the concentration of Fe3O4/PSSS nanoparticles as low as 0.1 wt % at different temperatures. For salt tolerance test, the higher concentration of the Fe3O4/PSSS nanoparticles leads to the lower the amount of fluid loss at the same concentration of KCl. With the concentration of nanoparticles grows to 0.1 wt %, the amount of fluid loss volume was minimum, indicating that Fe3O4/PSSS nanoparticles in WBDFs improve the filtration. The WBDFs with performance improved by Fe3O4/PSSS nanoparticles can be used as effective drilling fluids even under high temperature and high salinity, demonstrating that the modified fluids are potential candidates for drilling in deep and salty formation.",19,20,8
Drilling Fluid,Shale Stabilizer,"Zhang, Xianmin; Jiang, Guancheng; Dong, Tengfei; Wang, Le; Li, Xinliang; Wang, Guoshuai",An amphoteric polymer as a shale borehole stabilizer in water-based drilling fluids,Borehole stabilizer; Amphoteric polymers; Shale hydration; Micro-nanometer plugging; Water-based drilling fluid,ELEVATED-TEMPERATURE; WELLBORE INSTABILITY; POLYACRYLAMIDE; NANOPARTICLES; SPECTROSCOPY; WELLS; MUDS,"An amphoteric polymer P (acrylamide-styrene-butyl acrylate) (ASBA) was evaluated for use as a shale borehole stabilizer and for its ability to counter the problem of well instability during shale gas exploration and development. The hydrophilic groups in the ASBA increased the adsorption between the ASBA and the shale formation and the hydrophobic groups reduced the hydrophilicity of the sodium bentonite (BT). The addition of 1.6 wt% ASBA resulted in a water contact angle of the BT/ASBA that was more than 40 degrees larger than that of the BT. The amount of linear swelling decreased by 37.81% and the hot-rolling recovery rate of the shale cuttings was more than 60% higher in the 1.6 wt% ASBA solution than in deionized water. The ASBA exhibited micro/nanometer globules with an average diameter of 250.4 nm in aqueous solution. This was in agreement with the results of the morphology tests (scanning electron microscopy (SEM) and transmission electron microscopy (TEM)). The morphology tests, elemental analysis, and thermogravimetric analysis showed that the polymer was evenly dispersed in the aqueous solution and effectively adsorbed onto the BT instead of the free water. The soft globules changed under pressure and effectively plugged the various pores in the formation. Due to the hydrophobicity and the plugging effect, the ASBA prevented the BT aggregation and reduced the filtration loss; the American Petroleum Institute (API) filtration loss of the basic mud containing 1.6 wt% ASBA was reduced by 56.67% compared to the basic mud without ASBA after aging at 150 degrees C. Due to the excellent inhibition of the shale hydration and the micro/nanometer plugging performance, the ASBA has a potential application as a borehole stabilizer in drilling fluids.",19,20,4
Drilling Fluid,Apparent Viscosity,"Perween, Shama; Beg, Mukarram; Shankar, Ravi; Sharma, Shivanjali; Ranjan, Amit",Effect of zinc titanate nanoparticles on rheological and filtration properties of water based drilling fluids,Electrospun ZnTiO3 nanoparticles; Nanoenhanced drilling fluid; Rheology and filtration properties,XANTHAN GUM; NANOCOMPOSITE; GAS,"The aim of this work is to evaluate the effect of laboratory synthesized ZnTiO3 nanoparticles on rheological and filtration characteristics and their response to heating in a drilling fluid. This work is the first study where the use of zinc titanate (ZnTiO3) nanoparticles is reported to improve the rheological and filtrate loss properties of water based drilling fluid (WBDF). The role of nanoparticles is examined by performing a comparative study on drilling fluid properties by incorporating the ZnTiO3 nanoparticles from 0.05 to 0.30 w/v% in mud formulations. The nanoparticles are obtained by two different synthesis approaches: (a) sol-gel bulk polymerization method (SNP), and (b) sol-electrospinning technique (ENP). These two methods yield nanoparticles with different mean sizes and size distributions. The experimental work has been carried out to investigate the influence of concentration of ZnTiO3 nanoparticles on fluid rheology at 20 degrees C and 70 degrees C and API filtrate at normal temperature and 100 psi pressure according to American Petroleum Institute (API) methodology. The mud samples are subjected to ageing process in hot rolling oven at 110 degrees C for 16 h to study thermal stability and the effect of ageing on rheological and filtration properties. The experimental results show that ZnTiO3 nanoparticles significantly affect to the drilling fluid properties and considerably decrease the filtrate loss and improve thermal stability and rheological properties. Apparent viscosity (AV) for base mud indicated similar to 27% decrease on heating up to 70 degrees C, however, this decrease due to temperature rise is reduced by the addition of 0.30 w/v% nanoparticles (only 6% for SNP and 10% for ENP). It is also found that ageing of base mud at 110 degrees C caused similar to 17.3% reduction in AV at 20 degrees C and similar to 31.5% reduction at 70 degrees C. However, this decrease in AV due to hot rolling ageing was reduced by addition of 0.30w/v% nanoparticles (similar to 6% for SNP and similar to 12% for ENP) at 20 degrees C. AV was found to initially decrease and then increase with increasing concentration of nanoparticles. On addition of 0.30 w/v% nanoparticles, the AV of the hot rolled base mud increased by similar to 9.3% (21.5-23.5) for SNP, and by similar to 20.9% (21.5-26) for ENP. API filtrate of base mud, after hot rolling, reduced by 33% and 35.86% on using 0.30% (w/v) nanoparticle concentration of SNP and ENP, respectively which is a remarkable influence of NP as a fluid loss reducer. This effect can arise due to size, shape and surface area of the added nanoparticles.",33,33,1
Drilling Fluid,Apparent Viscosity,"Pang, Boxue; Wang, Shuyan; Wang, Qiujin; Yang, Kai; Lu, Huilin; Hassan, Muhammad; Jiang, Xiaoxue",Numerical prediction of cuttings transport behavior in well drilling using kinetic theory of granular flow,Cuttings transport; Kinetic theory of granular flow; Granular temperature; Pressure drop; Non-newtonian fluid; Drill pipe rotation,NON-NEWTONIAN FLUIDS; SOLID-LIQUID FLOW; DRILLPIPE ROTATION; PIPE ROTATION; ANNULUS; PARAMETERS; PROFILES; VELOCITY; MODEL; CFD,"The cuttings transport during well drilling was numerically simulated based on kinetic theory of granular flow in combination with sliding mesh for drill pipe rotation. The power-law model was implemented to describe the rheological behavior of drilling fluid. Numerical results were compared with available experimental data in the literature to validate the algorithm, and good agreement was found. Three distinguishable regions of cuttings flow pattern and swaying phenomenon of cuttings distribution were observed along the direction of drill pipe rotation. Increasing the fluid velocity results in a reduction in the height of cuttings bed and weakening of the swaying phenomenon. Higher apparent viscosity of drilling fluid contributes to a good performance of cuttings transport at a low annular velocity, but rising in pressure loss. There is critical inclination angle of the well.ctr for cuttings transport ratio and theta(dp) for pressure drop through the annulus. The most difficult of cuttings transport occurs in the well inclinations around 35 degrees-65 degrees. There is no additional contribution of drill pipe rotation to cuttings transport after reaching a critical rotation speed. Increasing the cutting size leads to a reduction in the cuttings transport ratio and an increase in pressure drop.",32,34,8
Drilling Fluid,Apparent Viscosity,"Beg, Mukarram; Sharma, Shivanjali; Ojha, Umaprasana",Effect of cationic copolyelectrolyte additives on drilling fluids for shales,Copolyelectrolytes; Shale retention; Borehole instability; Phase segregation; Drilling fluids,OPTIMIZATION; FIELD; MUD,"Wellbore instability remains one of the major challenges in terms of both time and economy during drilling. The issue is more pronounced in reactive shale formations. A set of polytertiary amines (PTA)-ran-polyquaternary amines (PQA) polymers possessing different ratios of tertiary amine to quaternary amine (0: 100, 40: 60, 60: 40, mol: mol) segments were synthesized and their efficacy towards the wellbore stability of shale reservoirs were ascertained. When added in similar weight proportions, the copolymer possessing 60: 40 (mol: mol) ratio of tertiary to quaternary amine moieties (PTA-ran-PQA-64) enhanced the apparent (>= 58%) and plastic (>= 71%) viscosities of silicate drilling fluid to maximum extent. The amount of API filtrate reduced with increasing concentration of the copolymers and filtrate loss in case of the mud containing polyelectrolyte PTA-ran-PQA-64 was lower compared to the other two polyelectrolytes. Hot rolling shale dispersion test showed that the shale recovery improved from 91 to 97% on inclusion of minimum amounts (0.25 wt%) of these polyelectrolytes in the drilling fluid. The Linear Swell Meter (LSM) data demonstrated, the swelling in shale pallet is 11% in absence of polyelectrolytes and gets reduced to 4.3% in presence of PTA-ran-PQA-64. The above studies revealed that, these copolymers are viable candidates as drilling fluid additives to possibly enhance the wellbore stability.",27,27,0
Drilling Fluid,Apparent Viscosity,"Fakoya, Muili F.; Ahmed, Ramadan M.",A generalized model for apparent viscosity of oil-based muds,Invert-emulsion mud; Shear thinning; Temperature; Oil-water ratio; Clay content; Apparent viscosity,DRILLING-FLUIDS; RHEOLOGY; TEMPERATURE; SUSPENSIONS; EMULSIONS,"Oil-based drilling fluid, typically called oil-based mud (OBM), is an invert emulsion that finds application in drilling operations owing to its outstanding performance, especially in high pressure and high temperature (HPHT) wells. Besides, OBM promotes a better lubricity, ensures wellbore stability, increases the rate of penetration, and facilitates the achievement of low fluid loss and a thin filter-cake. Due to environmental concerns, the use of low-toxicity mineral oils as the base fluid or continuous phase for OBM is preferable. The flow behavior of OBM mainly depends on rheological properties of its continuous phase, and the volume fraction of the dispersed phase. Besides this, other imposed conditions like shear rate and temperature play a significant role. The availability of rheological models that show this connection is necessary for predicting rheology of OBM based on its formulation and borehole condition. This work presents an experimental investigation of the apparent viscosity of OBM within a temperature range of 24-87 degrees C. The continuous phase was prepared with mineral oil, surfactants (emulsifier and wetting agent), organophilic clay, lime, and calcium chloride. Organophilic clay concentrations and oil/water ratio (OWR) were varied. Apparent viscosity measurements are gathered and analyzed. OBM displayed shear-thinning behavior that best fits the Herschel-Bulkley model. The results reveal notable trends of apparent viscosity and rheological parameters with increasing temperature, organophilic clay concentration, and OWR. Generalized empirical models that link the apparent viscosity of the continuous phase to that of OBM are developed by applying nonlinear regression analysis. The prediction of OBM rheological parameters requires the knowledge of continuous phase apparent viscosity at ambient temperature, dispersed phase volume fraction, and temperature. The models give a reasonable prediction of OBM apparent viscosity. The comparison of normalized or reduced rheological parameters and apparent viscosity of OBM and water-based mud (WBM) revealed the sensitivity of viscous properties of OBM to temperature as compared to that of WBM. This revelation shows why OBM is more susceptible to barite sag phenomenon than WBM.",16,16,0
Drilling Fluid,Apparent Viscosity,"Luo, Zhihua; Wang, Longxiang; Pei, Jingjing; Yu, Peizhi; Xia, Boru",A novel star-shaped copolymer as a rheology modifier in water-based drilling fluids,Star-shaped copolymer; Linear copolymer; Drilling fluids; Rheological properties; Filtration,HIGH-TEMPERATURE; PERFORMANCE; ADSORPTION; BENTONITE; ADDITIVES; CLAY,"Compared to linear polymers, star polymers have drawn significant research interest due to their excellent physical and rheological properties. In this paper, a star-shaped copolymer of acrylamide (AM) and 2-acrylamide-2-methyl-propanesulfonic acid sodium (AMPS) [S-poly(AM-co-AMPS)] is prepared using multifunctional macro-initiator, and serve as an additive to control the rheological and filtration performances of water-based drilling fluids. The results show that the yield point/plastic viscosity ratio (y(p)/mu(p)) of the formulated drilling fluids reaches a maximum value when the concentration of S-poly(AM-co-AMPS) is 0.3 wt%. Compared with the linear poly(AM-co-AMPS) having the similar molecular weight, S-poly(AM-co-AMPS) provides the drilling fluids with better shear-thinning characteristics and much lower apparent viscosities under non-aging and high-temperatures. In addition, the drilling fluids containing 0.3 wt% star copolymer show better resistance to cuttings contamination and shearing at high temperatures. The American Petroleum Institute (API) and High Temperature and High Pressure (HTHP) filtration tests indicate that the star-shaped copolymer can effectively reduce the filtration volumes. S-poly(AM-co-AMPS) shows better shearing resistance than the linear copolymer, which might contribute to better rheological performances of the drilling fluids formulated with only star copolymer while controlling the filtration performance.",15,16,6
Drilling Fluid,Apparent Viscosity,"Costa Santos, Nara Brandao; Fagundes, Flavia Marques; Arouca, Fabio de Oliveira; Ribeiro Damasceno, Joao Jorge",Sedimentation of solids in drilling fluids used in oil well drilling operations,Drilling fluids; Rheology; Suspension sedimentation; Gamma-ray attenuation technique,SHEAR-THINNING FLUIDS; STRESS; AGGREGATION; EQUATION,"Petroleum stands out as an important energy source. In oil well drilling operations, drilling fluids are used with the main purpose of cleaning and maintaining the hydrostatic pressure in the wellbore. Due to the importance of understanding solid-fluid interaction and the lack of quantitative studies on solids content in regions with high solids concentrations, this study evaluated the stability of drilling fluids. Rheological tests and gravitational and batch sedimentation tests with fluids differentiated by the addition of calcium carbonate assessed the separation dynamics as a function of time and position and determined the constitutive equations for pressure on solids, which are fundamental to solve models of flow through porous media. Gamma-ray attenuation, a non-destructive technique, quantified the local volumetric solids concentration in sedimentary regions. The results showed a shear-thinning behavior and thixotropic effects in the fluids and the influence of calcium carbonate on the sedimentation profile. The non-thickened suspension had lower values of apparent viscosity, higher sedimentation rates, and more compressible sediments than the thickened system. Thus, the formulation of drilling fluids affected the separation process in suspensions; for that reason, it must be adjusted to the operational conditions. This study contributed to increase rheological and stability knowledge on non-Newtonian suspensions.",15,16,0
Drilling Fluid,Flow Rate,"Akhshik, Siamak; Rajabi, Majid",CFD-DEM modeling of cuttings transport in underbalanced drilling considering aerated mud effects and downhole conditions,CFD-DEM; Cuttings transport; Aerated mud drilling; Downhole condition; Volume-of-fluid (VOF); Underbalanced drilling (UBD),SIMULATION; LIFT; FLOW; VISCOSITY; SPHERE; FORCE,"This paper presents a developed CFD (Computational fluid dynamics)-DEM (Discrete elements method) model to study the cuttings transportation in aerated mud drilling process for inclined annuli at downhole conditions. The model is conducted to determine the effects of liquid flow rate, air injection rate, annulus inclination angle, elevated temperature and pressure on the cuttings transport efficiency. The motion of the fluid is computed using CFD based approach with gas-liquid interface capturing provided by the volume-of-fluid (VOF) method. The dynamics of cutting phase is studied by DEM using soft sphere approach in order to take into account the particle collision phenomenon. The continuum and dispersed phases are strongly coupled via the interaction forces such as drag force, lift force and pressure gradient force, which are considered in the developed CFD-DEM model. In addition, the real gas law governs the dynamics of injected air and the gas-liquid viscosity is assumed to be temperature dependant. The predicted results have been compared with the experimental data and fair agreement has been established. The results have indicated that in addition to the liquid flow rate, the cuttings transport efficiency is affected by gas-liquid ratio, ambient temperature and injection pressure.",23,24,2
Drilling Fluid,Flow Rate,"Yang, Zhao-Zhong; Yi, Liang-Ping; Li, Xiao-Gang; He, Wei",Pseudo-three-dimensional numerical model and investigation of multi-cluster fracturing within a stage in a horizontal well,Displacement discontinuity method; Multi-cluster fracturing; Horizontal well; Three-dimensional fracture,HYDRAULIC FRACTURES; PROPAGATION,"Multi-cluster fracturing and horizontal drilling are the key techniques used to exploit unconventional reservoirs. However, field production has revealed that certain perforation clusters are invalid. In order to find the most effective approaches to improve the uniformity of multiple-fracture growth, a pseudo-3D multi-cluster fracturing model is established in this study. In our model, complex in-situ stress distributions are considered and the stress interactions between fractures are calculated using the displacement discontinuity method (DDM). Fluid dynamic flow distributions into different clusters are calculated using Kirchhoff's second law. Fracture height and length extension velocities are determined based on the fracture edge energy release rate. The effectiveness of our model is verified by comparing the single fracture extension results obtained by our model to those obtained by a semi-analytical model. Based on our numerical model, possible approaches to promoting the uniform growth of multiple fractures are discussed. The results indicate that adjusting spacing is an inefficient method to promote multiple-fracture uniform growth under the condition of four clusters fracturing within a stage. However, regulating perforation friction, reducing fracturing fluid viscosity, and increasing injection rate are useful ways to improve the uniformity of multiple-fracture propagation.",20,24,4
Drilling Fluid,Flow Rate,"Tian, Jialin; Li, Jurui; Cheng, Wenming; Zhu, Zhi; Yang, Lin; Yang, Yi; Zhang, Tangjia",Working mechanism and rock-breaking characteristics of coring drill bit,Drilling; Coring drill bit; Drillability; ROP(rate of penetration); Mechanism; Cores,,"For improving the rate of penetration of the complex well structure and performance of the coring drill bit, this paper is to investigate a new type of coring drill bit that generates small-diameter core samples during the drilling process. A special jet channel is designed inside the drill bit body, and the high-pressure drilling fluid flows through the special jet channel to the coring channel, then the cored rock is taken out of the downhole from the drill bit under the negative pressure. Based on the hydrodynamics theory, rock breaking mechanics and actual drilling conditions, the rock breaking mechanism model of the coring drill bit is established. The difference of rock breaking performance between the new drill bit and the existing drill bit is analyzed based on the analysis of numerical example, laboratory and field test. The research results indicate that the special structure design in the new drill bit has the effect of 'absorbing the bottom rock cuttings and pushing the upper rock cuttings' during the process of rock breaking. The effect can reduce the repeated cutting of cores at the bottom hole and improve the ROP(rate of penetration). Field tests show that when the flow rate of drill pump is 25L/s, the result of ROP can be increased by 15%-40%. The new design drill bit can present innovative ideas for improving the efficiency of coring and the quality of geological logging during the drilling process. Moreover, the analysis models can provide references for the new research of improving ROP and drilling efficiency, especially under the conditions of complex structure or large displacement wells.",19,22,3
Drilling Fluid,Flow Rate,"Fakoya, Muili F.; Ahmed, Ramadan M.",A generalized model for apparent viscosity of oil-based muds,Invert-emulsion mud; Shear thinning; Temperature; Oil-water ratio; Clay content; Apparent viscosity,DRILLING-FLUIDS; RHEOLOGY; TEMPERATURE; SUSPENSIONS; EMULSIONS,"Oil-based drilling fluid, typically called oil-based mud (OBM), is an invert emulsion that finds application in drilling operations owing to its outstanding performance, especially in high pressure and high temperature (HPHT) wells. Besides, OBM promotes a better lubricity, ensures wellbore stability, increases the rate of penetration, and facilitates the achievement of low fluid loss and a thin filter-cake. Due to environmental concerns, the use of low-toxicity mineral oils as the base fluid or continuous phase for OBM is preferable. The flow behavior of OBM mainly depends on rheological properties of its continuous phase, and the volume fraction of the dispersed phase. Besides this, other imposed conditions like shear rate and temperature play a significant role. The availability of rheological models that show this connection is necessary for predicting rheology of OBM based on its formulation and borehole condition. This work presents an experimental investigation of the apparent viscosity of OBM within a temperature range of 24-87 degrees C. The continuous phase was prepared with mineral oil, surfactants (emulsifier and wetting agent), organophilic clay, lime, and calcium chloride. Organophilic clay concentrations and oil/water ratio (OWR) were varied. Apparent viscosity measurements are gathered and analyzed. OBM displayed shear-thinning behavior that best fits the Herschel-Bulkley model. The results reveal notable trends of apparent viscosity and rheological parameters with increasing temperature, organophilic clay concentration, and OWR. Generalized empirical models that link the apparent viscosity of the continuous phase to that of OBM are developed by applying nonlinear regression analysis. The prediction of OBM rheological parameters requires the knowledge of continuous phase apparent viscosity at ambient temperature, dispersed phase volume fraction, and temperature. The models give a reasonable prediction of OBM apparent viscosity. The comparison of normalized or reduced rheological parameters and apparent viscosity of OBM and water-based mud (WBM) revealed the sensitivity of viscous properties of OBM to temperature as compared to that of WBM. This revelation shows why OBM is more susceptible to barite sag phenomenon than WBM.",16,16,0
Drilling Fluid,Flow Rate,"Alshubbar, Ghassan; Nygaard, Runar; Jeennakorn, Montri",The effect of wellbore circulation on building an LCM bridge at the fracture aperture,Loss circulation materials; Lost circulation; Drilling induced fractures; Borehole integrity,,"Different laboratory experimental setups with slotted disks, simulating fractures' apertures, have been used extensively to formulate effective loss circulation materials (LCM) recipes. The amount of fluid loss and sealing pressure have been used as the evaluation criteria. The question still remains is how valuable these tests are when LCM fluids are circulated in the wellbore to stop losses. The main objective of this work is to study the effect of the annular fluid flow on building an LCM bridge at the fracture aperture. To address the objective, a fluid loss apparatus has been developed to mimic wellbore circulation. Tapered slotted disks were placed upward in a cylinder filled with drilling fluid and LCM additives. Drilling fluid is pumped at the bottom of the cylinder and the wellbore circulation is simulated through the use of stirring paddle. Previously reported effective LCM recipes have been retested conventionally, no simulated circulation, and under simulated circulation condition (S-circ) with varying pump flow rates and tapered slotted disk sizes. A new term, sealing effectiveness ratio (SER), is introduced to effectively evaluate the sealing integrity of the LCM recipes at the Scirc. The results showed when stirring the sample, a higher fluid loss was required before the sample sealed and the maximum sealing pressure (P-max) was lower than sealing pressures reported from conventional tests. Different LCM recipes required a different minimum flow rate for a seal to initiate at the Scirc. Increasing the flow rate improved the sealing effectiveness ratios of all LCM recipes. At high flow rates some recipes gave very similar Pmax as conventional tests while others lost more than 35% of their strength. At a given flow rate with larger opening size slot, the effect of Scirc was amplified as higher fluid loss was required to initiate a seal and a lower sealing effectiveness ratio was recorded. The most significant new finding is that LCM with lower specific gravity was less prone to the Scirc making them better preventive approach candidates.",16,16,0
Drilling Fluid,Flow Rate,"Costa Santos, Nara Brandao; Fagundes, Flavia Marques; Arouca, Fabio de Oliveira; Ribeiro Damasceno, Joao Jorge",Sedimentation of solids in drilling fluids used in oil well drilling operations,Drilling fluids; Rheology; Suspension sedimentation; Gamma-ray attenuation technique,SHEAR-THINNING FLUIDS; STRESS; AGGREGATION; EQUATION,"Petroleum stands out as an important energy source. In oil well drilling operations, drilling fluids are used with the main purpose of cleaning and maintaining the hydrostatic pressure in the wellbore. Due to the importance of understanding solid-fluid interaction and the lack of quantitative studies on solids content in regions with high solids concentrations, this study evaluated the stability of drilling fluids. Rheological tests and gravitational and batch sedimentation tests with fluids differentiated by the addition of calcium carbonate assessed the separation dynamics as a function of time and position and determined the constitutive equations for pressure on solids, which are fundamental to solve models of flow through porous media. Gamma-ray attenuation, a non-destructive technique, quantified the local volumetric solids concentration in sedimentary regions. The results showed a shear-thinning behavior and thixotropic effects in the fluids and the influence of calcium carbonate on the sedimentation profile. The non-thickened suspension had lower values of apparent viscosity, higher sedimentation rates, and more compressible sediments than the thickened system. Thus, the formulation of drilling fluids affected the separation process in suspensions; for that reason, it must be adjusted to the operational conditions. This study contributed to increase rheological and stability knowledge on non-Newtonian suspensions.",15,16,0
Drilling Fluid,Flow Rate,"Akhtar, Tarek Firoze; Ahmed, Ramadan; Elgaddafi, Rida; Shah, Subhash; Amani, Mahmmod",Rheological behavior of aqueous foams at high pressure,Foam; Rheology; Yield stress; Non-Newtonian fluid; Friction pressure loss; Wall-slip,CONSTITUTIVE EQUATION; SHEAR; FLOW,"Aqueous foams are used in many oil field applications including drilling, fracturing, and enhanced oil recovery operations. The success of all these operations strongly depends on viscosity and stability of foam. Rheology of foams is a function of foam quality (i.e. gas volume fraction), liquid phase viscosity, pressure, and temperature. Besides, foam generation method and stability are factors that influence its rheology. This article presents results of an experimental study performed to investigate the effects of foam quality, pressure, and wall slip on aqueous-foam rheology. Extensive tests were conducted using a foam recirculating flow loop consisting of three pipe viscometers. Experiments were performed at ambient temperature, and varying pressure (6.89-20.68 MPa), foam quality (40-80%), and pipe diameter (3.06, 6.22 and 12.67 mm). The foam was generated by passing a mixture of water containing 2% surfactant solution and gas phase (nitrogen) through a needle valve. To minimize degradation while testing, the foam was regenerated by circulating at the maximum flow rate (0.55 L/min) before each flow measurement was made. Results indicate strong non-Newtonian behavior of foam, which closely fits the power law model. For foams with more than 55% quality, measured viscosities were higher than the ones reported in the literature. Noticeable wall slip was not observed. Foam viscosity change because of pressure variation at a constant foam quality was negligible. Foams with quality higher than 70% exhibited yield pseudoplastic behavior. Their rheological behavior can be described better by Herschel-Bulkley model than power law model when the shear rate is below 20 1/s.",14,14,1
Drilling Fluid,Rock,"Mirzaei-Paiaman, Abouzar; Ostadhassan, Mehdi; Rezaee, Reza; Saboorian-Jooybari, Hadi; Chen, Zhangxin",A new approach in petrophysical rock typing,Petrophyisics; Rock typing; Hydraulic flow unit; Kozeny-carman; Reservoir characterization; FZI-Star; PSRTI,HYDRAULIC FLOW UNITS; SPONTANEOUS IMBIBITION; CAPILLARY-PRESSURE; PERMEABILITY; RESERVOIR; CENTRALITY; SELECTION,"Petrophysical rock typing in reservoir characterization is an important input for successful drilling, production, injection, reservoir studies and simulation. In this study petrophysical rock typing is divided into two major categories: 1) a petrophysical static rock type (PSRT): a collection of rocks having the same primary drainage capillary pressure curves or unique water saturation for a given height above the free water level, 2) a petrophysical dynamic rock type (PDRT): a set of rocks with a similar fluid flow behavior. It was shown that static and dynamic rock types do not necessarily overlap or share petrophysical properties, regardless of wettability. In addition, a new index is developed to define PDRTs via the Kozeny-Carman equation and Darcy's law. We also proposed a different index for delineation of PSRTs by combining the Young-Laplace capillary pressure expression and the Kozeny-Carman equation. These new indices were compared with the existing theoretical and empirical indices. Results showed that our indices are representatives of previously developed models which were also tested with mercury injection capillary pressure, water-oil primary drainage capillary pressure, and water-oil relative permeability data on core plugs from a highly heterogeneous carbonate reservoir in an Iranian oil field. This study enabled us to modify the conventional J-function to enhance its capability of normalizing capillary pressure data universally.",62,62,1
Drilling Fluid,Rock,"Chen, Pengju; Miska, Stefan Z.; Ren, Rui; Yu, Mengjiao; Ozbayoglu, Evren; Takach, Nicholas",Poroelastic modeling of cutting rock in pressurized condition,Poroelasticity; PDC single cutter; Rock cutting; Deep well drilling,EXTENDED-REACH WELL; TENSILE-STRENGTH; PERFORMANCE; LIMESTONE,"Cutting rock in pressurized conditions is essentially different as compared to the ambient conditions. Under pressurized condition, cutter is not only fragmenting the rock matrix, but also driving pore fluid to flow forward. Due to the coupling of stresses and pore pressure, the pore pressure change caused by cutter will affect effective stresses in the rock and eventually affect mechanical specific energy (MSE). The change in stresses and pore pressure caused by cutter movement are the poroelastic effects in cutting process. To study pressurized cutting process, we developed a cutting model based on the theory of linear poroelasticity. The model can predict coupled stresses and pore pressure in the rock and give a better understanding of the poroelastic effect in the cutting process. To obtain the desired solution, a Fourier Transform is employed. After the analytic solution in Fourier space is obtained, a Discrete Fourier Transform is employed to numerically invert the solution back to the real space. The Mohr-Coulomb failure criterion is also introduced to determine failure of the rock ahead of the cutter. Eventually, the model can predict cutting forces and MSE in pressurized cutting process. The model is also compared to the published experimental data and a good consistency between model and experiment results was found. The influence of hydrostatic pressure and the existence of cuttings on MSE are studied and poroelastic effect during cutting process is also discussed. The results in this paper can be applied to bit-rock interaction in well drilling.",28,28,1
Drilling Fluid,Rock,"Wu, Xiaoguang; Huang, Zhongwei; Li, Gensheng; Li, Ran; Yan, Pengsen; Deng, Xiao; Mu, Kaiwen; Dai, Xianwei",Experiment on coal breaking with cryogenic nitrogen jet,Liquid nitrogen; Jet; Coal breaking; Coal bed methane; Drilling,LIQUID-NITROGEN; METALLIC SURFACES; VELOCITY; STIMULATION; IMPINGEMENT; TECHNOLOGY; IMPACT; ROCKS; WELLS,"Severe leakage of drilling fluid and reservoir damage due to water and solid invasion during well drilling are the key factors that restrict economic exploitation of coal bed methane (CBM) in China. To solve these issues, this paper presents a method of CBM well drilling with the assistance of cryogenic nitrogen jet, in which no aqueous phase and solid phase are contained. To determine the feasibility of coal breaking by cryogenic nitrogen jet and the effects of different parameters, such as nozzle diameter, dimensionless standoff distance, nozzle pressure difference and exposure time, we conducted corresponding rock breaking experiments on artificial and natural coals with the cryogenic nitrogen jet and the water jet. Rock breaking features and the energy consumption by the two jets were compared. The results indicate that the cryogenic nitrogen jet has better rock breaking performances and consumes less energy. Under the same conditions, the average rock erosion volume and the energy consumption with the cryogenic nitrogen jet were 18.34 times larger and 90.8% lower than those with water jet, respectively. Visible netted fractures could be created on the surface of coal samples blasted with the cryogenic nitrogen jet, and thus rock breaking could be facilitated effectively. The outstanding rock breaking performances of cryogenic nitrogen jet are attributed to three mechanisms: high-velocity jet impact, thermal shock and gasification cracking effect. In addition, under our experimental conditions, the erosion volume and depth were proportional to the pressure difference and inversely proportional to the dimensionless standoff distance. When the nozzle diameter changed from 1.5 mm to 3 mm, the increases of erosion volume were 3% at the pressure difference of 5 MPa and 41.7% at the pressure difference of 10 MPa respectively. This indicates that the effect of nozzle diameter is more significant at relatively higher pressure drops. With the increase of exposure time, both of the rock erosion depth and volume rose, while with a smoother trend. The results of this study are expected to promote the application of cryogenic nitrogen jet in CBM well drilling.",27,31,3
Drilling Fluid,Rock,"Tian, Jialin; Li, Jurui; Cheng, Wenming; Zhu, Zhi; Yang, Lin; Yang, Yi; Zhang, Tangjia",Working mechanism and rock-breaking characteristics of coring drill bit,Drilling; Coring drill bit; Drillability; ROP(rate of penetration); Mechanism; Cores,,"For improving the rate of penetration of the complex well structure and performance of the coring drill bit, this paper is to investigate a new type of coring drill bit that generates small-diameter core samples during the drilling process. A special jet channel is designed inside the drill bit body, and the high-pressure drilling fluid flows through the special jet channel to the coring channel, then the cored rock is taken out of the downhole from the drill bit under the negative pressure. Based on the hydrodynamics theory, rock breaking mechanics and actual drilling conditions, the rock breaking mechanism model of the coring drill bit is established. The difference of rock breaking performance between the new drill bit and the existing drill bit is analyzed based on the analysis of numerical example, laboratory and field test. The research results indicate that the special structure design in the new drill bit has the effect of 'absorbing the bottom rock cuttings and pushing the upper rock cuttings' during the process of rock breaking. The effect can reduce the repeated cutting of cores at the bottom hole and improve the ROP(rate of penetration). Field tests show that when the flow rate of drill pump is 25L/s, the result of ROP can be increased by 15%-40%. The new design drill bit can present innovative ideas for improving the efficiency of coring and the quality of geological logging during the drilling process. Moreover, the analysis models can provide references for the new research of improving ROP and drilling efficiency, especially under the conditions of complex structure or large displacement wells.",19,22,3
Drilling Fluid,Rock,"Santos, Jessika Marina; Petri, Irineu Junior; Silva Mota, Ana Carolina; Morais, Anderson dos Santos; Ataide, Carlos Henrique",Optimization of the batch decontamination process of drill cuttings by microwave heating,Synthetic drilling fluid; Microwave heating; Gas chromatography; Drilling waste,REMEDIATION; DISPOSAL; CAVITY; FLUIDS,"In the drilling of oil and gas wells synthetic fluids can be used to remove rock fragments generated during the operation. However, the use of these fluids generates a solid-liquid mixture that must be separated in order to reduce the operational costs by the recovery of the fluid adhered to the solids and also to guarantee compliance with environmental legislation regarding drilling waste disposal. Therefore, the objective of this study was to evaluate the influence of some process variables on the decontamination of drill cuttings by microwave heating. Experimental conditions relative to the heating time, bed temperature and mass of samples contaminated with synthetic drilling fluid were optimized by means of a design of experiments (DOE) and a canonical analysis, reaching organic residual contents lower than 1% (mass). Furthermore, numerical simulations were executed for a better understanding of the microwave heating and drying process. Analyses using the gas chromatography technique were performed in order to evaluate possible composition changes in the recovered liquid samples during the condensation operation, which showed themselves to be sensitive to heating at higher temperatures.",18,19,3
Drilling Fluid,Temperature Profiles,"Pang, Boxue; Wang, Shuyan; Wang, Qiujin; Yang, Kai; Lu, Huilin; Hassan, Muhammad; Jiang, Xiaoxue",Numerical prediction of cuttings transport behavior in well drilling using kinetic theory of granular flow,Cuttings transport; Kinetic theory of granular flow; Granular temperature; Pressure drop; Non-newtonian fluid; Drill pipe rotation,NON-NEWTONIAN FLUIDS; SOLID-LIQUID FLOW; DRILLPIPE ROTATION; PIPE ROTATION; ANNULUS; PARAMETERS; PROFILES; VELOCITY; MODEL; CFD,"The cuttings transport during well drilling was numerically simulated based on kinetic theory of granular flow in combination with sliding mesh for drill pipe rotation. The power-law model was implemented to describe the rheological behavior of drilling fluid. Numerical results were compared with available experimental data in the literature to validate the algorithm, and good agreement was found. Three distinguishable regions of cuttings flow pattern and swaying phenomenon of cuttings distribution were observed along the direction of drill pipe rotation. Increasing the fluid velocity results in a reduction in the height of cuttings bed and weakening of the swaying phenomenon. Higher apparent viscosity of drilling fluid contributes to a good performance of cuttings transport at a low annular velocity, but rising in pressure loss. There is critical inclination angle of the well.ctr for cuttings transport ratio and theta(dp) for pressure drop through the annulus. The most difficult of cuttings transport occurs in the well inclinations around 35 degrees-65 degrees. There is no additional contribution of drill pipe rotation to cuttings transport after reaching a critical rotation speed. Increasing the cutting size leads to a reduction in the cuttings transport ratio and an increase in pressure drop.",32,34,8
Drilling Fluid,Temperature Profiles,"Al Saedi, A. Q.; Flori, R. E.; Kabir, C. S.","New analytical solutions of wellbore fluid temperature profiles during drilling, circulating, and cementing operations",,HEAT-TRANSFER; INJECTION; PREDICT; WELLS; MODEL; FLOW,"Historically, the formulation of the wellbore temperature profiles during drilling, circulating, and cementing operations relied upon the boundary condition or BC at the bottomhole location, wherein the tubular and annular temperatures become equal. This study presents two other formulations to explore alternative to bottomhole BC's that may potentially occur in wellbores. Application of the energy balance in the wellbore for both forward and reverse circulations underpins all three formulations. The wellbore temperature profiles generated by implementing the energy balance in the system depends on the type of the boundary condition used. Initially, we generated various temperature profiles using these models. In general, we observed that the maximum temperature occurs at the end of the tubular or some distance away from the bottom. For open and cased-hole sections, the difference in heat-transfer coefficients triggers different magnitudes of heat transfer and affects the corresponding temperature profiles. We compared the performance of our models with those presented in the literature. Thereafter, we sought to validate the models with diverse set of field data. Given the ability of all three models to handle changes in the geothermal gradient due to the characteristics of the sediments, salt domes, and gas hydrates, we explored their performance in situations where there is significant heat transfer. The holistic approach pursued here provided the necessary insights into various temperature profiles in a given situation.",15,15,1
Drilling Fluid,Heat Transfer,"Minakov, A. V.; Zhigarev, V. A.; Mikhienkova, E. I.; Neverov, A. L.; Buryukin, F. A.; Guzei, D. V.",The effect of nanoparticles additives in the drilling fluid on pressure loss and cutting transport efficiency in the vertical boreholes,Non-Newtonian fluids; Drilling fluid; Nanoparticles; Rheology; Annular channel; Pressure loss; Herschel-bulkley model; Cutting transport; Vertical borehole; Laminar flow,GRANULAR FLOW; KINETIC-THEORY; HEAT-TRANSFER; COUETTE-FLOW; NANOFLUIDS; PARTICLES; NANOCOMPOSITE; CONVECTION; VISCOSITY; CHANNEL,"The effect of nanoparticles of various chemical components and sizes on the rheological behaviour of drilling fluids, pressure loss and cuttings transport in the vertical borehole for a laminar flow regime is considered in the paper. The results of numerical and experimental studies are presented. Silicon, aluminium and titanium oxides nanoparticles are considered. A drilling fluid is Bentonite-water solution with a mass fraction of 5%. The particles concentration in the solution was varied from 0.25 to 2 wt percentages and the particles sizes ranged from 5 to 50 nm. The dependences of the effective viscosity and rheological parameters of the solutions on the nanoparticles concentrations, sizes and materials were obtained. It was shown that nanoparticles in drilling fluid increase cuttings transport by 17% and decrease the average slip velocity of the sludge particles in 1.7-2.0 times, but the pressure losses when pumping the drilling fluid increase in 2.5 times.",18,18,4
Drilling Fluid,Heat Transfer,"Al Saedi, A. Q.; Flori, R. E.; Kabir, C. S.","New analytical solutions of wellbore fluid temperature profiles during drilling, circulating, and cementing operations",,HEAT-TRANSFER; INJECTION; PREDICT; WELLS; MODEL; FLOW,"Historically, the formulation of the wellbore temperature profiles during drilling, circulating, and cementing operations relied upon the boundary condition or BC at the bottomhole location, wherein the tubular and annular temperatures become equal. This study presents two other formulations to explore alternative to bottomhole BC's that may potentially occur in wellbores. Application of the energy balance in the wellbore for both forward and reverse circulations underpins all three formulations. The wellbore temperature profiles generated by implementing the energy balance in the system depends on the type of the boundary condition used. Initially, we generated various temperature profiles using these models. In general, we observed that the maximum temperature occurs at the end of the tubular or some distance away from the bottom. For open and cased-hole sections, the difference in heat-transfer coefficients triggers different magnitudes of heat transfer and affects the corresponding temperature profiles. We compared the performance of our models with those presented in the literature. Thereafter, we sought to validate the models with diverse set of field data. Given the ability of all three models to handle changes in the geothermal gradient due to the characteristics of the sediments, salt domes, and gas hydrates, we explored their performance in situations where there is significant heat transfer. The holistic approach pursued here provided the necessary insights into various temperature profiles in a given situation.",15,15,1
Drilling Fluid,Sealing,"Zhong, Hanyi; Qiu, Zhengsong; Chai, Jinpeng; Guo, Baoyu; Sun, Dong; Liu, Junyi",A preliminary study of the preparation of shale stabilizer with oil sludge - From waste to resource,Oil sludge; Asphalt; Shale stabilizer; Drilling fluid; Preparation,WATER-TREATMENT; BIOREMEDIATION; FORMULATION; RECOVERY,"To convert the hazardous and waste oil sludge into shale stabilizer using in drilling fluid, a novel preparing method has been proposed in the current study. According to the characteristics of oil sludge, the preparation procedure was designed learning from conventional asphaltic-type shale stabilizer preparation method. Several additives such as gilsonite, calcium carbonate, surfactants (hexadecyltrimethylammonium chloride (CTAC) and polyoxyethylene octylphenol ether (OP-10)), polymers (polyethylene glycol (PEG-2000) and cationic polyacrylamide (CPAM)), and fluid loss reducers (sulfonated lignite and potassium humate) were incorporated into oil sludge with the assistance of melting, stirring, kneading, and drying. After the sequential steps of asphaltization, emulsification, and stabilization, a powdered shale stabilizer product (SS-OS) was obtained. The effect of SS-OS on rheology, filtration, and lubricity of drilling fluid bentonite dispersions was tested. Furthermore, the properties of stabilizing shale were evaluated. The results indicated that SS-OS could effectively inhibit shale swelling, dispersion, and exhibit excellent sealing performance. Moreover, it helped to reduce the fluid loss and significantly improve the lubricity of the drilling fluid. From the preliminary study, it was concluded that the strategy of preparing shale stabilizer with oil sludge could be employed to overcome waste, energy and environmental problems simultaneously and show promising application.",20,22,1
Drilling Fluid,Sealing,"Alshubbar, Ghassan; Nygaard, Runar; Jeennakorn, Montri",The effect of wellbore circulation on building an LCM bridge at the fracture aperture,Loss circulation materials; Lost circulation; Drilling induced fractures; Borehole integrity,,"Different laboratory experimental setups with slotted disks, simulating fractures' apertures, have been used extensively to formulate effective loss circulation materials (LCM) recipes. The amount of fluid loss and sealing pressure have been used as the evaluation criteria. The question still remains is how valuable these tests are when LCM fluids are circulated in the wellbore to stop losses. The main objective of this work is to study the effect of the annular fluid flow on building an LCM bridge at the fracture aperture. To address the objective, a fluid loss apparatus has been developed to mimic wellbore circulation. Tapered slotted disks were placed upward in a cylinder filled with drilling fluid and LCM additives. Drilling fluid is pumped at the bottom of the cylinder and the wellbore circulation is simulated through the use of stirring paddle. Previously reported effective LCM recipes have been retested conventionally, no simulated circulation, and under simulated circulation condition (S-circ) with varying pump flow rates and tapered slotted disk sizes. A new term, sealing effectiveness ratio (SER), is introduced to effectively evaluate the sealing integrity of the LCM recipes at the Scirc. The results showed when stirring the sample, a higher fluid loss was required before the sample sealed and the maximum sealing pressure (P-max) was lower than sealing pressures reported from conventional tests. Different LCM recipes required a different minimum flow rate for a seal to initiate at the Scirc. Increasing the flow rate improved the sealing effectiveness ratios of all LCM recipes. At high flow rates some recipes gave very similar Pmax as conventional tests while others lost more than 35% of their strength. At a given flow rate with larger opening size slot, the effect of Scirc was amplified as higher fluid loss was required to initiate a seal and a lower sealing effectiveness ratio was recorded. The most significant new finding is that LCM with lower specific gravity was less prone to the Scirc making them better preventive approach candidates.",16,16,0
Drilling Fluid,Natural Gas,"Sun, Jiaxin; Ning, Fulong; Lei, Hongwu; Gai, Xuerui; Sanchez, Marcelo; Lu, Jingan; Li, Yanlong; Liu, Lele; Liu, Changling; Wu, Nengyou; He, Yong; Wu, Min",Wellbore stability analysis during drilling through marine gas hydrate-bearing sediments in Shenhu area: A case study,Natural gas hydrates; Drilling mud invasion; Wellbore stability; Drilling mud property; Reservoir physical property,METHANE HYDRATE; NUMERICAL-SIMULATION; RESERVOIR DISSOCIATION; MECHANICAL-BEHAVIOR; EAST-COAST; TEST-SITE; MODEL; FLUID; TEMPERATURE; INVASION,"Because of the metastable character of natural gas hydrate-bearing sediments (GHBS), they can be easily affected by drilling operations, thereby inducing the wellbore instability risk. This issue is studied in this paper by means of numerical simulations based on the first exploration well performed in the Shenhu area of the South China Sea in 2007. The corresponding simulated results were compared against the field caliper logging curve. Besides this analysis, the effects of both drilling mud properties (i.e., temperature, density, and salinity) and initial reservoir conditions (i.e., permeability, and saturation) on the wellbore stability were further investigated under the condition of drilling mud invasion into the GHBS. It is anticipated that the coupled multiphysics phenomena triggered under operation conditions can lead to wellbore instability and may also trigger the formation of fractures. The simulation results show that the predicted yield region around the borehole of well SH2 conforms to the borehole enlargement observed in the field. The sensitivity analyses indicate that a local increase in the pore pressure is likely to be generated in the wellbore vicinity, triggered by the large amount of free gas to be released during hydrate dissociation, which is in turn induced by heating (i.e., coming from the drilling-friction effects) and the high salinity of the drilling muds typically used. This study shows that by engineering the salinity of the drilling mud, the amount of free gas to be produced from marine GHBS can be controlled, preventing in this way further wellbore instability issues. This research also shows that an increase in the drilling-mud density not only impact on the development of pore pressures near the borehole, but it also affects the extent of drilling-mud invasion. This effect will extend the hydrate dissociation to a wider area and will also reduce the resistance of the formation, leading to further deformation and potential failure. The analyses also show that the increase in the initial hydrate saturation is associated with a stronger sediment and a more stable wellbore. The model also predicts that GHBS with higher absolute permeability will dissipate faster the excess of pore pressure in the surrounding sediment, contributing to wellbore stability; however, the extent of the hydrate dissociation zone will expand and thereby will increase the yield region.",49,54,11
Drilling Fluid,Natural Gas,"Xie, Binqiang; Ting, Li; Zhang, Yan; Liu, Chen",Rheological properties of bentonite-free water-based drilling fluids with novel polymer viscosifier,Water-soluble polymers; Viscosifier; Thermo-thickening; Rheology; Bentonite-free drilling fluid,ACRYLAMIDE-BASED TERPOLYMER; ENHANCED OIL-RECOVERY; AQUEOUS-SOLUTION; GRAFT-COPOLYMERS; THERMOASSOCIATIVE COPOLYMERS; CELLULOSE NANOPARTICLES; FORMATION DAMAGE; PERFORMANCE; BEHAVIOR; ADDITIVES,"Water-based drilling fluids with no bentonite content was particularly advantageous in oil and natural gas exploration due to the excellent characteristics including faster rates of penetration, enhanced hole cleaning, less formation damage, etc. However, how to keep the excellent rheological regulation of bentonite-free drilling fluids was still one of the most serious issues for the mud designers. In this study, novel polymer viscosifier (SDKP) was prepared under optimal synthesis conditions through the copolymerization of N-vinylcaprolactam and sodium 2-acrylamido-2-methylpropane sulfonate. The effect of SDKP on rheological behavior of bentonite-free fluids was studied according to American Petroleum Institute standard. Results showed that SDKP could improve the rheological properties of bentonite-free fluids. In addition, the good thermal stability and salt stability in improving rheological behavior of fluids made SDKP more attractive. Rheological behavior of SDKP based bentonite-free fluids at different temperatures was also evaluated. Results showed that SDKP based bentonite-free fluids showed certain thermo-viscosifying behavior in the temperature range of 80-140 degrees C even in high salinity, which was benefit for carrying cuttings. Shear test showed that the magnitude of the thermo-thickening viscosity was very sensitive to shear rate, and SDKP containing fluids became better shear-thinning upon heating, which could be more easily pumped into the well. In addition, the mechanism of SDKP in improving rheological behavior of bentonite-free fluids was revealed based on the investigation of morphology of SDKP through Environmental Scanning Electron Microscopy experiment.",24,25,3
Two-phase Flow,Relative Permeability,"Wang, Xiukun; Sheng, James J.",Spontaneous imbibition analysis in shale reservoirs based on pore network modeling,Spontaneous imbibition; Shale; Pore network modeling; Two-phase flow,NON-DARCY FLOW; 2-PHASE FLOW; RELATIVE PERMEABILITY; WETTING LIQUID; DISPLACEMENT; WETTABILITY; PRESSURE; NANOPORES; BEHAVIOR; FLUID,"Capillary spontaneous imbibition is vital to the successful development of shale reservoirs. The two-phase flow macro-properties of shale are significantly difficult to be measured in the laboratory. A pore network model is proposed in this work. The model is validated in the conventional Bentheimer sandstone and then applied to shale matrix with the consideration of variable wettability. Some representative relative permeability and capillary pressure curves are obtained from this pore network model. Based on an analytical solution of spontaneous imbibition, we propose a computational algorithm to calculate the oil recovery factors using the calculated macro-properties from our pore network model. Combining these two, the effects of wettability and absolute permeability on the spontaneous imbibition are studied. The absolute permeability plays an important role in the oil recovery factor induced by spontaneous imbibition. The recovery factor is proportional to the quartic root of absolute permeability. A relative small portion of oil wet pores (less than 40%) in a mixed wet formation won't prevent water from imbibing into the shale matrix and increasing the oil recovery. However, when the portion of oil wet pores is too large, the imbibition recovery drops dramatically. The attempt of this work is made to investigate the two-phase flow and spontaneous imbibition of shale reservoirs in the perspective of micro-scale.",25,26,7
Two-phase Flow,Relative Permeability,"Wang, Xiukun; Sheng, James J.",Pore network modeling of the Non-Darcy flows in shale and tight formations,Pore network modeling; Non-darcy flow; Tight; Shale; Relative permeability,STEP-DECAY MEASUREMENTS; GAS-FLOW; CARBON NANOTUBES; PETROPHYSICAL INTERPRETATION; RELATIVE PERMEABILITY; NANOPORES; SLIPPAGE; RESERVOIRS; TRANSPORT; OIL,"Pore network modeling is a powerful tool to simulate multiphase flow in porous media. Quasi-static model is used in this work and the drainage displacement process is simulated. In shale and tight formations, there are proposed non-Darcy flow mechanisms: gas non-Darcy flow and liquid low velocity non-Darcy flow. The gas flow in shale and tight formations is generally classified in slip flow and transitional flow regimes according to the Knudsen number values. The BK model (Beskok and Karniadakis, 1999) is used for gas non-Darcy flow in this study and the liquid low velocity non-Darcy flow is mainly based on our previous work (Wang and Sheng, 2017a, b). Both effects are incorporated into our pore network model separately. For gas-water flow, gas is the non-wetting phase with gas non-Darcy flow and water is the wetting phase with Darcy flow. For oil-water flow, the low velocity non-Darcy flow is considered for both water and oil phases. Then our model is applied in 3 cases. Case 1 is the Berea sandstone (Valvatne, 2004), which is the benchmark for conventional pore network modeling. In this case, no non-Darcy flows is considered in our pore network model and it is totally Darcy flow. The absolute permeability and relative permeability are both matched with the experimental data. Case 2 is the Bossier tight gas sandstone (Rushing et al., 2003). Gas apparent permeability vs. pressure was measured at different water saturations in their experiments. In this way, the gas non-Darcy flow in two-phase conditions are verified. Case 3 is the Barnett shale (Moghaddam and Jamiolahmady, 2016), which is our major focus. The two types of non-Darcy flows are studied and further discussed in this case. Specifically, the effect of gas non-Darcy flow enhances the gas permeability 2.66 times of the Darcy permeability when pressure is 10 MPa, while the effect of liquid low velocity non-Darcy flow decreases the liquid permeability to 40% of the Darcy permeability when pressure gradient is 0.1 MPa/m. Two types of relative permeability (k(r)) definition are presented in this study: Darcy permeability based kr and normalized k(r) where non-Darcy permeability is used as the base permeability. In the results, the normalized relative permeability doesn't change much for both non-Darcy flows, which implies that we can probably assume the relative permeability unchanged and just consider the effect on absolute permeability, when we deal with these non-Darcy flow mechanisms.",23,24,2
Two-phase Flow,Relative Permeability,"Meng, Shangzhi; Li, Yong; Wang, Lei; Wang, Kai; Pan, Zhejun",A mathematical model for gas and water production from overlapping fractured coalbed methane and tight gas reservoirs,Coproduction; Coalbed methane; Tight gas; Interference phenomenon; Unconventional natural gas coproduction,RELATIVE PERMEABILITY; NATURAL-GAS; ORDOS BASIN; WELL TEST; CHINA; ACCUMULATIONS; ADSORPTION; SIMULATION; GEOLOGY; STRATA,"With the continuous expansion, exploration and development of unconventional natural gas resources, mainly coalbed methane, shale gas and tight gas, some areas overlapped by two or three types of unconventional natural gas reservoirs are explored, e.g., the Linxing, Shilou and Linfen blocks located in the east margin of the Ordos Basin, China. Gas extraction from an individual reservoir becomes not economic as gas resources are not fully recovered; thus, gas coproduction from two or multiple layers is an effective method for improving gas production. In this work, a mathematical model of gas and water two-phase flow for the coproduction of coalbed methane and tight gas is developed. The adsorption characteristics, stress-sensitive and matrix shrinkage effects on coal permeability, and the stress-sensitive effect of tight sandstone are all considered in the model. The gas production related parameters, such as bottom hole flowing pressure, reservoir pressure differences, reservoir properties (e.g., permeability, cleat compressibility of coal, and Langmuir isotherm parameters) are discussed and compared with different geological conditions. The results show that the gas and water flow from the coalbed and sandstone reservoirs show no interference between each other under a constant pressure drainage system; the sandstone reservoirs show a fast pressure drawdown with a high gas production rate decline, while the coalbed reservoir is slow in pressure drawdown and the gas production rate increases gradually. The properties of a specific reservoir have a great influence on its own gas production performance, but with no influence on the other reservoirs. It was found that a lower constant drainage pressure should be adopted in the case of stress-sensitive effects, and coal with a lower cleat compression coefficient and Poisson's ratio value is better for higher gas production. The production contribution from each layer can be acquired if a specific production rate is set. If the reservoir pressure difference between the two reservoirs is too high (for instance at least > 3 MPa in the cases studied in this work), gas and water intrusion may happen, but the reservoirs would be balanced quickly. Thus, the coproduction of coalbed methane and tight gas from one well bore is feasible, and more work should be conducted on proposing a proper drainage strategy to improve the gas resource recovery efficiency in coal-bearing strata.",18,19,5
Two-phase Flow,Relative Permeability,"Luo, Haishan; Delshad, Mojdeh; Pope, Gary A.; Mohanty, Kishore K.",Scaling up the interplay of fingering and channeling for unstable water/polymer floods in viscous-oil reservoirs,Fingering; Channeling; Viscous oil; Water/polymer flood; Field simulation,POROUS-MEDIA; PERMEABILITY HETEROGENEITY; DISPLACEMENT; INSTABILITY; STABILITY; SIMULATOR; FLUID; FLOW,"Unstable displacement and the resulting viscous fingers remain a challenge for reservoir simulation as practical gridblock sizes are usually much larger than the viscous finger wavelength. Traditional reservoir simulators do not consider sub-grid viscous fingering effects and tend to overestimate the oil recovery at the field scale. Several previous studies suggested that fingering can be ignored at the field scale because channeling (caused by heterogeneity) is dominant, but they missed the existence of viscous fingering at the small scale, which affects the displacement efficiency. In our work, we consider that fingering and channeling coexist in the field across different scales, based on the fact that the heterogeneity increases with the scale. At the small-scale (e.g., lab-scale) where heterogeneity is small, fingering is dominant and causes oil bypassing. An effective-fingering model was developed to scale up fingering effects. The model divides each gridblock into three dynamic regions: two-phase flow, oil single-phase flow, and bypassed-oil regions. Model parameters represent the maximum fraction of viscous fingering and the growth factors of different regions, and they are used to modify flow functions. Model parameters from history-matches of a set of laboratory experiments show clear power-law correlations with a dimensionless viscous finger number, a function of viscosity ratio, fluid velocity, permeability, interfacial tension, and core cross-sectional area. The correlation was achieved at the lab-scale by considering relatively homogeneous cores. We extended it further to the field scale by performing high-order spatially accurate numerical simulations at the intermediate scale using gridblock sizes that are roughly the same as that of the core. Geostatistical realizations of the permeability field were generated with various variances and correlation lengths. In a statistical way, we were able to quantify the viscous finger number for a gridblock at the field-scale affected by various heterogeneities. It is also observed that channelized permeability distributions increase the viscous finger number drastically, showing the important role of channeling in such cases. This new model was applied to a synthetic field case with high heterogeneity undergoing water/polymer floods. It is observed that the oil recovery was improved by the polymer slug because of the enhancement in both local displacement efficiency and sweep efficiency.",18,19,2
Two-phase Flow,Relative Permeability,"Ren, Xiaoxia; Li, Aifen; Fu, Shuaishi; Wang, Shoulong",Experimental study on the oil-water relative permeability relationship for tight sandstone considering the nonlinear seepage characteristics,Tight sandstone; Oil-water relative permeability; Unsteady-state method; Nonlinear flow; JBN,,"Oil-water relative permeability is an important parameter to describe the oil-water two-phase flow in oil reservoirs. The permeability rules for oil-water flow in tight sandstone reservoirs do not exactly follow the Darcy law due to its tight lithology and small pore-throat. In addition, the relative permeability curve obtained from traditional processing methods cannot accurately describe the seepage characteristics for this type of oil reservoirs, and therefore, may lead to unreasonable evaluation and prediction of productivity. In this work, the reservoir conditions are simulated and the test for oil (S-wc) flow of tight sandstone has been carried out. Additionally, the relative permeability curve of water-oil displacement in unsteady state has also been obtained. When the oil (S-wc) gets through the tight sandstone sample, the relationship between the flow velocity and the pressure gradient is not a straight line. In addition, the flow velocity and pressure gradient satisfy the equation of nu = k/mu(o)del P(1-1/a+b del P). The traditional JBN method is improved considering the nonlinear seepage characteristics, and the data processing method of oil-water relative permeability for tight sandstone reservoirs is established. Compared with the traditional JBN method, the oil-phase relative permeability, as calculated using the JBN method with the consideration of nonlinearity, is found to be higher. The results also show that the equal permeability point of has moved towards the right.",16,18,2
Two-phase Flow,Relative Permeability,"Mahmoodi, Ali; Javadi, Aliyar; Sola, Behnam Sedaee",Porous media acidizing simulation: New two-phase two-scale continuum modeling approach,Carbonate oil reservoir; Porous media acidizing; Two-phase flow; Two-scale simulation; Wormhole formation,WORMHOLE FORMATION; CHEMICAL DISSOLUTION; REACTIVE DISSOLUTION; CATALYTIC MONOLITHS; FRACTAL PATTERNS; CARBONATE ROCKS; 3-D SIMULATION; PROPAGATION; TRANSPORT; FLUID,"In Recent years some experimental studies have been conducted to investigate the effects of presence of a nonaqueous phase during carbonate acidizing process. Narrower and longer wormholes were observed to be formed when acid is injected into an oil-saturated porous medium, instead of a water-saturated one; which can provide breakthrough earlier with less injected pore volume. However, the mechanisms responsible for these observations had not been comprehensively studied. In this research, a two-phase two-scale continuum (TPTSC) model for simulation of dissolution process during acid injection into carbonate rocks is presented. This model couples two-phase fluid flow equations in porous media and the previously developed two-scale continuum (TSC) model equations for carbonate acidizing. A synthetic case is simulated and the effect of the restricted flow due to various relative permeability values, viscous fingering effects on injected pore volumes to breakthrough; and dissolution patterns are investigated. Our simulation results demonstrate positive effects of two-phase flow and viscous fingering on formation of narrower and longer wormholes. It is observed that pore volumes to breakthrough for an initially high viscosity oil-saturated core is significantly less than pore volumes to breakthrough for an initially water-saturated core. Flow restriction around wormhole due to less relative permeability values and viscous fingering phenomenon can be responsible for gaining lower injected acid volumes to breakthrough. Thus, especially for high viscosity oil reservoir conditions, direct injection of acid to an oil-saturated medium, instead of injecting a pre-flush to push back the saturating oil, can be beneficial.",15,15,0
Two-phase Flow,Porous Media,"Wang, Xiukun; Sheng, James J.",Pore network modeling of the Non-Darcy flows in shale and tight formations,Pore network modeling; Non-darcy flow; Tight; Shale; Relative permeability,STEP-DECAY MEASUREMENTS; GAS-FLOW; CARBON NANOTUBES; PETROPHYSICAL INTERPRETATION; RELATIVE PERMEABILITY; NANOPORES; SLIPPAGE; RESERVOIRS; TRANSPORT; OIL,"Pore network modeling is a powerful tool to simulate multiphase flow in porous media. Quasi-static model is used in this work and the drainage displacement process is simulated. In shale and tight formations, there are proposed non-Darcy flow mechanisms: gas non-Darcy flow and liquid low velocity non-Darcy flow. The gas flow in shale and tight formations is generally classified in slip flow and transitional flow regimes according to the Knudsen number values. The BK model (Beskok and Karniadakis, 1999) is used for gas non-Darcy flow in this study and the liquid low velocity non-Darcy flow is mainly based on our previous work (Wang and Sheng, 2017a, b). Both effects are incorporated into our pore network model separately. For gas-water flow, gas is the non-wetting phase with gas non-Darcy flow and water is the wetting phase with Darcy flow. For oil-water flow, the low velocity non-Darcy flow is considered for both water and oil phases. Then our model is applied in 3 cases. Case 1 is the Berea sandstone (Valvatne, 2004), which is the benchmark for conventional pore network modeling. In this case, no non-Darcy flows is considered in our pore network model and it is totally Darcy flow. The absolute permeability and relative permeability are both matched with the experimental data. Case 2 is the Bossier tight gas sandstone (Rushing et al., 2003). Gas apparent permeability vs. pressure was measured at different water saturations in their experiments. In this way, the gas non-Darcy flow in two-phase conditions are verified. Case 3 is the Barnett shale (Moghaddam and Jamiolahmady, 2016), which is our major focus. The two types of non-Darcy flows are studied and further discussed in this case. Specifically, the effect of gas non-Darcy flow enhances the gas permeability 2.66 times of the Darcy permeability when pressure is 10 MPa, while the effect of liquid low velocity non-Darcy flow decreases the liquid permeability to 40% of the Darcy permeability when pressure gradient is 0.1 MPa/m. Two types of relative permeability (k(r)) definition are presented in this study: Darcy permeability based kr and normalized k(r) where non-Darcy permeability is used as the base permeability. In the results, the normalized relative permeability doesn't change much for both non-Darcy flows, which implies that we can probably assume the relative permeability unchanged and just consider the effect on absolute permeability, when we deal with these non-Darcy flow mechanisms.",23,24,2
Two-phase Flow,Porous Media,"Abbasi, Jassem; Ghaedi, Mojtaba; Riazi, Masoud",A new numerical approach for investigation of the effects of dynamic capillary pressure in imbibition process,Dynamic capillary pressure; Imbibition; Scaling; Two-phase flow,POROUS-MEDIA; 2-PHASE FLOW,"Capillary pressure is important in simulation of fluid flow in porous media at different scales. In ongoing simulation methods, capillary pressure is considered as a static process. However, recent researches have shown that capillary pressure is dynamic parameter. That is, its value directly depends on the rate of saturation changes. Including the effects of dynamic capillary pressure is especially important in prediction of imbibition process, which is an important mechanism in oil production from naturally fractured reservoirs. In this study, to investigate the effects of dynamic capillary pressure in two-phase flow process, an implicit and iterative method is proposed, and it is implemented in an open-source simulator named Matlab Reservoir Simulation Toolbox (MRST). The convergence results show that the proposed algorithm works well and the obtained results are acceptable. Furthermore, the analysis is made on the effects of dynamic capillary pressure functions in vertical imbibition process cases. The results confirm that considering dynamic capillary effects is critical in the simulation of two-phase flow in porous media. This is more important in imbibition process, where the capillary force is the dominant driving force. It is also found that at high permeability cases, considering dynamic capillary pressure effects is more crucial. Also, it is concluded that in high mobility ratios, due to low imbibition rates, effect of considering dynamic capillary pressure curves is not significant.",18,19,5
Two-phase Flow,Porous Media,"Luo, Haishan; Delshad, Mojdeh; Pope, Gary A.; Mohanty, Kishore K.",Scaling up the interplay of fingering and channeling for unstable water/polymer floods in viscous-oil reservoirs,Fingering; Channeling; Viscous oil; Water/polymer flood; Field simulation,POROUS-MEDIA; PERMEABILITY HETEROGENEITY; DISPLACEMENT; INSTABILITY; STABILITY; SIMULATOR; FLUID; FLOW,"Unstable displacement and the resulting viscous fingers remain a challenge for reservoir simulation as practical gridblock sizes are usually much larger than the viscous finger wavelength. Traditional reservoir simulators do not consider sub-grid viscous fingering effects and tend to overestimate the oil recovery at the field scale. Several previous studies suggested that fingering can be ignored at the field scale because channeling (caused by heterogeneity) is dominant, but they missed the existence of viscous fingering at the small scale, which affects the displacement efficiency. In our work, we consider that fingering and channeling coexist in the field across different scales, based on the fact that the heterogeneity increases with the scale. At the small-scale (e.g., lab-scale) where heterogeneity is small, fingering is dominant and causes oil bypassing. An effective-fingering model was developed to scale up fingering effects. The model divides each gridblock into three dynamic regions: two-phase flow, oil single-phase flow, and bypassed-oil regions. Model parameters represent the maximum fraction of viscous fingering and the growth factors of different regions, and they are used to modify flow functions. Model parameters from history-matches of a set of laboratory experiments show clear power-law correlations with a dimensionless viscous finger number, a function of viscosity ratio, fluid velocity, permeability, interfacial tension, and core cross-sectional area. The correlation was achieved at the lab-scale by considering relatively homogeneous cores. We extended it further to the field scale by performing high-order spatially accurate numerical simulations at the intermediate scale using gridblock sizes that are roughly the same as that of the core. Geostatistical realizations of the permeability field were generated with various variances and correlation lengths. In a statistical way, we were able to quantify the viscous finger number for a gridblock at the field-scale affected by various heterogeneities. It is also observed that channelized permeability distributions increase the viscous finger number drastically, showing the important role of channeling in such cases. This new model was applied to a synthetic field case with high heterogeneity undergoing water/polymer floods. It is observed that the oil recovery was improved by the polymer slug because of the enhancement in both local displacement efficiency and sweep efficiency.",18,19,2
Two-phase Flow,Porous Media,"Alpak, Faruk; Samardzic, Aleksandar; Frank, Florian",A distributed parallel direct simulator for pore-scale two-phase flow on digital rock images using a finite difference implementation of the phase-field method,Phase-field method; Pore-scale two-phase flow; Digital rock; Finite difference method (FDM); Computational fluid dynamics (CFD),DIFFUSE-INTERFACE MODEL; MOVING-CONTACT-LINE; DISSIPATIVE PARTICLE DYNAMICS; OF-FLUID METHOD; POROUS-MEDIA; LEVEL-SET; NONUNIFORM SYSTEM; FREE-ENERGY; SHEAR-FLOW; IRREVERSIBLE-PROCESSES,"The phase-field method is a versatile and robust technique for modeling interfacial motion in multiphase flows in pore-scale media. The method provides an effective way to account for surface effects by use of diffuse interfaces. The resulting model significantly simplifies the numerical implementation of mass transport and momentum balance solvers for simulating two-phase flow with a large number of moving interfaces. The thermodynamically consistent governing equations minimize the Helmholtz free energy, leading to formation, transport, and/or destruction of interfaces. The phase-field method accurately conserves mass and is relatively straightforward to implement in conjunction with contact-angle models that account for wettability on rock surfaces. The underlying free-energy minimization framework leads to the advective Cahn-Hilliard equation and modified Navier-Stokes equations that form the phase-field model. We have implemented a particular variant of the phase-field method (PFM) into the computational core of a pore-scale multiphase flow simulator, namely PMFS-PFM, for the numerical simulations of incompressible flow of two immiscible fluid phases. The implementation was discussed in a previous paper for rectangular prism-shaped fully-connected domains, e. g., for simulating two-phase flow in a 2D slit or a 3D duct (Alpak et al., 2016). In this paper, we discuss the recent developments on PMFS-PFM. The main components of the new work are (I) implementation of support for inactive cells that model the solid parts of a rock by extending the original finite difference method (FDM) based discretizations of the underlying partial differential equations (PDEs) in order to solve realistic 3D pore-scale flow problems on rock volumes stemming from imaging, and (II) enhancing the performance of the simulator through implementation of modern sparse linear solvers and distributed parallel computing. It has been shown that the simulations performed on complex pore-scale domains are consistent with the physics of the immiscible two-phase displacement. The parallel scalability of the code is reasonably well varying between 50% and 86% for the investigated test cases of different complexity. Results indicate that the more disconnected the pore-scale domains are, the lower is the parallel efficiency. It has been noted that there is a possibility of improving the parallel efficiency by exploring various grid subdivisions.",16,16,3
Two-phase Flow,Porous Media,"Mahmoodi, Ali; Javadi, Aliyar; Sola, Behnam Sedaee",Porous media acidizing simulation: New two-phase two-scale continuum modeling approach,Carbonate oil reservoir; Porous media acidizing; Two-phase flow; Two-scale simulation; Wormhole formation,WORMHOLE FORMATION; CHEMICAL DISSOLUTION; REACTIVE DISSOLUTION; CATALYTIC MONOLITHS; FRACTAL PATTERNS; CARBONATE ROCKS; 3-D SIMULATION; PROPAGATION; TRANSPORT; FLUID,"In Recent years some experimental studies have been conducted to investigate the effects of presence of a nonaqueous phase during carbonate acidizing process. Narrower and longer wormholes were observed to be formed when acid is injected into an oil-saturated porous medium, instead of a water-saturated one; which can provide breakthrough earlier with less injected pore volume. However, the mechanisms responsible for these observations had not been comprehensively studied. In this research, a two-phase two-scale continuum (TPTSC) model for simulation of dissolution process during acid injection into carbonate rocks is presented. This model couples two-phase fluid flow equations in porous media and the previously developed two-scale continuum (TSC) model equations for carbonate acidizing. A synthetic case is simulated and the effect of the restricted flow due to various relative permeability values, viscous fingering effects on injected pore volumes to breakthrough; and dissolution patterns are investigated. Our simulation results demonstrate positive effects of two-phase flow and viscous fingering on formation of narrower and longer wormholes. It is observed that pore volumes to breakthrough for an initially high viscosity oil-saturated core is significantly less than pore volumes to breakthrough for an initially water-saturated core. Flow restriction around wormhole due to less relative permeability values and viscous fingering phenomenon can be responsible for gaining lower injected acid volumes to breakthrough. Thus, especially for high viscosity oil reservoir conditions, direct injection of acid to an oil-saturated medium, instead of injecting a pre-flush to push back the saturating oil, can be beneficial.",15,15,0
Two-phase Flow,"Natural Fractures,Shale Gas Reservoir","AlTwaijri, Mohammad; Xia, Zhaohui; Yu, Wei; Qu, Liangchao; Hu, Yunpeng; Xu, Yifei; Sepehrnoori, Kamy",Numerical study of complex fracture geometry effect on two-phase performance of shale-gas wells using the fast EDFM method,Shale gas; Complex fractures; Natural fractures; Two-phase flow; Water flowback,WATER; SIMULATION; TRANSPORT; RESERVOIR; MODEL; FLOWBACK; OIL,"Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced ( hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of local grid refinement approach, hydraulic fractures are assumed to be planar ( orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational resources. In this paper, we introduce an embedded discrete fracture model (EDFM) to explicitly model complex fracture geometries. The EDFM efficient approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, we constructed a 3D reservoir model to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In our investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set of natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of nonorthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells.",23,23,3
Two-phase Flow,"Natural Fractures,Shale Gas Reservoir","Wang, Xiukun; Sheng, James J.",Pore network modeling of the Non-Darcy flows in shale and tight formations,Pore network modeling; Non-darcy flow; Tight; Shale; Relative permeability,STEP-DECAY MEASUREMENTS; GAS-FLOW; CARBON NANOTUBES; PETROPHYSICAL INTERPRETATION; RELATIVE PERMEABILITY; NANOPORES; SLIPPAGE; RESERVOIRS; TRANSPORT; OIL,"Pore network modeling is a powerful tool to simulate multiphase flow in porous media. Quasi-static model is used in this work and the drainage displacement process is simulated. In shale and tight formations, there are proposed non-Darcy flow mechanisms: gas non-Darcy flow and liquid low velocity non-Darcy flow. The gas flow in shale and tight formations is generally classified in slip flow and transitional flow regimes according to the Knudsen number values. The BK model (Beskok and Karniadakis, 1999) is used for gas non-Darcy flow in this study and the liquid low velocity non-Darcy flow is mainly based on our previous work (Wang and Sheng, 2017a, b). Both effects are incorporated into our pore network model separately. For gas-water flow, gas is the non-wetting phase with gas non-Darcy flow and water is the wetting phase with Darcy flow. For oil-water flow, the low velocity non-Darcy flow is considered for both water and oil phases. Then our model is applied in 3 cases. Case 1 is the Berea sandstone (Valvatne, 2004), which is the benchmark for conventional pore network modeling. In this case, no non-Darcy flows is considered in our pore network model and it is totally Darcy flow. The absolute permeability and relative permeability are both matched with the experimental data. Case 2 is the Bossier tight gas sandstone (Rushing et al., 2003). Gas apparent permeability vs. pressure was measured at different water saturations in their experiments. In this way, the gas non-Darcy flow in two-phase conditions are verified. Case 3 is the Barnett shale (Moghaddam and Jamiolahmady, 2016), which is our major focus. The two types of non-Darcy flows are studied and further discussed in this case. Specifically, the effect of gas non-Darcy flow enhances the gas permeability 2.66 times of the Darcy permeability when pressure is 10 MPa, while the effect of liquid low velocity non-Darcy flow decreases the liquid permeability to 40% of the Darcy permeability when pressure gradient is 0.1 MPa/m. Two types of relative permeability (k(r)) definition are presented in this study: Darcy permeability based kr and normalized k(r) where non-Darcy permeability is used as the base permeability. In the results, the normalized relative permeability doesn't change much for both non-Darcy flows, which implies that we can probably assume the relative permeability unchanged and just consider the effect on absolute permeability, when we deal with these non-Darcy flow mechanisms.",23,24,2
Two-phase Flow,"Natural Fractures,Shale Gas Reservoir","Abbasi, Jassem; Ghaedi, Mojtaba; Riazi, Masoud",A new numerical approach for investigation of the effects of dynamic capillary pressure in imbibition process,Dynamic capillary pressure; Imbibition; Scaling; Two-phase flow,POROUS-MEDIA; 2-PHASE FLOW,"Capillary pressure is important in simulation of fluid flow in porous media at different scales. In ongoing simulation methods, capillary pressure is considered as a static process. However, recent researches have shown that capillary pressure is dynamic parameter. That is, its value directly depends on the rate of saturation changes. Including the effects of dynamic capillary pressure is especially important in prediction of imbibition process, which is an important mechanism in oil production from naturally fractured reservoirs. In this study, to investigate the effects of dynamic capillary pressure in two-phase flow process, an implicit and iterative method is proposed, and it is implemented in an open-source simulator named Matlab Reservoir Simulation Toolbox (MRST). The convergence results show that the proposed algorithm works well and the obtained results are acceptable. Furthermore, the analysis is made on the effects of dynamic capillary pressure functions in vertical imbibition process cases. The results confirm that considering dynamic capillary effects is critical in the simulation of two-phase flow in porous media. This is more important in imbibition process, where the capillary force is the dominant driving force. It is also found that at high permeability cases, considering dynamic capillary pressure effects is more crucial. Also, it is concluded that in high mobility ratios, due to low imbibition rates, effect of considering dynamic capillary pressure curves is not significant.",18,19,5
Two-phase Flow,"Natural Fractures,Shale Gas Reservoir","Meng, Shangzhi; Li, Yong; Wang, Lei; Wang, Kai; Pan, Zhejun",A mathematical model for gas and water production from overlapping fractured coalbed methane and tight gas reservoirs,Coproduction; Coalbed methane; Tight gas; Interference phenomenon; Unconventional natural gas coproduction,RELATIVE PERMEABILITY; NATURAL-GAS; ORDOS BASIN; WELL TEST; CHINA; ACCUMULATIONS; ADSORPTION; SIMULATION; GEOLOGY; STRATA,"With the continuous expansion, exploration and development of unconventional natural gas resources, mainly coalbed methane, shale gas and tight gas, some areas overlapped by two or three types of unconventional natural gas reservoirs are explored, e.g., the Linxing, Shilou and Linfen blocks located in the east margin of the Ordos Basin, China. Gas extraction from an individual reservoir becomes not economic as gas resources are not fully recovered; thus, gas coproduction from two or multiple layers is an effective method for improving gas production. In this work, a mathematical model of gas and water two-phase flow for the coproduction of coalbed methane and tight gas is developed. The adsorption characteristics, stress-sensitive and matrix shrinkage effects on coal permeability, and the stress-sensitive effect of tight sandstone are all considered in the model. The gas production related parameters, such as bottom hole flowing pressure, reservoir pressure differences, reservoir properties (e.g., permeability, cleat compressibility of coal, and Langmuir isotherm parameters) are discussed and compared with different geological conditions. The results show that the gas and water flow from the coalbed and sandstone reservoirs show no interference between each other under a constant pressure drainage system; the sandstone reservoirs show a fast pressure drawdown with a high gas production rate decline, while the coalbed reservoir is slow in pressure drawdown and the gas production rate increases gradually. The properties of a specific reservoir have a great influence on its own gas production performance, but with no influence on the other reservoirs. It was found that a lower constant drainage pressure should be adopted in the case of stress-sensitive effects, and coal with a lower cleat compression coefficient and Poisson's ratio value is better for higher gas production. The production contribution from each layer can be acquired if a specific production rate is set. If the reservoir pressure difference between the two reservoirs is too high (for instance at least > 3 MPa in the cases studied in this work), gas and water intrusion may happen, but the reservoirs would be balanced quickly. Thus, the coproduction of coalbed methane and tight gas from one well bore is feasible, and more work should be conducted on proposing a proper drainage strategy to improve the gas resource recovery efficiency in coal-bearing strata.",18,19,5
Two-phase Flow,"Natural Fractures,Shale Gas Reservoir","Ranjith, P. G.; Wanniarachchi, W. A. M.; Perera, M. S. A.; Rathnaweera, T. D.",Investigation of the effect of foam flow rate on foam-based hydraulic fracturing of shale reservoir rocks with natural fractures: An experimental study,Foam; Fracturing; Breakdown pressure; Flow rate; Fracture permeability; CT scanning,PERMEABILITY; PRESSURE; ENERGY; GAS; PROPAGATION,"Foam-based hydraulic fracturing has been identified as a good solution for the extraction of natural gas from deep shale reservoirs, due to its unique advantages such as low water consumption and high proppant carrying capacity. However, lack of knowledge of foam-based shale fracturing and complex nature of two-phase foam, make it challenging to use in field conditions, and one unclear area is the effect of the foam flow rate on fracturing and fracture characteristics. Therefore, the aim of this study was to investigate the effect of foam flow rate on breakdown pressure, fracture permeability and generated fracture characteristics. In order to achieve this, a series of hydraulic fracturing experiments was conducted for shale rocks with existing natural fractures, using nitrogen-based foam. Fracture permeability was also evaluated for intact and fractured rock samples. Micro-CT scanning technology was adopted to characterise the geometrical properties of fractures, in order to investigate the effect of foam flow rate within the fracture. Experimental results show that the breakdown pressure increases by 30% while energy release decreases by 78% when the foam flow rate increases from 10 to 70 ml/min. In addition, the results suggest that the permeability of a fractured sample at 10 ml/min injection rate is about 15 times higher than that of a fractured sample at 70 ml/min injection rate. The findings of this study reveal that low foam-flow rates can create a better inter-connected fracture network than higher flow rates.",15,15,4
Two-phase Flow,Slug Flow,"Luo, Haishan; Delshad, Mojdeh; Pope, Gary A.; Mohanty, Kishore K.",Scaling up the interplay of fingering and channeling for unstable water/polymer floods in viscous-oil reservoirs,Fingering; Channeling; Viscous oil; Water/polymer flood; Field simulation,POROUS-MEDIA; PERMEABILITY HETEROGENEITY; DISPLACEMENT; INSTABILITY; STABILITY; SIMULATOR; FLUID; FLOW,"Unstable displacement and the resulting viscous fingers remain a challenge for reservoir simulation as practical gridblock sizes are usually much larger than the viscous finger wavelength. Traditional reservoir simulators do not consider sub-grid viscous fingering effects and tend to overestimate the oil recovery at the field scale. Several previous studies suggested that fingering can be ignored at the field scale because channeling (caused by heterogeneity) is dominant, but they missed the existence of viscous fingering at the small scale, which affects the displacement efficiency. In our work, we consider that fingering and channeling coexist in the field across different scales, based on the fact that the heterogeneity increases with the scale. At the small-scale (e.g., lab-scale) where heterogeneity is small, fingering is dominant and causes oil bypassing. An effective-fingering model was developed to scale up fingering effects. The model divides each gridblock into three dynamic regions: two-phase flow, oil single-phase flow, and bypassed-oil regions. Model parameters represent the maximum fraction of viscous fingering and the growth factors of different regions, and they are used to modify flow functions. Model parameters from history-matches of a set of laboratory experiments show clear power-law correlations with a dimensionless viscous finger number, a function of viscosity ratio, fluid velocity, permeability, interfacial tension, and core cross-sectional area. The correlation was achieved at the lab-scale by considering relatively homogeneous cores. We extended it further to the field scale by performing high-order spatially accurate numerical simulations at the intermediate scale using gridblock sizes that are roughly the same as that of the core. Geostatistical realizations of the permeability field were generated with various variances and correlation lengths. In a statistical way, we were able to quantify the viscous finger number for a gridblock at the field-scale affected by various heterogeneities. It is also observed that channelized permeability distributions increase the viscous finger number drastically, showing the important role of channeling in such cases. This new model was applied to a synthetic field case with high heterogeneity undergoing water/polymer floods. It is observed that the oil recovery was improved by the polymer slug because of the enhancement in both local displacement efficiency and sweep efficiency.",18,19,2
Two-phase Flow,Slug Flow,"Bordalo, Sergio N.; Morooka, Celso K.",Slug flow induced oscillations on subsea petroleum pipelines,Subsea pipelines oscillations; Petroleum risers; Petroleum production; Internal flow forces; Two-phase slug flow; Curvature,INTERNAL FLOW; MODEL; TRANSITIONS; FREQUENCY; BEHAVIOR,"A slug flow load model is proposed to simulate the oscillations induced by the internal flow on pipelines conveying liquid and gas mixtures. The internal flow loads imposed on the pipelines are deduced and implemented in a 3D simulator of pipelines structural dynamics. These internal flow forces, due to gravity and to the curvature of the pipeline, are expressed in vector form providing generality to the formulation, which, combined with the 3D simulator, allows the analysis of a large variety of geometries. A computer code is implemented with the proposed model and tested against cases for which theoretical results can be calculated, displaying good agreement. Further, the model is used to simulate various slug flow conditions in deep water petroleum production risers - steel catenary riser and lazy wave configurations, demonstrating that these pipelines may present oscillations solely due to the internal flow, even when no other external excitations are present. This study also presents the effect of the slug frequency on the amplitude of oscillations of these risers, indicating that large oscillations are indeed possible. The flow load model accepts any valid combinations of gas flow rates and liquid flow rates; thus the pipeline designer may sweep a wide range of production conditions, detecting those that might pose the pipeline in danger, due to alternate stresses inducing fatigue. In general, the modeling algorithms developed in the present work may be inserted in any other pipeline simulator.",16,16,3
Two-phase Flow,Slug Flow,"Saieed, Ahmed; Pao, William; Hewakandamby, Buddhika; Azzopardi, Barry J.; Wood, David A.; Ali, Hafiz M.",Experimental investigation on the effect of diameter ratio on two-phase slug flow separation in a T-Junction,T-junction; Slug flow; Gas-liquid separation; Diameter ratio,INCLINED BRANCH ARM; NUMERICAL-SIMULATION; STRATIFIED FLOW; PIPE TEE; SPLIT; MODEL,"T-junctions are often used in offshore platforms to partially separate gas from produced fluids. Poorly designed T-junctions frequently produce very high liquid (oil and/or water) carryovers, causing major issues to the downstream equipment train which is not designed to handle excessive liquid. This paper reports the liquid carryover experiments in T-junctions using five different side to main arm diameter ratios under slug flow regime. The obtained phase separation curves can be divided into two component variables; liquid-carryover threshold and peak liquid carryover. The experiments demonstrate that with a decrease in diameter ratio both of these variables decrease. Yet, for superior multiphase flow separation, a high liquid carryover threshold and a low peak liquid carryover are required. Hence, the generally accepted rule that a reduction in diameter ratio improves the phase separation is revealed to be an over-extrapolated statement. The novel findings of this work are: 1) for optimum flow splitting under slug flow conditions, the diameter ratio should be kept between 1 and 0.67, while the diameter ratio 0.67 was found to be most suitable; 2) two correlations were developed for predicting two-phase slug flow separation in different diameter ratio T-junctions. These correlations offer beneficial guidance and clarifications for a number of oil and gas flowline and pipeline applications.",15,15,0
Two-phase Flow,Slug Flow,"Bouyahiaoui, Hiba; Azzi, Abdelwahid; Zeghloul, Ammar; Hasan, Abbas; Berrouk, Abdallah Sofiane",Experimental investigation of a vertically downward two-phase air-water slug flow,Downward; Slug; Void fraction; Vertical; Frequency; Characteristics,VOID FRACTION; REGIME IDENTIFICATION; LIQUID FLOW; COCURRENT; BUBBLE; PATTERN; MOTION,"The present experimental work investigates the vertical downward two-phase slug flow in a transparent vertical pipe of 34 mm internal diameter. The gas and liquid superficial velocities are in the range of 0-3.27 m/s and 0.015-1.4 m/s respectively. The cross-sectional averaged void fraction has been measured at seven positions along the test section by the intermediary of the conductance probe technique. The results of the development of the void fraction time-series and Probability Density Function along the tube are presented. A good accordance was found between the experimental data and the line transitions of the flow pattern map proposed by (Usui, 1989). We also present results of the structure velocity of the slug flow, where the distribution parameter is found to be lower than unity. A new correlation for the prediction of slug frequencies is also proposed. It agrees well with the data collected in this study with +/- 10% error.",14,14,1
Two-phase Flow,Steam,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Liu, Qing; Han, Song; Zhou, Yunjian",Effect of friction work on key parameters of steam at different state in toe-point injection horizontal wellbores,Heavy oil recovery; Toe-point injection horizontal well; Friction work; Temperature distribution; Steam quality distribution; Steam state,HEAT-TRANSFER CHARACTERISTICS; MULTI-THERMAL FLUID; SUPERHEATED-STEAM; 2-PHASE FLOW; OIL-RECOVERY; PERFORMANCE ANALYSIS; SUPERCRITICAL CO2; MODEL; TEMPERATURE; WELLS,"When modeling of steam flow in wellbores, the effect of friction work on temperature/ steam quality of both fluid in wellbores and reservoir should be considered. A model that can describe the energy re-distribution in the system should be built. In this paper, new energy balance equations for steam flow in inner tubing (IT) and annuli are developed with consideration of the effect of frction work on the energy re-distribution process in the system. The heat energy caused by shear stress has an obvious influence on the increase of steam quality or superheated steam temperature, especially under high injection speed condition. Firstly, a model for steam flow is developed in wellbores based on the energy and momentum balance equations. The energy balance equation controlls the predicted values of steam quality or superheated steam temperature, and the momentum balance equation controlls mainly the steam pressure. Secondly, coupled with the seepage model in oil layer, a comprehensive mathematical model is establiehed for single, two-phase flow of steam in horizontal wells with toe-point injection technique. Results show that: ( a) when the effect of friction work was neglected, the predicted steam quality or superheated steam temperature were obviously smaller than field data. (b) While seam quality decreases with distance when wet steam flows in wellbores, superheated steam temperature in annuli has an increase at the heel-point in annuli. This is because the fluid with lower temperature in annuli absorbs heat from steam with higher temperature in IT. (c). In order to obtain a satisfactory oil recovery ratio, field engineers are suggested to increase the injection pressure to a reasonable level based on the rock fracture pressure experiment.",35,38,0
Two-phase Flow,Steam,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Li, Xiangfang; Zhang, Tao; Lu, Chengang; Liu, Wenyuan",An improved two-phase model for saturated steam flow in multi-point injection horizontal wells under steady-state injection condition,Heavy oil; Multi-point injection; Horizontal well; Two-phase steam flow; Steam quality; Friction work,HEAT-TRANSFER CHARACTERISTICS; MASS-TRANSFER CHARACTERISTICS; MULTICOMPONENT THERMAL FLUID; SUPERHEATED STEAM; NONCONDENSING GASES; SUPERCRITICAL CO2; POROUS ENCLOSURE; KEY PARAMETERS; OIL PRODUCTION; CURVE ANALYSIS,"Previous models neglected the effect of frictional heating on steam quality and enthalpy in wellbores when saturated steam is injected into multi-point injection horizontal wellbores. In this paper, new energy conservation equations were developed for increasing the calculation accuracy of steam quality in inner tubing (IT) and annuli. Then, coupled with the momentum balance equations, the distributions of steam quality and pressure along the IT and annuli were obtained by using the straight forward numerical method. The predicted results from the new model were compared against field data and previous models. It is found that: (a). The effect of heat loss to surrounding formation on the temperature profiles is weak. However, the heat loss has a significant influence on the profile of steam quality in wellbores. (b) When removing the item of frictional work from the energy balance equations, the predicted values of steam quality and enthalpy are lower than actual data. This error in energy conservation equation may be hidden when the predicted temperatures showed good agreement with field data. (c) With the help of multi-point injection technique, formation heating effect at both heel-point and toe-point can be improved.",32,33,1
Two-phase Flow,Steam,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Han, Song; Liu, Qing; Liu, Wenyuan",Type curve analysis of multi-phase flow of multi-component thermal fluid in toe-point injection horizontal wells considering phase change,Heavy oil recovery; Phase change; Toe-point injection horizontal wells; Non-condensing gases; Superheated state; Saturated state,HEAVY OIL-RECOVERY; SUPERHEATED-STEAM INJECTION; 2-PHASE FLOW; PERFORMANCE ANALYSIS; NONCONDENSING GASES; GRAVITY DRAINAGE; KEY PARAMETERS; HOT-WATER; WELLBORE; MODEL,"Huge amount of works were done on modeling of wet steam flow in the conventional heel-point injection horizontal wellbores. With the rapid development of technology, new technology of superheated steam - non-condensing gases (SNG) injection coupled with toe-point injection wellbores was adopted in oil field. In this paper, a series of works were done on modeling of SNG flow in a horizontal wellbore with toe-point injection technique. The two-phase flow model was embedded in this SNG model for describing the phase change phenomenon. Firstly, a hydraulics model comprised of mass, momentum and energy conservation equations was developed. Then, coupled with the seepage model in oil layer, a wellbore/formation coupled model was established. Thirdly, straight forward numerical method was adopted to solve the model. Finally, model verification and sensitivity analysis were conducted sequentially. Results show that: (1) The SNG temperature in annuli has an increase at the heel-point due to heat conduction from IT to annuli. (2) When the mass injection rate is kept unchanged, the SNG temperature at a certain place in annuli decreases with increasing of the mass content of non-condensing gases. (3) The SNG in IT undergoes phase change into saturated state at the distance of 150 m. Then, from the distance of 150 m-200 m, the gas content in the mixture system gets an increase and the superheat degree is equal to zero. (4) Phase change occurs again in annuli when the SNG reaches the distance of 110 m where the wet fluid turns into superheated state, after which the superheated degree of SNG increases continuously as SNG is flowing to the heel-point.",32,32,1
Two-phase Flow,Complex,"AlTwaijri, Mohammad; Xia, Zhaohui; Yu, Wei; Qu, Liangchao; Hu, Yunpeng; Xu, Yifei; Sepehrnoori, Kamy",Numerical study of complex fracture geometry effect on two-phase performance of shale-gas wells using the fast EDFM method,Shale gas; Complex fractures; Natural fractures; Two-phase flow; Water flowback,WATER; SIMULATION; TRANSPORT; RESERVOIR; MODEL; FLOWBACK; OIL,"Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced ( hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of local grid refinement approach, hydraulic fractures are assumed to be planar ( orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational resources. In this paper, we introduce an embedded discrete fracture model (EDFM) to explicitly model complex fracture geometries. The EDFM efficient approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, we constructed a 3D reservoir model to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In our investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set of natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of nonorthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells.",23,23,3
Two-phase Flow,Complex,"Alpak, Faruk; Samardzic, Aleksandar; Frank, Florian",A distributed parallel direct simulator for pore-scale two-phase flow on digital rock images using a finite difference implementation of the phase-field method,Phase-field method; Pore-scale two-phase flow; Digital rock; Finite difference method (FDM); Computational fluid dynamics (CFD),DIFFUSE-INTERFACE MODEL; MOVING-CONTACT-LINE; DISSIPATIVE PARTICLE DYNAMICS; OF-FLUID METHOD; POROUS-MEDIA; LEVEL-SET; NONUNIFORM SYSTEM; FREE-ENERGY; SHEAR-FLOW; IRREVERSIBLE-PROCESSES,"The phase-field method is a versatile and robust technique for modeling interfacial motion in multiphase flows in pore-scale media. The method provides an effective way to account for surface effects by use of diffuse interfaces. The resulting model significantly simplifies the numerical implementation of mass transport and momentum balance solvers for simulating two-phase flow with a large number of moving interfaces. The thermodynamically consistent governing equations minimize the Helmholtz free energy, leading to formation, transport, and/or destruction of interfaces. The phase-field method accurately conserves mass and is relatively straightforward to implement in conjunction with contact-angle models that account for wettability on rock surfaces. The underlying free-energy minimization framework leads to the advective Cahn-Hilliard equation and modified Navier-Stokes equations that form the phase-field model. We have implemented a particular variant of the phase-field method (PFM) into the computational core of a pore-scale multiphase flow simulator, namely PMFS-PFM, for the numerical simulations of incompressible flow of two immiscible fluid phases. The implementation was discussed in a previous paper for rectangular prism-shaped fully-connected domains, e. g., for simulating two-phase flow in a 2D slit or a 3D duct (Alpak et al., 2016). In this paper, we discuss the recent developments on PMFS-PFM. The main components of the new work are (I) implementation of support for inactive cells that model the solid parts of a rock by extending the original finite difference method (FDM) based discretizations of the underlying partial differential equations (PDEs) in order to solve realistic 3D pore-scale flow problems on rock volumes stemming from imaging, and (II) enhancing the performance of the simulator through implementation of modern sparse linear solvers and distributed parallel computing. It has been shown that the simulations performed on complex pore-scale domains are consistent with the physics of the immiscible two-phase displacement. The parallel scalability of the code is reasonably well varying between 50% and 86% for the investigated test cases of different complexity. Results indicate that the more disconnected the pore-scale domains are, the lower is the parallel efficiency. It has been noted that there is a possibility of improving the parallel efficiency by exploring various grid subdivisions.",16,16,3
Two-phase Flow,Complex,"Ranjith, P. G.; Wanniarachchi, W. A. M.; Perera, M. S. A.; Rathnaweera, T. D.",Investigation of the effect of foam flow rate on foam-based hydraulic fracturing of shale reservoir rocks with natural fractures: An experimental study,Foam; Fracturing; Breakdown pressure; Flow rate; Fracture permeability; CT scanning,PERMEABILITY; PRESSURE; ENERGY; GAS; PROPAGATION,"Foam-based hydraulic fracturing has been identified as a good solution for the extraction of natural gas from deep shale reservoirs, due to its unique advantages such as low water consumption and high proppant carrying capacity. However, lack of knowledge of foam-based shale fracturing and complex nature of two-phase foam, make it challenging to use in field conditions, and one unclear area is the effect of the foam flow rate on fracturing and fracture characteristics. Therefore, the aim of this study was to investigate the effect of foam flow rate on breakdown pressure, fracture permeability and generated fracture characteristics. In order to achieve this, a series of hydraulic fracturing experiments was conducted for shale rocks with existing natural fractures, using nitrogen-based foam. Fracture permeability was also evaluated for intact and fractured rock samples. Micro-CT scanning technology was adopted to characterise the geometrical properties of fractures, in order to investigate the effect of foam flow rate within the fracture. Experimental results show that the breakdown pressure increases by 30% while energy release decreases by 78% when the foam flow rate increases from 10 to 70 ml/min. In addition, the results suggest that the permeability of a fractured sample at 10 ml/min injection rate is about 15 times higher than that of a fractured sample at 70 ml/min injection rate. The findings of this study reveal that low foam-flow rates can create a better inter-connected fracture network than higher flow rates.",15,15,4
Two-phase Flow,non-Darcy Flow,"Wang, Xiukun; Sheng, James J.",Spontaneous imbibition analysis in shale reservoirs based on pore network modeling,Spontaneous imbibition; Shale; Pore network modeling; Two-phase flow,NON-DARCY FLOW; 2-PHASE FLOW; RELATIVE PERMEABILITY; WETTING LIQUID; DISPLACEMENT; WETTABILITY; PRESSURE; NANOPORES; BEHAVIOR; FLUID,"Capillary spontaneous imbibition is vital to the successful development of shale reservoirs. The two-phase flow macro-properties of shale are significantly difficult to be measured in the laboratory. A pore network model is proposed in this work. The model is validated in the conventional Bentheimer sandstone and then applied to shale matrix with the consideration of variable wettability. Some representative relative permeability and capillary pressure curves are obtained from this pore network model. Based on an analytical solution of spontaneous imbibition, we propose a computational algorithm to calculate the oil recovery factors using the calculated macro-properties from our pore network model. Combining these two, the effects of wettability and absolute permeability on the spontaneous imbibition are studied. The absolute permeability plays an important role in the oil recovery factor induced by spontaneous imbibition. The recovery factor is proportional to the quartic root of absolute permeability. A relative small portion of oil wet pores (less than 40%) in a mixed wet formation won't prevent water from imbibing into the shale matrix and increasing the oil recovery. However, when the portion of oil wet pores is too large, the imbibition recovery drops dramatically. The attempt of this work is made to investigate the two-phase flow and spontaneous imbibition of shale reservoirs in the perspective of micro-scale.",25,26,7
Two-phase Flow,non-Darcy Flow,"Wang, Xiukun; Sheng, James J.",Pore network modeling of the Non-Darcy flows in shale and tight formations,Pore network modeling; Non-darcy flow; Tight; Shale; Relative permeability,STEP-DECAY MEASUREMENTS; GAS-FLOW; CARBON NANOTUBES; PETROPHYSICAL INTERPRETATION; RELATIVE PERMEABILITY; NANOPORES; SLIPPAGE; RESERVOIRS; TRANSPORT; OIL,"Pore network modeling is a powerful tool to simulate multiphase flow in porous media. Quasi-static model is used in this work and the drainage displacement process is simulated. In shale and tight formations, there are proposed non-Darcy flow mechanisms: gas non-Darcy flow and liquid low velocity non-Darcy flow. The gas flow in shale and tight formations is generally classified in slip flow and transitional flow regimes according to the Knudsen number values. The BK model (Beskok and Karniadakis, 1999) is used for gas non-Darcy flow in this study and the liquid low velocity non-Darcy flow is mainly based on our previous work (Wang and Sheng, 2017a, b). Both effects are incorporated into our pore network model separately. For gas-water flow, gas is the non-wetting phase with gas non-Darcy flow and water is the wetting phase with Darcy flow. For oil-water flow, the low velocity non-Darcy flow is considered for both water and oil phases. Then our model is applied in 3 cases. Case 1 is the Berea sandstone (Valvatne, 2004), which is the benchmark for conventional pore network modeling. In this case, no non-Darcy flows is considered in our pore network model and it is totally Darcy flow. The absolute permeability and relative permeability are both matched with the experimental data. Case 2 is the Bossier tight gas sandstone (Rushing et al., 2003). Gas apparent permeability vs. pressure was measured at different water saturations in their experiments. In this way, the gas non-Darcy flow in two-phase conditions are verified. Case 3 is the Barnett shale (Moghaddam and Jamiolahmady, 2016), which is our major focus. The two types of non-Darcy flows are studied and further discussed in this case. Specifically, the effect of gas non-Darcy flow enhances the gas permeability 2.66 times of the Darcy permeability when pressure is 10 MPa, while the effect of liquid low velocity non-Darcy flow decreases the liquid permeability to 40% of the Darcy permeability when pressure gradient is 0.1 MPa/m. Two types of relative permeability (k(r)) definition are presented in this study: Darcy permeability based kr and normalized k(r) where non-Darcy permeability is used as the base permeability. In the results, the normalized relative permeability doesn't change much for both non-Darcy flows, which implies that we can probably assume the relative permeability unchanged and just consider the effect on absolute permeability, when we deal with these non-Darcy flow mechanisms.",23,24,2
Two-phase Flow,Multiphase Pump,"Shi, Yi; Zhu, Hongwu; Zhang, Jinya; Zhang, Jiate; Zhao, Junlin",Experiment and numerical study of a new generation three-stage multiphase pump,Helico-axial pump; Multiphase flow; Gas volume fraction; Computational fluid dynamics; Performance validation; Interphase drag force,IMPELLER,"Multiphase pump is a cost-effective option for subsea gas and oil fields development. The ability of handling different gas volume fractions with high rotational speed is necessary to optimize the operating performance of a multiphase pump. Thus meeting the demand for increasing gas and oil production of undersea wells especially for those brownfields. This study aims to validate the performance of a three-stage helico-axial multiphase pump with new designed impellers and high rotational speed in both single and two-phase experiments. Then establish a numerical analysis method to predict the pump performance and evaluate the characteristics of multiphase flow with high reliability by using commercial CFD packages. The design volume flowrate of the pump is 100 m(3)/h and rotational speed is 4500 rpm. The experiment results show that the highest efficiency is 45% in water condition at the design parameters. There is not much difference on the pump performance at low inlet gas volume fractions (GVF) such as 5% and 10%, which indicates that multi-stage pump can prevent large performance degradation at low inlet GVFs. Numerical simulations are implemented by solving the three-dimensional steady Reynolds-Averaged Navier-Stokes (RANS) equations. The effects of various turbulence models, wall roughness, gas bubble sizes and interphase drag models on the hydraulic performance of multiphase are investigated. The results show that the predicted performance with Shear Stress Transport (SST) turbulence model at the optimal conditions agree well with the experiment data. Wall roughness should be considered since it has a significant effect on pump efficiency. Gas bubble size varies according to different inlet GVFs and rotational speed. The in-situ alpha(g) is high in diffuser and it varies with different interphase drag force models. The reliability of the numerical analysis method is proven by comparing the numerical results and experiments data.",36,38,1
Two-phase Flow,Multiphase Pump,"Ma, Yi; Ni, Yang; Zhang, He; Zhou, Shuiqing; Deng, Hongying",Influence of valve's lag characteristic on pressure pulsation and performance of reciprocating multiphase pump,Multiphase pump; Computational fluid dynamics; Two-phase flow; Lag characteristic; Pressure pulsation,ELECTRICAL SUBMERSIBLE PUMP; FLUID-FLOW; NUMERICAL-SIMULATION; COMPRESSOR,"Reciprocating multiphase pump is the key equipment for the oil-gas transport technology in the petroleum industry. The opening and closing motions of suction and discharge valves directly affect the transport performance and stability of pump. In this paper, the whole working cycle of reciprocating multiphase pump is studied by using computational fluid dynamics (CFD) method. The combined actions of piston, suction and discharge valves are dealt with User Defined Functions and dynamic grid technique. Based on the instantaneous motions of valves, the lag characteristics of suction and discharge valves under different working conditions are analyzed. And the influences of lag angles on the pressure pulsation, P-V diagram and input power of the pump are further investigated. The results show that the lag angles have a significant impact on the internal and external characteristics of the reciprocating multiphase pump. Due to the most obvious opening lag angle of discharge valve, the pump pressures and PV diagram have the sudden fluctuations just after the end of compression process, which appear in the range of. 0=240.7 degrees-273.1 degrees for the initial condition. The gas volume fraction (GVF) plays more important role than the suction and discharge pressures in the working of reciprocating multiphase pump, and the opening lag angles of suction and discharge valves at GVF = 0.9 increase to more than 6 times at GVF = 0.1. By the comparisons of input power, the simulated results for reciprocating multiphase pump show good agreement with the results of prototype test. This study would provide a theoretical basis for the design of high-efficiency multiphase pump and valve.",16,19,6
Two-phase Flow,Hydraulic Fracture,"AlTwaijri, Mohammad; Xia, Zhaohui; Yu, Wei; Qu, Liangchao; Hu, Yunpeng; Xu, Yifei; Sepehrnoori, Kamy",Numerical study of complex fracture geometry effect on two-phase performance of shale-gas wells using the fast EDFM method,Shale gas; Complex fractures; Natural fractures; Two-phase flow; Water flowback,WATER; SIMULATION; TRANSPORT; RESERVOIR; MODEL; FLOWBACK; OIL,"Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced ( hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of local grid refinement approach, hydraulic fractures are assumed to be planar ( orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational resources. In this paper, we introduce an embedded discrete fracture model (EDFM) to explicitly model complex fracture geometries. The EDFM efficient approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, we constructed a 3D reservoir model to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In our investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set of natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of nonorthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells.",23,23,3
Two-phase Flow,Hydraulic Fracture,"Ranjith, P. G.; Wanniarachchi, W. A. M.; Perera, M. S. A.; Rathnaweera, T. D.",Investigation of the effect of foam flow rate on foam-based hydraulic fracturing of shale reservoir rocks with natural fractures: An experimental study,Foam; Fracturing; Breakdown pressure; Flow rate; Fracture permeability; CT scanning,PERMEABILITY; PRESSURE; ENERGY; GAS; PROPAGATION,"Foam-based hydraulic fracturing has been identified as a good solution for the extraction of natural gas from deep shale reservoirs, due to its unique advantages such as low water consumption and high proppant carrying capacity. However, lack of knowledge of foam-based shale fracturing and complex nature of two-phase foam, make it challenging to use in field conditions, and one unclear area is the effect of the foam flow rate on fracturing and fracture characteristics. Therefore, the aim of this study was to investigate the effect of foam flow rate on breakdown pressure, fracture permeability and generated fracture characteristics. In order to achieve this, a series of hydraulic fracturing experiments was conducted for shale rocks with existing natural fractures, using nitrogen-based foam. Fracture permeability was also evaluated for intact and fractured rock samples. Micro-CT scanning technology was adopted to characterise the geometrical properties of fractures, in order to investigate the effect of foam flow rate within the fracture. Experimental results show that the breakdown pressure increases by 30% while energy release decreases by 78% when the foam flow rate increases from 10 to 70 ml/min. In addition, the results suggest that the permeability of a fractured sample at 10 ml/min injection rate is about 15 times higher than that of a fractured sample at 70 ml/min injection rate. The findings of this study reveal that low foam-flow rates can create a better inter-connected fracture network than higher flow rates.",15,15,4
Two-phase Flow,Angle,"Ma, Yi; Ni, Yang; Zhang, He; Zhou, Shuiqing; Deng, Hongying",Influence of valve's lag characteristic on pressure pulsation and performance of reciprocating multiphase pump,Multiphase pump; Computational fluid dynamics; Two-phase flow; Lag characteristic; Pressure pulsation,ELECTRICAL SUBMERSIBLE PUMP; FLUID-FLOW; NUMERICAL-SIMULATION; COMPRESSOR,"Reciprocating multiphase pump is the key equipment for the oil-gas transport technology in the petroleum industry. The opening and closing motions of suction and discharge valves directly affect the transport performance and stability of pump. In this paper, the whole working cycle of reciprocating multiphase pump is studied by using computational fluid dynamics (CFD) method. The combined actions of piston, suction and discharge valves are dealt with User Defined Functions and dynamic grid technique. Based on the instantaneous motions of valves, the lag characteristics of suction and discharge valves under different working conditions are analyzed. And the influences of lag angles on the pressure pulsation, P-V diagram and input power of the pump are further investigated. The results show that the lag angles have a significant impact on the internal and external characteristics of the reciprocating multiphase pump. Due to the most obvious opening lag angle of discharge valve, the pump pressures and PV diagram have the sudden fluctuations just after the end of compression process, which appear in the range of. 0=240.7 degrees-273.1 degrees for the initial condition. The gas volume fraction (GVF) plays more important role than the suction and discharge pressures in the working of reciprocating multiphase pump, and the opening lag angles of suction and discharge valves at GVF = 0.9 increase to more than 6 times at GVF = 0.1. By the comparisons of input power, the simulated results for reciprocating multiphase pump show good agreement with the results of prototype test. This study would provide a theoretical basis for the design of high-efficiency multiphase pump and valve.",16,19,6
Two-phase Flow,Angle,"Zhang, Feifei; Miska, Stefan; Yu, Mengjiao; Ozbayoglu, Evren",A unified transient solid-liquid two-phase flow model for cuttings transport-modelling part,Transient solid transport; Unified model; Flow pattern; Hole cleaning; Drilling hydraulic,VELOCITY; PIPES,"A unified transient model is presented for predictions of flow pattern transitions, pressure gradient, solid particle concentration in solid-liquid two-phase flow. The transient mechanistic model is based on the conservation of mass and momentum and coupled with flow pattern prediction methods. Changes of flow patterns are reflected by assigning certain terms to zeros in the general equations and changing the number of equations. Thus, the model can be automatically adjusted for flow patterns in transient simulation. A semi-implicit approach is used to solve the model. The velocities and pressures are solved implicitly based on the momentum conservation equations and the solids concentrations are updated explicitly based on the mass conservation equations. The model is validated by conducting a series of experimental tests on a full scale flow loop (0.2 x 0.11 x 25 m). The validation of the transient simulation includes the validation of the transient build-up stage and the validation of the cuttings volumetric concentration at fully developed stage. Results found that increase of the flow rate significantly reduces the build-up time, and effects of pipe rotation vary at different inclined angles. The effect of inclination angle on solids profile build-up is similar to the effects of well inclination angle on steady state cuttings concentration. Below 60 degrees, the build-up time increases significantly as the well inclination angle increases. When the well inclination angle goes to over 60 degrees, the effects of well inclination angle become insignificant.",15,17,2
Tight Sandstone,Natural Fractures,"Chen, Zhiqiang; Yang, Zhengming; Wang, Moran",Hydro-mechanical coupled mechanisms of hydraulic fracture propagation in rocks with cemented natural fractures,Hydraulic fracture; Cemented fracture; Natural fracture; LBM-DEM,LATTICE-BOLTZMANN METHOD; GENERAL SHAPES; BARNETT SHALE; FLUID-FLOW; PERMEABILITY; MODEL; DISCONTINUITIES; CRITERION,"Natural fractures commonly exist in unconventional reservoirs such as shale and tight gas sandstone, which are mostly cemented (or sealed) with minerals and not able to contribute to reservoir storage or rock permeability. However, during hydraulic fracture stimulation, these cemented natural fractures will be encountered and influence hydraulic fracture geometry greatly and, thereby, gas production. In this work, hydraulic fracture propagation in rock with cemented natural fracture is investigated using our recently developed and validated hydromechanical coupled LBM-DEM model. The numerical results show that both the strength ratio (between cemented natural fracture and host rock) and the approach angle (between hydraulic and cemented natural fracture) significantly affect the hydraulic fracture propagation. A larger strength contrast or a smaller approach angle will be more conducive to deflection, which is consistent with experimental observation. For rocks with weakly cemented natural fractures, deflection is mainly caused by shear failure in weakly cemented fracture. However, for rocks with strongly cemented natural fractures, deflection happens accompanying with tensile failure in host rock along the cement wall, which cannot be captured by the previous numerical models where the cemented natural fracture is treated as a bonded interface. In addition, complex fracture network is more easily formed if multiple weakly cemented natural fractures are orthogonal to the hydraulic fracture propagation direction.",31,32,3
Tight Sandstone,Natural Fractures,"Meng, Shangzhi; Li, Yong; Wang, Lei; Wang, Kai; Pan, Zhejun",A mathematical model for gas and water production from overlapping fractured coalbed methane and tight gas reservoirs,Coproduction; Coalbed methane; Tight gas; Interference phenomenon; Unconventional natural gas coproduction,RELATIVE PERMEABILITY; NATURAL-GAS; ORDOS BASIN; WELL TEST; CHINA; ACCUMULATIONS; ADSORPTION; SIMULATION; GEOLOGY; STRATA,"With the continuous expansion, exploration and development of unconventional natural gas resources, mainly coalbed methane, shale gas and tight gas, some areas overlapped by two or three types of unconventional natural gas reservoirs are explored, e.g., the Linxing, Shilou and Linfen blocks located in the east margin of the Ordos Basin, China. Gas extraction from an individual reservoir becomes not economic as gas resources are not fully recovered; thus, gas coproduction from two or multiple layers is an effective method for improving gas production. In this work, a mathematical model of gas and water two-phase flow for the coproduction of coalbed methane and tight gas is developed. The adsorption characteristics, stress-sensitive and matrix shrinkage effects on coal permeability, and the stress-sensitive effect of tight sandstone are all considered in the model. The gas production related parameters, such as bottom hole flowing pressure, reservoir pressure differences, reservoir properties (e.g., permeability, cleat compressibility of coal, and Langmuir isotherm parameters) are discussed and compared with different geological conditions. The results show that the gas and water flow from the coalbed and sandstone reservoirs show no interference between each other under a constant pressure drainage system; the sandstone reservoirs show a fast pressure drawdown with a high gas production rate decline, while the coalbed reservoir is slow in pressure drawdown and the gas production rate increases gradually. The properties of a specific reservoir have a great influence on its own gas production performance, but with no influence on the other reservoirs. It was found that a lower constant drainage pressure should be adopted in the case of stress-sensitive effects, and coal with a lower cleat compression coefficient and Poisson's ratio value is better for higher gas production. The production contribution from each layer can be acquired if a specific production rate is set. If the reservoir pressure difference between the two reservoirs is too high (for instance at least > 3 MPa in the cases studied in this work), gas and water intrusion may happen, but the reservoirs would be balanced quickly. Thus, the coproduction of coalbed methane and tight gas from one well bore is feasible, and more work should be conducted on proposing a proper drainage strategy to improve the gas resource recovery efficiency in coal-bearing strata.",18,19,5
Tight Sandstone,Natural Fractures,"Song, Zhaojie; Hou, Jirui; Liu, Xiaochun; Wei, Qi; Hao, Hongda; Zhang, Liya",Conformance control for CO2-EOR in naturally fractured low permeability oil reservoirs,CO2 flooding; Low permeability oil reservoir; Gas channeling; CO2 production control,CARBON-DIOXIDE; CO2 STORAGE; TIGHT OIL; RECOVERY; GAS; PERFORMANCE; IMPROVEMENT,"Poor sweep efficiency seriously limits field applications of CO2-EOR, especially in fractured reservoirs. The investigation of CO2 production performance and the method to control CO2 production becomes a key to successfully run a CO2-EOR project. In this study, artificial sandstone cores were used to perform a series of CO2 flooding experiments at reservoir conditions of pressure, temperature and formation water salinity. Injection pressure and rock heterogeneity were taken into account to study their effect on CO2 production performance. Two-stage gas channeling control with three different scenarios, including PLS gel and ethylenediamine, starch gel and ethylenediamine, and starch gel and CO2 foam, was presented to improve the conformance in 3-D fractured-core models. Based on production performance and experimental observation, three production stages were clearly stated, including gas-free production stage, oil/gas co-production stage, and gas channeling stage. Oil/ gas co-production stage contributed the most to oil recovery. This finding was very consistent with the practical production performance of CO2 flooding in oil fields. The conformance improvement and the increase in injection pressure (within permissible range bearing in mind of fracturing pressure) could remarkably enhance the oil recovery at oil/gas co-production stage. In 3-D radial flow experiments, the two-stage gas channeling control presented great potential in delaying gas production and improving CO2 flooding efficiency. The combination of starch gel and ethylenediamine achieved the best result. The starch gel could effectively block the fracture, while the viscous reactant of ethylenediamine and in-situ CO2 within high permeability layer could successfully tune injected CO2 to flood low permeability layer. This study could help field engineers determine the optimal timing of CO2 production control, and also offered an optimal method to improve the conformance for CO2-EOR.",17,17,8
Tight Sandstone,Natural Fractures,"Liu, Jingshou; Ding, Wenlong; Wang, Ruyue; Yang, Haimeng; Wang, Xinghua; Li, Ang",Methodology for quantitative prediction of fracture sealing with a case study of the lower Cambrian Niutitang Formation in the Cen'gong block in South China,Fracture sealing; Shale reservoir; Paleotectonic stress field; Lower Cambrian; Cen'gong block,PALEOTECTONIC STRESS-FIELDS; SHALE-GAS; PRESERVATION CONDITIONS; CRUSTAL DEFORMATION; NATURAL FRACTURES; NORTHERN GUIZHOU; BASIN; RESERVOIRS; SIMULATION; DEPRESSION,"Industrial levels of shale gas have been produced from the Niutitang Formation in the lower Cambrian of the Cen'gong block, South China. The practice of exploration and development of shale gas in the Cen'gong block shows that the abundance of gas in different layers and wells is closely related to the degree of development of fractures. In this study, data obtained from outcrops, cores, and thin sections from the Cen'gong block were used to determine the development characteristics of such natural fractures. Combined with the analysis of burial history and fluid inclusions, the stress fields during three periods (the Yanshanian period, Himalayan period and neotectonic period) are suspected to play a critical role in fracture sealing. The paleotectonic stress tensor is determined using fault activity analysis, acoustic emission tests, and burial history. The magnitude and direction of current in situ stresses are determined by drilling-induced fractures, deviated well information, and cross multipole array acoustic (XMAC) logging. Under the constraints of XMAC logging interpretation and mechanical experiments, the spatial distribution of mechanical parameters is obtained by seismic inversion, and 3D heterogeneous geomechanical models are established using a finite element method (FEM). Then, the fracture density, reactivity, and aperture are identified. The results show that the magnitudes of the maximum horizontal principal stress during the Yanshanian period, the Himalayan period, and the neotectonic period are 150-170 MPa, 110-130 MPa, and 35-45 MPa, respectively. Using the fracture sealing calculation model, the fracture sealing that developed in the Himalayan period is the worst, the fracture sealing that developed in the Yanshanian period is intermediate, and the fracture sealing that developed in the neotectonic period is the best. Based on three-dimensional heterogeneous geomechanical modeling and tectonic stress evolution estimates, the fracture sealing calculation model proposed in this paper can be widely used in the evaluation of the preservation conditions of shale reservoirs, tight sandstone reservoirs and low-permeability reservoirs in complex tectonic areas.",14,15,2
Tight Sandstone,Relative Permeability,"Wang, Xiukun; Sheng, James J.",Pore network modeling of the Non-Darcy flows in shale and tight formations,Pore network modeling; Non-darcy flow; Tight; Shale; Relative permeability,STEP-DECAY MEASUREMENTS; GAS-FLOW; CARBON NANOTUBES; PETROPHYSICAL INTERPRETATION; RELATIVE PERMEABILITY; NANOPORES; SLIPPAGE; RESERVOIRS; TRANSPORT; OIL,"Pore network modeling is a powerful tool to simulate multiphase flow in porous media. Quasi-static model is used in this work and the drainage displacement process is simulated. In shale and tight formations, there are proposed non-Darcy flow mechanisms: gas non-Darcy flow and liquid low velocity non-Darcy flow. The gas flow in shale and tight formations is generally classified in slip flow and transitional flow regimes according to the Knudsen number values. The BK model (Beskok and Karniadakis, 1999) is used for gas non-Darcy flow in this study and the liquid low velocity non-Darcy flow is mainly based on our previous work (Wang and Sheng, 2017a, b). Both effects are incorporated into our pore network model separately. For gas-water flow, gas is the non-wetting phase with gas non-Darcy flow and water is the wetting phase with Darcy flow. For oil-water flow, the low velocity non-Darcy flow is considered for both water and oil phases. Then our model is applied in 3 cases. Case 1 is the Berea sandstone (Valvatne, 2004), which is the benchmark for conventional pore network modeling. In this case, no non-Darcy flows is considered in our pore network model and it is totally Darcy flow. The absolute permeability and relative permeability are both matched with the experimental data. Case 2 is the Bossier tight gas sandstone (Rushing et al., 2003). Gas apparent permeability vs. pressure was measured at different water saturations in their experiments. In this way, the gas non-Darcy flow in two-phase conditions are verified. Case 3 is the Barnett shale (Moghaddam and Jamiolahmady, 2016), which is our major focus. The two types of non-Darcy flows are studied and further discussed in this case. Specifically, the effect of gas non-Darcy flow enhances the gas permeability 2.66 times of the Darcy permeability when pressure is 10 MPa, while the effect of liquid low velocity non-Darcy flow decreases the liquid permeability to 40% of the Darcy permeability when pressure gradient is 0.1 MPa/m. Two types of relative permeability (k(r)) definition are presented in this study: Darcy permeability based kr and normalized k(r) where non-Darcy permeability is used as the base permeability. In the results, the normalized relative permeability doesn't change much for both non-Darcy flows, which implies that we can probably assume the relative permeability unchanged and just consider the effect on absolute permeability, when we deal with these non-Darcy flow mechanisms.",23,24,2
Tight Sandstone,Relative Permeability,"Cao, Zhe; Liu, Guangdi; Meng, Wei; Wang, Peng; Yang, Chengyu",Origin of different chlorite occurrences and their effects on tight clastic reservoir porosity,Chlorite occurrence; Porosity; Hydrodynamic; Bernoulli's theory; Diagenesis,ANOMALOUSLY HIGH-POROSITY; GRAIN-COATING CHLORITE; GAS-FIELD; NORPHLET FORMATION; CLAY-MINERALS; SANDSTONES; DIAGENESIS; BASIN; EVOLUTION; PERMEABILITY,"The effects of chlorite on tight sandstone reservoirs have not been fully understood yet. In this paper, two different chlorite occurrences are observed in the Upper Triassic Xujiahe tight sandstones of Guang'an Area, Sichuan Basin (grain coating) and in the Permian Lucaogou tight sandstones of Jimusar Sag, Junggar Basin (pore filling), respectively. The effects these two chlorite occurrences having on reservoir quality are evaluated. Results show the influence of chlorite on porosity of tight clastic reservoir depends on its occurrences. Grain-coating chlorite has positive effect on porosity preservation, while pore-filling chlorite plays a negative role. Analysis of grain size indicates that grain-coating and pore-filling chlorites always occur in high-energy and low-energy environments, respectively. The water current carries an abundance of medium-grained saltating contents in strong hydrodynamic tractive current environment that leads to a relative motion between the saltating population and suspended clay in water. As indicated by Bernoulli's theory, the saltating grains are coated by clay on the surface because of the local flow pressure resulting from relative velocity. However, in the case of a weak hydrodynamic tractive current depositional environment, sand is entrained with clay, i.e., both sand grains and clays are in suspension and they have no relative velocity; thus, the clay cannot completely coat the grain surface. As the precursor of chlorite, occurrence of smectite-dominant clays determines the occurrence of chlorite during diagenesis, and therefore, determines whether the chlorite has a positive effect on porosity of tight clastic reservoirs.",21,23,3
Tight Sandstone,Relative Permeability,"Meng, Shangzhi; Li, Yong; Wang, Lei; Wang, Kai; Pan, Zhejun",A mathematical model for gas and water production from overlapping fractured coalbed methane and tight gas reservoirs,Coproduction; Coalbed methane; Tight gas; Interference phenomenon; Unconventional natural gas coproduction,RELATIVE PERMEABILITY; NATURAL-GAS; ORDOS BASIN; WELL TEST; CHINA; ACCUMULATIONS; ADSORPTION; SIMULATION; GEOLOGY; STRATA,"With the continuous expansion, exploration and development of unconventional natural gas resources, mainly coalbed methane, shale gas and tight gas, some areas overlapped by two or three types of unconventional natural gas reservoirs are explored, e.g., the Linxing, Shilou and Linfen blocks located in the east margin of the Ordos Basin, China. Gas extraction from an individual reservoir becomes not economic as gas resources are not fully recovered; thus, gas coproduction from two or multiple layers is an effective method for improving gas production. In this work, a mathematical model of gas and water two-phase flow for the coproduction of coalbed methane and tight gas is developed. The adsorption characteristics, stress-sensitive and matrix shrinkage effects on coal permeability, and the stress-sensitive effect of tight sandstone are all considered in the model. The gas production related parameters, such as bottom hole flowing pressure, reservoir pressure differences, reservoir properties (e.g., permeability, cleat compressibility of coal, and Langmuir isotherm parameters) are discussed and compared with different geological conditions. The results show that the gas and water flow from the coalbed and sandstone reservoirs show no interference between each other under a constant pressure drainage system; the sandstone reservoirs show a fast pressure drawdown with a high gas production rate decline, while the coalbed reservoir is slow in pressure drawdown and the gas production rate increases gradually. The properties of a specific reservoir have a great influence on its own gas production performance, but with no influence on the other reservoirs. It was found that a lower constant drainage pressure should be adopted in the case of stress-sensitive effects, and coal with a lower cleat compression coefficient and Poisson's ratio value is better for higher gas production. The production contribution from each layer can be acquired if a specific production rate is set. If the reservoir pressure difference between the two reservoirs is too high (for instance at least > 3 MPa in the cases studied in this work), gas and water intrusion may happen, but the reservoirs would be balanced quickly. Thus, the coproduction of coalbed methane and tight gas from one well bore is feasible, and more work should be conducted on proposing a proper drainage strategy to improve the gas resource recovery efficiency in coal-bearing strata.",18,19,5
Tight Sandstone,Relative Permeability,"Ren, Xiaoxia; Li, Aifen; Fu, Shuaishi; Wang, Shoulong",Experimental study on the oil-water relative permeability relationship for tight sandstone considering the nonlinear seepage characteristics,Tight sandstone; Oil-water relative permeability; Unsteady-state method; Nonlinear flow; JBN,,"Oil-water relative permeability is an important parameter to describe the oil-water two-phase flow in oil reservoirs. The permeability rules for oil-water flow in tight sandstone reservoirs do not exactly follow the Darcy law due to its tight lithology and small pore-throat. In addition, the relative permeability curve obtained from traditional processing methods cannot accurately describe the seepage characteristics for this type of oil reservoirs, and therefore, may lead to unreasonable evaluation and prediction of productivity. In this work, the reservoir conditions are simulated and the test for oil (S-wc) flow of tight sandstone has been carried out. Additionally, the relative permeability curve of water-oil displacement in unsteady state has also been obtained. When the oil (S-wc) gets through the tight sandstone sample, the relationship between the flow velocity and the pressure gradient is not a straight line. In addition, the flow velocity and pressure gradient satisfy the equation of nu = k/mu(o)del P(1-1/a+b del P). The traditional JBN method is improved considering the nonlinear seepage characteristics, and the data processing method of oil-water relative permeability for tight sandstone reservoirs is established. Compared with the traditional JBN method, the oil-phase relative permeability, as calculated using the JBN method with the consideration of nonlinearity, is found to be higher. The results also show that the equal permeability point of has moved towards the right.",16,18,2
Tight Sandstone,Nuclear Magnetic Resonance,"Wang, Xixin; Hou, Jiagen; Song, Suihong; Wang, Dongmei; Gong, Lei; Ma, Ke; Liu, Yuming; Li, Yongqiang; Yan, Lin",Combining pressure-controlled porosimetry and rate-controlled porosimetry to investigate the fractal characteristics of full-range pores in tight oil reservoirs,Tight oil reservoir; Pore size distributions; Fractal characteristics; Mineral composition; Mercury intrusion porosimetry,NUCLEAR-MAGNETIC-RESONANCE; PERMIAN LUCAOGOU FORMATION; SIZE DISTRIBUTION; ORDOS BASIN; SONGLIAO BASIN; GAS SANDSTONES; JUNGGAR BASIN; JIMUSAER SAG; DIMENSION; SHALE,"Tight oil reservoirs have the characteristics of wide pore size range and complex pore system. The understanding of pore characteristics is the basis for studying the accumulation and migration of oil and gas. To better study the fractal characteristics of full-range pores in Lucaogou tight oil reservoir, scanning electron microscopy (SEM) and mercury intrusion porosimetry (MIP) were used to obtain the pore size. XRD was used to obtain the mineral composition. In addition, fractal analysis was performed on the samples based on MIP data. The results show fracture pore (FP), residual interparticle pore (RIP), dissolution pore (DP) and clay dominated pore (CDP) are the main pore types. The interparticle pores is commonly largest in size, followed by dissolution pores. Quartz and feldspar play dominant roles in the composition in Lucaogou tight oil reservoir. The full-range pore size distribution (PSD) curves ranged from 3.6 nm to 400 mu m with two main distribution intervals. The fractal dimensions (D-1, D-2 and D-3) reflect the complexity of CDPs, DPs and RIPs, respectively. The average values of fractal dimensions were 2.88, 2.8 and 2.56, the smaller pores have more complex pore system. The pore structure of clay dominated pores is most complex. The more complex the pore structure, the worse the reservoir performance. Quartz shows negative correlation with D-3, Clay shows positive correlation with D-1, and feldspar is positively correlated with D-2. D-1, D-2 and D-3 are negatively correlated to porosity, D-1 shows a strong negative correlation with permeability.",68,70,6
Tight Sandstone,Nuclear Magnetic Resonance,"Huang, Hexin; Sun, Wei; Ji, Wenming; Zhang, Ronghui; Du, Kun; Zhang, Shaohua; Ren, Dazhong; Wang, Youwei; Chen, Lei; Zhang, Xi","Effects of pore-throat structure on gas permeability in the tight sandstone reservoirs of the Upper Triassic Yanchang formation in the Western Ordos Basin, China",Yanchang formation tight sandstone; Permeability; Movable fluid porosity; Nuclear magnetic resonance; Constant-rate mercury injection,SIZE DISTRIBUTIONS; CAPILLARY-PRESSURE; MERCURY INTRUSION; NMR; SHALE; CONDUCTIVITY; PREDICTION; QUALITY,"The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.",48,48,7
Tight Sandstone,Nuclear Magnetic Resonance,"Wu, Hao; Zhang, Chunlin; Ji, Youliang; Liu, Ruie; Wu, Heng; Zhang, Yunzhao; Geng, Zhi; Zhang, Yilou; Yang, Jiaqi",An improved method of characterizing the pore structure in tight oil reservoirs: Integrated NMR and constant-rate-controlled porosimetry data,Tight sandstone; Pore structure; Nuclear magnetic resonance; Constant-rate-controlled porosimetry; Permeability prediction,NUCLEAR-MAGNETIC-RESONANCE; TRIASSIC YANCHANG FORMATION; MERCURY INTRUSION POROSIMETRY; MISSISSIPPIAN BARNETT SHALE; FORMATION CHANG 7; ORDOS BASIN; PERMEABILITY ESTIMATION; SIZE DISTRIBUTIONS; THROAT STRUCTURE; GAS-ADSORPTION,"Tight oil reservoirs have an ultrafine pore structure with a large heterogeneity, which requires the integration of multiple techniques to characterize pore structure characteristics systematically and, therefore, to gain a better understanding of reservoir quality. Tight oil sandstone samples from the Upper Triassic Yanchang Formation in the Ordos basin were measured by nuclear magnetic resonance (NMR), constant-rate-controlled mercury porosimetry (CMP) and field emission scanning electron microscopy (FE-SEM) to investigate the pore structure characteristics and their control on petrophysical properties. Various types of pores from intergranular pores, dissolution pores, and intercrystalline pores to small microfractures occurred in the studied tight sandstones, which indicates that the NMR T-2 distributions may be unimodal or bimodal in behaviour with a wide range. The short components of the T-2 distributions match the CMP-derived throat size distributions regarding the dimensions, width and shape of the curves. We combined CMP and NMR to uncover the total pore size distribution; the size distributions of the throat and pore body range from 0.01 to 1 mu m and from 0.1 mu m to tens of microns respectively, which match the FE-SEM results. The pore body-to-throat ratio may be the important factor affecting the free water saturation in the pore body, which, in turn, is probably associated with the mineralogy of tight sandstones, in particular, the quartz, feldspar and clay mineral contents. The pore radius of 0.3-0.5 mu m is the percolation threshold. The seepage porosity rather than total porosity overwhelmingly dominates the permeability, which, in turn, relates to the pore types, i. e., mesopores and macropores. An improved permeability prediction model is presented for tight oil reservoirs based on the contribution from different pore size intervals to the permeability. This model has a distinctly better performance than the classic models such as the Timur-Coates and SDR models and may be generalized to other similar reservoirs with ultrafine pore structures and significant volumes of clay minerals.",35,39,3
Tight Sandstone,Nuclear Magnetic Resonance,"Krakowska, P.; Puskarczyk, E.; Jedrychowski, M.; Habrat, M.; Madejski, P.; Dohnalik, M.",Innovative characterization of tight sandstones from Paleozoic basins in Poland using X-ray computed tomography supported by nuclear magnetic resonance and mercury porosimetry,Computed X-ray tomography; Tight sandstones; Nuclear magnetic resonance; Mercury porosimetry; Semivariograms,RESERVOIR PROPERTIES; SOURCE ROCKS; USEFUL TOOL; MICROTOMOGRAPHY; PERMEABILITY; GENERATION; MODELS,"Computed X-ray tomography, nuclear magnetic resonance spectroscopy and mercury porosimetry are key experimental methods for detailed pore space characterization of low porosity and low permeability rocks. Calculations dedicated to bones parametrization were carried out and tested on tight sandstones in order to get the quantitative information about pore space structure. Innovative approach in estimating pore throat diameter is introduced based on best-fit ellipsoid's radiuses. Application of semivariogram for pores location allows assessing the heterogeneity in pore space structure. Sphericity determined based on enclosed volume and surface area is a more creditable parameter in comparison to parameter reflecting the pore roundness calculated from moments of inertia. Undeniable CT advantage is a possibility to perform 3D pore space visualization what confirmed the usefulness of quantitative parameters. New software poROSE was presented as porous materials examination software for images qualitative and quantitative interpretation.",24,26,4
Tight Sandstone,Mercury Injection,"Huang, Hexin; Sun, Wei; Ji, Wenming; Zhang, Ronghui; Du, Kun; Zhang, Shaohua; Ren, Dazhong; Wang, Youwei; Chen, Lei; Zhang, Xi","Effects of pore-throat structure on gas permeability in the tight sandstone reservoirs of the Upper Triassic Yanchang formation in the Western Ordos Basin, China",Yanchang formation tight sandstone; Permeability; Movable fluid porosity; Nuclear magnetic resonance; Constant-rate mercury injection,SIZE DISTRIBUTIONS; CAPILLARY-PRESSURE; MERCURY INTRUSION; NMR; SHALE; CONDUCTIVITY; PREDICTION; QUALITY,"The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474-2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.",48,48,7
Tight Sandstone,Mercury Injection,"Wang, Ruifei; Chi, Yungang; Zhang, Lei; He, Runhua; Tang, Zhixia; Liu, Zheng","Comparative studies of microscopic pore throat characteristics of unconventional super-low permeability sandstone reservoirs: Examples of Chang 6 and Chang 8 reservoirs of Yanchang Formation in Ordos Basin, China",Constant-rate mercury injection; Ordos Basin; Pore throat characteristic parameters; Super-low permeability sandstone reservoir; Yanchang Formation,TIGHT GAS; CAPILLARY-PRESSURE; POROSITY; OIL; DIAGENESIS; CLASSIFICATION; EXPLORATION; FACIES; IMPACT; SIZES,"It's difficult to evaluate the unconventional super-low permeability sandstone reservoir by conventional mercury injection test. In order to evaluate this kind of reservoir more efficiently, in this study, we mainly measure the microscopic pore throat characteristic parameters and the curves of the reservoir by constant-rate mercury injection test, such as the average pore radius, average throat radius, pore throat radius ratio, maximum throat radius and other parameters. The reservoir characteristic curves include the pore radius distribution, throat radius distribution, pore throat radius ratio, and capillary pressure. Samples of tight sandstone in typical blocks from the Chang 6 and Chang 8 reservoirs were analyzed by a constant-rate mercury injection test to determine the differences in microscopic pore throat characteristics of unconventional super-low permeability sandstone oil reservoirs in the Yanchang formation of the Ordos Basin. According to the comprehensive classification results of PetroChina, a current super-low permeability reservoir can be classified as super-low permeability class I: 0.5 mD <= K <= 1.0 mD, super-low permeability class II: 0.3 mD <= K < 0.5 mD, and super-low permeability class III: 0.1 mD <= K < 0.3 mD (Yang and Fu, 2012). Firstly, the results of a constant-rate mercury injection test in the study area are classified and compared. Secondly, for the same class of reservoirs, the differences of microscopic pore throat characteristics in different blocks of the reservoir groups are analyzed separately. Thirdly, the microscopic pore throat characteristics between the Chang 6 and Chang 8 reservoir of the same class are analyzed. The analysis of blocks belonging to the same class of reservoir shows that in the Chang 6 reservoir the Xin'anbian block is superior to the Huaqing block, and the Huaqing block is superior to the Heshui block. In the Chang 8 reservoir, the Xifeng block is superior to the Huaqing block in classes I and II, and the Jiyuan block is superior to the Heshui block in class III. Between the Chang 6 and Chang 8 reservoirs, we found that the Chang 8 reservoir is dominant in class I reservoirs; the Chang 6 reservoir is slightly superior to the Chang 8 reservoir in class II, and the Chang 8 reservoir is better than the Chang 6 reservoir in class III.",26,27,5
Tight Sandstone,Mercury Injection,"Liu, Hangyu; Tian, Zhongyuan; Liu, Bo; Guo, Rui; Yang, Di; Deng, Ya; Yu, Yichang; Shi, Kaibo","Pore types, origins and control on reservoir heterogeneity of carbonate rocks in Middle Cretaceous Mishrif Formation of the West Qurna oilfield, Iraq",Pore types; Pore origins; Reservoir heterogeneity; Carbonates; Mishrif Formation; West Qurna oilfield,SOUTHERN MESOPOTAMIAN BASIN; RUDIST-BEARING CARBONATES; TIGHT SANDSTONES; ARABIAN GULF; CLASSIFICATION; SEQUENCE; FEATURES; GENESIS; SPACE,"Carbonates in Upper Cretaceous Mishrif Formation of the West Qurna oilfield in Iraq are characterized by complicated rocks and pores types, and strong heterogeneity. Based on the cores and cast thin sections of three wells, pore types were identified, and pore origins were analyzed from the perspective of sedimentary and diagenesis features. Porosity and permeability measurement, and high pressure mercury injection capillary pressure tests were conducted to determine the relationships between pores and reservoir heterogeneity. Six types of pores are identified, and they are intragranular pores, moldic pores, residual moldic pores, intergranular pores, micropores and intercrystal pores. The pore origins were controlled by the sedimentary environments and diagenesis. Pore types were controlled by lime mud contents, bioclastic textures, types and abundance that were controlled by sedimentary environments. Pore occurrence was determined by various diagenesis, while pore occurrence was mainly attributed to dissolution, which was influenced by the mineral composition of bioclastics. In addition, pores were altered by micritization, cementation and compaction. Results from the comparison of reservoir parameters show that the reservoir physical properties and pore structure of the each dominant pore type are similar. The study proves that reservoir characteristics are controlled by dominant pore types and reveals that pore type is a crucial cause for strong reservoir heterogeneity of carbonates.",16,19,0
Tight Sandstone,Strain Energy Density,"Yin, Shuai; Zhao, Jingzhou; Wu, Zhonghu; Ding, Wenlong",Strain energy density distribution of a tight gas sandstone reservoir in a low-amplitude tectonic zone and its effect on gas well productivity: A 3D FEM study,Strain energy density; Tight gas sandstone; Paleotectonic stress field; Productivity,IN-SITU STRESS; ORDOS BASIN; TARIM BASIN; NUMERICAL-SIMULATION; FRACTURE SYSTEM; PERMIAN STRATA; HANCHENG BLOCK; EASTERN MARGIN; TAZHONG AREA; COAL-BED,"The tight gas sandstone reservoirs in the Paleozoic of the Sulige gas field in China are highly heterogeneous, and fractures are key factors for stable reservoir production. Low-amplitude folds or nose-like structures are widely developed in the Upper Paleozoic strata in this area. To effectively predict gas well productivity, in this paper, a 3D FEM numerical simulation based on the deformation and energy variation of the rock mass was used to predict the "" sweet spots"" of gas well productivity in a tight gas sandstone reservoir using the He8 segment of the Middle Permian Xiashihezi Formation in the Central Sulige block as an example. The paleotectonic stress field of the study area during the maximum episode of compression in the Yanshanian movement was restored, and the two rupture parameters of the integrated rupture rate (IF) and strain energy density (U) were constructed. The strain energy density distribution has a high correlation with gas well productivity, indicating that it can better predict the rock rupture degree in low-amplitude tectonic zones. A complex relationship exists between the strain energy density distribution and low-amplitude folds. The high strain energy density zones are mainly distributed among the high positions and wing areas of the low-amplitude fold zone, but the top area of the low-amplitude fold does not necessarily have a high strain energy density. Portions of the high strain energy density zones are located in the gentle tectonic zone, located near but outside the low-amplitude fold zone. The strain energy in these gentle tectonic zones with a high strain energy density value is relatively high, and the rock mass is prone to rupture. This study is of great value in enriching the prediction of "" sweet spots"" in tight gas sandstone reservoirs in low-amplitude tectonic zones worldwide.",54,54,1
Tight Sandstone,Strain Energy Density,"Feng, Jianwei; Ren, Qiqiang; Xu, Ke","Quantitative prediction of fracture distribution using geomechanical method within Kuqa Depression, Tarim Basin, NW China",3D tectonic stress field; Tectonic fractures prediction; Geomechanical model; Super-deep tight sandstone; Top-popup fold,TECTONIC STRESS-FIELD; FAULT-BEND FOLDS; NUMERICAL-SIMULATION; PORE PRESSURE; MODELS; EVOLUTION; PROVINCE; ZONES; ACCUMULATION; RESERVOIRS,"Understanding and predicting the development and distribution of tectonic fractures in the super-deep tight sandstone reservoir are important for both gas exploration and exploitation activities in Kuqa Depression. We analyzed the characteristics of regional structural evolution and paleotectonic stress field setting. A reasonable geological model of the research area was built based on an interpretation of the geological structure, a test for rock mechanics, and experiment on acoustic emission. Thereafter, a three-dimensional paleotectonic stress field during the Late Himalayan movement was simulated by the finite element method. Composite rock failure criterion and geomechanical models between fracture density, aperture, strike and strain energy density were used to determine the quantitative development of fractures and predict zones that are prone to fracture development. Areas with well-developed tectonic fractures are mainly controlled by the tectonic stress field and elastic strain energy density, typically located in the fold limbs, fault zones and locations of changes in the orientation of fault. In turn, factors of faults, the lithology, depth and curvature control the development and distribution of tectonic fractures in the tight sandstone. The overall simulated results match well with core observation and FMI (Formation MicroScanner Image) results both in the whole geometry and fracture distribution. This evolutionary model of the structures present to us is a distinct and intuitive top-popup fold with low amplitude and relatively low-density fractures in the top, has only experienced pre-folding stage and strong folding stage, and has not yet been developed to vertical uplift stage.",23,26,6
Tight Sandstone,Hydraulic Fracture,"Li, Yuwei; Yang, Shuai; Zhao, Wanchun; Li, Wei; Zhang, Jun",Experimental of hydraulic fracture propagation using fixed-point multistage fracturing in a vertical well in tight sandstone reservoir,Tight sandstone reservoir; Fixed-point multistage fracturing; Fracture propagation; Fracture geometry,HIGHLY DEVIATED WELL; SHALE GAS-RESERVOIRS; LABORATORY EXPERIMENTS; ORIENTED PERFORATION; INITIATION PRESSURE; BEHAVIOR; NETWORKS; VOLUME; ROCK,"Fixed-point multistage fracturing can effectively increase the stimulated reservoir volume (SRV) in tight sand-stone reservoir. In different geological and engineering conditions, how to explain the geometric form of fracture propagation in fixed-point multistage fracturing has not been reported yet, and the propagation mechanism of hydraulic fracture is ambiguous. To clarify this mechanism, fourteen large-scale triaxial tests were deployed in this study to investigate the fracture propagation behavior in fixed-point multistage fracturing, and the influences of various factors on fracture geometries were studied. The results show that there are six types of fractures in the horizontal plane when the fixed-point multistage fracturing are carried out in a vertical well in tight sandstone reservoir: bi-wing planar fracture; bi-wing non-planar fracture; L-type fracture; X-type fracture; biwing turning fracture and re-orientation turning fracture. Fixed-point multistage fracturing can increase the SRV mainly because it is equivalent to carry out refracturing in the reservoir, so it can form a complex fracture system similar to refracturing. The research proves that it is difficult to form a complex fracture system through the fixed-point of multistage fracturing when the stress difference is more than 6 MPa in the horizontal direction. The fracturing fluid injection rate has an obvious effect on the formation of multi-fractures, and the multi-fracture can not form when the injection rate is too large. The enhancement of rock heterogeneity will lead to more energy consumption in fracturing process, which is not conducive to the initiation and propagation of fractures. Therefore, the in-situ stress, rock heterogeneity, injection rate and other factors should be comprehensive considered when designing the fixed-point multistage fracturing scheme for vertical well in tight sandstone reservoir.",47,51,5
Tight Sandstone,Hydraulic Fracture,"Chen, Zhiqiang; Yang, Zhengming; Wang, Moran",Hydro-mechanical coupled mechanisms of hydraulic fracture propagation in rocks with cemented natural fractures,Hydraulic fracture; Cemented fracture; Natural fracture; LBM-DEM,LATTICE-BOLTZMANN METHOD; GENERAL SHAPES; BARNETT SHALE; FLUID-FLOW; PERMEABILITY; MODEL; DISCONTINUITIES; CRITERION,"Natural fractures commonly exist in unconventional reservoirs such as shale and tight gas sandstone, which are mostly cemented (or sealed) with minerals and not able to contribute to reservoir storage or rock permeability. However, during hydraulic fracture stimulation, these cemented natural fractures will be encountered and influence hydraulic fracture geometry greatly and, thereby, gas production. In this work, hydraulic fracture propagation in rock with cemented natural fracture is investigated using our recently developed and validated hydromechanical coupled LBM-DEM model. The numerical results show that both the strength ratio (between cemented natural fracture and host rock) and the approach angle (between hydraulic and cemented natural fracture) significantly affect the hydraulic fracture propagation. A larger strength contrast or a smaller approach angle will be more conducive to deflection, which is consistent with experimental observation. For rocks with weakly cemented natural fractures, deflection is mainly caused by shear failure in weakly cemented fracture. However, for rocks with strongly cemented natural fractures, deflection happens accompanying with tensile failure in host rock along the cement wall, which cannot be captured by the previous numerical models where the cemented natural fracture is treated as a bonded interface. In addition, complex fracture network is more easily formed if multiple weakly cemented natural fractures are orthogonal to the hydraulic fracture propagation direction.",31,32,3
Tight Sandstone,Migration,"Wang, Xixin; Hou, Jiagen; Song, Suihong; Wang, Dongmei; Gong, Lei; Ma, Ke; Liu, Yuming; Li, Yongqiang; Yan, Lin",Combining pressure-controlled porosimetry and rate-controlled porosimetry to investigate the fractal characteristics of full-range pores in tight oil reservoirs,Tight oil reservoir; Pore size distributions; Fractal characteristics; Mineral composition; Mercury intrusion porosimetry,NUCLEAR-MAGNETIC-RESONANCE; PERMIAN LUCAOGOU FORMATION; SIZE DISTRIBUTION; ORDOS BASIN; SONGLIAO BASIN; GAS SANDSTONES; JUNGGAR BASIN; JIMUSAER SAG; DIMENSION; SHALE,"Tight oil reservoirs have the characteristics of wide pore size range and complex pore system. The understanding of pore characteristics is the basis for studying the accumulation and migration of oil and gas. To better study the fractal characteristics of full-range pores in Lucaogou tight oil reservoir, scanning electron microscopy (SEM) and mercury intrusion porosimetry (MIP) were used to obtain the pore size. XRD was used to obtain the mineral composition. In addition, fractal analysis was performed on the samples based on MIP data. The results show fracture pore (FP), residual interparticle pore (RIP), dissolution pore (DP) and clay dominated pore (CDP) are the main pore types. The interparticle pores is commonly largest in size, followed by dissolution pores. Quartz and feldspar play dominant roles in the composition in Lucaogou tight oil reservoir. The full-range pore size distribution (PSD) curves ranged from 3.6 nm to 400 mu m with two main distribution intervals. The fractal dimensions (D-1, D-2 and D-3) reflect the complexity of CDPs, DPs and RIPs, respectively. The average values of fractal dimensions were 2.88, 2.8 and 2.56, the smaller pores have more complex pore system. The pore structure of clay dominated pores is most complex. The more complex the pore structure, the worse the reservoir performance. Quartz shows negative correlation with D-3, Clay shows positive correlation with D-1, and feldspar is positively correlated with D-2. D-1, D-2 and D-3 are negatively correlated to porosity, D-1 shows a strong negative correlation with permeability.",68,70,6
Tight Sandstone,Migration,"Zhang, Yongchao; Zeng, Jianhui; Dai, Zhenxue; Viswanathan, Hari; Xiao, Ting; Ma, Yong; Feng, Xiao",Experimental investigation on oil migration and accumulation in tight sandstones,Tight sandstone; Tight oil; Migration and accumulation; Apparent permeability; Minimum migration pressure gradient; Terminal oil saturation,TRIASSIC YANCHANG FORMATION; RESERVOIR QUALITY PREDICTION; FORMATION CHANG 7; ORDOS BASIN; LOW PERMEABILITY; SECONDARY MIGRATION; BOUNDARY-LAYER; GAS MIGRATION; ENTRAPMENT; DIAGENESIS,"This study presents an experimental investigation to simulate and analyze the physical processes of oil migration and accumulation with 19 tight sandstone cores. Characteristic curves of oil migration were obtained by using the experimental results. It shows that the curve variations were mainly influenced by two factors: the permeability of the core and the viscosity of the injected oil. Based on the experimental results, we introduced three important parameters to quantitatively characterize and determine the processes of oil migration and accumulation in tight sandstones. The apparent permeability was introduced to describe the level of oil migration during experiments. The minimum migration pressure gradient (MMPG) and the terminal oil saturation were proposed to evaluate the features of the beginning and final stages of the migration, respectively. The relationships between MMPG, terminal oil saturation and mobility were analyzed, all showed strong linear relationships in the double logarithmic coordinate system. Furthermore, a prediction map of tight oil accumulation was plotted according to the measured oil saturation data, which could be used for estimating the scale and size of oil accumulation in tight reservoirs. The concepts and results in this study provide valuable insight for understanding and quantitatively analyzing the processes of oil migration and accumulation in tight sandstones.",19,19,5
Tight Sandstone,"Oil Saturation,Formation Chang 7","Wu, Hao; Zhang, Chunlin; Ji, Youliang; Liu, Ruie; Wu, Heng; Zhang, Yunzhao; Geng, Zhi; Zhang, Yilou; Yang, Jiaqi",An improved method of characterizing the pore structure in tight oil reservoirs: Integrated NMR and constant-rate-controlled porosimetry data,Tight sandstone; Pore structure; Nuclear magnetic resonance; Constant-rate-controlled porosimetry; Permeability prediction,NUCLEAR-MAGNETIC-RESONANCE; TRIASSIC YANCHANG FORMATION; MERCURY INTRUSION POROSIMETRY; MISSISSIPPIAN BARNETT SHALE; FORMATION CHANG 7; ORDOS BASIN; PERMEABILITY ESTIMATION; SIZE DISTRIBUTIONS; THROAT STRUCTURE; GAS-ADSORPTION,"Tight oil reservoirs have an ultrafine pore structure with a large heterogeneity, which requires the integration of multiple techniques to characterize pore structure characteristics systematically and, therefore, to gain a better understanding of reservoir quality. Tight oil sandstone samples from the Upper Triassic Yanchang Formation in the Ordos basin were measured by nuclear magnetic resonance (NMR), constant-rate-controlled mercury porosimetry (CMP) and field emission scanning electron microscopy (FE-SEM) to investigate the pore structure characteristics and their control on petrophysical properties. Various types of pores from intergranular pores, dissolution pores, and intercrystalline pores to small microfractures occurred in the studied tight sandstones, which indicates that the NMR T-2 distributions may be unimodal or bimodal in behaviour with a wide range. The short components of the T-2 distributions match the CMP-derived throat size distributions regarding the dimensions, width and shape of the curves. We combined CMP and NMR to uncover the total pore size distribution; the size distributions of the throat and pore body range from 0.01 to 1 mu m and from 0.1 mu m to tens of microns respectively, which match the FE-SEM results. The pore body-to-throat ratio may be the important factor affecting the free water saturation in the pore body, which, in turn, is probably associated with the mineralogy of tight sandstones, in particular, the quartz, feldspar and clay mineral contents. The pore radius of 0.3-0.5 mu m is the percolation threshold. The seepage porosity rather than total porosity overwhelmingly dominates the permeability, which, in turn, relates to the pore types, i. e., mesopores and macropores. An improved permeability prediction model is presented for tight oil reservoirs based on the contribution from different pore size intervals to the permeability. This model has a distinctly better performance than the classic models such as the Timur-Coates and SDR models and may be generalized to other similar reservoirs with ultrafine pore structures and significant volumes of clay minerals.",35,39,3
Tight Sandstone,"Oil Saturation,Formation Chang 7","Zhang, Yongchao; Zeng, Jianhui; Dai, Zhenxue; Viswanathan, Hari; Xiao, Ting; Ma, Yong; Feng, Xiao",Experimental investigation on oil migration and accumulation in tight sandstones,Tight sandstone; Tight oil; Migration and accumulation; Apparent permeability; Minimum migration pressure gradient; Terminal oil saturation,TRIASSIC YANCHANG FORMATION; RESERVOIR QUALITY PREDICTION; FORMATION CHANG 7; ORDOS BASIN; LOW PERMEABILITY; SECONDARY MIGRATION; BOUNDARY-LAYER; GAS MIGRATION; ENTRAPMENT; DIAGENESIS,"This study presents an experimental investigation to simulate and analyze the physical processes of oil migration and accumulation with 19 tight sandstone cores. Characteristic curves of oil migration were obtained by using the experimental results. It shows that the curve variations were mainly influenced by two factors: the permeability of the core and the viscosity of the injected oil. Based on the experimental results, we introduced three important parameters to quantitatively characterize and determine the processes of oil migration and accumulation in tight sandstones. The apparent permeability was introduced to describe the level of oil migration during experiments. The minimum migration pressure gradient (MMPG) and the terminal oil saturation were proposed to evaluate the features of the beginning and final stages of the migration, respectively. The relationships between MMPG, terminal oil saturation and mobility were analyzed, all showed strong linear relationships in the double logarithmic coordinate system. Furthermore, a prediction map of tight oil accumulation was plotted according to the measured oil saturation data, which could be used for estimating the scale and size of oil accumulation in tight reservoirs. The concepts and results in this study provide valuable insight for understanding and quantitatively analyzing the processes of oil migration and accumulation in tight sandstones.",19,19,5
Tight Sandstone,Microscope,"Wang, Ruifei; Chi, Yungang; Zhang, Lei; He, Runhua; Tang, Zhixia; Liu, Zheng","Comparative studies of microscopic pore throat characteristics of unconventional super-low permeability sandstone reservoirs: Examples of Chang 6 and Chang 8 reservoirs of Yanchang Formation in Ordos Basin, China",Constant-rate mercury injection; Ordos Basin; Pore throat characteristic parameters; Super-low permeability sandstone reservoir; Yanchang Formation,TIGHT GAS; CAPILLARY-PRESSURE; POROSITY; OIL; DIAGENESIS; CLASSIFICATION; EXPLORATION; FACIES; IMPACT; SIZES,"It's difficult to evaluate the unconventional super-low permeability sandstone reservoir by conventional mercury injection test. In order to evaluate this kind of reservoir more efficiently, in this study, we mainly measure the microscopic pore throat characteristic parameters and the curves of the reservoir by constant-rate mercury injection test, such as the average pore radius, average throat radius, pore throat radius ratio, maximum throat radius and other parameters. The reservoir characteristic curves include the pore radius distribution, throat radius distribution, pore throat radius ratio, and capillary pressure. Samples of tight sandstone in typical blocks from the Chang 6 and Chang 8 reservoirs were analyzed by a constant-rate mercury injection test to determine the differences in microscopic pore throat characteristics of unconventional super-low permeability sandstone oil reservoirs in the Yanchang formation of the Ordos Basin. According to the comprehensive classification results of PetroChina, a current super-low permeability reservoir can be classified as super-low permeability class I: 0.5 mD <= K <= 1.0 mD, super-low permeability class II: 0.3 mD <= K < 0.5 mD, and super-low permeability class III: 0.1 mD <= K < 0.3 mD (Yang and Fu, 2012). Firstly, the results of a constant-rate mercury injection test in the study area are classified and compared. Secondly, for the same class of reservoirs, the differences of microscopic pore throat characteristics in different blocks of the reservoir groups are analyzed separately. Thirdly, the microscopic pore throat characteristics between the Chang 6 and Chang 8 reservoir of the same class are analyzed. The analysis of blocks belonging to the same class of reservoir shows that in the Chang 6 reservoir the Xin'anbian block is superior to the Huaqing block, and the Huaqing block is superior to the Heshui block. In the Chang 8 reservoir, the Xifeng block is superior to the Huaqing block in classes I and II, and the Jiyuan block is superior to the Heshui block in class III. Between the Chang 6 and Chang 8 reservoirs, we found that the Chang 8 reservoir is dominant in class I reservoirs; the Chang 6 reservoir is slightly superior to the Chang 8 reservoir in class II, and the Chang 8 reservoir is better than the Chang 6 reservoir in class III.",26,27,5
Tight Sandstone,Microscope,"Du, Shuheng; Pang, Shan; Shi, Yongmin",Quantitative characterization on the microscopic pore heterogeneity of tight oil sandstone reservoir by considering both the resolution and representativeness,"""Umbrella deconstruction"" method; Microscopic heterogeneity; Tight oil reservoir",MICRO-CT; COAL; POROSITY; SIZE,"This study aimed to raise the new experiment method named ""umbrella deconstruction"" to reveal the microscopic pore heterogeneity of tight oil sandstone reservoir by considering both the resolution and representativeness. Based on the FE-SEM and image processing technology, parameters like porosity, the ratio of the maximum to the minimum of pore orientation frequency, the content of cement, the ratio of the maximum to the minimum of cement orientation frequency and the fractal dimension of reservoir space could be applied into the microscopic heterogeneity characterization. The final imaging observation scale could reach approximately 20 mm (which is 10 times CT observation scale), the precision can reach 10 nm (almost equal to the CT observation resolution). This method would help to the research work in the microscopic heterogeneity characterization of unconventional reservoir.",20,25,5
Tight Sandstone,Apparent Permeability,"Wang, Xiukun; Sheng, James J.",Pore network modeling of the Non-Darcy flows in shale and tight formations,Pore network modeling; Non-darcy flow; Tight; Shale; Relative permeability,STEP-DECAY MEASUREMENTS; GAS-FLOW; CARBON NANOTUBES; PETROPHYSICAL INTERPRETATION; RELATIVE PERMEABILITY; NANOPORES; SLIPPAGE; RESERVOIRS; TRANSPORT; OIL,"Pore network modeling is a powerful tool to simulate multiphase flow in porous media. Quasi-static model is used in this work and the drainage displacement process is simulated. In shale and tight formations, there are proposed non-Darcy flow mechanisms: gas non-Darcy flow and liquid low velocity non-Darcy flow. The gas flow in shale and tight formations is generally classified in slip flow and transitional flow regimes according to the Knudsen number values. The BK model (Beskok and Karniadakis, 1999) is used for gas non-Darcy flow in this study and the liquid low velocity non-Darcy flow is mainly based on our previous work (Wang and Sheng, 2017a, b). Both effects are incorporated into our pore network model separately. For gas-water flow, gas is the non-wetting phase with gas non-Darcy flow and water is the wetting phase with Darcy flow. For oil-water flow, the low velocity non-Darcy flow is considered for both water and oil phases. Then our model is applied in 3 cases. Case 1 is the Berea sandstone (Valvatne, 2004), which is the benchmark for conventional pore network modeling. In this case, no non-Darcy flows is considered in our pore network model and it is totally Darcy flow. The absolute permeability and relative permeability are both matched with the experimental data. Case 2 is the Bossier tight gas sandstone (Rushing et al., 2003). Gas apparent permeability vs. pressure was measured at different water saturations in their experiments. In this way, the gas non-Darcy flow in two-phase conditions are verified. Case 3 is the Barnett shale (Moghaddam and Jamiolahmady, 2016), which is our major focus. The two types of non-Darcy flows are studied and further discussed in this case. Specifically, the effect of gas non-Darcy flow enhances the gas permeability 2.66 times of the Darcy permeability when pressure is 10 MPa, while the effect of liquid low velocity non-Darcy flow decreases the liquid permeability to 40% of the Darcy permeability when pressure gradient is 0.1 MPa/m. Two types of relative permeability (k(r)) definition are presented in this study: Darcy permeability based kr and normalized k(r) where non-Darcy permeability is used as the base permeability. In the results, the normalized relative permeability doesn't change much for both non-Darcy flows, which implies that we can probably assume the relative permeability unchanged and just consider the effect on absolute permeability, when we deal with these non-Darcy flow mechanisms.",23,24,2
Tight Sandstone,Apparent Permeability,"Zhang, Yongchao; Zeng, Jianhui; Dai, Zhenxue; Viswanathan, Hari; Xiao, Ting; Ma, Yong; Feng, Xiao",Experimental investigation on oil migration and accumulation in tight sandstones,Tight sandstone; Tight oil; Migration and accumulation; Apparent permeability; Minimum migration pressure gradient; Terminal oil saturation,TRIASSIC YANCHANG FORMATION; RESERVOIR QUALITY PREDICTION; FORMATION CHANG 7; ORDOS BASIN; LOW PERMEABILITY; SECONDARY MIGRATION; BOUNDARY-LAYER; GAS MIGRATION; ENTRAPMENT; DIAGENESIS,"This study presents an experimental investigation to simulate and analyze the physical processes of oil migration and accumulation with 19 tight sandstone cores. Characteristic curves of oil migration were obtained by using the experimental results. It shows that the curve variations were mainly influenced by two factors: the permeability of the core and the viscosity of the injected oil. Based on the experimental results, we introduced three important parameters to quantitatively characterize and determine the processes of oil migration and accumulation in tight sandstones. The apparent permeability was introduced to describe the level of oil migration during experiments. The minimum migration pressure gradient (MMPG) and the terminal oil saturation were proposed to evaluate the features of the beginning and final stages of the migration, respectively. The relationships between MMPG, terminal oil saturation and mobility were analyzed, all showed strong linear relationships in the double logarithmic coordinate system. Furthermore, a prediction map of tight oil accumulation was plotted according to the measured oil saturation data, which could be used for estimating the scale and size of oil accumulation in tight reservoirs. The concepts and results in this study provide valuable insight for understanding and quantitatively analyzing the processes of oil migration and accumulation in tight sandstones.",19,19,5
Tight Sandstone,Coal,"Du, Shuheng; Pang, Shan; Shi, Yongmin",Quantitative characterization on the microscopic pore heterogeneity of tight oil sandstone reservoir by considering both the resolution and representativeness,"""Umbrella deconstruction"" method; Microscopic heterogeneity; Tight oil reservoir",MICRO-CT; COAL; POROSITY; SIZE,"This study aimed to raise the new experiment method named ""umbrella deconstruction"" to reveal the microscopic pore heterogeneity of tight oil sandstone reservoir by considering both the resolution and representativeness. Based on the FE-SEM and image processing technology, parameters like porosity, the ratio of the maximum to the minimum of pore orientation frequency, the content of cement, the ratio of the maximum to the minimum of cement orientation frequency and the fractal dimension of reservoir space could be applied into the microscopic heterogeneity characterization. The final imaging observation scale could reach approximately 20 mm (which is 10 times CT observation scale), the precision can reach 10 nm (almost equal to the CT observation resolution). This method would help to the research work in the microscopic heterogeneity characterization of unconventional reservoir.",20,25,5
Tight Sandstone,Coal,"Meng, Shangzhi; Li, Yong; Wang, Lei; Wang, Kai; Pan, Zhejun",A mathematical model for gas and water production from overlapping fractured coalbed methane and tight gas reservoirs,Coproduction; Coalbed methane; Tight gas; Interference phenomenon; Unconventional natural gas coproduction,RELATIVE PERMEABILITY; NATURAL-GAS; ORDOS BASIN; WELL TEST; CHINA; ACCUMULATIONS; ADSORPTION; SIMULATION; GEOLOGY; STRATA,"With the continuous expansion, exploration and development of unconventional natural gas resources, mainly coalbed methane, shale gas and tight gas, some areas overlapped by two or three types of unconventional natural gas reservoirs are explored, e.g., the Linxing, Shilou and Linfen blocks located in the east margin of the Ordos Basin, China. Gas extraction from an individual reservoir becomes not economic as gas resources are not fully recovered; thus, gas coproduction from two or multiple layers is an effective method for improving gas production. In this work, a mathematical model of gas and water two-phase flow for the coproduction of coalbed methane and tight gas is developed. The adsorption characteristics, stress-sensitive and matrix shrinkage effects on coal permeability, and the stress-sensitive effect of tight sandstone are all considered in the model. The gas production related parameters, such as bottom hole flowing pressure, reservoir pressure differences, reservoir properties (e.g., permeability, cleat compressibility of coal, and Langmuir isotherm parameters) are discussed and compared with different geological conditions. The results show that the gas and water flow from the coalbed and sandstone reservoirs show no interference between each other under a constant pressure drainage system; the sandstone reservoirs show a fast pressure drawdown with a high gas production rate decline, while the coalbed reservoir is slow in pressure drawdown and the gas production rate increases gradually. The properties of a specific reservoir have a great influence on its own gas production performance, but with no influence on the other reservoirs. It was found that a lower constant drainage pressure should be adopted in the case of stress-sensitive effects, and coal with a lower cleat compression coefficient and Poisson's ratio value is better for higher gas production. The production contribution from each layer can be acquired if a specific production rate is set. If the reservoir pressure difference between the two reservoirs is too high (for instance at least > 3 MPa in the cases studied in this work), gas and water intrusion may happen, but the reservoirs would be balanced quickly. Thus, the coproduction of coalbed methane and tight gas from one well bore is feasible, and more work should be conducted on proposing a proper drainage strategy to improve the gas resource recovery efficiency in coal-bearing strata.",18,19,5
Multiphase Flow,Porous Media,"Xie, Chiyu; Lv, Weifeng; Wang, Moran",Shear-thinning or shear-thickening fluid for better EOR? - A direct pore-scale study,Multiphase flow; Non-Newtonian fluid; Diversion effect; Lattice Boltzmann method; Porous media; Enhanced Oil Recovery (EOR),ENHANCED OIL-RECOVERY; POROUS-MEDIA; FOAM; FLOW; POLYMERS; SWEEP; FIELD,"Non-Newtonian fluids are widely applied in Enhanced Oil Recovery (EOR) techniques, and the good performances have been ascribed to the shear-thinning or shear-thickening characteristics of them. In this paper, we aim at discovering the roles of these rheological properties in non-Newtonian fluid displacement from the pore scale. A recently developed lattice Boltzmann model (LBM) for multiphase viscoplastic fluid flow [ Xie et al. J Non-Newton Fluid, 2016.234: 118-128] is used. Displacements in both homogeneous and heterogeneous porous media are considered. For homogeneous cases, the performances of shear-thinning and shear-thickening fluids are almost the same when compared in favorable displacement regime; while the performance of shear-thinning fluid is poorer than that of shear-thickening fluid in unfavorable displacement regime. For heterogeneous cases, we demonstrate that the shear-thinning property does not contribute too much to the diversion effect, which clarifies the debate of understandings. Our pore-scale modeling results also indicate the significance of low viscosity ratio for diversion and EOR, which can stabilize the displacing front despite of the increased viscous resistance.",31,31,4
Multiphase Flow,Porous Media,"Wang, Xiukun; Sheng, James J.",Pore network modeling of the Non-Darcy flows in shale and tight formations,Pore network modeling; Non-darcy flow; Tight; Shale; Relative permeability,STEP-DECAY MEASUREMENTS; GAS-FLOW; CARBON NANOTUBES; PETROPHYSICAL INTERPRETATION; RELATIVE PERMEABILITY; NANOPORES; SLIPPAGE; RESERVOIRS; TRANSPORT; OIL,"Pore network modeling is a powerful tool to simulate multiphase flow in porous media. Quasi-static model is used in this work and the drainage displacement process is simulated. In shale and tight formations, there are proposed non-Darcy flow mechanisms: gas non-Darcy flow and liquid low velocity non-Darcy flow. The gas flow in shale and tight formations is generally classified in slip flow and transitional flow regimes according to the Knudsen number values. The BK model (Beskok and Karniadakis, 1999) is used for gas non-Darcy flow in this study and the liquid low velocity non-Darcy flow is mainly based on our previous work (Wang and Sheng, 2017a, b). Both effects are incorporated into our pore network model separately. For gas-water flow, gas is the non-wetting phase with gas non-Darcy flow and water is the wetting phase with Darcy flow. For oil-water flow, the low velocity non-Darcy flow is considered for both water and oil phases. Then our model is applied in 3 cases. Case 1 is the Berea sandstone (Valvatne, 2004), which is the benchmark for conventional pore network modeling. In this case, no non-Darcy flows is considered in our pore network model and it is totally Darcy flow. The absolute permeability and relative permeability are both matched with the experimental data. Case 2 is the Bossier tight gas sandstone (Rushing et al., 2003). Gas apparent permeability vs. pressure was measured at different water saturations in their experiments. In this way, the gas non-Darcy flow in two-phase conditions are verified. Case 3 is the Barnett shale (Moghaddam and Jamiolahmady, 2016), which is our major focus. The two types of non-Darcy flows are studied and further discussed in this case. Specifically, the effect of gas non-Darcy flow enhances the gas permeability 2.66 times of the Darcy permeability when pressure is 10 MPa, while the effect of liquid low velocity non-Darcy flow decreases the liquid permeability to 40% of the Darcy permeability when pressure gradient is 0.1 MPa/m. Two types of relative permeability (k(r)) definition are presented in this study: Darcy permeability based kr and normalized k(r) where non-Darcy permeability is used as the base permeability. In the results, the normalized relative permeability doesn't change much for both non-Darcy flows, which implies that we can probably assume the relative permeability unchanged and just consider the effect on absolute permeability, when we deal with these non-Darcy flow mechanisms.",23,24,2
Multiphase Flow,Porous Media,"Smal, Pavel; Gouze, Philippe; Rodriguez, Olivier",An automatic segmentation algorithm for retrieving sub-resolution porosity from X-ray tomography images,X-ray microtomography; Porosity estimation; Sub-resolution porosity; Multiphase segmentation,CARBONATE ROCKS; PORE-SCALE; POROUS-MEDIA; FLOW PROPERTIES; TRANSPORT; MICROTOMOGRAPHY; DISSOLUTION; LIMESTONE; MULTISCALE; SYSTEMS,"X-ray computed tomography is a nondestructive technique often used in geosciences to obtain a threedimensional representation of the pore space geometry that will be used for running fluid dynamic simulations. However, rocks often display a very large distribution of pore sizes and consequently pores of size smaller than the X-ray tomography resolution. Not taking such pores into account leads to incorrect calculations of petrophysical properties of rock, therefore the problem of characterizing sub-resolution porosity is identified as a critical issue for geosciences applications. In this paper we propose a new algorithm that allows localization and quantification of sub-resolution porosity. The proposed algorithm can operate in two modes: one of them could be considered as a multi-phase segmentation and could be applied for a variety of X-ray tomography image segmentation tasks; whereas second modification gives better porosity estimation. The algorithm is applied to two images. Good quality image is processed with automatic choice of parameters and without preprocessing. Image of lower quality is processed with preprocessing and manual choice of parameters. In both cases, the computed porosity fits reasonably well with the laboratory measured porosity.",18,18,0
Multiphase Flow,Porous Media,"Alpak, Faruk; Samardzic, Aleksandar; Frank, Florian",A distributed parallel direct simulator for pore-scale two-phase flow on digital rock images using a finite difference implementation of the phase-field method,Phase-field method; Pore-scale two-phase flow; Digital rock; Finite difference method (FDM); Computational fluid dynamics (CFD),DIFFUSE-INTERFACE MODEL; MOVING-CONTACT-LINE; DISSIPATIVE PARTICLE DYNAMICS; OF-FLUID METHOD; POROUS-MEDIA; LEVEL-SET; NONUNIFORM SYSTEM; FREE-ENERGY; SHEAR-FLOW; IRREVERSIBLE-PROCESSES,"The phase-field method is a versatile and robust technique for modeling interfacial motion in multiphase flows in pore-scale media. The method provides an effective way to account for surface effects by use of diffuse interfaces. The resulting model significantly simplifies the numerical implementation of mass transport and momentum balance solvers for simulating two-phase flow with a large number of moving interfaces. The thermodynamically consistent governing equations minimize the Helmholtz free energy, leading to formation, transport, and/or destruction of interfaces. The phase-field method accurately conserves mass and is relatively straightforward to implement in conjunction with contact-angle models that account for wettability on rock surfaces. The underlying free-energy minimization framework leads to the advective Cahn-Hilliard equation and modified Navier-Stokes equations that form the phase-field model. We have implemented a particular variant of the phase-field method (PFM) into the computational core of a pore-scale multiphase flow simulator, namely PMFS-PFM, for the numerical simulations of incompressible flow of two immiscible fluid phases. The implementation was discussed in a previous paper for rectangular prism-shaped fully-connected domains, e. g., for simulating two-phase flow in a 2D slit or a 3D duct (Alpak et al., 2016). In this paper, we discuss the recent developments on PMFS-PFM. The main components of the new work are (I) implementation of support for inactive cells that model the solid parts of a rock by extending the original finite difference method (FDM) based discretizations of the underlying partial differential equations (PDEs) in order to solve realistic 3D pore-scale flow problems on rock volumes stemming from imaging, and (II) enhancing the performance of the simulator through implementation of modern sparse linear solvers and distributed parallel computing. It has been shown that the simulations performed on complex pore-scale domains are consistent with the physics of the immiscible two-phase displacement. The parallel scalability of the code is reasonably well varying between 50% and 86% for the investigated test cases of different complexity. Results indicate that the more disconnected the pore-scale domains are, the lower is the parallel efficiency. It has been noted that there is a possibility of improving the parallel efficiency by exploring various grid subdivisions.",16,16,3
Multiphase Flow,Porous Media,"Yan, Bicheng; Mi, Lidong; Chai, Zhi; Wang, Yuhe; Killough, John E.",An Enhanced Discrete Fracture Network model for multiphase flow in fractured reservoirs,Multiphase flow; Fractured reservoirs; Reservoir modeling; EDFN,NUMERICAL-SIMULATION; SHALE GAS; BEHAVIOR; BLOCKS,"We present an Enhanced Discrete Fracture Network (EDFN) model for multiphase flow simulation in fractured reservoirs. EDFN can efficiently represent complex fractured porous media and accurately simulate fluid exchange between matrix and fracture. By using EDFN the fracture network is discretized with minimum number of grids based on the fracture intersecting points and fracture extremities. The matrix is also optimally decomposed into coarse blocks with different geometries using a rapid image processing algorithm. Each coarse matrix block is designed to be associated with one fracture grid and then discretized logarithmically to handle 1D flow between matrix and fracture. EDFN can greatly optimize the discretization for fractured porous media to conform interconnected fractures of arbitrary orientations. Via unstructured format, EDFN is successfully linked with an in-house unstructured compositional simulator. We validate the accuracy of EDFN through a number of multiphase flow simulations in fractured porous media with/without considering capillary pressure. Its efficiency is demonstrated to be superior by using a much less grid blocks comparing with other approaches. Ultimately EDFN is applied to predict hydrocarbon production in a shale oil reservoir and it enables to capture multi-scale fluid transfer in such complex system.",15,15,3
Multiphase Flow,Wellbore,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Han, Song; Liu, Qing; Liu, Wenyuan",Type curve analysis of multi-phase flow of multi-component thermal fluid in toe-point injection horizontal wells considering phase change,Heavy oil recovery; Phase change; Toe-point injection horizontal wells; Non-condensing gases; Superheated state; Saturated state,HEAVY OIL-RECOVERY; SUPERHEATED-STEAM INJECTION; 2-PHASE FLOW; PERFORMANCE ANALYSIS; NONCONDENSING GASES; GRAVITY DRAINAGE; KEY PARAMETERS; HOT-WATER; WELLBORE; MODEL,"Huge amount of works were done on modeling of wet steam flow in the conventional heel-point injection horizontal wellbores. With the rapid development of technology, new technology of superheated steam - non-condensing gases (SNG) injection coupled with toe-point injection wellbores was adopted in oil field. In this paper, a series of works were done on modeling of SNG flow in a horizontal wellbore with toe-point injection technique. The two-phase flow model was embedded in this SNG model for describing the phase change phenomenon. Firstly, a hydraulics model comprised of mass, momentum and energy conservation equations was developed. Then, coupled with the seepage model in oil layer, a wellbore/formation coupled model was established. Thirdly, straight forward numerical method was adopted to solve the model. Finally, model verification and sensitivity analysis were conducted sequentially. Results show that: (1) The SNG temperature in annuli has an increase at the heel-point due to heat conduction from IT to annuli. (2) When the mass injection rate is kept unchanged, the SNG temperature at a certain place in annuli decreases with increasing of the mass content of non-condensing gases. (3) The SNG in IT undergoes phase change into saturated state at the distance of 150 m. Then, from the distance of 150 m-200 m, the gas content in the mixture system gets an increase and the superheat degree is equal to zero. (4) Phase change occurs again in annuli when the SNG reaches the distance of 110 m where the wet fluid turns into superheated state, after which the superheated degree of SNG increases continuously as SNG is flowing to the heel-point.",32,32,1
Multiphase Flow,Wellbore,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Chen, Zhili; Chang, Yucui; Cao, Meng; Han, Song; Chaohui, Iv; Feng, Dong; Sun, Zheng",Effect of Flowing Seawater on Supercritical CO2 - Superheated Water Mixture Flow in an Offshore Oil Well Considering the distribution of heat generated by the work of friction,Wellbore hydraulics; Effect of seawater; Supercritical CO2; Superheated water; CO2 sequestration; Heavy oil recovery,RAPID MULTIPHASE FLOW; STEAM INJECTION; HORIZONTAL WELLS; 2-PHASE FLOW; SEMIANALYTICAL MODEL; PERFORMANCE ANALYSIS; NONCONDENSING GASES; PRESSURE; RECOVERY; ADSORPTION,"The modeling of thermal fluid (mostly reported for saturated steam) flow in wells involving steady-state heat transfer inside wellbores and transient heat transfer in sea water or formation is reviewed and inherited. It is a good addition of modeling of supercritical/superheated fluid to the existing body of literature. The flow of supercritical CO2 coupled with superheated water (SHW) in offshore wells is described by means of the differential mass, energy and momentum balance equations along the vertical wellbores. The effect of supercritical CO2 on pressure and temperature of the multi-component thermal fluid is expressed in terms of the real gas model (the S-R-K model). The differential equations are solved with finite difference method on space involving the constant injection parameters at wellhead. It is found out that: (a). while seawater has a significant influence on temperature drop in wellbores, its effect on pressure profiles is weak. (b). both temperature and superheat degree decrease with increasing of the content of supercritical CO2. Besides, study of the effect of injection rate and pressure is conducted.",30,30,1
Multiphase Flow,Wellbore,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Li, Xiangfang; Chen, Mingqiang; Chen, Gang; Zhang, Tao",Analysis of superheated steam performance in offshore concentric dual-tubing wells,Offshore Wellbore modeling; Energy balance; Superheated steam; Concentric dual-tubing wells; Enthalpy data,HEAT-TRANSFER CHARACTERISTICS; MULTICOMPONENT THERMAL FLUID; 2-PHASE FLOW; OIL-RECOVERY; HORIZONTAL WELLS; NONCONDENSING GASES; SUPERCRITICAL CO2; MULTIPHASE FLOW; INJECTION WELLS; CURVE ANALYSIS,"Superheated steam (SHS) injection in concentric dual-tubing wells (CDTW) is a new technology for offshore heavy oil recovery. Firstly, compared with conventional saturated steam injection in single-tubing wells, the key advantages of SHS injection in CDTW for heavy oil recovery are introduced. Secondly, a novel mathematical model is proposed to analysis the heat transfer characteristics of SHS flow in offshore CDTW. Then, based upon the validated model, type curves of SHS flow in offshore CDTW are analyzed in detail. The results show that: (1). The heat exchange between the integral joint tubing (IJT) and annuli has a significant influence on SHS temperature and superheat degree in each tubing. (2). More heat get lost when the seawater starts to flow, and the heat loss rate in the sea section of the wellbores is larger than that in the formation section of the wellbores. Moreover, in order to flexibly use the model in practice, the key intrinsic flow characteristics of SHS in offshore CDTW are unraveled. It is found that: (1). The SHS temperature increases at first but turns to decrease with the continuous increase of injection rate due to the fact that the drop of SHS pressure gradually replaces heat losses as the dominant factor on temperature change. (2). The superheat degree at well bottom always increases with the increase of injection rate. This paper presents a basic reference for engineers in heat loss evaluations as well as performance estimations of SHS flow in offshore CDTW.",29,29,0
Multiphase Flow,Wellbore,"Sun, Xiaohui; Sun, Baojiang; Zhang, Shuai; Wang, Zhiyuan; Gao, Yonghai; Li, Hao",A new pattern recognition model for gas kick diagnosis in deepwater drilling,Pattern recognition; Drilling; Kick; Fault diagnosis; Probability,TIME; FRACTION; FLOW; OIL,"Early kick detection is important to reduce the possibility of well blowouts, which have serious safety and financial implications in deepwater drilling. In this paper, a novel pattern recognition model for kick diagnosis is proposed. In the model, trend detection is used to make good decisions based upon noisy drilling data. The integrated model comprises two parts: (i) a dynamic wellbore flow model, which extracts the kick mode via multiphase flow simulation; and (ii) improved piecewise approximation and similarity measure algorithms. The proposed model successfully diagnoses gas kick faults in real time when it is applied in a field well. It offers significant sensitivity improvements while reducing the false alarm rate caused by ambiguous data, as both kick and non-kick events are accurately extracted and rapidly identified. This model is a new attempt to combat the problem of early kick detection via pattern recognition.",22,22,2
Multiphase Flow,Multiphase Pump,"Shi, Yi; Zhu, Hongwu; Zhang, Jinya; Zhang, Jiate; Zhao, Junlin",Experiment and numerical study of a new generation three-stage multiphase pump,Helico-axial pump; Multiphase flow; Gas volume fraction; Computational fluid dynamics; Performance validation; Interphase drag force,IMPELLER,"Multiphase pump is a cost-effective option for subsea gas and oil fields development. The ability of handling different gas volume fractions with high rotational speed is necessary to optimize the operating performance of a multiphase pump. Thus meeting the demand for increasing gas and oil production of undersea wells especially for those brownfields. This study aims to validate the performance of a three-stage helico-axial multiphase pump with new designed impellers and high rotational speed in both single and two-phase experiments. Then establish a numerical analysis method to predict the pump performance and evaluate the characteristics of multiphase flow with high reliability by using commercial CFD packages. The design volume flowrate of the pump is 100 m(3)/h and rotational speed is 4500 rpm. The experiment results show that the highest efficiency is 45% in water condition at the design parameters. There is not much difference on the pump performance at low inlet gas volume fractions (GVF) such as 5% and 10%, which indicates that multi-stage pump can prevent large performance degradation at low inlet GVFs. Numerical simulations are implemented by solving the three-dimensional steady Reynolds-Averaged Navier-Stokes (RANS) equations. The effects of various turbulence models, wall roughness, gas bubble sizes and interphase drag models on the hydraulic performance of multiphase are investigated. The results show that the predicted performance with Shear Stress Transport (SST) turbulence model at the optimal conditions agree well with the experiment data. Wall roughness should be considered since it has a significant effect on pump efficiency. Gas bubble size varies according to different inlet GVFs and rotational speed. The in-situ alpha(g) is high in diffuser and it varies with different interphase drag force models. The reliability of the numerical analysis method is proven by comparing the numerical results and experiments data.",36,38,1
Multiphase Flow,Multiphase Pump,"Suh, Jun-Won; Kim, Jin-Woo; Choi, Young-Seok; Kim, Jin-Hyuk; Joo, Won-Gu; Lee, Kyoung-Yong",Development of numerical Eulerian-Eulerian models for simulating multiphase pumps,Helico-axial pump; Multiphase; Gas volume fraction; Interphase force; Numerical analysis; Performance validation,TURBULENCE MODELS; FLOW; VALIDATION; FORCE,"Multiphase pumps are now in high demand as a result of undersea wells. The resulting sharp increase in the demand for multiphase pumps has made it necessary to optimize the operating performance of these pumps. The primary shortcoming of multiphase flow transport technology is that the characteristics of the internal flow change according to the gas volume fraction (GVF). This research aimed to establish a numerical analysis method that is used commercial CFD packages to evaluate the multiphase flow with high reliability and proposes a numerical method to investigate the effect of different GVFs on the flow characteristics. An appropriate combination of bubble size, closure interphase force model, and coefficient of force acting on the interface between the water and air phases is important for predicting the performance of the multiphase flow. The reliability of the new numerical analysis method was proven by comparing the numerical and experimental results. A model pump was produced and the structural stability of the prototype was secured through an analysis according to the API610 11th standard (Modal, Pressure Load). The model pump was made by AL7075 and the experiment device is connected with a 150A SUS pipe flange. The error range of the reliability verification of the multi-phase flow was about 0.5-1.5% at the flow rate used in the design. The numerical results obtained for pressure performance generally corresponded to high reliability within the operating range. Advanced computational fluid dynamics based on the three-dimensional steady and unsteady Reynolds-averaged Navier-Stokes equations were solved to analyze the detailed dynamic flow phenomenon with various GVFs. The effects of various interphase forces acting between the liquid and gas phase such as drag, lift, virtual mass, wall lubrication and turbulent dispersion forces, and the diameter of bubbles in the gas phase on the hydraulic performance were investigated.",35,39,1
Multiphase Flow,Multiphase Pump,"Ma, Yi; Ni, Yang; Zhang, He; Zhou, Shuiqing; Deng, Hongying",Influence of valve's lag characteristic on pressure pulsation and performance of reciprocating multiphase pump,Multiphase pump; Computational fluid dynamics; Two-phase flow; Lag characteristic; Pressure pulsation,ELECTRICAL SUBMERSIBLE PUMP; FLUID-FLOW; NUMERICAL-SIMULATION; COMPRESSOR,"Reciprocating multiphase pump is the key equipment for the oil-gas transport technology in the petroleum industry. The opening and closing motions of suction and discharge valves directly affect the transport performance and stability of pump. In this paper, the whole working cycle of reciprocating multiphase pump is studied by using computational fluid dynamics (CFD) method. The combined actions of piston, suction and discharge valves are dealt with User Defined Functions and dynamic grid technique. Based on the instantaneous motions of valves, the lag characteristics of suction and discharge valves under different working conditions are analyzed. And the influences of lag angles on the pressure pulsation, P-V diagram and input power of the pump are further investigated. The results show that the lag angles have a significant impact on the internal and external characteristics of the reciprocating multiphase pump. Due to the most obvious opening lag angle of discharge valve, the pump pressures and PV diagram have the sudden fluctuations just after the end of compression process, which appear in the range of. 0=240.7 degrees-273.1 degrees for the initial condition. The gas volume fraction (GVF) plays more important role than the suction and discharge pressures in the working of reciprocating multiphase pump, and the opening lag angles of suction and discharge valves at GVF = 0.9 increase to more than 6 times at GVF = 0.1. By the comparisons of input power, the simulated results for reciprocating multiphase pump show good agreement with the results of prototype test. This study would provide a theoretical basis for the design of high-efficiency multiphase pump and valve.",16,19,6
Multiphase Flow,Enhanced Oil-recovery,"Xie, Chiyu; Lv, Weifeng; Wang, Moran",Shear-thinning or shear-thickening fluid for better EOR? - A direct pore-scale study,Multiphase flow; Non-Newtonian fluid; Diversion effect; Lattice Boltzmann method; Porous media; Enhanced Oil Recovery (EOR),ENHANCED OIL-RECOVERY; POROUS-MEDIA; FOAM; FLOW; POLYMERS; SWEEP; FIELD,"Non-Newtonian fluids are widely applied in Enhanced Oil Recovery (EOR) techniques, and the good performances have been ascribed to the shear-thinning or shear-thickening characteristics of them. In this paper, we aim at discovering the roles of these rheological properties in non-Newtonian fluid displacement from the pore scale. A recently developed lattice Boltzmann model (LBM) for multiphase viscoplastic fluid flow [ Xie et al. J Non-Newton Fluid, 2016.234: 118-128] is used. Displacements in both homogeneous and heterogeneous porous media are considered. For homogeneous cases, the performances of shear-thinning and shear-thickening fluids are almost the same when compared in favorable displacement regime; while the performance of shear-thinning fluid is poorer than that of shear-thickening fluid in unfavorable displacement regime. For heterogeneous cases, we demonstrate that the shear-thinning property does not contribute too much to the diversion effect, which clarifies the debate of understandings. Our pore-scale modeling results also indicate the significance of low viscosity ratio for diversion and EOR, which can stabilize the displacing front despite of the increased viscous resistance.",31,31,4
Multiphase Flow,Enhanced Oil-recovery,"Liang, Tianbo; Li, Qingguang; Liang, Xingyuan; Yao, Erdong; Wang, Yanqing; Li, Yuan; Chen, Mai; Zhou, Fujian; Lu, Jun",Evaluation of liquid nanofluid as fracturing fluid additive on enhanced oil recovery from low-permeability reservoirs,Fracturing fluid additive; EOR; Tight oil; Wettability alteration,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; GRAVITY DRAINAGE; HIGH-TEMPERATURE; WATER BLOCKING; SHALE; SURFACTANTS; WET; CARBONATES; SYSTEM,"Hydraulic fracturing creates a complex fracture network that makes the oil production from low-permeability reservoirs economical. However, significant amount of water is likely lost into the rock matrix during hydraulic fracturing. This can cause formation damage due to multiphase flow, thus hindering the oil production rate. Surfactants can alter rock wettability and/or reduce oil-water interfacial tension (IFT), and it has been proposed to be used to mitigate such water blockage and enhance oil recovery. Among different approaches of using surfactants, forming liquid nanofluid (LNF) can minimize the adsorption of surfactants on rock surface, and it is likely to be one of the best options for low-permeability rocks with extensive surface area. In this study, the key properties of a well-screened LNF are evaluated, and then compared with a commercial flowback surfactant (CFS) that is widely used in the field. Pressure transmission test is further applied, which can determine the change of rock permeability due to different fluids and the potential formation damage due to multiphase flow. A systematic evaluation method is thus established to screen fracturing fluid additives to enhance oil production from low-permeability reservoirs both effectively and efficiently.",24,28,4
Multiphase Flow,Enhanced Oil-recovery,"Qu, Ming; Hou, Jirui; Qi, Pengpeng; Zhao, Fenglan; Ma, Shixi; Churchwell, Lauren; Wang, Qian; Li, Hui; Yang, Tianyuan",Experimental study of fluid behaviors from water and nitrogen floods on a 3-D visual fractured-vuggy model,Carbonate reservoir; 3-D physical experiment; Fluid flow behavior; Water flooding; Gas flooding; Enhanced oil recovery,3-DIMENSIONAL PHYSICAL SIMULATION; CARBONATE RESERVOIRS; OIL; PERFORMANCE; INJECTION; RECOVERY; UNIT,"Tahe oil field is a fractured-vuggy carbonate oil field in China. The fluid flow behaviors in this type of reservoir are complex due to multiple flow paths through the matrix, fractures and vugs. The main challenges of production include complicated oil-water distributions, rising state of water cone in different flow units, unclear multiphase flow behaviors, and lack of understanding of the fluid flow mechanism. Based on a geological map of the Tahe oil field, a physical 3-D fractured-vuggy model was designed and fabricated. Water and gas flooding experiments were performed, while the multiphase flow behaviors were captured with a high-resolution camera system. The pressure response was also monitored at different oil displacement stages. The results show that the 3-D physical model can be used to systematically and comprehensively investigate the fluid flow behaviors during the oil displacement process. The oil-water interfaces of prolific wells rise more rapidly than that from the stripper wells, leading to an uneven distribution of internal flow fields and cross-well interferences. Water breaks through early and water channeling is more significant in fractured than vuggy wells. The oil-water flow behavior in fractured-vuggy combinations is mainly determined by fractured-vuggy structure, viscous force, wettability, and the ratio of displacement forces to gravity. During nitrogen gas flooding, gas caps occur from gas displacing the remaining oil at the top of the reservoir. The synergistic interaction between nitrogen gas and injected water contributes to additional oil recovery. This study provides a guide for improving production performance in fractured-vuggy carbonate reservoirs.",23,27,2
Multiphase Flow,Network Model,"Wang, Xiukun; Sheng, James J.",Pore network modeling of the Non-Darcy flows in shale and tight formations,Pore network modeling; Non-darcy flow; Tight; Shale; Relative permeability,STEP-DECAY MEASUREMENTS; GAS-FLOW; CARBON NANOTUBES; PETROPHYSICAL INTERPRETATION; RELATIVE PERMEABILITY; NANOPORES; SLIPPAGE; RESERVOIRS; TRANSPORT; OIL,"Pore network modeling is a powerful tool to simulate multiphase flow in porous media. Quasi-static model is used in this work and the drainage displacement process is simulated. In shale and tight formations, there are proposed non-Darcy flow mechanisms: gas non-Darcy flow and liquid low velocity non-Darcy flow. The gas flow in shale and tight formations is generally classified in slip flow and transitional flow regimes according to the Knudsen number values. The BK model (Beskok and Karniadakis, 1999) is used for gas non-Darcy flow in this study and the liquid low velocity non-Darcy flow is mainly based on our previous work (Wang and Sheng, 2017a, b). Both effects are incorporated into our pore network model separately. For gas-water flow, gas is the non-wetting phase with gas non-Darcy flow and water is the wetting phase with Darcy flow. For oil-water flow, the low velocity non-Darcy flow is considered for both water and oil phases. Then our model is applied in 3 cases. Case 1 is the Berea sandstone (Valvatne, 2004), which is the benchmark for conventional pore network modeling. In this case, no non-Darcy flows is considered in our pore network model and it is totally Darcy flow. The absolute permeability and relative permeability are both matched with the experimental data. Case 2 is the Bossier tight gas sandstone (Rushing et al., 2003). Gas apparent permeability vs. pressure was measured at different water saturations in their experiments. In this way, the gas non-Darcy flow in two-phase conditions are verified. Case 3 is the Barnett shale (Moghaddam and Jamiolahmady, 2016), which is our major focus. The two types of non-Darcy flows are studied and further discussed in this case. Specifically, the effect of gas non-Darcy flow enhances the gas permeability 2.66 times of the Darcy permeability when pressure is 10 MPa, while the effect of liquid low velocity non-Darcy flow decreases the liquid permeability to 40% of the Darcy permeability when pressure gradient is 0.1 MPa/m. Two types of relative permeability (k(r)) definition are presented in this study: Darcy permeability based kr and normalized k(r) where non-Darcy permeability is used as the base permeability. In the results, the normalized relative permeability doesn't change much for both non-Darcy flows, which implies that we can probably assume the relative permeability unchanged and just consider the effect on absolute permeability, when we deal with these non-Darcy flow mechanisms.",23,24,2
Multiphase Flow,Network Model,"Yan, Bicheng; Mi, Lidong; Chai, Zhi; Wang, Yuhe; Killough, John E.",An Enhanced Discrete Fracture Network model for multiphase flow in fractured reservoirs,Multiphase flow; Fractured reservoirs; Reservoir modeling; EDFN,NUMERICAL-SIMULATION; SHALE GAS; BEHAVIOR; BLOCKS,"We present an Enhanced Discrete Fracture Network (EDFN) model for multiphase flow simulation in fractured reservoirs. EDFN can efficiently represent complex fractured porous media and accurately simulate fluid exchange between matrix and fracture. By using EDFN the fracture network is discretized with minimum number of grids based on the fracture intersecting points and fracture extremities. The matrix is also optimally decomposed into coarse blocks with different geometries using a rapid image processing algorithm. Each coarse matrix block is designed to be associated with one fracture grid and then discretized logarithmically to handle 1D flow between matrix and fracture. EDFN can greatly optimize the discretization for fractured porous media to conform interconnected fractures of arbitrary orientations. Via unstructured format, EDFN is successfully linked with an in-house unstructured compositional simulator. We validate the accuracy of EDFN through a number of multiphase flow simulations in fractured porous media with/without considering capillary pressure. Its efficiency is demonstrated to be superior by using a much less grid blocks comparing with other approaches. Ultimately EDFN is applied to predict hydrocarbon production in a shale oil reservoir and it enables to capture multi-scale fluid transfer in such complex system.",15,15,3
Multiphase Flow,Supercritical CO2,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Chen, Zhili; Chang, Yucui; Cao, Meng; Han, Song; Chaohui, Iv; Feng, Dong; Sun, Zheng",Effect of Flowing Seawater on Supercritical CO2 - Superheated Water Mixture Flow in an Offshore Oil Well Considering the distribution of heat generated by the work of friction,Wellbore hydraulics; Effect of seawater; Supercritical CO2; Superheated water; CO2 sequestration; Heavy oil recovery,RAPID MULTIPHASE FLOW; STEAM INJECTION; HORIZONTAL WELLS; 2-PHASE FLOW; SEMIANALYTICAL MODEL; PERFORMANCE ANALYSIS; NONCONDENSING GASES; PRESSURE; RECOVERY; ADSORPTION,"The modeling of thermal fluid (mostly reported for saturated steam) flow in wells involving steady-state heat transfer inside wellbores and transient heat transfer in sea water or formation is reviewed and inherited. It is a good addition of modeling of supercritical/superheated fluid to the existing body of literature. The flow of supercritical CO2 coupled with superheated water (SHW) in offshore wells is described by means of the differential mass, energy and momentum balance equations along the vertical wellbores. The effect of supercritical CO2 on pressure and temperature of the multi-component thermal fluid is expressed in terms of the real gas model (the S-R-K model). The differential equations are solved with finite difference method on space involving the constant injection parameters at wellhead. It is found out that: (a). while seawater has a significant influence on temperature drop in wellbores, its effect on pressure profiles is weak. (b). both temperature and superheat degree decrease with increasing of the content of supercritical CO2. Besides, study of the effect of injection rate and pressure is conducted.",30,30,1
Multiphase Flow,Supercritical CO2,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Li, Xiangfang; Chen, Mingqiang; Chen, Gang; Zhang, Tao",Analysis of superheated steam performance in offshore concentric dual-tubing wells,Offshore Wellbore modeling; Energy balance; Superheated steam; Concentric dual-tubing wells; Enthalpy data,HEAT-TRANSFER CHARACTERISTICS; MULTICOMPONENT THERMAL FLUID; 2-PHASE FLOW; OIL-RECOVERY; HORIZONTAL WELLS; NONCONDENSING GASES; SUPERCRITICAL CO2; MULTIPHASE FLOW; INJECTION WELLS; CURVE ANALYSIS,"Superheated steam (SHS) injection in concentric dual-tubing wells (CDTW) is a new technology for offshore heavy oil recovery. Firstly, compared with conventional saturated steam injection in single-tubing wells, the key advantages of SHS injection in CDTW for heavy oil recovery are introduced. Secondly, a novel mathematical model is proposed to analysis the heat transfer characteristics of SHS flow in offshore CDTW. Then, based upon the validated model, type curves of SHS flow in offshore CDTW are analyzed in detail. The results show that: (1). The heat exchange between the integral joint tubing (IJT) and annuli has a significant influence on SHS temperature and superheat degree in each tubing. (2). More heat get lost when the seawater starts to flow, and the heat loss rate in the sea section of the wellbores is larger than that in the formation section of the wellbores. Moreover, in order to flexibly use the model in practice, the key intrinsic flow characteristics of SHS in offshore CDTW are unraveled. It is found that: (1). The SHS temperature increases at first but turns to decrease with the continuous increase of injection rate due to the fact that the drop of SHS pressure gradually replaces heat losses as the dominant factor on temperature change. (2). The superheat degree at well bottom always increases with the increase of injection rate. This paper presents a basic reference for engineers in heat loss evaluations as well as performance estimations of SHS flow in offshore CDTW.",29,29,0
Multiphase Flow,Slug Flow,"Archibong-Eso, A.; Baba, Y.; Aliyu, A.; Zhao, Y.; Yan, W.; Yeung, H.",On slug frequency in concurrent high viscosity liquid and gas flow,Multiphase flow; Slug frequency; Slug holdup; Slug film; Heavy oil; Pressure gradient,HORIZONTAL PIPES; 2-PHASE FLOW; OIL; PREDICTION; DIAMETER; MODEL,"Slug frequency is an important input parameter in most mechanistic and semi-mechanistic models used for estimating slug flow characteristics such as pressure gradient, slug length and slug holdup. It is also essential in the design and sizing of transport and/or production pipelines, process flow control, design and operation of process equipment, etc. This study experimentally investigates slug frequency in two horizontal pipelines with internal diameters (ID) of 0.0254 and 0.0764 m. Test liquids used in the study were mineral oil (with viscosity ranging from 1.0 to 4.0 Poise) and water while compressed air is the gas phase. Effects of liquid viscosity, gas superficial velocity, liquid superficial velocity, pipe internal diameter, pipe length and pressure gradient are discussed. Results indicate that slug frequency increased with increase in oil viscosity; decreased with increase in pipe diameter; and reduces along the length of the pipe. For gas Reynolds number, Re-SG <= 2500, slug frequency increased with increase in gas superficial velocity, when Re-SG > 2500, slug frequency decreased with increase in gas superficial velocity. A new slug frequency correlation that accounts for liquid viscosity and gas superficial velocity, hitherto not included in other correlations was proposed. A comparative analysis of the proposed models and existing slug frequency correlation on a high viscosity databank showed that the proposed correlation gave the best prediction with an average absolute percentage error (AAPE) of 19.91%.",17,17,0
Multiphase Flow,Slug Flow,"Saieed, Ahmed; Pao, William; Hewakandamby, Buddhika; Azzopardi, Barry J.; Wood, David A.; Ali, Hafiz M.",Experimental investigation on the effect of diameter ratio on two-phase slug flow separation in a T-Junction,T-junction; Slug flow; Gas-liquid separation; Diameter ratio,INCLINED BRANCH ARM; NUMERICAL-SIMULATION; STRATIFIED FLOW; PIPE TEE; SPLIT; MODEL,"T-junctions are often used in offshore platforms to partially separate gas from produced fluids. Poorly designed T-junctions frequently produce very high liquid (oil and/or water) carryovers, causing major issues to the downstream equipment train which is not designed to handle excessive liquid. This paper reports the liquid carryover experiments in T-junctions using five different side to main arm diameter ratios under slug flow regime. The obtained phase separation curves can be divided into two component variables; liquid-carryover threshold and peak liquid carryover. The experiments demonstrate that with a decrease in diameter ratio both of these variables decrease. Yet, for superior multiphase flow separation, a high liquid carryover threshold and a low peak liquid carryover are required. Hence, the generally accepted rule that a reduction in diameter ratio improves the phase separation is revealed to be an over-extrapolated statement. The novel findings of this work are: 1) for optimum flow splitting under slug flow conditions, the diameter ratio should be kept between 1 and 0.67, while the diameter ratio 0.67 was found to be most suitable; 2) two correlations were developed for predicting two-phase slug flow separation in different diameter ratio T-junctions. These correlations offer beneficial guidance and clarifications for a number of oil and gas flowline and pipeline applications.",15,15,0
Multiphase Flow,Water Flooding,"Xie, Quan; Sari, Ahmad; Pu, Wanfen; Chen, Yongqiang; Brady, Patrick V.; Al Maskari, Nasser; Saeedi, Ali",pH effect on wettability of oil/brine/carbonate system: Implications for low salinity water flooding,Carbonate reservoirs; Low salinity water; Wettability; Geochemical modelling; pH,SURFACE COMPLEXATION MODEL; IMPROVED OIL-RECOVERY; IMPACT; CHALK; CARBONATES; SANDSTONE; EOR,"Wettability of oil/brine/carbonate system is a critical parameter to govern subsurface multi-phase flow behaviour, thus remaining oil saturation and ultimate oil recovery in carbonate reservoirs. Despite the fact that salinity level, ionic strength, oil composition and rock chemistry (e.g., limestone and dolomite) have been extensively investigated, few work has been done regarding the effect of pH on oil/brine/rock interaction, thus wettability. We thereby measured contact angles at two different pH (pH = 3 and 8) in the presence of either 1 mol/L Na2SO4 or 1 mol/L CaCl2 using a crude oil with acid number of 1.7 and base number of 1.2 mg KOH/g. Moreover, we performed a geochemical modelling study in light of the diffuse double layer to understand how pH controls the number of surface species at interfaces of oil/brine and brine/carbonate. Our results show that pH scales with oil/brine/carbonate wettability, demonstrating that pH is one of the controlling factors to govern the system wettability. Further, our results suggest that pH (6.5-7.5) likely triggers an oil-wet system, which is favourable for low salinity water flooding, but pH < 5 usually exhibits a water-wet system, which explains why low salinity effect is not always observed in carbonate reservoirs. This also confirms that CO2 flooding, carbonated water flooding, and CO2 huff-and-puff FOR very likely renders a strongly water-wet system due to H+ adsorption on the interface of oil/brine and brine/carbonate as a result of CO2 dissolution.",43,43,2
Multiphase Flow,Water Flooding,"Qu, Ming; Hou, Jirui; Qi, Pengpeng; Zhao, Fenglan; Ma, Shixi; Churchwell, Lauren; Wang, Qian; Li, Hui; Yang, Tianyuan",Experimental study of fluid behaviors from water and nitrogen floods on a 3-D visual fractured-vuggy model,Carbonate reservoir; 3-D physical experiment; Fluid flow behavior; Water flooding; Gas flooding; Enhanced oil recovery,3-DIMENSIONAL PHYSICAL SIMULATION; CARBONATE RESERVOIRS; OIL; PERFORMANCE; INJECTION; RECOVERY; UNIT,"Tahe oil field is a fractured-vuggy carbonate oil field in China. The fluid flow behaviors in this type of reservoir are complex due to multiple flow paths through the matrix, fractures and vugs. The main challenges of production include complicated oil-water distributions, rising state of water cone in different flow units, unclear multiphase flow behaviors, and lack of understanding of the fluid flow mechanism. Based on a geological map of the Tahe oil field, a physical 3-D fractured-vuggy model was designed and fabricated. Water and gas flooding experiments were performed, while the multiphase flow behaviors were captured with a high-resolution camera system. The pressure response was also monitored at different oil displacement stages. The results show that the 3-D physical model can be used to systematically and comprehensively investigate the fluid flow behaviors during the oil displacement process. The oil-water interfaces of prolific wells rise more rapidly than that from the stripper wells, leading to an uneven distribution of internal flow fields and cross-well interferences. Water breaks through early and water channeling is more significant in fractured than vuggy wells. The oil-water flow behavior in fractured-vuggy combinations is mainly determined by fractured-vuggy structure, viscous force, wettability, and the ratio of displacement forces to gravity. During nitrogen gas flooding, gas caps occur from gas displacing the remaining oil at the top of the reservoir. The synergistic interaction between nitrogen gas and injected water contributes to additional oil recovery. This study provides a guide for improving production performance in fractured-vuggy carbonate reservoirs.",23,27,2
Multiphase Flow,Gravity Drainage,"Sun, Fengrui; Yao, Yuedong; Li, Xiangfang; Li, Guozhen; Han, Song; Liu, Qing; Liu, Wenyuan",Type curve analysis of multi-phase flow of multi-component thermal fluid in toe-point injection horizontal wells considering phase change,Heavy oil recovery; Phase change; Toe-point injection horizontal wells; Non-condensing gases; Superheated state; Saturated state,HEAVY OIL-RECOVERY; SUPERHEATED-STEAM INJECTION; 2-PHASE FLOW; PERFORMANCE ANALYSIS; NONCONDENSING GASES; GRAVITY DRAINAGE; KEY PARAMETERS; HOT-WATER; WELLBORE; MODEL,"Huge amount of works were done on modeling of wet steam flow in the conventional heel-point injection horizontal wellbores. With the rapid development of technology, new technology of superheated steam - non-condensing gases (SNG) injection coupled with toe-point injection wellbores was adopted in oil field. In this paper, a series of works were done on modeling of SNG flow in a horizontal wellbore with toe-point injection technique. The two-phase flow model was embedded in this SNG model for describing the phase change phenomenon. Firstly, a hydraulics model comprised of mass, momentum and energy conservation equations was developed. Then, coupled with the seepage model in oil layer, a wellbore/formation coupled model was established. Thirdly, straight forward numerical method was adopted to solve the model. Finally, model verification and sensitivity analysis were conducted sequentially. Results show that: (1) The SNG temperature in annuli has an increase at the heel-point due to heat conduction from IT to annuli. (2) When the mass injection rate is kept unchanged, the SNG temperature at a certain place in annuli decreases with increasing of the mass content of non-condensing gases. (3) The SNG in IT undergoes phase change into saturated state at the distance of 150 m. Then, from the distance of 150 m-200 m, the gas content in the mixture system gets an increase and the superheat degree is equal to zero. (4) Phase change occurs again in annuli when the SNG reaches the distance of 110 m where the wet fluid turns into superheated state, after which the superheated degree of SNG increases continuously as SNG is flowing to the heel-point.",32,32,1
Multiphase Flow,Gravity Drainage,"Liang, Tianbo; Li, Qingguang; Liang, Xingyuan; Yao, Erdong; Wang, Yanqing; Li, Yuan; Chen, Mai; Zhou, Fujian; Lu, Jun",Evaluation of liquid nanofluid as fracturing fluid additive on enhanced oil recovery from low-permeability reservoirs,Fracturing fluid additive; EOR; Tight oil; Wettability alteration,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; GRAVITY DRAINAGE; HIGH-TEMPERATURE; WATER BLOCKING; SHALE; SURFACTANTS; WET; CARBONATES; SYSTEM,"Hydraulic fracturing creates a complex fracture network that makes the oil production from low-permeability reservoirs economical. However, significant amount of water is likely lost into the rock matrix during hydraulic fracturing. This can cause formation damage due to multiphase flow, thus hindering the oil production rate. Surfactants can alter rock wettability and/or reduce oil-water interfacial tension (IFT), and it has been proposed to be used to mitigate such water blockage and enhance oil recovery. Among different approaches of using surfactants, forming liquid nanofluid (LNF) can minimize the adsorption of surfactants on rock surface, and it is likely to be one of the best options for low-permeability rocks with extensive surface area. In this study, the key properties of a well-screened LNF are evaluated, and then compared with a commercial flowback surfactant (CFS) that is widely used in the field. Pressure transmission test is further applied, which can determine the change of rock permeability due to different fluids and the potential formation damage due to multiphase flow. A systematic evaluation method is thus established to screen fracturing fluid additives to enhance oil production from low-permeability reservoirs both effectively and efficiently.",24,28,4
Multiphase Flow,Angle,"Xie, Quan; Sari, Ahmad; Pu, Wanfen; Chen, Yongqiang; Brady, Patrick V.; Al Maskari, Nasser; Saeedi, Ali",pH effect on wettability of oil/brine/carbonate system: Implications for low salinity water flooding,Carbonate reservoirs; Low salinity water; Wettability; Geochemical modelling; pH,SURFACE COMPLEXATION MODEL; IMPROVED OIL-RECOVERY; IMPACT; CHALK; CARBONATES; SANDSTONE; EOR,"Wettability of oil/brine/carbonate system is a critical parameter to govern subsurface multi-phase flow behaviour, thus remaining oil saturation and ultimate oil recovery in carbonate reservoirs. Despite the fact that salinity level, ionic strength, oil composition and rock chemistry (e.g., limestone and dolomite) have been extensively investigated, few work has been done regarding the effect of pH on oil/brine/rock interaction, thus wettability. We thereby measured contact angles at two different pH (pH = 3 and 8) in the presence of either 1 mol/L Na2SO4 or 1 mol/L CaCl2 using a crude oil with acid number of 1.7 and base number of 1.2 mg KOH/g. Moreover, we performed a geochemical modelling study in light of the diffuse double layer to understand how pH controls the number of surface species at interfaces of oil/brine and brine/carbonate. Our results show that pH scales with oil/brine/carbonate wettability, demonstrating that pH is one of the controlling factors to govern the system wettability. Further, our results suggest that pH (6.5-7.5) likely triggers an oil-wet system, which is favourable for low salinity water flooding, but pH < 5 usually exhibits a water-wet system, which explains why low salinity effect is not always observed in carbonate reservoirs. This also confirms that CO2 flooding, carbonated water flooding, and CO2 huff-and-puff FOR very likely renders a strongly water-wet system due to H+ adsorption on the interface of oil/brine and brine/carbonate as a result of CO2 dissolution.",43,43,2
Multiphase Flow,Angle,"Ma, Yi; Ni, Yang; Zhang, He; Zhou, Shuiqing; Deng, Hongying",Influence of valve's lag characteristic on pressure pulsation and performance of reciprocating multiphase pump,Multiphase pump; Computational fluid dynamics; Two-phase flow; Lag characteristic; Pressure pulsation,ELECTRICAL SUBMERSIBLE PUMP; FLUID-FLOW; NUMERICAL-SIMULATION; COMPRESSOR,"Reciprocating multiphase pump is the key equipment for the oil-gas transport technology in the petroleum industry. The opening and closing motions of suction and discharge valves directly affect the transport performance and stability of pump. In this paper, the whole working cycle of reciprocating multiphase pump is studied by using computational fluid dynamics (CFD) method. The combined actions of piston, suction and discharge valves are dealt with User Defined Functions and dynamic grid technique. Based on the instantaneous motions of valves, the lag characteristics of suction and discharge valves under different working conditions are analyzed. And the influences of lag angles on the pressure pulsation, P-V diagram and input power of the pump are further investigated. The results show that the lag angles have a significant impact on the internal and external characteristics of the reciprocating multiphase pump. Due to the most obvious opening lag angle of discharge valve, the pump pressures and PV diagram have the sudden fluctuations just after the end of compression process, which appear in the range of. 0=240.7 degrees-273.1 degrees for the initial condition. The gas volume fraction (GVF) plays more important role than the suction and discharge pressures in the working of reciprocating multiphase pump, and the opening lag angles of suction and discharge valves at GVF = 0.9 increase to more than 6 times at GVF = 0.1. By the comparisons of input power, the simulated results for reciprocating multiphase pump show good agreement with the results of prototype test. This study would provide a theoretical basis for the design of high-efficiency multiphase pump and valve.",16,19,6
Hydrate,Shale,"Xu, Jian-gen; Qiu, Zheng-song; Zhao, Xin; Zhong, Han-yi; Li, Gong-rang; Huang, Wei-an",Synthesis and characterization of shale stabilizer based on polyethylene glycol grafted nano-silica composite in water-based drilling fluids,Polyethylene glycol grafted nano-silica composite (PEG-NS); Wellbore instability; Water-based drilling fluids; Shale stabilizer; Pressure transmission,WELLBORE STABILITY; PERFORMANCE; NANOCOMPOSITE; HYDRATION; MECHANISM,"In order to solve wellbore instability problems in the drilling process, high-performance shale stabilizers in waterbased drilling fluids are essential. In this paper, a novel shale stabilizer based on polyethylene glycol grafted nanosilica composite (PEG-NS) was successfully synthesized. Conventional techniques were used to characterize PEGNS including Flourier transform infrared spectroscopy (FT-IR), scanning electron microscope (SEM), transmission electron microscopy (TEM), particle size distribution (PSD) and thermogravimetric analysis (TGA). The results showed that the structure of PEG-NS was in agreement with the design objective. The particle size of PEG-NS ranged from 110 to 434 nm, and PEG-NS had good thermal stability. Pressure transmission test, pore structure characterization of shale, rolling recovery test were applied to evaluate the comprehensive performance of PEGNS as a novel shale stabilizer. The experimental data indicated that PEG-NS could effectively retard the pore pressure transmission and reduce the permeability of shale sample. PEG-NS could adsorb onto the shale surface and a dense plugging film could finally coat on it. Moreover, PEG-NS also exhibited better inhibition performance compared with that of potassium chloride (KCl) and polymeric alcohol (JHC) at the same concentration. Hence, PEG-NS could be a good shale stabilizer in water-based drilling fluids for drilling reactive shale formations.",49,52,10
Hydrate,Shale,"An, Yuxiu; Yu, Peizhi",A strong inhibition of polyethyleneimine as shale inhibitor in drilling fluid,Swelling; Inhibition; Mechanism; Polyethyleneimine; Shale,WELLBORE INSTABILITY; STABILITY; DESIGN; MODEL,"In this paper, the inhibition property of polyethyleneimine (PEI) in montmorillonite solution was studied. The inhibition property was evaluated by linear swelling test and rolling recovery test. Compared with other inhibitors, the addition of PEI resulted in the lowest swelling height in drilling fluid. In rolling recovery rate study, the addition of PEI resulted in the highest recovery rate after rolled at 120 degrees C. More importantly, PEI was environmental friendly inhibitor. The inhibition mechanism was investigated by Fourier transform infrared spectroscopy, X-ray diffraction, Transmission electron microscope, Scanning electron microscopy, Atomic force microscope, Zeta potential and Particle-size analyzer. The spectrums and images showed that the negative charge in the surface of montmorillonite (MMT) was neutralized by the positive charge in amino group of PEI. PEI was adsorbed in the surface and intercalated into interlayer of MMT, which reduced the hydration repulsion of diffuse electric double layer and prevented the invasion of water. Hydrogen bonding between hydroxyl in the surface of clay and amino groups in the backbone and side chain of PEI can be formed in the process. The adsorption and intercalation of PEI in the surface and interlayer of MMT was the major factor to prevent water molecules from invading into the gallery of clay. There were a quantity of positive ions in solution because of the protonation of nitrogen in water. More positive ions resulted in the stronger force between inhibitor and clay.",45,49,1
Hydrate,Shale,"Yue, Ye; Chen, Shuya; Wang, Ziqi; Yang, Xianyu; Peng, Yangdong; Cai, Jihua; Nasr-El-Din, Hisham A.",Improving wellbore stability of shale by adjusting its wettability,Shale Water-based mud (WBM); Wellbore stability; Wettability; Contact angle; Pressure transmission test (PTT),WATER; ADSORPTION; PRESSURE; MODEL; MUD,"The possibility of improving wellbore stability of shale by adjusting its wettability was investigated. First, an optimized surfactants combination (0.2 wt% cetyltrimethylammonium bromide (CTAB) plus 0.1 wt% sodium dodecyl benzene sulfonate (SDBS)) was screened out that could effectively reduce the surface tension of the water-based mud (WBM) or fresh water, and increase the contact angle with shale. Then, regular tests on viscosity, filtration, lubrication, water activity, and special tests on linear swelling, rolling recovery rate, temperature tolerance, salts, and active cuttings tolerance, along with pressure transmission test (PTT) of shale were conducted to evaluate the performance of the optimized surfactants combination. Results show that the WBM's surface tension could be decreased from 45.1 to 20.0 mN/m and the contact angle on the shale could be increased from 34.5 to 63.5 degrees. The optimized surfactants combination could also improve the WBM's performance to inhibit shale hydration. The WBM in the presence of the optimized surfactants combination had good tolerance to a pollutants complex (0.8 wt% CaCl2, 0.8 wt% MgCl2, 5 wt% sodium bentonite, and 10 wt% NaCl) and could withstand a high temperature of 130 degrees C. Foaming phenomenon could be avoided by adding surfactants in the last step. PTT results show that compared with 4 wt% NaCl, the optimized surfactants combination could effectively retard the pore pressure transmission in shale and reduce its permeability by 98.6%. The addition of CTAB to the WBM or fresh water, hydrolyzed CTA(+) cation adsorbs on the surface of shale via an ionic bond, forming a hydrophilic base toward shale and a lipophilic base toward the WBM or water, thus, increasing the contact angle with shale and improve wellbore stability in shale. This paper paves a new way to address wellbore stability issues in troublesome shale formations.",30,31,0
Hydrate,Shale,"Zhang, Xianmin; Jiang, Guancheng; Dong, Tengfei; Wang, Le; Li, Xinliang; Wang, Guoshuai",An amphoteric polymer as a shale borehole stabilizer in water-based drilling fluids,Borehole stabilizer; Amphoteric polymers; Shale hydration; Micro-nanometer plugging; Water-based drilling fluid,ELEVATED-TEMPERATURE; WELLBORE INSTABILITY; POLYACRYLAMIDE; NANOPARTICLES; SPECTROSCOPY; WELLS; MUDS,"An amphoteric polymer P (acrylamide-styrene-butyl acrylate) (ASBA) was evaluated for use as a shale borehole stabilizer and for its ability to counter the problem of well instability during shale gas exploration and development. The hydrophilic groups in the ASBA increased the adsorption between the ASBA and the shale formation and the hydrophobic groups reduced the hydrophilicity of the sodium bentonite (BT). The addition of 1.6 wt% ASBA resulted in a water contact angle of the BT/ASBA that was more than 40 degrees larger than that of the BT. The amount of linear swelling decreased by 37.81% and the hot-rolling recovery rate of the shale cuttings was more than 60% higher in the 1.6 wt% ASBA solution than in deionized water. The ASBA exhibited micro/nanometer globules with an average diameter of 250.4 nm in aqueous solution. This was in agreement with the results of the morphology tests (scanning electron microscopy (SEM) and transmission electron microscopy (TEM)). The morphology tests, elemental analysis, and thermogravimetric analysis showed that the polymer was evenly dispersed in the aqueous solution and effectively adsorbed onto the BT instead of the free water. The soft globules changed under pressure and effectively plugged the various pores in the formation. Due to the hydrophobicity and the plugging effect, the ASBA prevented the BT aggregation and reduced the filtration loss; the American Petroleum Institute (API) filtration loss of the basic mud containing 1.6 wt% ASBA was reduced by 56.67% compared to the basic mud without ASBA after aging at 150 degrees C. Due to the excellent inhibition of the shale hydration and the micro/nanometer plugging performance, the ASBA has a potential application as a borehole stabilizer in drilling fluids.",19,20,4
Hydrate,Temperature Profiles,"Huo, Jin-hua; Peng, Zhi-gang; Ye, Zhong-bin; Zuo, Guo-lei","Preparation, characterization and investigation of low hydration heat cement slurry system used in natural gas hydrate formation",Natural gas hydrate; Cement slurry system; Heat evaluation; Semi-adiabatic test; Transverse relaxation time; Application performance,FLY-ASH; PORTLAND-CEMENT; ENERGY RESOURCE; SILICA FUME; STEEL SLAG; STRENGTH; CONCRETE; BINDER; WATER,"Based on the low hydration heat requirement of cement slurry system used in natural gas hydrate formation and the effective utilization of industrial waste materials, the fly ash and slag were introduced into ordinary Portland cement to prepare a low hydration heat cement slurry system. During this study, the influences of fly ash and slag on the heat evaluation of cement slurry system were investigated by temperature profiles and hydration heat, which were tested by using a developed semi-adiabatic test equipment. Currently, the temperature profiles of cement slurry system were studied by the initial temperature (T-i), temperature rise (T-r), maximum temperature (T-m), and the hydration time (t(m)) corresponding to the maximum temperature, respectively. Moreover, the investigations of the influences of fly ash and slag on the strength property of cement stone were investigated. Then, a novel low hydration heat cement slurry system CFS1-1 used in natural gas hydrate formation was developed by the mass ratio of 2: 1: 1 (cement: fly ash: slag). Simultaneously, the initial hydration process of CFS1-1 was investigated by low field NMR, the rheological and thickening properties of CFS1-1 were also studied. Besides, some other application performances, such as density, fluidity, stability and consistency, were also studied. As a result, it was found that the application performances of CFS1-1 meet the cementing requirement of hydrate formation. In addition, the effective and reasonable utilization of industrial waste materials were also realized during this study.",16,18,2
Hydrate,Temperature Profiles,"Kim, Hyunho; Yoo, Wonwo; Lim, Youngsub; Seo, Yutaek",Economic evaluation of MEG injection and regeneration process for oil FPSO,Oil FPSO; Hydrate prevention; Mono ethylene glycol; Process simulation; Economic evaluation,HYDRATE FORMATION; WATER; INHIBITION; AGGLOMERATION; DESALINATION; PIPELINES; GLYCOL,"Injection and regeneration of MEG for an offshore oil field to prevent the risk of hydrate formation was compared to those of conventional hydrate inhibitor, MEOH (methanol). It was presumed that the injected MEG was regenerated in FPSO to 90 wt% concentration while the MeOH was simply treated without re-use. A multiphase simulation tool was employed to determine the temperature and pressure profile in subsea flowline, which provided the required concentration of hydrate inhibitors for hydrate prevention. While the required concentration of MeOH was around 18 to 30 wt% depending on the water depth, the concentration of MEG was varied from 28 to 46 wt%. NPC (net present cost) for MeOH and MEG injection was estimated as a function of injection count per year with economic assessment. The resulting NPC of MEG injection system for single injection event per year was expensive than that of MeOH injection system due to the higher total capital costs for MEG injection and regeneration system. However, the economic benefit of MeOH systems was decreased with increasing the injection event frequency because the injected MeOH cannot be recovered, and increasing storage tank and purchased MeOH cost were directly added to the total cost. When varying the water depth, i.e. ambient sea water temperature of the offshore oil field, the minimum number of injections per year was different for the MEG injection system to be economically favorable than the MeOH injection system. It became economically favorable when injected more than 2.2 times per year for the case of water depth 1250 m, while it required more than 3.3 times per year for the case of water depth of 600 m. The results showed that the MEG injection and regeneration system can be a feasible option for remote oil fields depending on the average number of hydrate inhibitor injection per year.",16,16,2
Hydrate,Temperature Profiles,"Al Saedi, A. Q.; Flori, R. E.; Kabir, C. S.","New analytical solutions of wellbore fluid temperature profiles during drilling, circulating, and cementing operations",,HEAT-TRANSFER; INJECTION; PREDICT; WELLS; MODEL; FLOW,"Historically, the formulation of the wellbore temperature profiles during drilling, circulating, and cementing operations relied upon the boundary condition or BC at the bottomhole location, wherein the tubular and annular temperatures become equal. This study presents two other formulations to explore alternative to bottomhole BC's that may potentially occur in wellbores. Application of the energy balance in the wellbore for both forward and reverse circulations underpins all three formulations. The wellbore temperature profiles generated by implementing the energy balance in the system depends on the type of the boundary condition used. Initially, we generated various temperature profiles using these models. In general, we observed that the maximum temperature occurs at the end of the tubular or some distance away from the bottom. For open and cased-hole sections, the difference in heat-transfer coefficients triggers different magnitudes of heat transfer and affects the corresponding temperature profiles. We compared the performance of our models with those presented in the literature. Thereafter, we sought to validate the models with diverse set of field data. Given the ability of all three models to handle changes in the geothermal gradient due to the characteristics of the sediments, salt domes, and gas hydrates, we explored their performance in situations where there is significant heat transfer. The holistic approach pursued here provided the necessary insights into various temperature profiles in a given situation.",15,15,1
Hydrate,Particle,"Xu, Jian-gen; Qiu, Zheng-song; Zhao, Xin; Zhong, Han-yi; Li, Gong-rang; Huang, Wei-an",Synthesis and characterization of shale stabilizer based on polyethylene glycol grafted nano-silica composite in water-based drilling fluids,Polyethylene glycol grafted nano-silica composite (PEG-NS); Wellbore instability; Water-based drilling fluids; Shale stabilizer; Pressure transmission,WELLBORE STABILITY; PERFORMANCE; NANOCOMPOSITE; HYDRATION; MECHANISM,"In order to solve wellbore instability problems in the drilling process, high-performance shale stabilizers in waterbased drilling fluids are essential. In this paper, a novel shale stabilizer based on polyethylene glycol grafted nanosilica composite (PEG-NS) was successfully synthesized. Conventional techniques were used to characterize PEGNS including Flourier transform infrared spectroscopy (FT-IR), scanning electron microscope (SEM), transmission electron microscopy (TEM), particle size distribution (PSD) and thermogravimetric analysis (TGA). The results showed that the structure of PEG-NS was in agreement with the design objective. The particle size of PEG-NS ranged from 110 to 434 nm, and PEG-NS had good thermal stability. Pressure transmission test, pore structure characterization of shale, rolling recovery test were applied to evaluate the comprehensive performance of PEGNS as a novel shale stabilizer. The experimental data indicated that PEG-NS could effectively retard the pore pressure transmission and reduce the permeability of shale sample. PEG-NS could adsorb onto the shale surface and a dense plugging film could finally coat on it. Moreover, PEG-NS also exhibited better inhibition performance compared with that of potassium chloride (KCl) and polymeric alcohol (JHC) at the same concentration. Hence, PEG-NS could be a good shale stabilizer in water-based drilling fluids for drilling reactive shale formations.",49,52,10
Hydrate,Particle,"Song, GuangChun; Li, YuXing; Wang, WuChang; Jiang, Kai; Shi, Zhengzhuo; Yao, Shupeng",Numerical simulation of hydrate slurry flow behavior in oil-water systems based on hydrate agglomeration modelling,Hydrate; Agglomeration; Dynamic model; Numerical simulation; Population balance,SMALL PARTICLES; TURBULENT-FLOW; PLUG FORMATION; COLLISION; DISSOCIATION; AGGREGATION; INHIBITORS; PIPES; FLUID,"Hydrate agglomeration in oil-water systems could lead to pipeline hydrate plugging. Dynamic modeling of pipeline hydrate particle agglomeration is of great importance to hydrate management. For this purpose, a dynamic model of hydrate agglomeration was established based on population balance equation, which took both hydrate agglomeration and hydrate breakage into consideration. The calculation methods of collision frequency, agglomeration efficiency, breakage frequency and particle size distribution function of the sub particles resulting from particle breakage were given and fully discussed in the dynamic model. Then, combined with several traditional solid-liquid flow models, the dynamic model was solved by the CFD software FLUENT 14.5 to simulate the influences of flow rate and hydrate volume fraction on pipeline hydrate slurry flow behavior in oil-water systems. The simulation results show that hydrate particle size distribution in pipeline flowing systems can be well described by log-normal distribution. Hydrate particle diameters and hydrate volume concentrations in the near wall region are larger than that in the center region of the pipeline. The proportion of large hydrate particles and the mean hydrate particle diameter in pipeline increase with the increase of flow rate and hydrate volume fraction. Hydrate particle diameter and pressure gradient in oil-water systems are larger than that in water systems.",17,17,3
Hydrate,Particle,"Luo, Tingting; Li, Yanghui; Sun, Xiang; Shen, Shi; Wu, Peng",Effect of sediment particle size on the mechanical properties of CH4 hydrate-bearing sediments,Sediment particle size; Proportion of large-particles; Stress-strain curves; Failure strength; Internal friction angle,QILIAN MOUNTAIN PERMAFROST; METHANE-HYDRATE; GAS-PRODUCTION; SHEAR-STRENGTH; STRAIN-RATE; CARBON-DIOXIDE; CO2 HYDRATE; BEHAVIOR; DISSOCIATION; DEPRESSURIZATION,"Previous study proved that the methane hydrate reservoirs in clay permafrost regions have great potential for exploitation. However, the widespread gradation of sediment matrices in hydrate-bearing sediments (HBS) would seriously affect the stability of the hydrate reservoirs, causing uneven distribution of pressure at the wall of the exploitation wellbore, and leading to a severe engineering hazard. Therefore, the effects of the sediment particle size on the mechanical stability of hydrate reservoir need to be investigated before the large-scale commercial production of methane hydrate. In this paper, sediments matrices containing different proportions of clay, silt and sand were prepared and mechanical properties of HBS were investigated and compared with each other. The results show that a bigger proportion of large-particles in the sediment matrix could significantly enhance the failure strength of HBS under different confining pressures, temperatures and strain rates. A better graded size distribution would also boost the failures strength of HBS, it's also found that the failure strength of HBS firstly increases and then declines with the rise of confining pressure, and that material exhibits greater failure strength at lower temperatures and higher strain rates. Finally, an analysis using Mohr-Coulomb strength theory indicates that the internal friction angle plays a dominant role in the failure strength increase of HBS with a greater proportion of large-particles in the sediment matrix.",15,15,2
Hydrate,Drilling Mud,"Sun, Jiaxin; Ning, Fulong; Lei, Hongwu; Gai, Xuerui; Sanchez, Marcelo; Lu, Jingan; Li, Yanlong; Liu, Lele; Liu, Changling; Wu, Nengyou; He, Yong; Wu, Min",Wellbore stability analysis during drilling through marine gas hydrate-bearing sediments in Shenhu area: A case study,Natural gas hydrates; Drilling mud invasion; Wellbore stability; Drilling mud property; Reservoir physical property,METHANE HYDRATE; NUMERICAL-SIMULATION; RESERVOIR DISSOCIATION; MECHANICAL-BEHAVIOR; EAST-COAST; TEST-SITE; MODEL; FLUID; TEMPERATURE; INVASION,"Because of the metastable character of natural gas hydrate-bearing sediments (GHBS), they can be easily affected by drilling operations, thereby inducing the wellbore instability risk. This issue is studied in this paper by means of numerical simulations based on the first exploration well performed in the Shenhu area of the South China Sea in 2007. The corresponding simulated results were compared against the field caliper logging curve. Besides this analysis, the effects of both drilling mud properties (i.e., temperature, density, and salinity) and initial reservoir conditions (i.e., permeability, and saturation) on the wellbore stability were further investigated under the condition of drilling mud invasion into the GHBS. It is anticipated that the coupled multiphysics phenomena triggered under operation conditions can lead to wellbore instability and may also trigger the formation of fractures. The simulation results show that the predicted yield region around the borehole of well SH2 conforms to the borehole enlargement observed in the field. The sensitivity analyses indicate that a local increase in the pore pressure is likely to be generated in the wellbore vicinity, triggered by the large amount of free gas to be released during hydrate dissociation, which is in turn induced by heating (i.e., coming from the drilling-friction effects) and the high salinity of the drilling muds typically used. This study shows that by engineering the salinity of the drilling mud, the amount of free gas to be produced from marine GHBS can be controlled, preventing in this way further wellbore instability issues. This research also shows that an increase in the drilling-mud density not only impact on the development of pore pressures near the borehole, but it also affects the extent of drilling-mud invasion. This effect will extend the hydrate dissociation to a wider area and will also reduce the resistance of the formation, leading to further deformation and potential failure. The analyses also show that the increase in the initial hydrate saturation is associated with a stronger sediment and a more stable wellbore. The model also predicts that GHBS with higher absolute permeability will dissipate faster the excess of pore pressure in the surrounding sediment, contributing to wellbore stability; however, the extent of the hydrate dissociation zone will expand and thereby will increase the yield region.",49,54,11
Hydrate,Drilling Mud,"Zhang, Xianmin; Jiang, Guancheng; Dong, Tengfei; Wang, Le; Li, Xinliang; Wang, Guoshuai",An amphoteric polymer as a shale borehole stabilizer in water-based drilling fluids,Borehole stabilizer; Amphoteric polymers; Shale hydration; Micro-nanometer plugging; Water-based drilling fluid,ELEVATED-TEMPERATURE; WELLBORE INSTABILITY; POLYACRYLAMIDE; NANOPARTICLES; SPECTROSCOPY; WELLS; MUDS,"An amphoteric polymer P (acrylamide-styrene-butyl acrylate) (ASBA) was evaluated for use as a shale borehole stabilizer and for its ability to counter the problem of well instability during shale gas exploration and development. The hydrophilic groups in the ASBA increased the adsorption between the ASBA and the shale formation and the hydrophobic groups reduced the hydrophilicity of the sodium bentonite (BT). The addition of 1.6 wt% ASBA resulted in a water contact angle of the BT/ASBA that was more than 40 degrees larger than that of the BT. The amount of linear swelling decreased by 37.81% and the hot-rolling recovery rate of the shale cuttings was more than 60% higher in the 1.6 wt% ASBA solution than in deionized water. The ASBA exhibited micro/nanometer globules with an average diameter of 250.4 nm in aqueous solution. This was in agreement with the results of the morphology tests (scanning electron microscopy (SEM) and transmission electron microscopy (TEM)). The morphology tests, elemental analysis, and thermogravimetric analysis showed that the polymer was evenly dispersed in the aqueous solution and effectively adsorbed onto the BT instead of the free water. The soft globules changed under pressure and effectively plugged the various pores in the formation. Due to the hydrophobicity and the plugging effect, the ASBA prevented the BT aggregation and reduced the filtration loss; the American Petroleum Institute (API) filtration loss of the basic mud containing 1.6 wt% ASBA was reduced by 56.67% compared to the basic mud without ASBA after aging at 150 degrees C. Due to the excellent inhibition of the shale hydration and the micro/nanometer plugging performance, the ASBA has a potential application as a borehole stabilizer in drilling fluids.",19,20,4
Hydrate,Natural Gas,"Sun, Jiaxin; Ning, Fulong; Lei, Hongwu; Gai, Xuerui; Sanchez, Marcelo; Lu, Jingan; Li, Yanlong; Liu, Lele; Liu, Changling; Wu, Nengyou; He, Yong; Wu, Min",Wellbore stability analysis during drilling through marine gas hydrate-bearing sediments in Shenhu area: A case study,Natural gas hydrates; Drilling mud invasion; Wellbore stability; Drilling mud property; Reservoir physical property,METHANE HYDRATE; NUMERICAL-SIMULATION; RESERVOIR DISSOCIATION; MECHANICAL-BEHAVIOR; EAST-COAST; TEST-SITE; MODEL; FLUID; TEMPERATURE; INVASION,"Because of the metastable character of natural gas hydrate-bearing sediments (GHBS), they can be easily affected by drilling operations, thereby inducing the wellbore instability risk. This issue is studied in this paper by means of numerical simulations based on the first exploration well performed in the Shenhu area of the South China Sea in 2007. The corresponding simulated results were compared against the field caliper logging curve. Besides this analysis, the effects of both drilling mud properties (i.e., temperature, density, and salinity) and initial reservoir conditions (i.e., permeability, and saturation) on the wellbore stability were further investigated under the condition of drilling mud invasion into the GHBS. It is anticipated that the coupled multiphysics phenomena triggered under operation conditions can lead to wellbore instability and may also trigger the formation of fractures. The simulation results show that the predicted yield region around the borehole of well SH2 conforms to the borehole enlargement observed in the field. The sensitivity analyses indicate that a local increase in the pore pressure is likely to be generated in the wellbore vicinity, triggered by the large amount of free gas to be released during hydrate dissociation, which is in turn induced by heating (i.e., coming from the drilling-friction effects) and the high salinity of the drilling muds typically used. This study shows that by engineering the salinity of the drilling mud, the amount of free gas to be produced from marine GHBS can be controlled, preventing in this way further wellbore instability issues. This research also shows that an increase in the drilling-mud density not only impact on the development of pore pressures near the borehole, but it also affects the extent of drilling-mud invasion. This effect will extend the hydrate dissociation to a wider area and will also reduce the resistance of the formation, leading to further deformation and potential failure. The analyses also show that the increase in the initial hydrate saturation is associated with a stronger sediment and a more stable wellbore. The model also predicts that GHBS with higher absolute permeability will dissipate faster the excess of pore pressure in the surrounding sediment, contributing to wellbore stability; however, the extent of the hydrate dissociation zone will expand and thereby will increase the yield region.",49,54,11
Hydrate,Natural Gas,"Huo, Jin-hua; Peng, Zhi-gang; Ye, Zhong-bin; Zuo, Guo-lei","Preparation, characterization and investigation of low hydration heat cement slurry system used in natural gas hydrate formation",Natural gas hydrate; Cement slurry system; Heat evaluation; Semi-adiabatic test; Transverse relaxation time; Application performance,FLY-ASH; PORTLAND-CEMENT; ENERGY RESOURCE; SILICA FUME; STEEL SLAG; STRENGTH; CONCRETE; BINDER; WATER,"Based on the low hydration heat requirement of cement slurry system used in natural gas hydrate formation and the effective utilization of industrial waste materials, the fly ash and slag were introduced into ordinary Portland cement to prepare a low hydration heat cement slurry system. During this study, the influences of fly ash and slag on the heat evaluation of cement slurry system were investigated by temperature profiles and hydration heat, which were tested by using a developed semi-adiabatic test equipment. Currently, the temperature profiles of cement slurry system were studied by the initial temperature (T-i), temperature rise (T-r), maximum temperature (T-m), and the hydration time (t(m)) corresponding to the maximum temperature, respectively. Moreover, the investigations of the influences of fly ash and slag on the strength property of cement stone were investigated. Then, a novel low hydration heat cement slurry system CFS1-1 used in natural gas hydrate formation was developed by the mass ratio of 2: 1: 1 (cement: fly ash: slag). Simultaneously, the initial hydration process of CFS1-1 was investigated by low field NMR, the rheological and thickening properties of CFS1-1 were also studied. Besides, some other application performances, such as density, fluidity, stability and consistency, were also studied. As a result, it was found that the application performances of CFS1-1 meet the cementing requirement of hydrate formation. In addition, the effective and reasonable utilization of industrial waste materials were also realized during this study.",16,18,2
Hydrate,Injection,"Kim, Hyunho; Yoo, Wonwo; Lim, Youngsub; Seo, Yutaek",Economic evaluation of MEG injection and regeneration process for oil FPSO,Oil FPSO; Hydrate prevention; Mono ethylene glycol; Process simulation; Economic evaluation,HYDRATE FORMATION; WATER; INHIBITION; AGGLOMERATION; DESALINATION; PIPELINES; GLYCOL,"Injection and regeneration of MEG for an offshore oil field to prevent the risk of hydrate formation was compared to those of conventional hydrate inhibitor, MEOH (methanol). It was presumed that the injected MEG was regenerated in FPSO to 90 wt% concentration while the MeOH was simply treated without re-use. A multiphase simulation tool was employed to determine the temperature and pressure profile in subsea flowline, which provided the required concentration of hydrate inhibitors for hydrate prevention. While the required concentration of MeOH was around 18 to 30 wt% depending on the water depth, the concentration of MEG was varied from 28 to 46 wt%. NPC (net present cost) for MeOH and MEG injection was estimated as a function of injection count per year with economic assessment. The resulting NPC of MEG injection system for single injection event per year was expensive than that of MeOH injection system due to the higher total capital costs for MEG injection and regeneration system. However, the economic benefit of MeOH systems was decreased with increasing the injection event frequency because the injected MeOH cannot be recovered, and increasing storage tank and purchased MeOH cost were directly added to the total cost. When varying the water depth, i.e. ambient sea water temperature of the offshore oil field, the minimum number of injections per year was different for the MEG injection system to be economically favorable than the MeOH injection system. It became economically favorable when injected more than 2.2 times per year for the case of water depth 1250 m, while it required more than 3.3 times per year for the case of water depth of 600 m. The results showed that the MEG injection and regeneration system can be a feasible option for remote oil fields depending on the average number of hydrate inhibitor injection per year.",16,16,2
Hydrate,Injection,"Al Saedi, A. Q.; Flori, R. E.; Kabir, C. S.","New analytical solutions of wellbore fluid temperature profiles during drilling, circulating, and cementing operations",,HEAT-TRANSFER; INJECTION; PREDICT; WELLS; MODEL; FLOW,"Historically, the formulation of the wellbore temperature profiles during drilling, circulating, and cementing operations relied upon the boundary condition or BC at the bottomhole location, wherein the tubular and annular temperatures become equal. This study presents two other formulations to explore alternative to bottomhole BC's that may potentially occur in wellbores. Application of the energy balance in the wellbore for both forward and reverse circulations underpins all three formulations. The wellbore temperature profiles generated by implementing the energy balance in the system depends on the type of the boundary condition used. Initially, we generated various temperature profiles using these models. In general, we observed that the maximum temperature occurs at the end of the tubular or some distance away from the bottom. For open and cased-hole sections, the difference in heat-transfer coefficients triggers different magnitudes of heat transfer and affects the corresponding temperature profiles. We compared the performance of our models with those presented in the literature. Thereafter, we sought to validate the models with diverse set of field data. Given the ability of all three models to handle changes in the geothermal gradient due to the characteristics of the sediments, salt domes, and gas hydrates, we explored their performance in situations where there is significant heat transfer. The holistic approach pursued here provided the necessary insights into various temperature profiles in a given situation.",15,15,1
Hydrate,Well Testing,"Wang, Zhiyuan; Zhao, Yang; Zhang, Jianbo; Pan, Shaowei; Yu, Jing; Sun, Baojiang",Flow assurance during deepwater gas well testing: Hydrate blockage prediction and prevention,Deepwater; Gas well testing; Flow assurance; Hydrate blockage; Hydrate Blockage Free Window,DEPOSITION; MODEL,"Hydrates cause serious flow assurance problems during deepwater operations (e.g. well testing). In order to efficiently prevent wellbore/pipeline blockage, it is of great importance to have a good understanding of hydrate formation, deposition and blockage behavior in the flowline. In this work, a model is developed to describe the development of hydrate blockage in the wellbore. The results indicate a non-uniform hydrate layer is formed on the inner wall along the testing tubing during deepwater gas well testing. With the proposed model, the position where hydrate blockage is most likely to occur can be identified. The blockage severity in terms of dimensionless hydrate layer thickness can also be assessed. Based on the model, a method is developed to prevent hydrate blockage with lower inhibitor consumption. We recommend that testing operations should be run within the Hydrate Blockage Free Window (HBFW). The HBFW refers to the period from the beginning of testing operations to the moment when a significant pressure drop increase is encountered. Implementation procedure of the proposed method is developed and further illustrated through case studies. The inhibitor consumption is much lower compared with the current over-inhibition THI-based method. This work provides possible ways to overcome the shortcomings of the current over-inhibition THI-based method.",32,32,4
Hydrate,Well Testing,"Zhang, Xianmin; Jiang, Guancheng; Dong, Tengfei; Wang, Le; Li, Xinliang; Wang, Guoshuai",An amphoteric polymer as a shale borehole stabilizer in water-based drilling fluids,Borehole stabilizer; Amphoteric polymers; Shale hydration; Micro-nanometer plugging; Water-based drilling fluid,ELEVATED-TEMPERATURE; WELLBORE INSTABILITY; POLYACRYLAMIDE; NANOPARTICLES; SPECTROSCOPY; WELLS; MUDS,"An amphoteric polymer P (acrylamide-styrene-butyl acrylate) (ASBA) was evaluated for use as a shale borehole stabilizer and for its ability to counter the problem of well instability during shale gas exploration and development. The hydrophilic groups in the ASBA increased the adsorption between the ASBA and the shale formation and the hydrophobic groups reduced the hydrophilicity of the sodium bentonite (BT). The addition of 1.6 wt% ASBA resulted in a water contact angle of the BT/ASBA that was more than 40 degrees larger than that of the BT. The amount of linear swelling decreased by 37.81% and the hot-rolling recovery rate of the shale cuttings was more than 60% higher in the 1.6 wt% ASBA solution than in deionized water. The ASBA exhibited micro/nanometer globules with an average diameter of 250.4 nm in aqueous solution. This was in agreement with the results of the morphology tests (scanning electron microscopy (SEM) and transmission electron microscopy (TEM)). The morphology tests, elemental analysis, and thermogravimetric analysis showed that the polymer was evenly dispersed in the aqueous solution and effectively adsorbed onto the BT instead of the free water. The soft globules changed under pressure and effectively plugged the various pores in the formation. Due to the hydrophobicity and the plugging effect, the ASBA prevented the BT aggregation and reduced the filtration loss; the American Petroleum Institute (API) filtration loss of the basic mud containing 1.6 wt% ASBA was reduced by 56.67% compared to the basic mud without ASBA after aging at 150 degrees C. Due to the excellent inhibition of the shale hydration and the micro/nanometer plugging performance, the ASBA has a potential application as a borehole stabilizer in drilling fluids.",19,20,4
Hydrate,Case Study,"Sun, Jiaxin; Ning, Fulong; Lei, Hongwu; Gai, Xuerui; Sanchez, Marcelo; Lu, Jingan; Li, Yanlong; Liu, Lele; Liu, Changling; Wu, Nengyou; He, Yong; Wu, Min",Wellbore stability analysis during drilling through marine gas hydrate-bearing sediments in Shenhu area: A case study,Natural gas hydrates; Drilling mud invasion; Wellbore stability; Drilling mud property; Reservoir physical property,METHANE HYDRATE; NUMERICAL-SIMULATION; RESERVOIR DISSOCIATION; MECHANICAL-BEHAVIOR; EAST-COAST; TEST-SITE; MODEL; FLUID; TEMPERATURE; INVASION,"Because of the metastable character of natural gas hydrate-bearing sediments (GHBS), they can be easily affected by drilling operations, thereby inducing the wellbore instability risk. This issue is studied in this paper by means of numerical simulations based on the first exploration well performed in the Shenhu area of the South China Sea in 2007. The corresponding simulated results were compared against the field caliper logging curve. Besides this analysis, the effects of both drilling mud properties (i.e., temperature, density, and salinity) and initial reservoir conditions (i.e., permeability, and saturation) on the wellbore stability were further investigated under the condition of drilling mud invasion into the GHBS. It is anticipated that the coupled multiphysics phenomena triggered under operation conditions can lead to wellbore instability and may also trigger the formation of fractures. The simulation results show that the predicted yield region around the borehole of well SH2 conforms to the borehole enlargement observed in the field. The sensitivity analyses indicate that a local increase in the pore pressure is likely to be generated in the wellbore vicinity, triggered by the large amount of free gas to be released during hydrate dissociation, which is in turn induced by heating (i.e., coming from the drilling-friction effects) and the high salinity of the drilling muds typically used. This study shows that by engineering the salinity of the drilling mud, the amount of free gas to be produced from marine GHBS can be controlled, preventing in this way further wellbore instability issues. This research also shows that an increase in the drilling-mud density not only impact on the development of pore pressures near the borehole, but it also affects the extent of drilling-mud invasion. This effect will extend the hydrate dissociation to a wider area and will also reduce the resistance of the formation, leading to further deformation and potential failure. The analyses also show that the increase in the initial hydrate saturation is associated with a stronger sediment and a more stable wellbore. The model also predicts that GHBS with higher absolute permeability will dissipate faster the excess of pore pressure in the surrounding sediment, contributing to wellbore stability; however, the extent of the hydrate dissociation zone will expand and thereby will increase the yield region.",49,54,11
Hydrate,Case Study,"Wang, Zhiyuan; Zhao, Yang; Zhang, Jianbo; Pan, Shaowei; Yu, Jing; Sun, Baojiang",Flow assurance during deepwater gas well testing: Hydrate blockage prediction and prevention,Deepwater; Gas well testing; Flow assurance; Hydrate blockage; Hydrate Blockage Free Window,DEPOSITION; MODEL,"Hydrates cause serious flow assurance problems during deepwater operations (e.g. well testing). In order to efficiently prevent wellbore/pipeline blockage, it is of great importance to have a good understanding of hydrate formation, deposition and blockage behavior in the flowline. In this work, a model is developed to describe the development of hydrate blockage in the wellbore. The results indicate a non-uniform hydrate layer is formed on the inner wall along the testing tubing during deepwater gas well testing. With the proposed model, the position where hydrate blockage is most likely to occur can be identified. The blockage severity in terms of dimensionless hydrate layer thickness can also be assessed. Based on the model, a method is developed to prevent hydrate blockage with lower inhibitor consumption. We recommend that testing operations should be run within the Hydrate Blockage Free Window (HBFW). The HBFW refers to the period from the beginning of testing operations to the moment when a significant pressure drop increase is encountered. Implementation procedure of the proposed method is developed and further illustrated through case studies. The inhibitor consumption is much lower compared with the current over-inhibition THI-based method. This work provides possible ways to overcome the shortcomings of the current over-inhibition THI-based method.",32,32,4
Hydrate,Great Importance,"Wang, Zhiyuan; Zhao, Yang; Zhang, Jianbo; Pan, Shaowei; Yu, Jing; Sun, Baojiang",Flow assurance during deepwater gas well testing: Hydrate blockage prediction and prevention,Deepwater; Gas well testing; Flow assurance; Hydrate blockage; Hydrate Blockage Free Window,DEPOSITION; MODEL,"Hydrates cause serious flow assurance problems during deepwater operations (e.g. well testing). In order to efficiently prevent wellbore/pipeline blockage, it is of great importance to have a good understanding of hydrate formation, deposition and blockage behavior in the flowline. In this work, a model is developed to describe the development of hydrate blockage in the wellbore. The results indicate a non-uniform hydrate layer is formed on the inner wall along the testing tubing during deepwater gas well testing. With the proposed model, the position where hydrate blockage is most likely to occur can be identified. The blockage severity in terms of dimensionless hydrate layer thickness can also be assessed. Based on the model, a method is developed to prevent hydrate blockage with lower inhibitor consumption. We recommend that testing operations should be run within the Hydrate Blockage Free Window (HBFW). The HBFW refers to the period from the beginning of testing operations to the moment when a significant pressure drop increase is encountered. Implementation procedure of the proposed method is developed and further illustrated through case studies. The inhibitor consumption is much lower compared with the current over-inhibition THI-based method. This work provides possible ways to overcome the shortcomings of the current over-inhibition THI-based method.",32,32,4
Hydrate,Great Importance,"Song, GuangChun; Li, YuXing; Wang, WuChang; Jiang, Kai; Shi, Zhengzhuo; Yao, Shupeng",Numerical simulation of hydrate slurry flow behavior in oil-water systems based on hydrate agglomeration modelling,Hydrate; Agglomeration; Dynamic model; Numerical simulation; Population balance,SMALL PARTICLES; TURBULENT-FLOW; PLUG FORMATION; COLLISION; DISSOCIATION; AGGREGATION; INHIBITORS; PIPES; FLUID,"Hydrate agglomeration in oil-water systems could lead to pipeline hydrate plugging. Dynamic modeling of pipeline hydrate particle agglomeration is of great importance to hydrate management. For this purpose, a dynamic model of hydrate agglomeration was established based on population balance equation, which took both hydrate agglomeration and hydrate breakage into consideration. The calculation methods of collision frequency, agglomeration efficiency, breakage frequency and particle size distribution function of the sub particles resulting from particle breakage were given and fully discussed in the dynamic model. Then, combined with several traditional solid-liquid flow models, the dynamic model was solved by the CFD software FLUENT 14.5 to simulate the influences of flow rate and hydrate volume fraction on pipeline hydrate slurry flow behavior in oil-water systems. The simulation results show that hydrate particle size distribution in pipeline flowing systems can be well described by log-normal distribution. Hydrate particle diameters and hydrate volume concentrations in the near wall region are larger than that in the center region of the pipeline. The proportion of large hydrate particles and the mean hydrate particle diameter in pipeline increase with the increase of flow rate and hydrate volume fraction. Hydrate particle diameter and pressure gradient in oil-water systems are larger than that in water systems.",17,17,3
Hydrate,Position,"An, Yuxiu; Yu, Peizhi",A strong inhibition of polyethyleneimine as shale inhibitor in drilling fluid,Swelling; Inhibition; Mechanism; Polyethyleneimine; Shale,WELLBORE INSTABILITY; STABILITY; DESIGN; MODEL,"In this paper, the inhibition property of polyethyleneimine (PEI) in montmorillonite solution was studied. The inhibition property was evaluated by linear swelling test and rolling recovery test. Compared with other inhibitors, the addition of PEI resulted in the lowest swelling height in drilling fluid. In rolling recovery rate study, the addition of PEI resulted in the highest recovery rate after rolled at 120 degrees C. More importantly, PEI was environmental friendly inhibitor. The inhibition mechanism was investigated by Fourier transform infrared spectroscopy, X-ray diffraction, Transmission electron microscope, Scanning electron microscopy, Atomic force microscope, Zeta potential and Particle-size analyzer. The spectrums and images showed that the negative charge in the surface of montmorillonite (MMT) was neutralized by the positive charge in amino group of PEI. PEI was adsorbed in the surface and intercalated into interlayer of MMT, which reduced the hydration repulsion of diffuse electric double layer and prevented the invasion of water. Hydrogen bonding between hydroxyl in the surface of clay and amino groups in the backbone and side chain of PEI can be formed in the process. The adsorption and intercalation of PEI in the surface and interlayer of MMT was the major factor to prevent water molecules from invading into the gallery of clay. There were a quantity of positive ions in solution because of the protonation of nitrogen in water. More positive ions resulted in the stronger force between inhibitor and clay.",45,49,1
Hydrate,Position,"Wang, Zhiyuan; Zhao, Yang; Zhang, Jianbo; Pan, Shaowei; Yu, Jing; Sun, Baojiang",Flow assurance during deepwater gas well testing: Hydrate blockage prediction and prevention,Deepwater; Gas well testing; Flow assurance; Hydrate blockage; Hydrate Blockage Free Window,DEPOSITION; MODEL,"Hydrates cause serious flow assurance problems during deepwater operations (e.g. well testing). In order to efficiently prevent wellbore/pipeline blockage, it is of great importance to have a good understanding of hydrate formation, deposition and blockage behavior in the flowline. In this work, a model is developed to describe the development of hydrate blockage in the wellbore. The results indicate a non-uniform hydrate layer is formed on the inner wall along the testing tubing during deepwater gas well testing. With the proposed model, the position where hydrate blockage is most likely to occur can be identified. The blockage severity in terms of dimensionless hydrate layer thickness can also be assessed. Based on the model, a method is developed to prevent hydrate blockage with lower inhibitor consumption. We recommend that testing operations should be run within the Hydrate Blockage Free Window (HBFW). The HBFW refers to the period from the beginning of testing operations to the moment when a significant pressure drop increase is encountered. Implementation procedure of the proposed method is developed and further illustrated through case studies. The inhibitor consumption is much lower compared with the current over-inhibition THI-based method. This work provides possible ways to overcome the shortcomings of the current over-inhibition THI-based method.",32,32,4
Hydrate,Current,"Wang, Zhiyuan; Zhao, Yang; Zhang, Jianbo; Pan, Shaowei; Yu, Jing; Sun, Baojiang",Flow assurance during deepwater gas well testing: Hydrate blockage prediction and prevention,Deepwater; Gas well testing; Flow assurance; Hydrate blockage; Hydrate Blockage Free Window,DEPOSITION; MODEL,"Hydrates cause serious flow assurance problems during deepwater operations (e.g. well testing). In order to efficiently prevent wellbore/pipeline blockage, it is of great importance to have a good understanding of hydrate formation, deposition and blockage behavior in the flowline. In this work, a model is developed to describe the development of hydrate blockage in the wellbore. The results indicate a non-uniform hydrate layer is formed on the inner wall along the testing tubing during deepwater gas well testing. With the proposed model, the position where hydrate blockage is most likely to occur can be identified. The blockage severity in terms of dimensionless hydrate layer thickness can also be assessed. Based on the model, a method is developed to prevent hydrate blockage with lower inhibitor consumption. We recommend that testing operations should be run within the Hydrate Blockage Free Window (HBFW). The HBFW refers to the period from the beginning of testing operations to the moment when a significant pressure drop increase is encountered. Implementation procedure of the proposed method is developed and further illustrated through case studies. The inhibitor consumption is much lower compared with the current over-inhibition THI-based method. This work provides possible ways to overcome the shortcomings of the current over-inhibition THI-based method.",32,32,4
Hydrate,Current,"Huo, Jin-hua; Peng, Zhi-gang; Ye, Zhong-bin; Zuo, Guo-lei","Preparation, characterization and investigation of low hydration heat cement slurry system used in natural gas hydrate formation",Natural gas hydrate; Cement slurry system; Heat evaluation; Semi-adiabatic test; Transverse relaxation time; Application performance,FLY-ASH; PORTLAND-CEMENT; ENERGY RESOURCE; SILICA FUME; STEEL SLAG; STRENGTH; CONCRETE; BINDER; WATER,"Based on the low hydration heat requirement of cement slurry system used in natural gas hydrate formation and the effective utilization of industrial waste materials, the fly ash and slag were introduced into ordinary Portland cement to prepare a low hydration heat cement slurry system. During this study, the influences of fly ash and slag on the heat evaluation of cement slurry system were investigated by temperature profiles and hydration heat, which were tested by using a developed semi-adiabatic test equipment. Currently, the temperature profiles of cement slurry system were studied by the initial temperature (T-i), temperature rise (T-r), maximum temperature (T-m), and the hydration time (t(m)) corresponding to the maximum temperature, respectively. Moreover, the investigations of the influences of fly ash and slag on the strength property of cement stone were investigated. Then, a novel low hydration heat cement slurry system CFS1-1 used in natural gas hydrate formation was developed by the mass ratio of 2: 1: 1 (cement: fly ash: slag). Simultaneously, the initial hydration process of CFS1-1 was investigated by low field NMR, the rheological and thickening properties of CFS1-1 were also studied. Besides, some other application performances, such as density, fluidity, stability and consistency, were also studied. As a result, it was found that the application performances of CFS1-1 meet the cementing requirement of hydrate formation. In addition, the effective and reasonable utilization of industrial waste materials were also realized during this study.",16,18,2
Hydrate,Order,"Xu, Jian-gen; Qiu, Zheng-song; Zhao, Xin; Zhong, Han-yi; Li, Gong-rang; Huang, Wei-an",Synthesis and characterization of shale stabilizer based on polyethylene glycol grafted nano-silica composite in water-based drilling fluids,Polyethylene glycol grafted nano-silica composite (PEG-NS); Wellbore instability; Water-based drilling fluids; Shale stabilizer; Pressure transmission,WELLBORE STABILITY; PERFORMANCE; NANOCOMPOSITE; HYDRATION; MECHANISM,"In order to solve wellbore instability problems in the drilling process, high-performance shale stabilizers in waterbased drilling fluids are essential. In this paper, a novel shale stabilizer based on polyethylene glycol grafted nanosilica composite (PEG-NS) was successfully synthesized. Conventional techniques were used to characterize PEGNS including Flourier transform infrared spectroscopy (FT-IR), scanning electron microscope (SEM), transmission electron microscopy (TEM), particle size distribution (PSD) and thermogravimetric analysis (TGA). The results showed that the structure of PEG-NS was in agreement with the design objective. The particle size of PEG-NS ranged from 110 to 434 nm, and PEG-NS had good thermal stability. Pressure transmission test, pore structure characterization of shale, rolling recovery test were applied to evaluate the comprehensive performance of PEGNS as a novel shale stabilizer. The experimental data indicated that PEG-NS could effectively retard the pore pressure transmission and reduce the permeability of shale sample. PEG-NS could adsorb onto the shale surface and a dense plugging film could finally coat on it. Moreover, PEG-NS also exhibited better inhibition performance compared with that of potassium chloride (KCl) and polymeric alcohol (JHC) at the same concentration. Hence, PEG-NS could be a good shale stabilizer in water-based drilling fluids for drilling reactive shale formations.",49,52,10
Hydrate,Order,"Wang, Zhiyuan; Zhao, Yang; Zhang, Jianbo; Pan, Shaowei; Yu, Jing; Sun, Baojiang",Flow assurance during deepwater gas well testing: Hydrate blockage prediction and prevention,Deepwater; Gas well testing; Flow assurance; Hydrate blockage; Hydrate Blockage Free Window,DEPOSITION; MODEL,"Hydrates cause serious flow assurance problems during deepwater operations (e.g. well testing). In order to efficiently prevent wellbore/pipeline blockage, it is of great importance to have a good understanding of hydrate formation, deposition and blockage behavior in the flowline. In this work, a model is developed to describe the development of hydrate blockage in the wellbore. The results indicate a non-uniform hydrate layer is formed on the inner wall along the testing tubing during deepwater gas well testing. With the proposed model, the position where hydrate blockage is most likely to occur can be identified. The blockage severity in terms of dimensionless hydrate layer thickness can also be assessed. Based on the model, a method is developed to prevent hydrate blockage with lower inhibitor consumption. We recommend that testing operations should be run within the Hydrate Blockage Free Window (HBFW). The HBFW refers to the period from the beginning of testing operations to the moment when a significant pressure drop increase is encountered. Implementation procedure of the proposed method is developed and further illustrated through case studies. The inhibitor consumption is much lower compared with the current over-inhibition THI-based method. This work provides possible ways to overcome the shortcomings of the current over-inhibition THI-based method.",32,32,4
Hydrate,Possibility,"Wang, Zhiyuan; Zhao, Yang; Zhang, Jianbo; Pan, Shaowei; Yu, Jing; Sun, Baojiang",Flow assurance during deepwater gas well testing: Hydrate blockage prediction and prevention,Deepwater; Gas well testing; Flow assurance; Hydrate blockage; Hydrate Blockage Free Window,DEPOSITION; MODEL,"Hydrates cause serious flow assurance problems during deepwater operations (e.g. well testing). In order to efficiently prevent wellbore/pipeline blockage, it is of great importance to have a good understanding of hydrate formation, deposition and blockage behavior in the flowline. In this work, a model is developed to describe the development of hydrate blockage in the wellbore. The results indicate a non-uniform hydrate layer is formed on the inner wall along the testing tubing during deepwater gas well testing. With the proposed model, the position where hydrate blockage is most likely to occur can be identified. The blockage severity in terms of dimensionless hydrate layer thickness can also be assessed. Based on the model, a method is developed to prevent hydrate blockage with lower inhibitor consumption. We recommend that testing operations should be run within the Hydrate Blockage Free Window (HBFW). The HBFW refers to the period from the beginning of testing operations to the moment when a significant pressure drop increase is encountered. Implementation procedure of the proposed method is developed and further illustrated through case studies. The inhibitor consumption is much lower compared with the current over-inhibition THI-based method. This work provides possible ways to overcome the shortcomings of the current over-inhibition THI-based method.",32,32,4
Hydrate,Possibility,"Yue, Ye; Chen, Shuya; Wang, Ziqi; Yang, Xianyu; Peng, Yangdong; Cai, Jihua; Nasr-El-Din, Hisham A.",Improving wellbore stability of shale by adjusting its wettability,Shale Water-based mud (WBM); Wellbore stability; Wettability; Contact angle; Pressure transmission test (PTT),WATER; ADSORPTION; PRESSURE; MODEL; MUD,"The possibility of improving wellbore stability of shale by adjusting its wettability was investigated. First, an optimized surfactants combination (0.2 wt% cetyltrimethylammonium bromide (CTAB) plus 0.1 wt% sodium dodecyl benzene sulfonate (SDBS)) was screened out that could effectively reduce the surface tension of the water-based mud (WBM) or fresh water, and increase the contact angle with shale. Then, regular tests on viscosity, filtration, lubrication, water activity, and special tests on linear swelling, rolling recovery rate, temperature tolerance, salts, and active cuttings tolerance, along with pressure transmission test (PTT) of shale were conducted to evaluate the performance of the optimized surfactants combination. Results show that the WBM's surface tension could be decreased from 45.1 to 20.0 mN/m and the contact angle on the shale could be increased from 34.5 to 63.5 degrees. The optimized surfactants combination could also improve the WBM's performance to inhibit shale hydration. The WBM in the presence of the optimized surfactants combination had good tolerance to a pollutants complex (0.8 wt% CaCl2, 0.8 wt% MgCl2, 5 wt% sodium bentonite, and 10 wt% NaCl) and could withstand a high temperature of 130 degrees C. Foaming phenomenon could be avoided by adding surfactants in the last step. PTT results show that compared with 4 wt% NaCl, the optimized surfactants combination could effectively retard the pore pressure transmission in shale and reduce its permeability by 98.6%. The addition of CTAB to the WBM or fresh water, hydrolyzed CTA(+) cation adsorbs on the surface of shale via an ionic bond, forming a hydrophilic base toward shale and a lipophilic base toward the WBM or water, thus, increasing the contact angle with shale and improve wellbore stability in shale. This paper paves a new way to address wellbore stability issues in troublesome shale formations.",30,31,0
Well Placement,,"Wang, HanYi; Sharma, Mukul M.",Modeling of hydraulic fracture closure on proppants with proppant settling,Hydraulic fracture; Fracture closure; Proppant transport; Proppants settlement; Proppant dune; Stress amplification,SHALE-GAS-PRODUCTION; CONDUCTIVITY; PROPAGATION; SYSTEMS; EMBEDMENT; TRANSPORT; DESIGN; ROCKS; WIDTH,"The placement of proppants in a hydraulic fracture is governed by slurry flow, proppant transport and settlement. The proppant distribution can significantly affect the conductivity of the hydraulic fracture, and hence will impact the productivity of hydraulic fractured wells. Past studies have investigated fracture closure on proppants by envisioning hydraulic fractures as two parallel plates with uniformly distributed proppants. However, in reality, hydraulically induced fractures are wider in the middle and narrower near the fracture edges. In addition, a proppant dune is likely to be accumulated at the bottom of the fracture because of proppant settling. As a result, fracture closure on proppants is controlled by both fracture geometry and the distribution of proppant in the fracture. This is a dynamic process where fracture geometry and the proppant pack will evolve as a function of pressure, and the associated surface contact problem is notoriously challenging to solve because of its non-linear and nonlocal nature. In this study, we proposed a general approach to model hydraulic fracture closure. The residual fracture width profile for both propped and un-propped sections can be obtained at different drawdown pressures for rocks with different clay content. The maximum stress acting on proppants can be calculated to guide the selection of proppants with appropriate strength. Most importantly, the effect of stress concentration and stress amplification can be quantified when a proppant dune or bank is formed. We also show that the traditional method of estimating the maximum stress on a proppant pack is an underestimation.",23,23,2
Well Placement,,"Roostaei, Morteza; Nouri, Alireza; Fattahpour, Vahidoddin; Chan, Dave",Numerical simulation of proppant transport in hydraulic fractures,Frac-packing; Hydraulic fracturing; Proppant transport; Shock capturing techniques,ESSENTIALLY NONOSCILLATORY SCHEMES; NEWTONIAN SLURRY; MODEL; SPHERES; WELLS,"A central issue in hydraulic fracturing treatment in petroleum wells is the transport of proppant particles by the injection fluid. In this paper, we present an innovative proppant transport model in a fixed rectangular-and elliptic-shaped slots. The proposed model is an improvement to the current modeling of proppant transport by applying a non-oscillatory numerical scheme which has high accuracy everywhere in solution domain, even close to the steep gradients. In addition, inertia, fracture wall, and concentration effects on proppant settling along with slurry evolution as a function of proppant concentration has been considered. This paper introduces the mathematical equations that govern the proppant transport phenomenon and discusses special front capturing numerical techniques, boundary conditions, coupling between proppant and slurry mass conservation equations and time stepping restrictions required for the solution stability. We incorporated published correlations obtained from proppant transport laboratory experiments in our numerical model to better capture the physics of the problem. 5th-order WENO scheme was used to avoid oscillation and diffusion at the proppant front since traditional finite difference discretization was found to be insufficient in solving the hyperbolic transport partial differential equations. Results show that the technique used in this study can capture the proppant distribution with minimum oscillation and diffusion. A series of sensitivity analysis was conducted to explore the legitimacy of these assumptions and to provide guidelines that allow more accurate predictions of the proppant and fluid transfer. Numerical results are presented to show how proppant distribution is impacted by the injection fluid viscosity, density difference between proppant particles and injection fluid, proppant size, and fluid flow injection rate. Results of the sensitivity analysis illustrate the significance of choosing appropriate viscosity of the injection fluid as small changes in the viscosity may cause noticeable effects on the concentration distribution. In addition, we found that variation of proppant size and density within a reasonable range have a modest effect on proppant concentration distribution. Furthermore, we also investigated the amount of gravity driven vertical motion of proppant which is driven by density differences ( convection) and compare it to a second gravity driven motion which is proppant settlement. Both of these two well recognized mechanisms can occur inside a fracture during proppant placement, however, the importance of each mechanism as a function of proppant injection design parameters is not fully understood.",22,23,5
Well Placement,,"Foroud, Toomaj; Baradaran, Ali; Seifi, Abbas",A comparative evaluation of global search algorithms in black box optimization of oil production: A case study on Brugge field,Oil production optimization; Black box simulator; Brugge field; Simultaneous perturbation stochastic approximation (SPSA); Ensemble base optimization (En-Opt); Particle swarm optimization (PSO); Pattern search (PS); Guided pattern search (GPS); Covariance matrix adaptation evolutionary strategy (CMAES); Differential evolution (DE); Self adaptive differential evolution (SADE),STOCHASTIC-APPROXIMATION; DIFFERENTIAL EVOLUTION; PATTERN SEARCH; WELL PLACEMENT; DESIGN,"We evaluate the application of eight different global search algorithms to the optimization of oil production from a mature field. Our focus is on algorithms that treat the reservoir simulator as a black box, which is the case for most commercial hydrocarbon reservoir simulators. The selected optimization algorithms have been divided in two categories. The first category consists of those algorithm that use approximated gradients, namely, simultaneous perturbation stochastic approximation (SPSA) and ensemble base optimization (En-Opt) methods. The second group includes derivative-free algorithms including particle swarm optimization (PSO), pattern search (PS), guided pattern search (GPS), covariance matrix adaptation evolutionary strategy (CMAES), differential evolution (DE) and self-adaptive differential evolution ( SADE). GPS algorithm has been recently introduced and applied in oil production optimization by the authors (Foroud and Seifi, 2016) while the other algorithms have been developed and coded in MATLAB software according to the most renowned studies in the literature. The selected algorithms have been applied to optimization of oil production in Brugge field. This problem is a bounded NPV optimization with 640 decision variables consist of injection and production rates over 10 years of operation and 200 linear inequality constraints. The results here show that algorithms that use approximated gradients (SPSA and En-Opt) and take advantage of physical properties of the underlying problem (GPS) are superior. Algorithms with self adaptation ability such as SADE and CMAES are the second best performers on this application. In fact, SADE which is the self adapted version of DE could achieve 7.5% more NPV than ordinary DE algorithm. Finally, in this study, GPS has been overall the most efficient algorithm with lowest number of function evaluations and the second highest NPV compared to other algorithms.",18,19,1
Well Placement,,"Liang, Tianbo; Zhou, Fujian; Shi, Yang; Liu, Xiongfei; Wang, Rui; Li, Ben; Li, Xiuhui",Evaluation and optimization of degradable-fiber-assisted slurry for fracturing thick and tight formation with high stress,Degradable fiber; Proppant settling; Proppant transport; Thick formation,PROPPANT TRANSPORT; GAS-PRODUCTION; WATER-USE; PERMEABILITY; SHALE; OIL,"Economically producing hydrocarbon from tight formations requires fracturing with a large volume of water and proppants to ensure a highly conductive fracture network. Proppant settling can hinder proppant transportation within fractures, limiting dimensions of the propped fractures and well production rates. This problem is more serious in thick formations that tall fractures are needed. In deep reservoirs with high closure stresses, using high pumping rate or viscous cross-linked gel have their own limitations, while adding degradable fibers can solve the problem. However, no visualized flow experiments have been conducted that can fill the gap between the benchtop measurements and the field tests, thus providing reliable mechanisms to guide the optimization of this technique for a chosen reservoir. In this study, a systematic screening and evaluation procedure is developed to quantify the effectiveness of degradable fibers on suspending proppants and enhancing fracture conductivity, so as to explore the mechanisms behind this technique. Results indicate that a dilute concentration of fibers in proppant slurry can double proppant placement efficiency without blocking perforation holes on the wellbore; fiber degradation leaves no residue that damages fracture conductivity; fiber degradation does not cause the closure of propped fractures even at high closure stresses.",17,18,1
Well Placement,,"Volkov, O.; Bellout, M. C.",Gradient-based constrained well placement optimization,Optimal well placement; Gradient-based optimization; Adjoint-based gradient; Single-segment deviated wellbores; Inter-well distance constraint; Well-to-boundary distance constraint,SIMULATION; ALGORITHM,"A novel well placement gradient approximation methodology is developed based on performing finite difference approximations of augmented Lagrangian derivatives within the adjoint formulation. The methodology is efficient because it requires only a pair of (forward and backward) simulations to yield a cost function sensitivity with respect to well placement coordinates. The approximated derivative is used within a Sequential Quadratic Programming (SQP) solver ensuring fast convergence and efficient constraint-handling. An extensive error analysis is performed to identify the gradient approximation errors associated with different perturbation ranges. This analysis provides information regarding the appropriate perturbation step size range needed to maintain a consistent gradient approximation while reducing errors associated with the simulation and the discretized nature of the reservoir. We validate the efficiency of the approach by solving for optimal well placement and comparing the results against two major gradient-based well placement approaches from the literature. For these cases, the methodology developed in this work delivers higher or similar final objective values while providing better performance in terms of fewer cost function evaluations. Finally, the methodology is used to find the optimal configuration of multiple deviated producers both in a binary channelized case and in a case based on the Brugge reservoir. These applications show that the proposed methodology can handle cases with more complex grid and production scenarios that require derivative information for the location of deviated wellbores in continuous space.",16,16,0
Well Placement,,"Tardy, Philippe M. J.",A 3D model for annular displacements of wellbore completion fluids with casing movement,Annular flow; Wellbore cementing; Mud circulation; Well integrity; Herschel-Bulkley fluid; Modeling,NUMERICAL-SOLUTION; ECCENTRIC ANNULUS; CEMENT PLACEMENT; NEWTONIAN FLUID; INNER CYLINDER; LAMINAR-FLOW; MUD REMOVAL; OIL-WELL,"During mud circulation and cementing operations, non-Newtonian completion fluids are injected along the wellbore annular space formed by the gap between the outer wall of the casing and the rock face. During such processes, these fluids displace each-other and follow a complex path given by pressure gradients, rheology and density contrasts, casing rotation and reciprocation and by the actual shape and orientation of the annulus. Muds and cement slurries also often exhibit a yield stress which may represent additional challenge for optimal fluid removal and cement coverage. This paper presents a novel approach to solving the 3D flow and displacement of completion fluids in the annulus. In particular, this work extends a model published in Tardy and Bittleston ( 2015) which solves the flow in the 2D axial-azimuthal plane, to now capture fluid distribution and velocity profiles across the gap width in the 3D axial-azimuthal-radial space. The new 3D model is derived using the socalled narrow-gap approximation for the momentum balance equations. This approximation provides a mean to solve the 3D velocity and concentration fields while solving a 2D-only elliptic pressure equation, which is significantly faster to solve than the original 3D pressure equation, and without suffering any significant loss of accuracy.",16,16,0
Well Placement,,"Karkevandi-Talkhooncheh, Abdorreza; Sharifi, Mohammad; Ahmadi, Mohammad",Application of hybrid adaptive neuro-fuzzy inference system in well placement optimization,Well placement optimization; Genetic algorithm; Particle swarm optimization; Adaptive neuro-fuzzy inference system; Reservoir opportunity index,HIGH-PRESSURE; ALGORITHM; NETWORK,"Well placement optimization as a key factor in field development, is one of the reservoir management cycles, which aims to economize oil and gas production from the reservoir. One of the reservoir development scenarios is determining parts of the reservoir in which hydrocarbons have not been drained completely. After determination of these areas, some new wells are drilled to improve oil production. In this study, a new model based on adaptive neuro-fuzzy inference system (ANFIS) for optimum well placement is proposed. Also, an application of opportunity index (OI) concept is used to develop this model. Using particle swarm optimization (PSO) and genetic algorithm (GA) as population based algorithms, the ANFIS model was optimized. In order to develop and validate the proposed AFNIS-PSO model, a large number of simulation runs were performed in synthetic models. In this study, the proposed model was applied in both synthetic and standard models to find the best location for new production wells. The Tenth SPE model as a standard model was used to evaluate the performance and accuracy of ANFIS-PSO model. The performance of new method compared to well placement optimizer algorithms, which is the combination of commercial flow simulator and evolutionary algorithms, was investigated in terms of the number of simulations and maximum net present value (NPV). Finally, the simulation results show that the proposed ANFIS model was able to achieve better results with fewer simulation runs and therefore improving the computational efficiency.",15,15,0
Well Placement,,"Khan, Rizwan A.; Awotunde, Abeeb A.",Determination of vertical/horizontal well type from generalized field development optimization,Field development; Well placement; Well type; Rate optimization; Well spacing,JOINT OPTIMIZATION; PLACEMENT,"Field development planning entails determination of the optimal number of wells (horizontal/vertical), well types (producer/injector), well locations, and well controls. The numerous variables to be estimated and the reservoir geological uncertainty complicate the problem of determining the optimal development plan. The improvements in computational science have advanced the use of automated optimization for field development decisions. In this paper, we present a generalized field development optimization methodology for estimating vertical and horizontal well-types in developing a hydrocarbon reservoir. Two approaches for the generalized field development optimization are presented. One approach is based on the well control zonation (WCZ) procedure; the other is based on the mixed integer non-linear programming (MINLP) procedure. In the WCZ procedure, five zones were identified, each signifying a region of either horizontal injection wells, vertical injection wells, no wells, vertical production wells or horizontal production wells. In the MINLP approach, separate variables were defined for the determination of the well type. Additionally, we present an efficient method to constrain the minimum well spacing of the horizontal and vertical wells to predetermined parameters. The aim was to optimize the number of wells, the well types, the well locations and the well controls (production rates). These operational variables were estimated simultaneously. Particle swarm optimization (PSO) algorithm was used as an optimizer to determine the optimal parameter values. The WCZ and MINLP approaches were tested with two examples to determine which methodology was more effective. The results indicated that both methods could successfully determine the optimal parameters while satisfying the spacing constraints imposed by the user. The comparison of the results showed that the WCZ approach was more effective than the MINLP approach.",15,15,0
Well Placement,,"Nath, F.; Kimanzi, R. J.; Mokhtari, M.; Salehi, S.",A novel method to investigate cement-casing bonding using digital image correlation,Casing/cement bonding; Water-cement ratio; Deformation; Strain development; Digital image correlation; Fracture,CAKE-SOLIDIFICATION-AGENTS; MUD; OIL,"The main focus of current industry practices on the cementing of oil and gas wells is short-term cement-design goals such as high strength, adequate pumpability and proper placement of cement in the wellbore. However, the bond between cement and casing is a major factor for long-term integrity of wellbore which requires more attention with the current increasing trend in horizontal drilling and hydraulic fracturing operations in unconventional resources. These wells experience various kinds of forces throughout their life in which the casing and cement bond can play a critical role in the integrity or failure of these wells. In this paper, we apply digital image correlation (DIC) technique to monitor strain development over the surface of a casing filled with cement while it is diametrically compressed. In this technique, the casing/cement sample is painted with random white and black speckles and the surface of sample is recorded by camera. Finally, strain development with time is calculated using image processing technique. This visualization helps to find out the points of weakness for strain accumulation which eventually end up for fracture initiation and propagation. In this laboratory setup, the tensile strain accumulation is the highest on the casing/cement interface 90-degree away from casing/loading point and the strain gradually increases at the casing/cement interface toward the casing/loading point. Then there is fracture generation at the center of cement sample propagating toward casing/loading point. We also review the impact of cement contamination, barite and water-cement ratios on cement/casing bonding and their associated DIC results.",14,14,0
Mercury Porosimetry,,"Wang, Xixin; Hou, Jiagen; Song, Suihong; Wang, Dongmei; Gong, Lei; Ma, Ke; Liu, Yuming; Li, Yongqiang; Yan, Lin",Combining pressure-controlled porosimetry and rate-controlled porosimetry to investigate the fractal characteristics of full-range pores in tight oil reservoirs,Tight oil reservoir; Pore size distributions; Fractal characteristics; Mineral composition; Mercury intrusion porosimetry,NUCLEAR-MAGNETIC-RESONANCE; PERMIAN LUCAOGOU FORMATION; SIZE DISTRIBUTION; ORDOS BASIN; SONGLIAO BASIN; GAS SANDSTONES; JUNGGAR BASIN; JIMUSAER SAG; DIMENSION; SHALE,"Tight oil reservoirs have the characteristics of wide pore size range and complex pore system. The understanding of pore characteristics is the basis for studying the accumulation and migration of oil and gas. To better study the fractal characteristics of full-range pores in Lucaogou tight oil reservoir, scanning electron microscopy (SEM) and mercury intrusion porosimetry (MIP) were used to obtain the pore size. XRD was used to obtain the mineral composition. In addition, fractal analysis was performed on the samples based on MIP data. The results show fracture pore (FP), residual interparticle pore (RIP), dissolution pore (DP) and clay dominated pore (CDP) are the main pore types. The interparticle pores is commonly largest in size, followed by dissolution pores. Quartz and feldspar play dominant roles in the composition in Lucaogou tight oil reservoir. The full-range pore size distribution (PSD) curves ranged from 3.6 nm to 400 mu m with two main distribution intervals. The fractal dimensions (D-1, D-2 and D-3) reflect the complexity of CDPs, DPs and RIPs, respectively. The average values of fractal dimensions were 2.88, 2.8 and 2.56, the smaller pores have more complex pore system. The pore structure of clay dominated pores is most complex. The more complex the pore structure, the worse the reservoir performance. Quartz shows negative correlation with D-3, Clay shows positive correlation with D-1, and feldspar is positively correlated with D-2. D-1, D-2 and D-3 are negatively correlated to porosity, D-1 shows a strong negative correlation with permeability.",68,70,6
Mercury Porosimetry,,"Wang, Boyang; Qin, Yong; Shen, Jian; Zhang, Qiusheng; Wang, Gang",Pore structure characteristics of low- and medium-rank coals and their differential adsorption and desorption effects,Low- and medium-rank coal; Fractal characteristics in different stages; Adsorption and desorption difference; Desorption stage,FRACTAL CHARACTERISTICS; METHANE ADSORPTION; SORPTION CAPACITY; GAS-ADSORPTION; LIGNITE; BASIN; TRANSPORT; RESERVOIR; MOISTURE; CO2,"The pores and methane adsorption-desorption characteristics are different between low- and medium-rank coal. For this paper, mercury intrusion porosimetry and isothermal adsorption experiments were carried out on thirteen coal samples with R-o,R-max between 0.22% and 0.98%. To evaluate the effect of the pore structure on coal permeability, we calculated the multi-scale fractal dimensions according to classic geometry models and discussed factors influencing pore fractals, including metamorphism degree, ash yield, and the content of vitrinite (huminite). Three key pressures in the stage of depressurization were calculated on the basis of Langmuir adsorption theory, and the influencing factors were discussed, including metamorphism degree, fractal dimension, and moisture content. The results show that pores of the coal can be divided into three types according to the pore diameter boundaries of 6,000 nm and 100 nm. The multi-scale fractal dimensions of coal pores (D-1, D-2, D-3) are in the range of 2.341-2.836, 2.041 to 2.476, 2.237 to 2.656, respectively. The pore fractal dimension (D-1) is controlled by the degree of metamorphism, and D-3 is mainly affected by ash yield, the content of vitrinite (huminite), and the degree of metamorphism. The adsorption of low-and medium-rank coal is a step-by-step control mode under the control of coal metamorphism, in which lignite mainly depends on the moisture content, and long-flame coal-gas coal mainly depends on the adsorption-diffusion hole (< 100 nm) pore structure. The lower the fractal dimension of adsorption pore, the better the adsorption. The higher the fractal dimension of the seepage pore, the better the seepage. Four desorption stages of the desorption process are subdivided according to three critical pressure points (starting pressure, transition pressure, and depletion pressure). The different critical pressure points are mainly affected by the degree of coal metamorphism, the pore structure characteristics of the primary seepage pore, and the moisture content. Larger Langmuir volume (V-L) and ratio of Langmuir constants (1/P-L) are beneficial to earlier advent of steady production stage, whereas it is also possible that the declining production stage may occur ahead of schedule.",36,39,19
Mercury Porosimetry,,"Wu, Hao; Zhang, Chunlin; Ji, Youliang; Liu, Ruie; Wu, Heng; Zhang, Yunzhao; Geng, Zhi; Zhang, Yilou; Yang, Jiaqi",An improved method of characterizing the pore structure in tight oil reservoirs: Integrated NMR and constant-rate-controlled porosimetry data,Tight sandstone; Pore structure; Nuclear magnetic resonance; Constant-rate-controlled porosimetry; Permeability prediction,NUCLEAR-MAGNETIC-RESONANCE; TRIASSIC YANCHANG FORMATION; MERCURY INTRUSION POROSIMETRY; MISSISSIPPIAN BARNETT SHALE; FORMATION CHANG 7; ORDOS BASIN; PERMEABILITY ESTIMATION; SIZE DISTRIBUTIONS; THROAT STRUCTURE; GAS-ADSORPTION,"Tight oil reservoirs have an ultrafine pore structure with a large heterogeneity, which requires the integration of multiple techniques to characterize pore structure characteristics systematically and, therefore, to gain a better understanding of reservoir quality. Tight oil sandstone samples from the Upper Triassic Yanchang Formation in the Ordos basin were measured by nuclear magnetic resonance (NMR), constant-rate-controlled mercury porosimetry (CMP) and field emission scanning electron microscopy (FE-SEM) to investigate the pore structure characteristics and their control on petrophysical properties. Various types of pores from intergranular pores, dissolution pores, and intercrystalline pores to small microfractures occurred in the studied tight sandstones, which indicates that the NMR T-2 distributions may be unimodal or bimodal in behaviour with a wide range. The short components of the T-2 distributions match the CMP-derived throat size distributions regarding the dimensions, width and shape of the curves. We combined CMP and NMR to uncover the total pore size distribution; the size distributions of the throat and pore body range from 0.01 to 1 mu m and from 0.1 mu m to tens of microns respectively, which match the FE-SEM results. The pore body-to-throat ratio may be the important factor affecting the free water saturation in the pore body, which, in turn, is probably associated with the mineralogy of tight sandstones, in particular, the quartz, feldspar and clay mineral contents. The pore radius of 0.3-0.5 mu m is the percolation threshold. The seepage porosity rather than total porosity overwhelmingly dominates the permeability, which, in turn, relates to the pore types, i. e., mesopores and macropores. An improved permeability prediction model is presented for tight oil reservoirs based on the contribution from different pore size intervals to the permeability. This model has a distinctly better performance than the classic models such as the Timur-Coates and SDR models and may be generalized to other similar reservoirs with ultrafine pore structures and significant volumes of clay minerals.",35,39,3
Mercury Porosimetry,,"Lu, Guanwen; Wang, Jilin; Wei, Chongtao; Song, Yu; Yan, Gaoyuan; Zhang, Junjian; Chen, Guanghuan",Pore fractal model applicability and fractal characteristics of seepage and adsorption pores in middle rank tectonic deformed coals from the Huaibei coal field,Tectonic deformed coal; Seepage pore; Adsorption pore; Fractal dimension; Fractal model applicability; Heterogeneity,WATER SORPTION BEHAVIOR; GAS-ADSORPTION; NONINTEGER DIMENSIONS; MERCURY POROSIMETRY; SURFACE; METHANE; DEFORMATION; INTRUSION; CHEMISTRY; SYSTEMS,"Middle rank tectonic deformed coal samples were screened from the Xutuan and Qinan coal mine in the Huaibei coal field, Anhui Province, North China. Based on mercury injection capillary pressure analysis and nitrogen sorption experiments using the Brunuaer-Emmett-Teller analysis, pore structure characteristics and applicability of the Sierpinski, Menger, Thermodynamics, and Frenkel-Halsey-Hill models for seepage and adsorption pore description were analyzed, as well as the fractal characteristics of the two types of pores. Several conclusions have been achieved. 1) The Sierpinski model can characterize the heterogeneity of seepage pores in tectonic deformed coals, and the thermodynamic model can be used for referencing and comparative analysis. The Frenkel-Halsey-Hill model can be used to describe the heterogeneity of adsorption pores, and the Sierpinski model can be a supplement. However, the Menger model is not suitable for characterizing the pore heterogeneity of coal because its fractal dimension exceeds three, and the standard deviation is larger than the others. 2) The fractal dimension of adsorption pores increases while seepage pores decreases, with the enhancement of tectonic deformation. The heterogeneity of adsorption pores in the cataclastic, schistose and scaly coals are weaker than that of seepage pores (D-s2 < D-s1), the heterogeneity of the adsorption pores in wrinkle coal is similar to that of seepage pores (D-s2 approximate to D-s1), whereas the adsorption pores' heterogeneity in mylonitic coal is stronger than that of seepage pores (D-s2 > D-s1).",32,33,12
Mercury Porosimetry,,"Liu, Kouqi; Ostadhassan, Mehdi; Kong, Lingyun",Multifractal characteristics of Longmaxi Shale pore structures by N-2 adsorption: A model comparison,N-2 adsorption; BJH model; DFT model; Shale; Multifractal; Comparison,TECTONICALLY DEFORMED COALS; SICHUAN BASIN; NITROGEN ADSORPTION; MERCURY POROSIMETRY; SIZE DISTRIBUTIONS; FRACTAL DIMENSION; ARGON ADSORPTION; POROUS MATERIALS; GAS-ADSORPTION; CHINA,"N-2 adsorption is one of the most widely used techniques to assess pore structures of shale samples due to its ability for characterizing pores in nanoscale. Various models have been developed to quantify pore structures based on adsorption isotherms. In this regard, using a suitable model can give us more accurate pore structure information. The Barret, Joyner and Halenda (BJH) model along with density functional theory (DFT), two most frequently used ones for pore structures of shales, employed on Longmaxi shale samples and compared. BJH model can be divided into two sub-models: adsorption (BJHAD) and desorption (BJHDE). First, the multifractal analysis was used to quantify the heterogeneity of pore size distributions derived from these models. Second, partial least regression analysis (PLS) was employed to quantify the correlations between pore structures and rock compositions. The results showed that pore structures (volume and surface area) and pore heterogeneity derived from BJHAD, BJHDE and DFT model would differ. In addition, PLS results indicated that minerals (except dolomite and clay) and organic matter would correlate positively while clay minerals negatively with pore surface area and volume independent of the method that was used. Finally, the comparison of results from these three methods demonstrated that DFT model is superior to BJHAD and BJHDE for pore structure characterization in shale gas formations.",27,30,11
Mercury Porosimetry,,"Krakowska, P.; Puskarczyk, E.; Jedrychowski, M.; Habrat, M.; Madejski, P.; Dohnalik, M.",Innovative characterization of tight sandstones from Paleozoic basins in Poland using X-ray computed tomography supported by nuclear magnetic resonance and mercury porosimetry,Computed X-ray tomography; Tight sandstones; Nuclear magnetic resonance; Mercury porosimetry; Semivariograms,RESERVOIR PROPERTIES; SOURCE ROCKS; USEFUL TOOL; MICROTOMOGRAPHY; PERMEABILITY; GENERATION; MODELS,"Computed X-ray tomography, nuclear magnetic resonance spectroscopy and mercury porosimetry are key experimental methods for detailed pore space characterization of low porosity and low permeability rocks. Calculations dedicated to bones parametrization were carried out and tested on tight sandstones in order to get the quantitative information about pore space structure. Innovative approach in estimating pore throat diameter is introduced based on best-fit ellipsoid's radiuses. Application of semivariogram for pores location allows assessing the heterogeneity in pore space structure. Sphericity determined based on enclosed volume and surface area is a more creditable parameter in comparison to parameter reflecting the pore roundness calculated from moments of inertia. Undeniable CT advantage is a possibility to perform 3D pore space visualization what confirmed the usefulness of quantitative parameters. New software poROSE was presented as porous materials examination software for images qualitative and quantitative interpretation.",24,26,4
Mercury Porosimetry,,"Hosseini, Mehdi; Tavakoli, Vahid; Nazemi, Maziyar","The effect of heterogeneity on NMR derived capillary pressure curves, case study of Dariyan tight carbonate reservoir in the central Persian Gulf",Pore facies; NMR log; MICP data; Pore network; Pore throat size; Tight carbonate,PORE SYSTEM CHARACTERIZATION; MERCURY POROSIMETRY; SOUTHERN IRAN; MIDDLE-EAST; ROCKS; LOGS; LIMESTONES; EVOLUTION; GEOMETRY; OFFSHORE,"The porous network controls the behavior of fluids in the reservoir rocks. In carbonate reservoirs fluid flow characteristics do not certainly follow initial sedimentary fabrics. Therefore in these reservoirs, the properties of the porous network should be used in determining the facies. In this study, using a combination of petrographic, reservoir petrophysical and reservoir engineering data, porous network in Aptian-Albian Dariyan carbonates have been studied in one of the central Persian Gulf fields. Accordingly, four pore facies were determined by capillary pressure curves from mercury injection and nuclear magnetic resonance data in four different types of lithology with different microfacies. Also, 13 different petrophysical parameters of these curves derived from both methods and compared with each other. A clear trend was observed in reducing the reservoir quality from pore facies 1 to pore facies 4. The performance of the capillary pressure curves obtained from mercury injection and nuclear magnetic resonance and their derived parameters in 4 facies and the effect of lithology on these curves have been investigated. Results showed that the porosity of the NMR is completely independent of lithology and complexity of the porous system, while the permeability-dependent parameters are largely influenced by both lithology and pore system structure. It was also shown that the NMR curves are a suitable tool for determining the pore facies and their petrophysical parameters in homogeneous tight carbonate lithology with a simple porous system.",19,19,2
Mercury Porosimetry,,"Njiekak, Gautier; Schmitt, Douglas R.; Kofman, Randolf S.","Pore systems in carbonate formations, Weyburn field, Saskatchewan, Canada: Micro-tomography, helium porosimetry and mercury intrusion porosimetry characterization",Carbonate rocks; X-ray micro-computed tomography; Helium porosimetry; Mercury porosimetry,RAY COMPUTED-TOMOGRAPHY; ROCK PHYSICS; INDIANA LIMESTONE; SCALE STRUCTURE; POROSITY; IMAGES; MICROTOMOGRAPHY; MICROSTRUCTURE; PERMEABILITY; GEOMETRY,"Capturing the multi-scale porosities inherent in carbonate rocks is critical for the understanding of their transport and elastic properties and how these are affected by pore and confining pressures. To ensure accuracy of such an assessment, sample selection, sample preparation and measurement techniques need to be fit for purpose. In the recent years, micro-computed tomography (micro-CT) has been increasingly used for the analysis of pore characteristics in rocks. One of the recurrent problem with respect to rock physics characterization, however, is that the values of porosity it can determine often differ from conventional laboratory measures. Today, for example, to our knowledge, there is no systematic workflow that will allow for a full characterization of microstructure details of carbonates. We expect the development of such workflow to go through testing and comparison of different porosity measurement strategies. In this regard, we provide in this paper a number of examples where micro-CT was used in addition to standard petrophysical measurements (helium and mercury intrusion porosimetry) to get estimates of porosity in dolomites and limestones from the Weyburn oilfield in southwestern Saskatchewan, Canada. Optical microscopy and SEM were used to have an overview of the pore shapes and sizes and, whenever needed, to condition the micro-CT image segmentation parameters. On about half of the studied twelve samples, the micro-CT porosity agrees within similar to 2% with the mercury and helium porosities and is lower (up to 16%) on the rest of the samples. On an oolitic limestone, we show how combining micro-CT and mercury porosimetry can allow quantitative estimation of connected and non-connected pores.",15,17,2
Mercury Porosimetry,,"Chen, Fangwen; Lu, Shuangfang; Ding, Xue; He, Xipeng; Xing, Huilin",The splicing of backscattered scanning electron microscopy method used on evaluation of microscopic pore characteristics in shale sample and compared with results from other methods,Microscopic pore; Longmaxi Shale; Frequency; Pore volume; Specific surface area,SIZE DISTRIBUTION; GAS-ADSORPTION; MERCURY INTRUSION; SURFACE-AREA; POROSITY; RESERVOIRS; CHINA; PHYSISORPTION; USANS/SANS; DENSITY,"The splicing of backscattered scanning electron microscopy (SB-SEM) method was applied to evaluate the microscopic pore characteristics of the Lower Silurian Longmaxi Shale samples from Py1 well in Southeast Chongqing, China. The results from SB-SEM, including frequencies, volumes and specific surface areas of organic and inorganic pores with different sizes, were compared with those of low temperature nitrogen adsorption/ desorption (LTNA) and mercury intrusion porosimetry (MIP). The results show that the changes in organic and inorganic surface porosity with increasing image area estimated from the SB-SEM method become almost stable when the SB-SEM image areas are larger than 0.4 mm(2), which indicates that the heterogeneities of organic and inorganic pore volumes in shale samples can be largely overcome. This method is suitable for evaluating the microscopic pore characteristics of shale samples. Although the SB-SEM underestimates the frequencies, volumes and specific surface areas of pores smaller than its resolution, it can obtain these characteristics of pores larger than 100 nm in width, which are not effectively evaluated by the LTNA method and are underestimated by the MIP method.",15,17,2
Flow Units,,"Mirzaei-Paiaman, Abouzar; Ostadhassan, Mehdi; Rezaee, Reza; Saboorian-Jooybari, Hadi; Chen, Zhangxin",A new approach in petrophysical rock typing,Petrophyisics; Rock typing; Hydraulic flow unit; Kozeny-carman; Reservoir characterization; FZI-Star; PSRTI,HYDRAULIC FLOW UNITS; SPONTANEOUS IMBIBITION; CAPILLARY-PRESSURE; PERMEABILITY; RESERVOIR; CENTRALITY; SELECTION,"Petrophysical rock typing in reservoir characterization is an important input for successful drilling, production, injection, reservoir studies and simulation. In this study petrophysical rock typing is divided into two major categories: 1) a petrophysical static rock type (PSRT): a collection of rocks having the same primary drainage capillary pressure curves or unique water saturation for a given height above the free water level, 2) a petrophysical dynamic rock type (PDRT): a set of rocks with a similar fluid flow behavior. It was shown that static and dynamic rock types do not necessarily overlap or share petrophysical properties, regardless of wettability. In addition, a new index is developed to define PDRTs via the Kozeny-Carman equation and Darcy's law. We also proposed a different index for delineation of PSRTs by combining the Young-Laplace capillary pressure expression and the Kozeny-Carman equation. These new indices were compared with the existing theoretical and empirical indices. Results showed that our indices are representatives of previously developed models which were also tested with mercury injection capillary pressure, water-oil primary drainage capillary pressure, and water-oil relative permeability data on core plugs from a highly heterogeneous carbonate reservoir in an Iranian oil field. This study enabled us to modify the conventional J-function to enhance its capability of normalizing capillary pressure data universally.",62,62,1
Flow Units,,"Riazi, Zahra",Application of integrated rock typing and flow units identification methods for an Iranian carbonate reservoir,Rock typing methods; Carbonate reservoir; Flow unit identification; Efficient type of wells; Level of up scaling; Graphical tools,PERMEABILITY; POROSITY,"During the exploration phase of any oil and gas field, recognition of borehole type, its completion approach, and understanding of the future reservoir performance are directly interrelated to identification of the reservoir's rock types and flow units. Identifying different geological events, lithofacies characteristics, diagenetic processes, and level of heterogeneity can be the first step for knowing rock types and consequently flow units in its reservoir layers. These result in an acceptable dynamic model of a field development and relatively reliable production forecasts. Focus of this paper is on rock typing and flow unit classification for a carbonate reservoir of a green field. Four petrophysical methods including Rock Fabric Number (RFN), Winland porosity-permeability plot (R35), Reservoir Quality Index/Flow Zone Indicator (RQI/FZI), and Bulk Volume Water (BVW) were implemented on four exploration wells. At the next step graphical tools (Stratigraphic Modified Lorenz Plot (SMLP), Modified Lorenz Plot (MLP) and Stratigraphic Flow Profile (SFP) were used to locate established flow units and rock types within the reservoir column. Lastly, variation and frequency of defined flow units have been used to achieve a satisfactory understanding of the level of heterogeneity and the possible effect on well production. Integration of defined flow units by different methods inferred a high level of heterogeneity in the studied reservoir and the BVW was chosen as the best method of rock typing for feeding to the static model. The BVW method assists in considering main variation of reservoir properties meanwhile avoid complexity of models. During modelling, choosing an optimum number of rock types for fine-grid model with small dimensions cells (50 m*50 m*1 m) can help to separate different layers vertically without necessity of dividing them to many distinct subzones. Usually, groping numerous subzones during up scaling is confusing and complicate; likewise, in a coarse grid may omit or mix some frequency of thin seal and productive subintervals in reservoir zones. Comparing achieved flow unit classification with outcomes of production test showed in this reservoir with high level of heterogeneity an adequate type of well is vertical and highly deviated ones, moreover, dual completion can be the best type of production which separate high and low productive zones.",28,28,0
Flow Units,,"Wang, Xidong; Yang, Shaochun; Zhao, Yongfu; Wang, Ya","Lithology identification using an optimized KNN clustering method based on entropy-weighed cosine distance in Mesozoic strata of Gaoqing field, Jiyang depression",Machine learning; Lithology identification; KNN clustering; Statistic method; Weighed cosine distance,CLASSIFICATION; FACIES,"KNN (K-Nearest Neighbors) clustering in machine learning is a very efficient clustering method applied in lithology identification, reservoir type recognition, flow unit classification and so on, but it is not working consistently because of its inherent limitation, like its initial center selection and clustering center shift caused by outliers. Moreover, KNN clustering is based on a mathematical algorithm, and does not necessarily cluster the space due to the geological and petrophysical aspects. To address this issue, an optimized KNN clustering method based on weighed cosine distance is proposed to better fit the lithology model. To deal with the problem of the initial center selection and outliers, a set of statistic methods is conducted. A set of data, sampled by different logging series, is made use to feature information about lithology as much as possible. New distance algorithm selection based on geology model and well logging data similarity attribute is obtained when utilizing. Taking the Mesozoic strata in Gaoqing field as example, a procedure fitter for utilization of machine learning technique in lithology identification is carried on, and the overall accurate rate of the optimized K-means clustering in lithology identification raised nearly 10% compared with the traditional K-means clustering especially in the differentiation between fine-sand and coarse-grained clastic sand. The predicted lithology match the core plugs better than the traditional KNN clustering.",23,26,6
Flow Units,,"Qu, Ming; Hou, Jirui; Qi, Pengpeng; Zhao, Fenglan; Ma, Shixi; Churchwell, Lauren; Wang, Qian; Li, Hui; Yang, Tianyuan",Experimental study of fluid behaviors from water and nitrogen floods on a 3-D visual fractured-vuggy model,Carbonate reservoir; 3-D physical experiment; Fluid flow behavior; Water flooding; Gas flooding; Enhanced oil recovery,3-DIMENSIONAL PHYSICAL SIMULATION; CARBONATE RESERVOIRS; OIL; PERFORMANCE; INJECTION; RECOVERY; UNIT,"Tahe oil field is a fractured-vuggy carbonate oil field in China. The fluid flow behaviors in this type of reservoir are complex due to multiple flow paths through the matrix, fractures and vugs. The main challenges of production include complicated oil-water distributions, rising state of water cone in different flow units, unclear multiphase flow behaviors, and lack of understanding of the fluid flow mechanism. Based on a geological map of the Tahe oil field, a physical 3-D fractured-vuggy model was designed and fabricated. Water and gas flooding experiments were performed, while the multiphase flow behaviors were captured with a high-resolution camera system. The pressure response was also monitored at different oil displacement stages. The results show that the 3-D physical model can be used to systematically and comprehensively investigate the fluid flow behaviors during the oil displacement process. The oil-water interfaces of prolific wells rise more rapidly than that from the stripper wells, leading to an uneven distribution of internal flow fields and cross-well interferences. Water breaks through early and water channeling is more significant in fractured than vuggy wells. The oil-water flow behavior in fractured-vuggy combinations is mainly determined by fractured-vuggy structure, viscous force, wettability, and the ratio of displacement forces to gravity. During nitrogen gas flooding, gas caps occur from gas displacing the remaining oil at the top of the reservoir. The synergistic interaction between nitrogen gas and injected water contributes to additional oil recovery. This study provides a guide for improving production performance in fractured-vuggy carbonate reservoirs.",23,27,2
Flow Units,,"Keewan, Mohammed; Banat, Fawzi; Alhseinat, Emad; Zain, Jerina; Pal, Priyabrata",Effect of operating parameters and corrosion inhibitors on foaming behavior of aqueous methyldiethanolamine solutions,Foaming; Corrosion inhibitors; Gas diffuser; Amine; Gas sweetening,BUBBLE FORMATION; CARBON-STEEL; GAS; COALESCENCE; DEGRADATION; THICKNESS; INDUSTRY; COLLAPSE,"Corrosion inhibitors are one of the main causes of amine foaming in gas sweetening units. A detailed understanding of amine foaming behavior in the presence of corrosion inhibitors is of great importance if the foaming is to be minimized. In this work, a comparative study was carried out to investigate the foaming tendency and bubbles characteristics of aqueous methyldiethanolamine (MDEA) in the presence of fatty acid-based (Bis(2-Hydroxyehyl) cocoalkylamine; BHCL) and hydrocarbon-based (HCB) corrosion inhibitors. The effect of different operating parameters such as nitrogen flow rate, corrosion inhibitor concentration, foaming time, solution temperature and pore size of the gas diffuser were studied using foam scan instrument. The results showed that on increasing the foaming time, solution temperature and corrosion inhibitor concentrations, the foaming tendency increased. For BHCL, the foam height tends to decrease with a high flow rate and a small pore size of the gas diffuser. Nevertheless, the opposite trend was observed in the presence of the HCB corrosion inhibitor. Depending upon the type of corrosion inhibitors, careful optimization of the operating conditions showed a high potential to minimize amine foaming.",16,17,5
Flow Units,,"Sun, Qian; Zhang, Na; Fadlelmula, Mohamed; Wang, Yuhe",Structural regeneration of fracture-vug network in naturally fractured vuggy reservoirs,Fracture-vug network; Improved simulated annealing method; Multiple point statistics; Digital rock; Superimposing method,PORE-SPACE RECONSTRUCTION; FINITE-ELEMENT; FLOW; SIMULATION; MICROSTRUCTURE; PERMEABILITY; PREDICTION; ALGORITHM; PHASE; MODEL,"Naturally fractured vuggy carbonate reservoirs play an important role in the world's oil and gas production. Porescale modeling is treated as an important approach for unveiling the flow mechanism in carbonate reservoirs. The realistic regeneration of fractured vuggy reservoirs needs to preserve the geological structures and complex pores morphologies. Nevertheless, regeneration of such reservoirs is a great challenge because of the co-existence of fractures and vugs over a wide range of scales. In this paper, the reference fracture-vug network will be divided into two systems: matrix-fracture and matrix-vug. The two systems are reconstructed in two ways: (I), the matrixvug and matrix-fracture systems are generated by improved simulated annealing method (ISAM) and multiple point statistics algorithm (MPS), respectively; (II), both of the matrix-vug and matrix-fracture systems are generated by MPS. When applying for ISAM, the multipoint histogram mainly depends on the N-point template. The template is a unit configuration, which is considered as the characteristic of the geometric features. Based on this, we introduce the correlation coefficient matrix to determine an optimal template, and the accuracy of template selection algorithm is also discussed. The optimal template represents essential geological features of the training image, and its size is much smaller than the template size selected by entropy. Therefore, it can improve the computing efficiency while preserving the key properties of the network. Then, a superimposing method is proposed to create the fracture-vug network by combining the matrix-vug with matrix-fracture models. The superimposing method using ISAM (for matrix-vug model generation) and MPS (for matrix-fracture model generation) is called SMIM, while superimposing method using MPS (for both of matrix-vug and matrix-fracture models generation) is called SMM. Finally, the spatial connectivity, local percolation probability and patterns reproduction of the generated models are used to compare with those of the reference model. The results show that the 7-point template selected by the correlation coefficient matrix is enough to get the spatial features of the matrix-vug system. The generated fracture-vug network using the selected template is able to retrieve the patterns of training image (reference model) more accurately than other used templates. The fracture-vug network generated by superimposing method produces better results than the other methods (all named as ""direct method""). The network simulated with SMIM algorithm matches the reference model better than SMM algorithm. The probable reason maybe exist in the different generation methods used for matrix-vug systems. The local percolation probability (LPP), treated as a general geometric characterization method, is used to characterize the connectivity of measured units at a given local porosity. The results of the probability analysis show that SMIM is better in depicting the expected patterns of geological heterogeneities and in producing higher degree of connectivity of pore space than the SMM. The pattern reproduction of SMIM model is assessed by scanning the generated model, and the ratio of pattern reproduction number to that of reference model (i.e. the similarity) is around 97.28%. These results may guide the further application of the proposed method to field-scale modeling of naturally fractured vuggy reservoirs.",15,19,4
Flow Units,,"Zhao, Jian; Zhang, Guicai; Xu, Yiji; Wang, Ruihe; Zhou, Weidong; Yang, Daoyong",Experimental and theoretical evaluation of solid particle erosion in an internal flow passage within a drilling bit,Solid-liquid flow; Solid particle erosion; Internal flow passage; Drilling bit; Erosion mechanism,NUMERICAL-SIMULATION; 2-PHASE FLOW; HARD-ROCK; IMPACT; PERFORATION; VELOCITY; METALS; ENERGY; MODEL; PIPE,"In this study, a pragmatic and robust technique has been developed to experimentally and numerically evaluate solid particle erosion in an internal flow passage within a drilling bit. Experimentally, a field-scaled three-dimensional (3D) experimental setup is developed to perform erosion experiments, while the erosion rate of the internal flow passage is continuously monitored and measured. Numerically, a two-way coupled Eulerian-Lagrangian approach is employed to describe the liquid-solid flow in the internal flow passage, while a commonly used erosion model is then utilized to quantify solid particle erosion. The good agreements between experimental measurements and theoretical calculation results indicate that such integrated techniques can be used to accurately evaluate the complicated erosion behaviour. The erosion is found to be mainly distributed on the contraction surface, while, at the inlet velocity greater than 6.0 m/s, the average erosion rate is dramatically increased. The maximum unit erosion rate is increased quickly as the particle concentration is smaller than 5.0 vol %, while it is increased as the inlet angle is smaller than 23 degrees. At a low erosion rate, the optimal particle diameter is found to be 2.0 mm.",15,17,1
Flow Units,,"Ezati, Mohsen; Azizzadeh, Mehran; Riahi, Mohammad Ali; Fattahpour, Vahidoddin; Honarmand, Javad","Characterization of micro-fractures in carbonate Sarvak reservoir, using petrophysical and geological data, SW Iran",Micro-fractures; Sarvak formation; Hydraulic flow unit; FZI*; Velocity deviation log; Image logs; Anisotropy,ZAGROS MOUNTAINS; DEZFUL EMBAYMENT; THRUST BELT; ROCK; OIL; PERMEABILITY; INTENSITY; ANTICLINE; EXPONENT; OUTCROP,"In this paper, an integrated study of micro-fractures is carried out in Sarvak Formation. To achieve this goal the data from three wells (A, B and C) in one of the southwestern Iranian oil fields were used. In this study petrographic thin sections, porosity-permeability core data, image logs, Dipole Shear Sonic Imager (DSI) log, Velocity Deviation Log (VDL), Hydraulic Flow Units (HFU) concept, resistivity logs and drilling mud reports were used to identify and analyze micro-fractures in Sarvak Formation. The micro-fractures were first detected in thin sections and image logs directly, then the results of other methods in micro-fracture zones were investigated. The results show there is an abnormal trend of porosity-permeability in core data which is compatible with micro-fracture zones. Also, the relationship between micro-fractures and flow units was studied. Eight HFUs were recognized using porosity-permeability core data and FZI* (Flow Zone Indicator-Star) method. Later each of the HFUs was divided into two sub-HFUs; one of them is well-matched with the micro-fracture zones. The negative parts of VDL were in good agreement with the micro-fracture zones. The slowness anisotropy was mainly affected by the micro-fracture zones, but the energy and traveltime anisotropies were under the influence of the other phenomena such as solution seams, shale layers and borehole washouts. The fast shear wave azimuth was mainly aligned with the SHmax (maximum horizontal stress) direction, however, in micro-fracture zones, the direction suddenly changes. It was also observed that the micro-fractures do not have a considerable effect on Stoneley wave reflection, while the borehole washouts and shale layers have a great impact on this. The mud loss and mud invasion were very low in micro-fractured zones, which is related to the lack of lateral continuity of micro-fractures in the formation. The measured fracture apertures using thin section and image logs are often less than 0.1 mm, but the calculated values using Pezard-Anderson equations are very high.",14,16,0
CBM Wells,,"Wu, Xiaoguang; Huang, Zhongwei; Li, Gensheng; Li, Ran; Yan, Pengsen; Deng, Xiao; Mu, Kaiwen; Dai, Xianwei",Experiment on coal breaking with cryogenic nitrogen jet,Liquid nitrogen; Jet; Coal breaking; Coal bed methane; Drilling,LIQUID-NITROGEN; METALLIC SURFACES; VELOCITY; STIMULATION; IMPINGEMENT; TECHNOLOGY; IMPACT; ROCKS; WELLS,"Severe leakage of drilling fluid and reservoir damage due to water and solid invasion during well drilling are the key factors that restrict economic exploitation of coal bed methane (CBM) in China. To solve these issues, this paper presents a method of CBM well drilling with the assistance of cryogenic nitrogen jet, in which no aqueous phase and solid phase are contained. To determine the feasibility of coal breaking by cryogenic nitrogen jet and the effects of different parameters, such as nozzle diameter, dimensionless standoff distance, nozzle pressure difference and exposure time, we conducted corresponding rock breaking experiments on artificial and natural coals with the cryogenic nitrogen jet and the water jet. Rock breaking features and the energy consumption by the two jets were compared. The results indicate that the cryogenic nitrogen jet has better rock breaking performances and consumes less energy. Under the same conditions, the average rock erosion volume and the energy consumption with the cryogenic nitrogen jet were 18.34 times larger and 90.8% lower than those with water jet, respectively. Visible netted fractures could be created on the surface of coal samples blasted with the cryogenic nitrogen jet, and thus rock breaking could be facilitated effectively. The outstanding rock breaking performances of cryogenic nitrogen jet are attributed to three mechanisms: high-velocity jet impact, thermal shock and gasification cracking effect. In addition, under our experimental conditions, the erosion volume and depth were proportional to the pressure difference and inversely proportional to the dimensionless standoff distance. When the nozzle diameter changed from 1.5 mm to 3 mm, the increases of erosion volume were 3% at the pressure difference of 5 MPa and 41.7% at the pressure difference of 10 MPa respectively. This indicates that the effect of nozzle diameter is more significant at relatively higher pressure drops. With the increase of exposure time, both of the rock erosion depth and volume rose, while with a smoother trend. The results of this study are expected to promote the application of cryogenic nitrogen jet in CBM well drilling.",27,31,3
CBM Wells,,"Chen, Shida; Tang, Dazhen; Tao, Shu; Xu, Hao; Li, Song; Zhao, Junlong; Cui, Yi; Li, Zhao","Characteristics of in-situ stress distribution and its significance on the coalbed methane (CBM) development in Fanzhuang-Zhengzhuang Block, Southern Qinshui Basin, China",In-situ stress; Permeability; Gas resource; Gas recovery; Deep coalbed methane,RESERVOIR PERMEABILITY; DEPENDENT PERMEABILITY; GEOLOGICAL CONTROLS; WESTERN GUIZHOU; PORE PRESSURE; ORDOS BASIN; NORTH CHINA; GAS; PREDICTION; SYSTEM,"In-situ stress is a vital index on the coal reservoir permeability and coalbed methane (CBM) development. Based on 41 sets of well test data at depths (h) of 353-1273 m in Fanzhuang-Zhengzhuang Block, the distribution of in-situ stress was analyzed systematically and its effect on coal permeability was also addressed. Results show that stress fields could convert in the vertical and four ranges corresponding to the certain depth can be characterized: the sigma(H) > sigma(v) > sigma(h) type mainly occurs in the shallow and deep coal seams (< 600 m and > 825 m); From 600 to 725 m, a stress transition zone can be observed (sigma(H) approximate to sigma(v) > sigma(h)); The sigma(v) > sigma(H) > sigma(h) type is dominant within depth from 725 to 825 m. With the increase of depth, well testing permeability (k) exhibits a trend of decrease (h < 600 m, 0.055 < k < 0.91mD) - increase (600 < h < 825 m, 0.02 < k < 1.13 mD) - decrease (h > 825 m, k < 0.1 mD), the essence of which is the open and closure of pores and fractures under the control of stress regime and vertical belting. Meanwhile, the correlation between gas content and depth was also illustrated, which shows two trends at the depth of 200-825 m (increase) and 825-1400 m (decrease), respectively. Generally, the coal reservoir deeper than 825 m is characterized by high in situ stress, low permeability and low gas resource, meaning that the geological conditions for CBM development deteriorate. The gas/water production of 500 CBM wells also indicates that the gas recovery rate in deeper coal seams is poorer than that in shallower coal seams. Therefore, a series of corresponding methods for these deep CBM (> 825 m) should be taken in the future CBM development strategy.",26,26,6
CBM Wells,,"Sun, Zheng; Shi, Juntai; Zhang, Tao; Wu, Keliu; Miao, Yanan; Feng, Dong; Sun, Fengrui; Han, Song; Wang, Shan; Hou, Chenhong; Li, Xiangfang",The modified gas-water two phase version flowing material balance equation for low permeability CBM reservoirs,FMB equation; Low-permeability CBM reservoirs; Pressure-saturation relationship; Gas-water two phase flow; Matrix shrinkage,COALBED-METHANE RESERVOIRS; DYNAMIC PREDICTION MODEL; RATE-TRANSIENT ANALYSIS; SEMIANALYTICAL MODEL; MATHEMATICAL-MODEL; DESORPTION AREA; WELLS; PRESSURE; ADSORPTION; BEHAVIOR,"The flowing material balance (FMB) equation is a frequently-utilized engineering tool to extract reservoir information according to production performance of producing wells. At present, it is still significantly challenging to adapt the FMB equation to CBM reservoirs due to the existence of gas-water two phase flow, stress dependence, matrix shrinkage and gas desorption. With all my respect to previous FMB equations for CBM reservoirs, a great deal of attention has been drawn to the single water/gas flow, which can only be applied for early production stage or cannot capture the gas-water two phase flow features of general CBM reservoirs. The most recent and comprehensive research effort of FMB equation for CBM reservoirs is performed by Clarkson and Salmachi (2017), which takes the aforementioned characteristics into account. However, suffering the limitation that the pressure-saturation relationship is not available, Clarkson and Salmachi (2017) assume the saturation and pressure gradients in coal seams are negligible, i.e., the relative permeability is not incorporated in the pseudo-pressure calculation, which will inevitably lead to large deviation compared with the precise results. Notably, during the depressurization development process of low-permeability CBM reservoirs, the pressure and saturation gradients are large enough and cannot be overlooked. Thus, a robust FMB equation for gas-water two phase flow in low-permeability CBM reservoirs is still lacking in the petroleum industry and is significantly necessary to be developed. In this study, the important pressure-saturation relationship is rigorously derived in terms of the conservation of mass and momentum equations, in which the gas desorption, matrix shrinkage and stress dependence are fully coupled. Next, the developed relationship is used to calculate the gas/water phase pseudopressure and subsequently the previous FMB equation for CBM reservoirs is modified. Finally, reliability of proposed FMB equation is successfully verified against the numerical simulation with excellent agreements compared with the input reservoir properties. In addition, with the intent of further solidifying the field applicability of the modified FMB equation, the production performance of an actual low-permeability CBM well in Hancheng field, China is analyzed through the proposed FMB equation and desirable interpretation results are achieved. Incorporating the pressure-saturation relationship for the first time, the modified FMB equation can serve as a practical and robust tool to extract valuable information regarding the low-permeability CBM reservoirs.",26,30,1
CBM Wells,,"Tang, Shuling; Tang, Dazhen; Li, Song; Xu, Hao; Tao, Shu; Geng, Yunguang; Ma, Liang; Zhu, Xueguang","Fracture system identification of coal reservoir and the productivity differences of CBM wells with different coal structures: A case in the Yanchuannan Block, Ordos Basin",Comprehensive method; Fracture system identification; Coal reservoirs; Productivity difference; Coal structure; The Yanchuannan Block,METHANE PRODUCTION; PERMEABILITY; IMPACT,"Fracture system identification of coal reservoirs plays a vital role in evaluating favorable zone of coalbed methane (CBM) development and improving CBM well productivity. In order to identify the fracture system of the No. 2 coal reservoir, and to determine the productivity differences of CBM wells with different coal structures in the Yanchuannan (YCN) Block, Ordos Basin, China, a comprehensive analysis method from macroscopy to microscopy and from static to dynamic was provided in this work. Site observations on coal sections and observations under light microscope and scanning electron microscopy (SEM) were combined to understand the fracture characteristics of the coal seam, and the spatial geological model of fracture development was built. The selected logging data was conducted cluster analysis to identify the coal structures of coring wells and to predict the coal structures of non-coring wells. The analysis results show that the No. 2 coal seam has a high fracture development degree, and is dominated by type II coal structure (cataclastic coals). The coals with different structures show evident zonation on the plane, which is largely controlled by faults. The well-developed fracture system and high permeability zone mainly concentrate on the tectonic rolling areas and the areas with small faults. Furthermore, the output data of coal fine and the drainage curves of CBM wells were performed dynamic analysis to indirectly reflect the fracture system difference and the resulting productivity difference. The results indicate that the wells with poor-preserved coals tend to produce more coal fine, and the gas production has a negative correlation with coal fine amount. The productivity pattern of CBM wells can be divided into ""high yield-long-term stable yield"" and ""low yield-decline quickly"". Almost all CBM wells with type I coal structure and most CBM wells with type II coal structure have the first productivity pattern, and part wells with type II coal structure and all wells with type III coal structure present the second productivity pattern.",21,22,3
CBM Wells,,"Meng, Ya; Liu, Shimin; Li, Zhiping",Experimental study on sorption induced strain and permeability evolutions and their implications in the anthracite coalbed methane production,Permeability evolution; Sorption-induced strain; Effective stress; Anthracite,MODEL; GAS; STRESS; COMPRESSIBILITY; RECOVERY; PRESSURE; SEAMS,"The dynamic changes of strain-induced strains and permeability are two key parameters to determine the production profile of coalbed methane (CBM) wells. Recent field observations from a group of anthracite CBM wells demonstrate that the permeability dramatically changed with depletion. In addition, different drainage strategies will induce different permeability evolution due to different matrix shrinkage behaviors. We carried out a series of experimental measurements on sorption induced strain evolution and its influence on permeability evolution for anthracites using a desorption-seepage testing system. The relationship between sorption pressure and its induced strains was studied. The results show that both axial and radial strains of a coal specimen increase with continuous methane injection pressure. It was found that the strain perpendicular to the bedding plane is higher than that parallel to the bedding plane. Under constant confining and axial stresses, the effective stress decreases with the increase of methane pressure, and permeability initially drops and then rebounds with continuous methane injection. The ""check-shape"" permeability evolution was observed for all three specimens and the turning points are 4-5 MPa for the tested anthracites. It was also found that sorption swelling strain depends on both petrographical properties and the degree of coalification. The strength of coal increases with the degree of coalification. At a constant confining and axial stresses, both sorption-induced swelling strain and the mechanical-induced strain decline with increase of coal strength. The sorption-induced strain increases with increase of the organic content. During primary CBM production, the permeability of coal initially decreases before reservoir pressure reaches the critical desorption pressure and it starts to increase at low pressure at which the reservoir pressure is below the critical desorption pressure. The results have theoretical and practical significance to guide the reasonable drainage of CBM wells.",21,23,2
CBM Wells,,"Wang, Gang; Qin, Yong; Xie, Yiwei; Shen, Jian; Zhao, Long; Huang, Bo; Zhao, Wenqiang","Coalbed methane system potential evaluation and favourable area prediction of Gujiao blocks, Xishan coalfield, based on multi-level fuzzy mathematical analysis",Multi-level fuzzy mathematical analysis; Coalbed methane (CBM) system; Gujiao blocks; Potential evaluation; Favourable areas prediction,SOUTHERN QINSHUI BASIN; SOUTHEASTERN ORDOS BASIN; GEOLOGICAL CONTROLS; GAS CONTENT; JHARIA COALFIELD; WESTERN GUIZHOU; CENTRAL PART; NORTH CHINA; WELL LOGS; PERMEABILITY,"Coalbed methane (CBM) resources are abundant in Gujiao blocks, Xishan coalfield, China. However, there is little previous geological research regarding coalbed methane. Using a quantitative and qualitative index, the hydrocarbon source rocks and preservation conditions of No. 2, 8 and 9 coalbed methane systems in Gujiao blocks were evaluated through a multi-level fuzzy method. On this basis, the comprehensive favourable area of three CBM systems and multi-layer commingled production were predicted. The results showed that the comprehensive score trend of hydrocarbon source rocks in Gujiao blocks gradually increases from southeast to northwest. The comprehensive score trend of preservation conditions increases gradually from north to south. The No. 2 coalbed methane system of the Shanxi formation is given priority over level II, which is distributed in the central and southern study area. The No. 8 coalbed methane system of the Taiyuan formation is given priority over level III, followed by level IV. The No. 9 coalbed methane system of the Taiyuan formation is given priority over level II and level III, which is distributed in the central and southern study area. Most of the area is suitable for individual CBM exploitation of No. 8 coal. The favourable area for the No. 2+8 coal layer is located in parts of the central, south-western and south-eastern study area. The favourable area for No. 8+9 coal layer is located in the Dongqu well field and the southern Tunlan well field. The favourable area for No. 2+8+9 coal layer is located in the eastern Yang Zhuang well field.",20,22,8
CBM Wells,,"Kang, Junqiang; Fu, Xuehai; Gao, Lin; Liang, Shun","Production profile characteristics of large dip angle coal reservoir and its impact on coalbed methane production: A case study on the Fukang west block, southern Junggar Basin, China",Coalbed methane; Large dip angle; Production profile; Factors affecting production; Southern Junggar Basin,QINSHUI BASIN; HUAIBEI COALFIELDS; SHIZHUANGNAN BLOCK; FANZHUANG BLOCK; SHANXI PROVINCE; GAS; RANK; PERMEABILITY; WELLS; WATER,"Xinjiang, China has abundant coalbed methane (CBM) resources, where most of the CBM exists in large dip angle (LDA) reservoirs (over 50 degrees) and the production profile characteristics and the impact on CBM production are rarely studied. This paper summarizes the production profile characteristics of CBM wells in LDA reservoirs based on field production data from the Fukang west block, southern Junggar Basin. The factors affecting CBM production were qualitatively and quantitatively analysed by scatter plot and Spearman rank correlation analysis. Eclipse numerical simulation software was used to simulate the gas production in LDA reservoirs. Using field production data and numerical simulation, we found that there are two peaks in the gas production profile of high-production wells (shallow part) and one peak in moderate-(middle part) and low-production (deep part) wells in the LDA reservoir. For high-production wells, large dip angles cause large differences in the depth over a small area, resulting in significant differences in the physical parameters of the upper and lower reservoirs, especially reservoir pressure, permeability and gas content, which lead to the phenomenon of unsynchronized gas production in the upper and lower reservoirs, resulting in two gas production peaks. For moderate-and low-production wells, the reservoir pressure is high and permeability is low due to the deeper burial depth, causing the time required to reach the critical desorption pressure to be longer and the second peak in the gas production to be delayed. The scatter plots and Spearman rank correlation analysis showed that there is a clear correlation between the reservoir pressure and permeability and the gas production, which means that both parameters play a major role in controlling CBM production. We also found that reservoir pressure and permeability are directly controlled by the burial depth, which indicated large dip angles can have a significant impact on CBM production.",17,20,9
Monte Carlo,,"Zhao, Tianyi; Li, Xiangfang; Ning, Zhengfu; Zhao, Huawei; Li, Meifen",Molecular simulation of methane adsorption on type II kerogen with the impact of water content,Molecular simulation; Methane adsorption; Kerogen; Moisture content; Shale gas,SHALE-GAS; ORGANIC-MATTER; THERMODYNAMIC PROPERTIES; SORPTION ISOTHERMS; THERMAL MATURITY; BARNETT SHALE; SICHUAN BASIN; PRESSURE; CO2; CAPACITY,"Based on realistic kerogen model, the effects of water content on methane (CH4) adsorption capacity were studied qualitatively and quantitatively using the molecular dynamics (MD) and Monte Carlo (MC) simulation methods. The methane single component adsorption process under the dry condition, methane and water two components competitive adsorption on dry kerogen, and methane single component adsorption on moist conditions (0.6, 1.2, 1.8, 2.4, and 3.0 wt%) were simulated. Adsorption processes under different temperatures (298, 323, and 348 K) were modeled, and the pressure was up to 20 MPa. Simulation results show that the absolute adsorption capacity of CH4 on the dry kerogen increases with the increasing pressure but decreases with the increasing temperature. The excess adsorption capacity increases up to a specific pressure and then declines with the increasing pressure. The competitive adsorption simulation results indicate that kerogen prefers to adsorb water (H2O) than CH4. At the pressure of 20 MPa and temperature of 298 K, the competitive adsorption capacity of CH4 (0.53 mmol/g) is only a seventh of the single component adsorption capacity of CH4 (3.92 mmol/g) on dry kerogen. The CH4 adsorption capacity on moist kerogen also decreases with the increasing moist content. Compared with the absolute adsorption capacity on the dry kerogen (3.92 mmol/g), the adsorption capacity on the moist kerogen reduces about 16%, 30%, 40%, 47%, and 55% at 20 MPa, respectively. The reduction of the adsorption capacity is attributed to the strong attraction between kerogen and water. At last, the effect of the water content on the shale gas adsorption is discussed under the micro-scale, and the adsorption capacity reduction curves were calculated under the reservoir conditions. The results show that the adsorption capacity of shale gas is significantly affected by water at the economically recoverable depth. The dry condition is considered as the situation of the maximal adsorption capacity of the shale gas reservoir. This study can serve as a reference for better understanding of the transportation and storage mechanism of shale gas under the reservoir conditions.",45,46,0
Monte Carlo,,"Chai, Z.; Yan, B.; Killough, J. E.; Wang, Y.",An efficient method for fractured shale reservoir history matching: The embedded discrete fracture multi-continuum approach,Fractured reservoir; EDFM; History matching; Uncertainty quantification; Neural network,,"In this study, we established a more efficient approach for fractured shale reservoir modeling with an emphasis on simplifying and automating the workflow for assisted history matching and uncertainty quantification. The improvement is especially notable for the process of history matching since the fracture geometry and properties can be directly set as parameters to be history matched. The resultant approach not only shows a significant reduction in the computational time while maintaining model accuracy, but also provides an automatic method for modifying the fracture related parameters - a laborious process in the traditional workflow. In the forward reservoir model, we implemented and extended the Embedded Discrete Fracture Model (Embedded DFM) approach for fractures with arbitrary strike and dip angle to a multiple porosity/permeability setting. The fractures are naturally discretized by the boundary of parent matrix grid blocks. Control volumes of fracture segments are generated according to the specific geometry of each of the segments. Three types of non-neighbor connections are then generated, namely the connection between the fracture segment and its parent matrix grid blocks, the connection between two intersecting fracture segments from different fractures, and the connection between two neighbor fracture segments from the same fracture. For each of the non-neighbor connections, transmissibility can be calculated honoring the physics of the flow. In our approach with Embedded Discrete Fracture Multiple-Porosity Model, the matrix is sub-divided into three porosity types, namely organic matrix (kerogen), inorganic matrix and natural fractures, with the necessary physics included for each of the porosity types. The macro fractures are explicitly represented with Embedded DFM. The proposed model provides a coherent method for characterizing the organic matrix, inorganic matrix, micro fractures as well as the hydraulic fractures of shale reservoirs. It offers a computationally efficient approach for modeling the severe heterogeneity due to hydraulic and natural fractures. Compared with traditional discrete fracture models, fewer grid blocks and lower levels of refinement are required. Compared with multiple porosity method, the proposed model has desirable accuracy for the simulation of reservoirs with large scale fractures. In the history matching and uncertainty quantification stage, due to the low efficiency of traditional Markov Chain Monte Carlo (MCMC) method when applied to reservoir history matching, a more advanced algorithm of two-stage MCMC is employed to evaluate the uncertainty for all the parameters. Since no upscaling of the fracture related parameters is required, the reservoir model can be generated by a pre-processor based on the proposed parameter, which maintains the adequacy of a Gaussian distribution assumption. Therefore, the workflow can be completely automated. By incorporating Embedded DFM and multiple porosity/permeability approaches, the improved model facilitates the history matching of fractured shale reservoirs by cutting the total amount of grid blocks, reducing the complexity of the gridding process, as well as improving the accuracy of fluid transportation within and among different porosity types.",28,28,1
Monte Carlo,,"Liu, Yu; Zhu, Yanming; Liu, Shimin; Li, Wu; Tang, Xin",Temperature effect on gas adsorption capacity in different sized pores of coal: Experiment and numerical modeling,Coalbed methane; Temperature effect; Methane adsorption; Pore structure; GCMC,CANONICAL MONTE-CARLO; SCANNING-ELECTRON-MICROSCOPY; MOLECULAR SIMULATION; METHANE ADSORPTION; MESOPOROUS CARBONS; ACTIVATED CARBON; PURE GASES; RESERVOIR; DISTRIBUTIONS; MICROPORES,"Accurate methane gas adsorption capacity estimation is key for the coalbed methane (CBM) reservoir gas-in-place assessment. As in situ, the reservoir pressure and temperature vary from one location to another. The temperature induced gas sorption capacity evaluation is important for the CBM and mining industry. In this study, grand canonical Monte Carlo (GCMC) simulation was used to investigate temperature effect on methane adsorption capacity and adsorbed methane density for different sized pores. Methane adsorption experiments were performed to show realistic temperature effect on methane adsorption capacity and the experimental data were used directly to validate the numerical model. The pore structure of coal was characterized by high-pressure mercury injection, low-pressure N-2 gas adsorption, low-pressure CO2 gas adsorption. The simulation results revealed that, first, temperature influence on methane adsorption was more obvious in smaller pores than that in larger pores. Based on the characteristics of the temperature influence on methane adsorption, pores can be divided into three categories: 0.7-0.9 nm pores, 1.0-1.3 nm pores and pores larger than 1.4 nm. In the 0.7-0.9 nm group, methane adsorption capacity decreased by approximately 19% at 3 MPa from 20 degrees C to 100 degrees C. In contrast, in the 1.0-1.3 nm pores and pores larger than 1.4 nm, methane adsorption capacity decreased by approximately 32% and 45%. Second, in 0.7 nm and 1.0 nm pores, methane adsorption capacity decreased linearly with an increase in temperature. In 4.0 nm pores methane adsorption capacity exhibited a negative exponential decrease with increasing temperature at low pressure (<3 MPa). Third, when the pore size was the same, the temperature effect was more obvious at a lower pressure than that at a higher pressure. The experimental results indicated that methane adsorption capacity in the coal sample decreased linearly with temperature increasing, and temperature effect on reducing methane adsorption capacity was greater at low pressure. These experimental results were consistent with the simulation results. Based on simulation and experimental data, it was obvious that temperature-induced gas adsorption capacity variation was both pore size dependent and pressure dependent.",26,27,9
Monte Carlo,,"Elkholy, Ayman E.; Heakal, F. El-Taib; Rashad, Ahmed M.; Zakaria, Khaled",Monte Carlo simulation for guar and xanthan gums as green scale inhibitors,Scale inhibition; Calcite; Anhydrite; Monte Carlo; Guar; Xanthan,MOLECULAR-DYNAMICS SIMULATION; CALCIUM-SULFATE; CARBOHYDRATE POLYMERS; CORROSION-INHIBITORS; POLYASPARTIC ACID; CARBONATE; POLYSACCHARIDES; ADSORPTION; BEHAVIOR; ALUMINA,"Scale formation is a serious problem in water systems where it causes process fouling and interruption. Guar and xanthan gums are naturally occurring and environmentally safe carbohydrate polymers. In an attempt to investigate their antiscaling effect, Monte Carlo (MC) simulation method was employed to screen their tendency to adsorb on growing scale crystals. This study was performed on calcite (CaCO3) and anhydrite (CaSO4) crystals. Molecules of both polymers show a tendency to adsorb on both salts. Adsorption tendency of gum polymers on both minerals is expressed in terms of the values of adsorption energy calculated from Monte Carlo simulation method. The effect of polymerization degree and the number of water molecules on both adsorption energy and deformation energy is involved. MC observations indicate that Xanthan demonstrates a higher tendency for adsorption on calcite surface than guar while guar shows a higher tendency for adsorption on anhydrite.",26,28,5
Monte Carlo,,"Qiu, Hongyuan; Yang, Jianming; Butt, Stephen",Investigation on bit stick-slip vibration with random friction coefficients,Drillstring; Bit stick-slip; Path integration; Random friction coefficient; Probability; Parametric studies,NUMERICAL PATH-INTEGRATION; OIL-WELL DRILLSTRINGS; STOCHASTIC DYNAMICS; DRAG BITS; SYSTEMS,"Torsional vibration of a drillstring, bit stick-slip in particular, is investigated with a simplified single degree of freedom (DOF) model in this paper. The friction in the bit-rock interaction is modeled as random, and the motions in stick and slip stages are treated separately. In the stick stage, it is treated as in static equilibrium. A single point or a range of points, at which the stick stage is completed and the slip stage is started, are determined depending on deterministic or random static friction coefficient assumed respectively. In the slip stage, the response at a time instant becomes a spreading area centered around the means due to the randomness of the kinetic friction. By assuming the random kinetic friction as White noise, the probabilistic distribution of the responses with displacement and velocity is calculated with the numerical path integration (PI) technique. For verification purpose, Monte Carlo (MC) simulation is also conducted. Also due to the randomness in friction, the time instants leaving the slip stage, or entering the stick stage, become random. Comparison between PI and MC shows that results from the two methods are in good agreement. In addition, parametric studies on damping, rotary speed, weight on bit, drillstring length and different combination of pipe and collar are conducted for both deterministic and random cases.",17,17,1
Monte Carlo,,"Shen, Qiuyang; Wu, Xuqing; Chen, Jiefu; Han, Zhu; Huang, Yueqin",Solving geosteering inverse problems by stochastic Hybrid Monte Carlo method,Statistical inversion; Hybrid Monte Carlo; Geosteering; Logging while drilling; Well logging,COMPUTATION,"The inverse problems arise in almost all fields of science where the real-world parameters are extracted from a set of measured data. The geosteering inversion plays an essential role in the accurate prediction of oncoming strata as well as a reliable guidance to adjust the borehole position on the fly to reach one or more geological targets. This mathematical treatment is not easy to solve, which requires finding an optimum solution among a large solution space, especially when the problem is non-linear and non-convex. Nowadays, a new generation of logging-while-drilling (LWD) tools has emerged on the market. The so-called azimuthal resistivity LWD tools have azimuthal sensitivity and a large depth of investigation. Hence, the associated inverse problems become much more difficult since the earth model to be inverted will have more detailed structures. The conventional deterministic methods are incapable to solve such a complicated inverse problem, where they suffer from the local minimum trap. Alternatively, stochastic optimizations are in general better at finding global optimal solutions and handling uncertainty quantification. In this paper, we investigate the Hybrid Monte Carlo (HMC) based statistical inversion approach and suggest that HMC based inference is more efficient in dealing with the increased complexity and uncertainty faced by the geosteering problems.",17,17,0
Monte Carlo,,"Naderi, Meysam; Khamehchi, Ehsan",Cutting transport efficiency prediction using probabilistic CFD and DOE techniques,Cutting transport efficiency; Computational fluid dynamic; Design of experiment; Monte Carlo simulation,LIFT ALLOCATION OPTIMIZATION; NONLINEAR RISK OPTIMIZATION; ARTIFICIAL-INTELLIGENCE; GAS; MODEL,"Efficient cutting transport plays an important role in drilling operation. This process is controlled by many factors such as well geometry, drilling fluid properties, geological features and rate of penetration. In order to minimize the operational cost of inefficient hole cleaning, it is crucial to thoroughly investigate the simultaneous effect of various factors on the process of cutting transport. In this regard, computational fluid dynamic (CFD) and design of experiment (DOE) techniques were used to predict the cutting transport efficiency (CTE) as a function mud velocity (V-m), drilling rate of penetration (ROP), mud weight (MW), cutting weight (CW), mud viscosity (mu m), pipe rotational speed (N), and cutting size (CS). The results of study based on probabilistic CFD calculations using DOE and Monte Carlo simulation (MCS) show that respectively factors of mud velocity, cutting weight, pipe rotational speed, mud weight, cutting diameter, mud viscosity, and drilling rate of penetration have the greatest impact on transportation of drilled cuttings from bottom of the well to the surface. In addition, result of MCS based on analysis of total variance reveals that 86.3% of cutting transport efficiency variation could be controlled by three factors of mud velocity, cutting weight and pipe rotational speed. Therefore, these factors should be carefully characterized during drilling and hole cleaning to maximize the cutting transport efficiency.",16,16,3
Source Rocks,,"Pang, Hong; Pang, Xiong-qi; Dong, Li; Zhao, Xu","Factors impacting on oil retention in lacustrine shale: Permian Lucaogou Formation in Jimusaer Depression, Junggar Basin",Oil retention; Lacustrine shale; Permian Lucaogou Formation; Junggar Basin,BOHAI BAY BASIN; ORGANIC-MATTER; HYDROCARBON EXPULSION; PETROLEUM SYSTEMS; NORTHWEST CHINA; RESOURCE PLAYS; TIGHT OIL; NW CHINA; MODEL; PRESSURE,"Luocaogou formation developed a set of good quality hydrocarbon source rock in the Jimusaer Depression. Plenty of hydrocarbon shows in shale have been discovered, indicating a good prospect for shale oil exploration. In this paper, the data including Rock-Eval pyrolysis, X-ray diffraction (XRD), lithology, and porosity were used to analyze the impact of oil retention in Lucaogou shale. The results showed that the TOC contents of lacustrine shale have a maximum of 15.51%, averaging 3.49%; the maturity is in the range 0.5%-1.1%; and the organic matters are of type I; the largest net thickness of source rock can reach 194 m, mainly distributed in the centre area rounding J35-J174 well block. Impacts of oil retention in lacustrine shale include TOC, Ro and reservoir physical property. S-1 contents increase with growing TOC, and when TOC content is more than 3%, hydrocarbon show thickness ratios (thickness ratio of hydrocarbon show to strata) are over 90%. When Ro reaches 0.8%, OSI (S-1/TOC. 100) become largest, and hydrocarbon show thickness ratios are over 80%. Good oil saturation relates to high porosity. Argillaceous limestone and argillaceous dolomite primarily develop matrix pores, while mudstone mainly develops organic pores. Since lower content of clay and higher content of brittle minerals in argillaceous limestone and argillaceous dolomite than in mudstone, both of the porosity and oil saturation of argillaceous limestone and argillaceous dolomite are better than that of mudstone. Generally, the areas deeper than hydrocarbon expulsion threshold (3200-4300 m of depth or 0.8%-1.3% of Ro) are most favourable for shale oil accumulation, which matches the actual oil production data. The depths of high production wells are no less than hydrocarbon expulsion threshold, since S-1 contents are high enough to satisfy critical residual amount and pores are developed. Meanwhile, good quality of reservoir developed when organic pores and overpressure were formed during hydrocarbon generation and expulsion.",41,42,1
Source Rocks,,"Krakowska, P.; Puskarczyk, E.; Jedrychowski, M.; Habrat, M.; Madejski, P.; Dohnalik, M.",Innovative characterization of tight sandstones from Paleozoic basins in Poland using X-ray computed tomography supported by nuclear magnetic resonance and mercury porosimetry,Computed X-ray tomography; Tight sandstones; Nuclear magnetic resonance; Mercury porosimetry; Semivariograms,RESERVOIR PROPERTIES; SOURCE ROCKS; USEFUL TOOL; MICROTOMOGRAPHY; PERMEABILITY; GENERATION; MODELS,"Computed X-ray tomography, nuclear magnetic resonance spectroscopy and mercury porosimetry are key experimental methods for detailed pore space characterization of low porosity and low permeability rocks. Calculations dedicated to bones parametrization were carried out and tested on tight sandstones in order to get the quantitative information about pore space structure. Innovative approach in estimating pore throat diameter is introduced based on best-fit ellipsoid's radiuses. Application of semivariogram for pores location allows assessing the heterogeneity in pore space structure. Sphericity determined based on enclosed volume and surface area is a more creditable parameter in comparison to parameter reflecting the pore roundness calculated from moments of inertia. Undeniable CT advantage is a possibility to perform 3D pore space visualization what confirmed the usefulness of quantitative parameters. New software poROSE was presented as porous materials examination software for images qualitative and quantitative interpretation.",24,26,4
Source Rocks,,"Gao, Gang; Yang, Shangru; Ren, Jiangling; Zhang, Weiwei; Xiang, Baoli",Geochemistry and depositional conditions of the carbonate-bearing lacustrine source rocks: A case study from the Early Permian Fengcheng Formation of Well FN7 in the northwestern Junggar Basin,Geochemistry; Lacustrine source rocks; Shale; Argillaceous dolomites; Fengcheng Formation; Junggar Basin,PETROLEUM SOURCE-ROCK; OILS; ENVIRONMENTS; PYROLYSIS; FACIES; INPUT,"Measurements of TOC, Rock-Eval pyrolysis, carbon isotope composition, solvent extract, extract fractionation, and the gas chromatography-mass spectrum (GC-MS) of the saturated fraction were conducted on the Lower Permian Fengcheng Formation carbonate-bearing shales and argillaceous dolomites of Well FN7 in the northwestern Junggar Basin to understand the geochemistry and depositional environmental evolution of the carbonate-bearing lacustrine source rocks. The results indicate that the Fengcheng Formation carbonate-bearing shales are fair to good source rocks with Type II kerogen for generating oil and minor gas, and the argillaceous dolomites are poor source rocks. The thermal mature shales contain more residually generated hydrocarbon, whereas the argillaceous dolomites contain more migrated hydrocarbon. This property is favorable for shale oil or tight oil accumulation in the Fengcheng Formation. Biomarker analyses indicate that the Fengcheng Formation source rocks were formed in the anoxic reducing lacustrine depositional environment with a stratified water column and high salinity. The source rock organic matter has major aquatic phytoplankton and algae input and less terrestrial organic matter input. During the Fengcheng Formation period, oxidation had a weak increasing tendency and salinity had a weak decreasing tendency from the early to late periods under the background of a reducing environment. Except for poor source rocks in upper and lower parts, the good source rocks are primarily in the middle part of the Fengcheng Formation.",22,24,5
Source Rocks,,"Wang, Gang; Qin, Yong; Xie, Yiwei; Shen, Jian; Zhao, Long; Huang, Bo; Zhao, Wenqiang","Coalbed methane system potential evaluation and favourable area prediction of Gujiao blocks, Xishan coalfield, based on multi-level fuzzy mathematical analysis",Multi-level fuzzy mathematical analysis; Coalbed methane (CBM) system; Gujiao blocks; Potential evaluation; Favourable areas prediction,SOUTHERN QINSHUI BASIN; SOUTHEASTERN ORDOS BASIN; GEOLOGICAL CONTROLS; GAS CONTENT; JHARIA COALFIELD; WESTERN GUIZHOU; CENTRAL PART; NORTH CHINA; WELL LOGS; PERMEABILITY,"Coalbed methane (CBM) resources are abundant in Gujiao blocks, Xishan coalfield, China. However, there is little previous geological research regarding coalbed methane. Using a quantitative and qualitative index, the hydrocarbon source rocks and preservation conditions of No. 2, 8 and 9 coalbed methane systems in Gujiao blocks were evaluated through a multi-level fuzzy method. On this basis, the comprehensive favourable area of three CBM systems and multi-layer commingled production were predicted. The results showed that the comprehensive score trend of hydrocarbon source rocks in Gujiao blocks gradually increases from southeast to northwest. The comprehensive score trend of preservation conditions increases gradually from north to south. The No. 2 coalbed methane system of the Shanxi formation is given priority over level II, which is distributed in the central and southern study area. The No. 8 coalbed methane system of the Taiyuan formation is given priority over level III, followed by level IV. The No. 9 coalbed methane system of the Taiyuan formation is given priority over level II and level III, which is distributed in the central and southern study area. Most of the area is suitable for individual CBM exploitation of No. 8 coal. The favourable area for the No. 2+8 coal layer is located in parts of the central, south-western and south-eastern study area. The favourable area for No. 8+9 coal layer is located in the Dongqu well field and the southern Tunlan well field. The favourable area for No. 2+8+9 coal layer is located in the eastern Yang Zhuang well field.",20,22,8
Source Rocks,,"Mashhadian, Mohammad; Verde, Alexander; Sharma, Prashant; Abedi, Sara",Assessing mechanical properties of organic matter in shales: Results from coupled nanoindentation/SEM-EDX and micromechanical modeling,Mechanical properties; Kerogen; Nanoindentation; Energy dispersive X-ray spectroscopy (EDX); Miromechanical modeling; Shale rocks,RICH SHALES; INDENTATION; ANISOTROPY; MATURITY; MODULUS; SCALE; ROCKS,"Mechanical properties of organic matter in fine grained source rocks has been the subject of extensive research. Most studies on kerogen have been performed on kerogen samples isolated by dissolving the rock matrix. However, recent studies have shown significant microstructural alteration of kerogen samples after demineralization leading to alteration of their mechanical properties. In this work, in order to study the role of organic matter on mechanical properties of the rock, both organic-rich and organicfree carbonate-rich shale rocks are investigated. A recently developed nano-chemomechanical characterization method is used to directly correlate mechanical properties of both organic-rich and organic-free samples with their chemical composition and mineralogy at micrometer length scales using coupled nanoindentation and Energy Dispersive X-ray Spectroscopy (EDX) technique. The experimental results are used in multiscale structure thought models in which the role of organic matter is modeled as a matrix surrounding inclusions in the composite. Application of these models to the interpretation of nanoindentation results allows us to obtain consistent mechanical properties for the main constituents of these samples, i.e. organic matter and calcite, which are in excellent agreement with the results in the literature. Moreover, adequate agreement is observed between model predictions and experimental measurements of elastic properties of carbonate-rich shale rocks at macroscale.",16,16,2
Source Rocks,,"Wang, Chen; Zeng, Jianhui; Zhang, Zhongtao; Shi, Ning; Lao, Miaoji; Zhao, Qing; Dai, Jinhui; Wang, Fangfang; Liu, Xiaofeng","Origin and distribution of natural gas and oil in the Baiyun Depression, Pearl River Mouth Basin, South China Sea",Gas washing; Petroleum origin; Distribution pattern of natural gas and oil; The Baiyun Depression; Deep-water area of South China Sea,PETROLEUM MIGRATION PATHWAYS; SOURCE ROCKS; DEPOSITIONAL ENVIRONMENT; CHARGE CONCENTRATION; 3-DIMENSIONAL MODEL; LIGHT-HYDROCARBONS; ORGANIC-MATTER; GENERATION; FRACTIONATION; INDICATORS,"The Baiyun Depression is the main hydrocarbon-rich province in the deep-water area of the Pearl River Mouth Basin, South China Sea. Several petroleum samples, well data and 3D-seismic data from the Baiyun Depression were collected, the geochemical features and origins were determined using various methods, and finally, their distribution pattern was analysed. The results are as follows: (1) the natural gases are the thermogenic gases of organic matter belonging to terrestrial organic gas. They are mainly kerogen-cracking gases with high maturities, and their kerogen is the mixed sapropelic-humic type. The carbon isotope of the oil indicates that its source rock may be a continental deposit. Most of the oil in the Baiyun Depression has suffered from gas washing, which substantially affected its light hydrocarbon content. The biomarker features of the oil contain high Pr/Ph (pristane/phytane), high oleanane and medium bicadinane, reflecting that its source rock contains a large amount of terrestrial organic matter. The steranes indicate that the oil is mature and is derived from both higher plant and algae. It can be concluded that natural gas and oil in the Baiyun Depression mainly originated from source rocks of Enping Formation. (2) The distribution pattern of natural gas and oil is mainly controlled by the characteristics of the hydrocarbon source kitchens and the hydrocarbon migration pathways. These results can provide some information for future petroleum exploration in the Baiyun Depression, as well as in other petroliferous basins with similar geological settings.",14,14,2
Artificial Neural Network,,"Xie, Yunxin; Zhu, Chenyang; Zhou, Wen; Li, Zhongdong; Liu, Xuan; Tu, Mei",Evaluation of machine learning methods for formation lithology identification: A comparison of tuning processes and model performances,Lithology identification; Supervised learning; Gradient boosting; Tuning parameter,TRAINING DATA; LOGS; PREDICTION; GAS,"Identification of underground formation lithology from well log data is an important task in petroleum exploration and engineering. Recently, several computational algorithms have been used for lithology identification to improve the prediction accuracy. In this paper, we evaluate five typical machine learning methods, namely the Naive Bayes, Support Vector Machine, Artificial Neural Network, Random Forest and Gradient Tree Boosting, for formation lithology identification using data from the Daniudui gas field and the Hangjinqi gas field. The input to each model consists of features selected from different well log data samples. To determine the best model to classify the lithology type, this study used validation curve to determine the parameter search range and adopted the hyper-parameter optimization method to obtain the best parameter set for each model. The performance of each classifier is also evaluated using 5-fold cross validation. The results suggest that ensemble methods are good algorithm choices for supervised classification of lithology using well log data. The Gradient Tree Boosting classifier is robust to overfitting because it grows trees sequentially by adjusting the weight of the training data distribution to minimize a loss function. The random forest classifier is also a suitable option. An evaluation matrix showed that the Gradient Tree Boosting and Random Forest classifiers have lower prediction errors compared with the other three models. Although all the models have difficulties in distinguishing sandstone classes, the Gradient Tree Boosting performs well on this task compared with the other four methods. Moreover, the classification accuracy is remarkably similar across the lithology classes for both the Random Forest and Gradient Tree Boosting models.",78,81,8
Artificial Neural Network,,"Onalo, David; Adedigba, Sunday; Khan, Faisal; James, Lesley A.; Butt, Stephen",Data driven model for sonic well log prediction,Artificial neural network; Sand production; Wellbore failure; Well log; Sonic velocity,ARTIFICIAL NEURAL-NETWORK; SHEAR-WAVE VELOCITY; INTELLIGENT SYSTEMS; COMPRESSIONAL-WAVE; PETROPHYSICAL DATA; SEISMIC VELOCITY; SAND PRODUCTION; CLAY CONTENT; SANDSTONE; RESERVOIR,"Near wellbore failure during the exploration of hydrocarbon reservoirs presents a serious concern to the oil and gas industry. To predict the probability of these undesirable phenomena, engineers study the mechanical rock properties of the formation such as Young's modulus, Bulk modulus, shear modulus and Poisson's ratio. Conventionally, these are measured indirectly using the established petro physical relationships from sonic wave velocities which can be obtained from sonic well logs. Unfortunately, reliable sonic well logs are not always available, due to poor borehole conditions ( wash out), damaged tools and offset well data. Most offset well log data are not acquired with dipole sonic tools; they are acquired with a borehole compensated logging tool. This limits the application of acoustic measurements to estimate the mechanical rock properties. In this study, a three-layer feedforward multilayered perceptron artificial neural network model is presented. This model aims to estimate compressional wave transit time and shear wave transit time using real gamma ray and formation density logs. The validation of the model is confirmed by using an oil and gas offshore shaley sandstone reservoir located in West Africa. The results of the validation show that the model presented in this study can be used to determine the sanding potential of the formation without performing a compressive geoscientific analysis in the absence of sonic well logs. The developed model's effectiveness is tested by comparing the predicted results with results obtained from the measured well log. The paper provides a tool to give preliminary recommendations of the likelihood of the formation to produce sand. Implementation of the proposed model can serve as a cost-effective and reliable alternative for the oil and gas industry.",31,31,1
Artificial Neural Network,,"Ma, Zhiwei; Leung, Juliana Y.; Zanon, Stefan",Integration of artificial intelligence and production data analysis for shale heterogeneity characterization in steam-assisted gravity-drainage reservoirs,,NEURAL-NETWORKS; HEAVY OIL; PERFORMANCE; SIMULATION; WAVELETS; SYSTEM; ZONES,"Steam-Assisted Gravity Drainage (SAGD) recovery is strongly impacted by distributions of heterogeneous shale barriers, which impede the vertical growth and lateral spread of a steam chamber and potentially reduce oil production. Conventional reservoir heterogeneities characterization workflows that entail updating static reservoir models with dynamic flow data are quite time-consuming. Furthermore, certain assumptions are often needed to approximate the complex physical processes. This study proposes a workflow integrating artificial intelligence (AI) in a model selection framework that aims to identify associated shale heterogeneities in SAGD reservoir based on extracted features from production time-series data. A series of SAGD models based on typical Athabasca oil reservoir properties and operating conditions is constructed. After constructing the base homogeneous model, the shale barriers are assigned randomly by sampling their location, lateral extent, and thickness from several probability distributions, which are inferred from field data assembled from the public domain. Sensitivity analysis is carried out to identify and analyze features in the production response that are related to shale characteristics: whenever the steam chamber encounters a shale barrier, a drop in the production is observed; this drop continues until the steam chamber has advanced past the shale barrier, and the production would rise again. Several types of input feature extraction methods are introduced in this work: piecewise linear approximation (PLA), cubic spline interpolation (CSI), and discrete wavelet transform (DWT). Next, artificial neural network (ANN) is constructed to calibrate a relationship between the retrieved production pattern parameters (inputs) and the corresponding geologic parameters describing shale heterogeneities (outputs), which include some variables capturing the location, orientation or size of a particular shale barrier encountered by the steam chamber. The final model is implemented in a novel characterization workflow to infer shale heterogeneities from production profiles. A number of realistic applications are presented to illustrate its utility. The ANN models are validated using numerous synthetic models, where the exact shale distributions are known. The trained ANN models can reliably estimate the relevant shale parameters and the associated uncertainties, while accurately predicting the corresponding production responses. It is intended to extend the proposed method to construct the ANN models directly from well logs and production data. This work presents a preliminary attempt in correlating stochastic shale parameters with observable features in production time-series data using AI techniques. The proposed method facilitates the selection of an ensemble of reservoir models that are consistent with the production history; these models can be subjected to further history-matching for a precise final match. The proposed methodology does not intend to replace traditional simulation and history-matching workflows, but it rather offers a complementary tool for extracting additional information from field data and incorporating AI-based models into practical reservoir modeling workflows.",21,22,1
Artificial Neural Network,,"Lee, Kyungbook; Lim, Jungtek; Ahn, Seongin; Kim, Jaejun",Feature extraction using a deep learning algorithm for uncertainty quantification of channelized reservoirs,Stacked autoencoder (SAE); Deep learning; Distance-based clustering (DBC); Uncertainty quantification; Channelized reservoirs,ENSEMBLE KALMAN FILTER; NEURAL-NETWORK; DYNAMIC DATA; MODEL PARAMETERIZATION; CLUSTERED COVARIANCE; BACK-PROPAGATION; SMOOTHER; INTEGRATION; IMPROVEMENT; DISTANCES,"Reservoir models are generated by geostatistics using available static data. However, there is inherent uncertainty in the reservoir models due to limited information. A number of reservoir models with equivalent probabilities are created to quantitatively assess model uncertainty. The easiest way to evaluate the uncertainty is to perform a reservoir simulation for hundreds of reservoir models, but the simulation cost is too high. Recently, distance-based clustering (DBC) has been used as a means of efficient uncertainty assessment. DBC classifies similar reservoir models into the same group. Because models belonging to the same group have similar reservoir performances, simulating a representative model for each group will give a comparable uncertainty range from simulating all models. For DBC to be successful, the definition of distance, which represents nonsimilarity between models, is the key factor. In this research, after the main information from a reservoir model is extracted through a stacked autoencoder (SAE), which is one of deep learning algorithms, the 2-norm of feature vectors for two models is defined as the distance. First, the hyperparameters for SAE are analyzed by sensitivity analysis in order to optimize the feature vector from reservoir facies model. Similar to other artificial neural network algorithms, uncertainty results are sensitive to the number of neurons and the number of hidden layers but are stable for the number of clusters. After SAE-based clustering, only 20 representative models can realize the uncertainty range present in 800 individual initial models. If there are observed dynamic data, the best representative model can be determined by a misfit between the simulated production from the representative models and the observed data. The best model and its 9 closest models in feature space are selected as qualified models from among the entire 800 models. Additional reservoir simulations for the closest models can dramatically improve the uncertainty range of the prior models without inverse algorithms. The 10 qualified models can be utilized for generating pseudostatic data or can be used as initial models for inverse algorithms for further improvement of reservoir characterization.",17,17,0
Artificial Neural Network,,"Derakhshanfard, Fahimeh; Mehralizadeh, Amir",Application of artificial neural networks for viscosity of crude oil-based nanofluids containing oxides nanoparticles,Artificial neural network; RBF; Nanofluids; Oxide nanoparticles; Viscosity,THERMAL-CONDUCTIVITY; PARTICLE-SIZE; HEAT-TRANSFER,"In this research, the effect of general performances of radial basis function (RBF) method of artificial neural networks (ANN) with laboratory data on NiO, WO3, TiO2, ZnO and FeO3 nanoparticles in different temperatures and mass fractions on viscosity of crude oil were studied. The morphology and nanoparticles stability were analyzed with the DLS and TEM analysis. The results showed that the average nanoparticles diameter ranged from 10 to 40 nm for different oxide nanoparticles. For learning RBF networks, the major method for calculating isotropic Gaussian basis functions span for RBF networks containing special algorithm were presented. The results declared RBF neural networks had an acceptable performance because of having strong academic basic and ability of filtering the noises. This method contain all the experimental data perfectly, and provides the possibility of using different mass fractions and temperatures and simulated charts for knowing the information about the viscosity. For TiO2, ZnO and FeO3 nanoparticles, adding small amounts of nanoparticles decreased the relative viscosity comparing to the base fluid viscosity. But for WO3 and NiO nanoparticles the viscosity of nanofluids was higher than base fluid with any mass fractions.",16,16,1
Artificial Neural Network,,"Zhang, Hua; Yin, Shunde; Aadnoy, Bernt",Poroelastic modeling of borehole breakouts for in-situ stress determination by finite element method,Borehole breakouts; Finite element method; Inverse analysis; In-situ stress; Poroelasticity,PRINCIPAL STRESS; CAJON PASS; FAILURE; WELL; FRACTURE; ROCK; CRITERION; STRENGTH; MOGI,"Borehole breakouts are changes in borehole geometry in a cross section perpendicular to the borehole axis when rock subjected to in-situ stress experiences shear failure. By finite element modeling of borehole breakouts considering poroelasticity, the authors simulate the process of borehole breakouts in terms of initiation, propagation and stability in the condition of Mogi-Coulomb criteria, and can get the shape of borehole breakouts. It's desirable that this information of borehole breakouts can be used to determine in-situ stress by inverse analysis. Artificial neural network provides such a tool to establish the relationship between in-situ stress and shape on borehole breakouts, by which in-situ stress can be obtain according to different shape of borehole breakouts. In this paper, there are two steps to determinate in-situ stress by inverse analysis. First, Sets of finite element modeling provides sets of data on in-situ stress and borehole breakout measures, which will be used to train an artificial neural network that can eventually represent the relationship between the in-situ stress and borehole breakout measures. Second, for a given measure of borehole breakouts, the trained artificial neural network will be used to predict the corresponding in-situ stress. Results show that the inverse analysis based on finite element modeling of borehole breakouts and artificial neural network can effectively determine in-situ stress.",14,14,4
Cutter,,"Liu, Weiji; Zhu, Xiaohua; Jing, Jun",The analysis of ductile-brittle failure mode transition in rock cutting,Rock cutting; MSE; Ductile to brittle transition; PFC2D; Critical depth of cut,SIMULATION; MECHANICS; ENERGY,"It is well known that there exhibits a transition of failure mode from ductile to brittle in the rock cutting process. The rock failure modes directly influence the design of cutter and the determination of optimum drilling parameters etc., which has an essential effect on the drilling efficiency and cost. It is therefore quite significant to analysis the ductile-brittle failure mode transition during rock cutting. For this purpose, an effort was made to model the critical depth of cut of the rock failure transition from ductile to brittle mode based on the rock fragmentation theory. What is more, the numerical simulation of rock cutting is also conducted to reproduce the transition by using the discrete element method (PFC2D). The process of the rock failure transition and its influence factors are performed, the correctness of the critical depth of cut model is verified by the results of numerical simulation and laboratory experiment. The research results show that the ductile failure mode of rock occurs when the depth of cut is shallow, and the corresponding Mechanical Specific Energy (MSE) almost remains a constant. As the depth of cut increasing the brittle failure will take place and the magnitude of MSE will decrease. The critical depth of cut observed under the condition of hydraulic pressure is larger than the atmosphere pressure, as well as the MSE. Besides, larger cutting velocity and rake angle both will result in larger magnitude of critical depth of cut and MSE. The work has done in this paper provides a very useful approach for predicting the critical depth of cut which can be used to optimize the drilling parameters, and makes a well understanding of ductile-brittle failure mode transition in rock cutting.",33,33,5
Cutter,,"Chen, Pengju; Miska, Stefan Z.; Ren, Rui; Yu, Mengjiao; Ozbayoglu, Evren; Takach, Nicholas",Poroelastic modeling of cutting rock in pressurized condition,Poroelasticity; PDC single cutter; Rock cutting; Deep well drilling,EXTENDED-REACH WELL; TENSILE-STRENGTH; PERFORMANCE; LIMESTONE,"Cutting rock in pressurized conditions is essentially different as compared to the ambient conditions. Under pressurized condition, cutter is not only fragmenting the rock matrix, but also driving pore fluid to flow forward. Due to the coupling of stresses and pore pressure, the pore pressure change caused by cutter will affect effective stresses in the rock and eventually affect mechanical specific energy (MSE). The change in stresses and pore pressure caused by cutter movement are the poroelastic effects in cutting process. To study pressurized cutting process, we developed a cutting model based on the theory of linear poroelasticity. The model can predict coupled stresses and pore pressure in the rock and give a better understanding of the poroelastic effect in the cutting process. To obtain the desired solution, a Fourier Transform is employed. After the analytic solution in Fourier space is obtained, a Discrete Fourier Transform is employed to numerically invert the solution back to the real space. The Mohr-Coulomb failure criterion is also introduced to determine failure of the rock ahead of the cutter. Eventually, the model can predict cutting forces and MSE in pressurized cutting process. The model is also compared to the published experimental data and a good consistency between model and experiment results was found. The influence of hydrostatic pressure and the existence of cuttings on MSE are studied and poroelastic effect during cutting process is also discussed. The results in this paper can be applied to bit-rock interaction in well drilling.",28,28,1
Cutter,,"Yang, Yingxin; Zhang, Chunliang; Lin, Min; Chen, Lian",Research on rock-breaking mechanism of cross-cutting PDC bit,Cross-scraping; Rock-breaking; Track; Load; Experiment,DRILL BITS,"Cross-cutting PDC (Polycrystalline Diamond Compact) bit is an efficient drilling technology that increases the rock-breaking efficiency and prolongs the service life of the bit through forming mesh-like pattern in the bottom-hole. This paper studies the rock-breaking mechanism of the cross-cutting PDC bit with the combination of both experiment and numerical simulation. With the nonlinear dynamical model being established, the stress status within rock units, sliding fracture characteristic, plastic energy consumption and stress distribution along the cutter edge are analyzed in the cross-cutting process. Compared with unidirectional cutting, cross-cutting generates larger tensile stress within the rock unit and achieves lower plastic energy consumption. Moreover average stress on the cutter edge in cross-cutting is much smaller than that in unidirectional cutting. When cutters break the rock protrusions formed during cross-cutting process, cracks inside of the rock will rapidly run through the protrusion, generating brittle fractures within the rock and consequently producing sizable volumetric fractures. During cross-cutting, the rock is damaged not only because the shear failure, but also brittle fracture, which is conductive to improving the rock-breaking efficiency. Through unit experiment under cross-cutting condition, this paper studies the influencing regularity of experimental parameters (including the cutter diameter, back rake angle, cross-cutting angle, cutters spacing and rock hardness etc.) on the cutting load, the research achievements are conductive to the deeper understanding of rock-breaking mechanism of the new bit and provides theoretical basis for the application of the technology.",25,28,4
Cutter,,"Cheng, Zhen; Sheng, Mao; Li, Gensheng; Huang, Zhongwei; Wu, Xiaoguang; Zhu, Zhaopeng; Yang, Jiawei",Imaging the formation process of cuttings: Characteristics of cuttings and mechanical specific energy in single PDC cutter tests,PDC bit; Single cutter test; Cuttings formation; MSE,HARD-ROCK; FRAGMENTATION; BITS,"Polycrystalline Diamond Compact (PDC) bits account for most of the footage drilled in the oil field. Abundant information relating to cutter-rock interactions and rock breaking mechanism are provided by the cuttings and Mechanical Specific Energy (MSE) in single cutter tests, which are crucial for insuring the longevity and rate of penetration (ROP) enhancement of PDC bits. In this paper, a series of linear cutting tests was conducted at different depths of cut, back rake angles and cutting speeds on three kinds of rock. The formation of cuttings was recorded frame by frame with a high-speed camera. Then, the cuttings were collected and divided into five groups by sieving. Finally, the mass fraction change of cuttings in each group was compared with the MSE variation. The results show that a PDC cutter does not move at a constant speed: relatively slower when crushing and faster when chipping, and crushing dominates almost the entire cutting process. The mass fraction of chunklike cuttings generated in chipping is increased with decreasing back rake angle, while increasing depth of cut and cutting speed; and the mass fraction of powderlike cuttings generated in crushing shows an opposite trend. Furthermore, because of the crystalloblastic texture and well-developed cleavages in calcite, far more chunklike cuttings and totally different fracture surfaces are found when cutting marble, compared with sandstone and granite. Finally, a strong correlation between the mass fraction of cuttings and MSE is found. This indicates that the mass fraction of cuttings could be deemed as a simple method to evaluate the efficiency of rock breaking by PDC cutters. The results in this paper are expected to provide guidelines to the selection of drilling practices and PDC bit design.",24,24,3
Cutter,,"Rostamsowlat, Iman; Akbari, Babak; Evans, Brian",Analysis of rock cutting process with a blunt PDC cutter under different wear flat inclination angles,Rock cutting; Contact stress; Wear flat inclination angle; Depth of cut; Pure cutting process; Frictional contact process,FAILURE MODE TRANSITION; SELF-EXCITED VIBRATIONS; BACK RAKE ANGLE; DEPTH; MECHANICS; DYNAMICS; FORCE; BITS,"It is generally accepted that drilling with drag bits (Polycrystalline Diamond Compact bits) simultaneously consists of ""pure cutting"" and ""frictional contact"" processes. To date, the mechanics of rock cutting have been mostly based on the assumption that these two processes are fully independent as the influence of wear flat inclination angle (beta) with respect to the cutter velocity vector (nu) on the frictional contact force is often not accounted for. The specific aim of this study is to determine the effect of wear flat inclination angle on the frictional force acting on the wear flat surface of a single blunt cutter over a wide range of depths of cut (d). For this purpose, an extensive and comprehensive set of cutting experiments was performed on two sedimentary rock samples (a limestone and a sandstone) using a state-of-the-art rock cutting equipment and a unique cutter holder. The results show that the normal contact stress (sigma) at the wear flat-rock interface (and therefore the normal frictional force acting on the wear flat) is dependent on the depth of cut within the elastoplastic and particularly plastic regimes of frictional contact; however, the contact stress is invariant with depth of cut within the elastic regime. Further investigations indicate that the assumption that the force acting on the wear flat surface of a blunt cutter is independent of the cutting process taking place ahead of the cutter is not valid in particular, for the large values of inclination angles.",20,21,4
Cutter,,"Ma, Yachao; Huan, Zhiqiang; Li, Qin; Zhou, Yi; Peng, Shijin",Cutter layout optimization for reduction of lateral force on PDC bit using Kriging and particle swarm optimization methods,PDC bit; Cutter layout optimization; Wearing condition; Lateral force; Kriging model; Particle swarm optimization,ALGORITHM; DESIGN,"Polycrystalline diamond compact (PDC) bits are the dominant bit-types in oil and gas fields all over the world. Reducing the lateral force on PDC bits plays an important role in reducing drilling vibration and improving the service life of PDC bits. However, balancing the lateral force on PDC bit through the cutter layout design cannot precisely meet design requirements, especially after the bits wear. There is a large unbalanced lateral force when the bit is worn. In this paper, considering the bit wear, a cutter layout optimization model for reducing the lateral force is proposed. A models of wear and force for PDC cutters are built. Then, the optimal approach for lateral force on PDC bits is discussed, and an optimization case for a PDC bit is presented. The results show that the proposed zero point traversal (ZPT) algorithm can be used to calculate the unknown parameters in force and wear models of cutters. The proposed optimal approach has high computational efficiency, and can perform multiparameter linkage adjustment. The optimization case shows that there is a significant reduction of the lateral force after cutter layout optimization. The stability of the bit is enhanced, and the service life of PDC bits is improved.",16,16,1
Reaction Rate,,"Jia, Hu; Chen, Hao",Using DSC technique to investigate the non-isothermal gelation kinetics of the multi-crosslinked Chromium acetate (Cr3+)-Polyethyleneimine (PEI)-Polymer gel sealant,Polymer gel; Multi-crosslinking; Gelation kinetic; Polyethyleneimine; Water shutoff; Temporary plugging,WATER-SHUTOFF; LINKING REACTION; POLYACRYLAMIDE; TEMPERATURE; CRYSTALLIZATION; MECHANISM; PARAMETERS; BEHAVIOR; SYSTEM,"Polymer gel based on multi-crosslinking is aroused great interesting in the aspect of oil/and or gas well water shutoff and temporary plugging in well completion and workover. While the complex gelation mechanism is not well understood. Most previous studies focus on using a coarse method such as rheological techniques or simple bottle test to investigate the gelation kinetic. This work presents the first attempt to use the DSC technique to study the non-isothermal gelation kinetic of the multi-crosslinking gel system. The target polymer gel is reported in our previous study, which is a multi-crosslinked Cr3+-PEI-SPAM gel. The DSC curve shows an endotherm peak followed by an exotherm peak, indicating the multiple reactions taken place during the heating of Cr3+-PEI-SPAM gel system. The endothermic process shows that the first gelation reaction occurs between the SPAM and Cr3+. And the exothermic process can be regarded as the secondary gelation reaction between the SPAM and PEI. Nonisothermal gelation kinetic parameters were determined by Jeziorny model, Mo's model and Rate model, respectively. All results show a good linear relationship with the experimental data. The non-isothermal gelation kinetic parameters from the Jeziorny model indicate that the gelation mechanism between Cr3+-SPAM and PEISPAM is very different. The results of Mo's model show that the gelation process becomes difficult as the gelation progresses. Non-isothermal gelation kinetic parameters calculated from the Rate model indicate that the crosslinking between SPAM and Cr3+ is a multistage reaction including three stages, while the crosslinking between SPAM and PEI only has two stages.",40,41,1
Reaction Rate,,"Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Yuan, Chengdong; Pan, Jingjun; Wang, Ruyan; Chen, Long; Kan, Ni",Low-temperature oxidation of light and heavy oils via thermal analysis: Kinetic analysis and temperature zone division,Low-temperature oxidation; Light and heavy oils; Thermal analysis; Kinetic analysis; Temperature zone division,PRESSURE AIR INJECTION; CRUDE-OIL; THERMOGRAVIMETRIC ANALYSIS; COMBUSTION KINETICS; SARA FRACTIONS; PYROLYSIS; BEHAVIORS; RECOVERY; MODEL; DECOMPOSITION,"This research is intended to investigate low-temperature oxidation (LTO) behavior and kinetics of light and heavy oils and to divide their LTO intervals. Ramped thermogravimetry/derivative thermogravimetry (TG/DTG) and differential scanning calorimetry (DSC) experiments and isothermal TG experiments with different temperature intervals were used to characterize LTO behavior and to obtain kinetic parameters determined by Ozawa-Flynn-Wall (OFW) and general reaction rate models. The results indicated that there were three (two) distinct variation trends about the conversion rate versus temperature for light (heavy) oil in the LTO region, manifesting the LTO interval of light (heavy) oil should be controlled by multiple-step mechanisms and divided into at least three (two) reaction subintervals. The LTO interval of both light and heavy oils used could be subdivided into three temperature intervals inferred from the variation trend of activation energy over temperature for ramped experiments. Additionally, the LTO region of both light and heavy oils held three subzones in the aspect of isothermal tests. For light oil, the reaction rate augmented from 50 to 250 degrees C where the activation energy was positive, while it reduced from 250 to 350 degrees C coupled with negative activation energy. As for heavy oil, the reaction rate presented an increasing trend in the first and third subintervals (50-150 degrees C and 250 350 degrees C) with positive activation energy and a declining trend in the second subinterval (150 250 degrees C) with negative activation energy. It is believed that this research can add new insights to the LTO interval division of crude oil regarding to the isothermal and non-isothermal conditions, which are of significance for understanding LTO reaction pathways and mechanisms.",26,27,1
Reaction Rate,,"Liu, Min; Shabaninejad, Mehdi; Mostaghimi, Peyman","Predictions of permeability, surface area and average dissolution rate during reactive transport in multi-mineral rocks",Pore-scale modelling; Reactive transport; Mineralogical heterogeneity; 3D imaging,PORE-SCALE SIMULATION; NUMERICAL-SIMULATION; WORMHOLE FORMATION; CARBONATE; COAL; POROSITY; IMPACT; FLOW; HETEROGENEITY; SEGMENTATION,"The interactions between minerals and reactive fluids have great impact on the pore structure and hydrologic properties of rocks. A 3D pore-scale reactive transport model is applied to predict multi-mineral reactions in porous rocks. Eight mineral phases are distinguished in 2D slices of a reservoir sandstone by using Quantitative Evaluation of Minerals by SCANning electron microscopy (QEMSCAN) imaging technique. The 2D image is then registered into the corresponding cross-section of the 3D rock image obtained from micro-computed tomography (CT) scanning. Reactive transport with chemical dissolution is simulated directly on the 3D image of the sandstone. In the simulations, each mineral is assigned with a specific intrinsic reaction rate constant. The dissolution-induced changes in the pore structure are measured. The pore size distribution of the rock is analysed to investigate the evolution of the pore space. The changes of surface area and permeability are compared with single mineral simulations to illustrate the importance of mineralogical heterogeneity on reactive transport. The results show that the 3D pore-scale mineralogical heterogeneity causes overestimation of the permeability variations during reactive transport. The average effective dissolution rates for the rock are also measured. The simulations with single mineral assumptions present an overall reaction rate which is 10 times higher than the predictions with multi-mineral dissolution at the start of reactions. Relationships between average reaction rate and time are proposed to characterise the evolution of dissolution rate. A correction is also suggested to reduce the errors in predictions of reaction rates with single mineral assumptions.",25,25,4
Reaction Rate,,"Yoo, Hyunsang; Kim, Youngmin; Lee, Wonsuk; Lee, Jeonghwan",An experimental study on acid-rock reaction kinetics using dolomite in carbonate acidizing,Carbonate acidizing; Spent acid; Dissolution rate; Diffusion coefficient,DISSOLUTION; ACIDIZATION; TRANSPORT,"This study presents experimental results on the reaction kinetics of dolomite with fresh and spent acid in carbonate acidizing. Spent acid is defined as a partially reacted acid involving reaction products, such as calcium and magnesium ions, during an acid-rock reaction. A newly designed apparatus was developed to quantify the effect of spent acid on the acid-rock reaction kinetics at reservoir conditions. A total of 4 runs with 36 experiments at same conditions using the apparatus were repeatedly carried out to investigate the reaction kinetics of dolomite rock under the various concentrations of fresh acid and spent acid. The reaction results showed the dolomite disk was more dissolved in the spent acid than the fresh acid. Moreover, it was observed that the kinematic viscosity was higher, and the pH was lower in the spent acid, when compared with the fresh acid. From the results, it was revealed that the dissolution rate and diffusion coefficient for spent acid were higher than those of fresh acid due to the higher kinematic viscosity and the lower pH of spent acid. This means that the chemical reaction becomes more vigorous due to the long contact time and high acidity of the spent acid at the surface of the dolomite disk. These results suggest that the uncommon ion effect by the impurities, such as ferric oxide and aluminum oxide in clay, which is not related to the reaction of HCl and dolomite, can promote the reactions. A conventional approach using fresh acid could result in significant errors in determining the injection parameters, such as injection rate, volume, and pumping schedule in a carbonate acidizing job, because of the underestimated the dissolution rate and diffusion coefficient. Therefore, the effect of spent acid on acid-rock reaction kinetics should be essentially considered to design the injection conditions in carbonate acidizing.",22,24,6
Reaction Rate,,"Pei, Shufeng; Wang, Yanyong; Zhang, Liang; Huang, Lijuan; Cui, Guodong; Zhang, Panfeng; Ren, Shaoran",An innovative nitrogen injection assisted in-situ conversion process for oil shale recovery: Mechanism and reservoir simulation study,In-situ conversion process; Nitrogen injection; Oil shale; Reservoir numerical simulation; Kerogen pyrolysis,HEAVY OIL; CRACKING; MODEL,"In-situ conversion process (ICP) can be an effective technique for the development of oil shale and ultra heavy oils, in which kerogen or heavy components will be cracked into light oils and gases via underground heating and pyrolysis, and the retorted oil can be recovered via conventional extraction techniques. Heating of targeted formation can be conducted using electrical heaters installed in vertical or horizontal wells, while a slow heating rate and lack of driving energy for oil production are the main issues of the conventional in-situ conversion process. In this study, an innovative nitrogen injection assisted in-situ conversion process (NAICP) was proposed to increase formation heating rate and improve oil production from oil shale. Reaction models of kerogen pyrolysis at elevated temperature were established, along with models for the evolution of porosity and permeability of oil shale formation during the pyrolysis process. The performance of nitrogen injection on the effectiveness of the ICP was then investigated through reservoir numerical simulation. The simulation results show that additional nitrogen injection can improve the heating rate of the oil shale formation, enhance oil production and energy efficiency in comparison with the conventional ICPs, which can be attributed to enhanced heat convection, pressurization effect and gas driving mechanism. Nitrogen injection assisted in-situ conversion process can be a promising technique for the exploitation of oil shale.",19,21,9
Reaction Rate,,"Ren, Guangwei; Nguyen, Quoc P.; Hon Chung Lau",Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants,CO2 soluble surfactants; Partition coefficient; CO2 foam; Fractured carbonate reservoir; EOR,INTERFACIAL-TENSION; GRAVITY DRAINAGE; MOBILITY CONTROL; CRUDE-OIL; DISPLACEMENT; EOR; MICROEMULSIONS; WETTABILITY; SOLUBILITY; REDUCTION,"Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions. A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 degrees C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water. RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam. These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.",19,20,2
Machine Learning,,"Xie, Yunxin; Zhu, Chenyang; Zhou, Wen; Li, Zhongdong; Liu, Xuan; Tu, Mei",Evaluation of machine learning methods for formation lithology identification: A comparison of tuning processes and model performances,Lithology identification; Supervised learning; Gradient boosting; Tuning parameter,TRAINING DATA; LOGS; PREDICTION; GAS,"Identification of underground formation lithology from well log data is an important task in petroleum exploration and engineering. Recently, several computational algorithms have been used for lithology identification to improve the prediction accuracy. In this paper, we evaluate five typical machine learning methods, namely the Naive Bayes, Support Vector Machine, Artificial Neural Network, Random Forest and Gradient Tree Boosting, for formation lithology identification using data from the Daniudui gas field and the Hangjinqi gas field. The input to each model consists of features selected from different well log data samples. To determine the best model to classify the lithology type, this study used validation curve to determine the parameter search range and adopted the hyper-parameter optimization method to obtain the best parameter set for each model. The performance of each classifier is also evaluated using 5-fold cross validation. The results suggest that ensemble methods are good algorithm choices for supervised classification of lithology using well log data. The Gradient Tree Boosting classifier is robust to overfitting because it grows trees sequentially by adjusting the weight of the training data distribution to minimize a loss function. The random forest classifier is also a suitable option. An evaluation matrix showed that the Gradient Tree Boosting and Random Forest classifiers have lower prediction errors compared with the other three models. Although all the models have difficulties in distinguishing sandstone classes, the Gradient Tree Boosting performs well on this task compared with the other four methods. Moreover, the classification accuracy is remarkably similar across the lithology classes for both the Random Forest and Gradient Tree Boosting models.",78,81,8
Machine Learning,,"Bhattacharya, Shuvajit; Mishra, Srikanta","Applications of machine learning for facies and fracture prediction using Bayesian Network Theory and Random Forest: Case studies from the Appalachian basin, USA",Bayesian network theory; Random forest; Data analytics; Predictive performance; Causality; Petrophysical logs,MARCELLUS SHALE LITHOFACIES; WELL LOGS; MODEL,"Identification and prediction of facies and fractures are critical to subsurface geosystems analysis and hydrocarbon exploration. However, accurate prediction of facies and fractures is hard in the absence of high-resolution advanced geophysical logs (e.g. image logs) and core samples. This study demonstrates the application of machine learning algorithms, such as Bayesian Network Theory and Random Forest to predict the presence of different facies and fractures in sedimentary rocks using common well logs. We build and train supervised machine learning models using Bayesian Network Theory and Random Forest to classify facies and fractures in unconventional shale and conventional sandstone, and carbonate reservoirs. The trained machine-learning models are cross-validated 10-fold to check their robustness. Application of Bayesian Network theory and Random Forest shows that both facies and fractures can be predicted with high accuracy using limited common well logs. In addition, the Bayesian Network shows the complex causal relationship among the input petrophysical parameters and output (facies or fracture), which is its unique feature compared to other machine learning algorithms, such as Random Forest.",46,48,8
Machine Learning,,"Nwachukwu, Azor; Jeong, Hoonyoung; Pyrcz, Michael; Lake, Larry W.",Fast evaluation of well placements in heterogeneous reservoir models using machine learning,Surrogate reservoir modeling; Machine learning; Well placements,CONNECTIVITY; PERMEABILITY; DEFORMATION,"Surrogate models, or proxies, provide computationally inexpensive alternatives for approximating reservoir responses. Proxy models are routinely developed to generate spatially-varying output such as field pressures and saturations, or well responses such as production rates and bottom- hole pressures. In this study, a machine learning approach is adopted to predict reservoir responses based on injector well locations. The proxy developed in this work is trained to reproduce reservoir-wide objective functions, i.e., total profit, cumulative oil/gas produced, or net CO2 stored. Because of the geological complexity of most reservoirs, slight adjustments in injector well locations could yield dramatic changes in the objective function responses. Hence, most proxies do not include well locations as inputs in their formulation. This complex relationship between well locations and reservoir-wide responses makes nonparametric, machine learning-based methods an attractive option. We introduce a machine learning approach in which the primary predictors are physical well locations, and the primary response is a defined objective function such as NPV. The complexity of the response surface with respect to well locations necessitates that we augment the predictor variables with well-to-well pairwise connectivities, injector block permeabilities and porosities, and initial injector block saturations. Introducing well-to-well connectivities yields significant improvements in prediction accuracy. Connectivities are represented by 'diffusive times of flight' of the pressure front, which is computed using the Fast Marching Method. A handful of training observations are obtained from numerical reservoir simulations. The Extreme Gradient Boosting method is then used to build an intelligent model for making predictions given any set of observations. The proposed approach is demonstrated using five synthetic case studies: i) a homogeneous reservoir waterflood, ii) a channelized reservoir waterflood, iii) a 20-model ensemble waterflood, iv) a CO2 flood in a heterogeneous reservoir, v) a CO2 flood in a heterogeneous reservoir with complex topography. Results show a significant correlation between proxy predictions and reservoir simulation results.",46,47,6
Machine Learning,,"Li, Kun; Han, Ying; Wang, Tong",A novel prediction method for down-hole working conditions of the beam pumping unit based on 8-directions chain codes and online sequential extreme learning machine,Beam pumping unit; Working conditions prediction; Time series analysis; 8-Directions chain codes; OS-ELM; Grey interval relational degree,GREY RELATIONAL ANALYSIS; FAULT-DIAGNOSIS; MOMENT,"In the oilfield operation, the beam pumping unit is a very important artificial lift method. As the down-hole parts work at hundred and thousand meters underground, they are hard to be found immediately when failures come out. If we can predict down-hole working conditions and master its continuous operation states in time, great improvement of the oil well production will be developed. In this paper, a novel down-hole working conditions prediction method for the beam pumping unit based on the chaos time series prediction is proposed. First, curve contour of the dynamometer card is redrawn by 8-directions chain codes, and then eight feature vectors are extracted to construct eight feature vector time series; then, the online sequential extreme learning machine (OS-ELM) method is used to build the prediction model, which can realize fast updating with dynamic work condition changes; finally, the grey interval relational degree between the predicted feature vectors and feature vectors of each fault type is calculated to determine the predicted fault type. Actual production data of an oil well are used for example verification, and both online diagnosis and offline diagnosis illustrate the effectiveness of the method.",33,37,0
Machine Learning,,"Wang, Xidong; Yang, Shaochun; Zhao, Yongfu; Wang, Ya","Lithology identification using an optimized KNN clustering method based on entropy-weighed cosine distance in Mesozoic strata of Gaoqing field, Jiyang depression",Machine learning; Lithology identification; KNN clustering; Statistic method; Weighed cosine distance,CLASSIFICATION; FACIES,"KNN (K-Nearest Neighbors) clustering in machine learning is a very efficient clustering method applied in lithology identification, reservoir type recognition, flow unit classification and so on, but it is not working consistently because of its inherent limitation, like its initial center selection and clustering center shift caused by outliers. Moreover, KNN clustering is based on a mathematical algorithm, and does not necessarily cluster the space due to the geological and petrophysical aspects. To address this issue, an optimized KNN clustering method based on weighed cosine distance is proposed to better fit the lithology model. To deal with the problem of the initial center selection and outliers, a set of statistic methods is conducted. A set of data, sampled by different logging series, is made use to feature information about lithology as much as possible. New distance algorithm selection based on geology model and well logging data similarity attribute is obtained when utilizing. Taking the Mesozoic strata in Gaoqing field as example, a procedure fitter for utilization of machine learning technique in lithology identification is carried on, and the overall accurate rate of the optimized K-means clustering in lithology identification raised nearly 10% compared with the traditional K-means clustering especially in the differentiation between fine-sand and coarse-grained clastic sand. The predicted lithology match the core plugs better than the traditional KNN clustering.",23,26,6
Cement Sheath,,"Xi, Yan; Li, Jun; Liu, Gonghui; Cha, Chunqing; Fu, Yongqiang",Numerical investigation for different casing deformation reasons in Weiyuan-Changning shale gas field during multistage hydraulic fracturing,Volume fracturing; Casing deformation; Numerical calculation; Lithologic interface; Cement void; Formation slipping,UNCONVENTIONAL RESERVOIRS; HORIZONTAL WELLS; FINITE-ELEMENT; DESIGN; VOLUME; PRESSURE; WEAR,"Casing deformation has been found to be a very significant issue in the development process of shale gas in China. The rate of casing deformation is 34.34% (34 wells of 101), and statistical data show that it decreased the test output of wells by approximately 30%. Based on investigation and analysis of the engineering and geological conditions of 25 wells, 12 of which have casing deformations, both physical models and finite element models were established. Furthermore, the effects of fracturing pressure, geostress, anisotropy, lithologic interface, temperature variation, and cement void were analyzed. The results show the following. a) When the casing deformation points appear far away from point A (the landing point, which is the starting point of the horizontal segment), the influence of the lithologic interface on casing stress plays a decisive role under the combined effect of internal and external pressures when the cement sheath is completed. b) Under the same conditions, but when the casing is in contact with the borehole wall near the bottom because of gravity, a narrow fluid retention space was formed, leading to cementing sheath voids. The effect of cement void pressure reduction is the main reason behind the casing deformation. c) When casing deformation points appear near point A, the activation of the weak plane in the beddings during fracturing causes the casing deformation. The stress of 14 casing deformation points was calculated according to actual engineering and geological conditions, and 78.6% of the results were consistent with field measurements.",35,41,3
Cement Sheath,,"Liu, Kui; Gao, Deli; Taleghani, Arash Dahi",Analysis on integrity of cement sheath in the vertical section of wells during hydraulic fracturing,Sustained casing pressure; Cement sheath; Shale gas; Well integrity; Hydraulic fracturing,WELLBORE,"The sustained casing pressure (SCP) problems occur mainly in intermediate casing that might affect the safety and efficiency of shale gas production. Cement sheath is the main barrier against leakage and migration of gas from the pay zone to the shallow zones. Since the production casing is cemented all the way up to the intermediate casing in the vertical section of the well, the in-situ stress can only act on the intermediate casing and not directly on production casing. Based on this situation, an analytical model considering the well completion steps is established to study the integrity of cement sheath as a two-layer casing-cement system. The effect of mechanical and geometrical parameters of casing and cement are further investigated through a sensitivity analysis. The results show that the tensile failure more likely occurs at the inner face of the cement sheath in the intermediate casing. The casing thickness is in favor of decreasing the tensile stress in the cement sheath. But on the contrary, increasing the thickness and elastic modulus of the cement sheath may increase the risk of tensile failure in the cement sheath while reducing the costs. However, an appropriate increase of back pressure in the annulus during cementing is beneficial to reduce the tensile stress in the cement sheath.",26,30,2
Cement Sheath,,"Paiva, Maria D. M.; Silva, Emilio C. C. M.; Melo, Dulce M. A.; Martinelli, Antonio E.; Schneider, Jose F.",A geopolymer cementing system for oil wells subject to steam injection,Geopolymer; Alkali-activated binder; Well cementing integrity; Mechanical properties; Triaxial testing; Computer simulation,MECHANICAL-BEHAVIOR; TEMPERATURE,"Oil wells subjected to cyclic steam injection often present cement sheath failures due to thermal loads. Currently, different Portland based systems are employed to mitigate this risk. We developed and tested geopolymer systems that meet oil well cementing requirements and achieve high mechanical performance. A metakaolin-potassium-based formulation, containing microsilica, mineral fiber and retarder, was adjusted to the desired rheology and thickening time. Triaxial compression and indirect tensile tests were performed and the properties were used in finite element simulations of the life of a model onshore well. Compared to the Portland based system currently in use, the geopolymer has superior uniaxial compressive strength and lower stiffness. Tensile strength increased significantly with the addition of mineral fibers and became higher than that of the Portland system. Numerical simulations show that the geopolymer can withstand steam injection temperatures comparable to a conventional system, remaining in the elastic region. These results show that geopolymers are a viable alternative well cementing system for this application, with significant improvement in mechanical performance.",20,20,1
Cement Sheath,,"Arjomand, Elaheh; Bennett, Terry; Nguyen, Giang D.",Evaluation of cement sheath integrity subject to enhanced pressure!,Cement sheath integrity; Concrete damage plasticity model; Casing eccentricity; Anisotropic in-situ stresses; Compression damage; Tensile damage,PLASTIC-DAMAGE MODEL; FINITE-ELEMENT; CONCRETE; INTERFACES,"Well-cementing (cementation) is an influential stage of a wellbore completion, as the cement sheath is responsible for providing a complete zonal isolation. Therefore, it is of utmost importance to understand the cement mechanical failure mechanisms since well cement failure and interfacial debonding between the cement and casing and cement and rock formations can lead to a barrier failure. During the wellbore lifetime, a cement sheath is subjected to pressure loading variations. This paper demonstrates the results of an experimental-numerical study to investigate the cement sheath integrity after being subjected an enhanced pressure. A constitutive model specifically formulated for the modelling of quasi-brittle materials is applied to the investigation of cement sheath integrity, incorporating both compression and tensile damage mechanisms. Laboratory experiments are carried out to obtain strength properties of cement class G followed by calibration of the model parameters based on the obtained experimental results. A three-dimensional finite element framework employing the constitutive model for cement sheath and a surface-based cohesive behaviour for the interfaces is developed for integrity investigations. The effects of different orientations of in-situ stresses, different stiffness's of surrounding rock, and the eccentricity of the casing within the wellbore on the integrity of the cement and interfaces are investigated. The significance of cement sheath centralisation and elevated risk of cement mechanical failure caused by wellbore operations in anisotropic fields with soft rocks formation were highlighted. Furthermore, the relatively high magnitude of tensile damage (cracking index) within the cement sheath confirms the importance of tensile properties to be incorporated into the constitutive modelling.",19,22,7
Drill String,,"Hakim, Hadyan; Katende, Allan; Sagala, Farad; Ismail, Issham; Nsamba, Hussein",Performance of polyethylene and polypropylene beads towards drill cuttings transportation in horizontal wellbore,Drilled cuttings; Drilling mud; Water-based mud; Polymer beads; Polyethylene beads; Polypropylene beads,,"Drilled cuttings removal is critical in drilling operations, especially in horizontal wells. These cuttings are postulated to be among the possible causes of many costly complications, such as mechanical pipe sticking, bore hole instability, drag and torque. This study proposes a new approach that uses polymer beads as a mud additive to improve cutting transportation. In this study, the effect of the concentration of polyethylene (PE) and polypropylene (PP) polymer beads on cuttings transport efficiency (CTE) in water-based mud in a horizontal wellbore was investigated. Experiments were conducted in a lab-scale flow loop equipped with a 13-ft (3.96 m) test section consisting of a concentric annulus acrylic outer casing (2 in. ID) and a static inner PVC drill string (0.79 in. OD). A total of 150 tests were conducted using 10 ppg water based mud (WBM) with 1%-5% by vol. Concentrations of polymer beads (PE and PP) were added at a range of 8-9.5 cp. Six different sizes of drilled cuttings ranging from 0.5 to 4.0mm were used as samples to determine the CTE at a constant 0.69 m/s average annular fluid velocity. The results revealed that CTE increased with the increase of polymer bead concentrations and that PP is better compared to PE overall due to its low density. The highest CTE was recorded at a 5% concentration of water-based mud polypropylene (WBMPP), which is approximately 96% for cutting sizes of 0.50mm-0.99 mm.",33,34,2
Drill String,,"Aarsnes, Ulf Jakob F.; Shor, Roman J.","Torsional vibrations with bit off bottom: Modeling, characterization and field data validation",,STICK-SLIP OSCILLATIONS; SELF-EXCITED VIBRATIONS; STABILITY ANALYSIS; SYSTEMS,"A distributed model of a drill string is presented, with Coulomb stiction as a distributed source term, to investigate the effect of borehole inclination and borehole friction on the incidence of torsional vibrations along a drill-string. To isolate the effect of this distributed friction, only cases where the bit is off bottom and with no axial movement are considered, and consequently a purely torsional model is used. The model is used to study the stick slip limit cycle, as caused by distributed Coulomb friction, and the limit-cycle period and amplitude dependence on the friction parameters is derived. This enables the qualitative limit-cycle behavior to be characterized as inertia or stick dominated, and examples of this characterization is validated with the field data. For comparison, high frequency field data from two deviated wells from surface and downhole sensors are considered. Time-series are isolated where angular rotation is restarted after a connection, with the bit off bottom and before axial motion is re-initiated, to make the data consistent with the model assumptions. A close match is obtained between recorded and modeled downhole data, however, in some cases either the initial torsional strain in the drillstring is not known or axial motion is initiated, which violates model assumptions, causing a mismatch.",23,23,1
Drill String,,"Liu, Yang; Ma, Tianshou; Chen, Ping; Yang, Chuan",Method and apparatus for monitoring of downhole dynamic drag and torque of drill-string in horizontal wells,Horizontal well; Drill-string; Dynamic drag force; Dynamic torque; Weight-on-bit; Torque-on-bit,FRICTION-REDUCING PERFORMANCE; AXIAL OSCILLATION TOOL; MODEL; SYSTEM; PREDICTION,"Monitoring and control downhole drag and torque is a eternal research topic in horizontal drilling technique, but the theory and experience are still in the exploring stage. In this work, an integrated dynamic monitoring method, including a downhole parameters measuring system and a model for calculating the effective weight of drillstring, is proposed to discover the downhole drag and torque. A computational program is developed in the Visual Basic environment. Taking well T2-4-22H1 as an example, the downhole experiment are conducted to obtain downhole weight-on-bit (DWOB) and downhole torque-on-bit (DTOB) by using the developed downhole parameters measuring apparatus (DPMA). The experiment results are utilized for verifying the feasibility and suitability of the present method. The results show that the measured DWOB is significantly lower than the recorded surface weight-on-bit (SWOB) under sliding mode. As a result, the downhole based drag force is obviously higher than that based on surface data. For rotary mode, though the weight-on-bit and drag force do not make significant difference on both surface and downhole, but excessive frictional torque is generated due to drillstring rotating. The main reasons caused the diversity of surface and downhole parameters are discussed. Additionally, based on the measured downhole parameters, the changing rules of friction coefficient under different drilling modes are inversed. The present drag and torque monitoring method can provide a powerful technical support for the safe and high-efficiency drilling of horizontal wells.",17,17,1
Drill String,,"Qiu, Hongyuan; Yang, Jianming; Butt, Stephen",Investigation on bit stick-slip vibration with random friction coefficients,Drillstring; Bit stick-slip; Path integration; Random friction coefficient; Probability; Parametric studies,NUMERICAL PATH-INTEGRATION; OIL-WELL DRILLSTRINGS; STOCHASTIC DYNAMICS; DRAG BITS; SYSTEMS,"Torsional vibration of a drillstring, bit stick-slip in particular, is investigated with a simplified single degree of freedom (DOF) model in this paper. The friction in the bit-rock interaction is modeled as random, and the motions in stick and slip stages are treated separately. In the stick stage, it is treated as in static equilibrium. A single point or a range of points, at which the stick stage is completed and the slip stage is started, are determined depending on deterministic or random static friction coefficient assumed respectively. In the slip stage, the response at a time instant becomes a spreading area centered around the means due to the randomness of the kinetic friction. By assuming the random kinetic friction as White noise, the probabilistic distribution of the responses with displacement and velocity is calculated with the numerical path integration (PI) technique. For verification purpose, Monte Carlo (MC) simulation is also conducted. Also due to the randomness in friction, the time instants leaving the slip stage, or entering the stick stage, become random. Comparison between PI and MC shows that results from the two methods are in good agreement. In addition, parametric studies on damping, rotary speed, weight on bit, drillstring length and different combination of pipe and collar are conducted for both deterministic and random cases.",17,17,1
Inorganic Pores,,"Su, Siyuan; Jiang, Zhenxue; Shan Xuanlong; Zhang, Chunwei; Zou, Qingtian; Li, Zheng; Zhu, Rifang","The effects of shale pore structure and mineral components on shale oil accumulation in the Zhanhua Sag, Jiyang Depression, Bohai Bay Basin, China",Shale oil; Pore structure; Mineral component; Occurrence of space; Free phase; Adsorbed phase; Enrichment,MISSISSIPPIAN BARNETT SHALE; LACUSTRINE SHALE; METHANE SORPTION; ORDOS BASIN; GAS-STORAGE; RESERVOIRS; ADSORPTION; MORPHOLOGY; USA,"The pore structure and mineral components of shale have different effects on the enrichment of different phases of shale oil. Thus, research on the relationships between shale's pore structure and mineral components and shale oil enrichment is particularly important. Using core observations, scanning electron microscopy, whole rock mineral diffraction analysis, CO2 and N-2 low-temperature and -pressure adsorption experiments and nuclear magnetic resonance experiments, this study analyzed the effects of the pore structure characteristics and mineral components of shale on shale oil accumulation in the lower segment of the third member of the Shahejie Formation in the Zhanhua Sag, Jiyang Depression, Bohai Bay Basin, China. This shale segment primarily contains inorganic pores and fractures. The inorganic pores include intergranular, intragranular, intercrystalline and dissolution pores. Structural microfractures and bedding fractures are the main types of fractures in the connected network of the shale rocks. Organic pores are not fully developed in the segment, and a few organic materials with interbedded clay minerals form the intergranular and dissolution pores with calcite. The pore structures in the study area are very complex. Micropores, mesopores and macropores are all present, and micropores account for 19% of the pores, mesopores account for 31%, and macropores account for 50%. We compared the results of CO2 and N-2 adsorption experiments performed before and after chloroform extraction of shale samples and found that adsorbed-phase shale oil is primarily stored in micropores, which have diameters less than 2 nm, whereas free-phase shale oil is stored in mesopores, macropores and microfractures, which all have diameters greater than 2 nm. The carbonate content ranges from 46% to 88% and primarily comprises calcite, which favors the formation of intergranular and dissolution pores. The pyrite content is positively correlated with the pore volume, which is conducive to the development of pores. However, the clay content is negatively correlated with the pore volume, which is not conducive to the development of larger pores or the enrichment of movable shale oil.",32,36,6
Inorganic Pores,,"Su, Siyuan; Jiang, Zhenxue; Shan, Xuanlong; Zhu, Yunfeng; Wang, Peng; Luo, Xuan; Li, Zheng; Zhu, Rifang; Wang, Xiaoyong",The wettability of shale by NMR measurements and its controlling factors,Shale oil; Wettability; Nuclear magnetic resonance; Geochemistry; Mineral,BOHAI BAY BASIN; EASTERN CHINA; JIYANG DEPRESSION; CONTINENTAL SHALE; PORE TYPES; RESERVOIRS; SAG,"In this study, shale samples from the Zhanhua Sag in the Jiyang Depression of the Bohai Bay Basin were used to test the wettability of shale by nuclear magnetic resonance (NMR). The organic matter abundance, movable hydrocarbon content, clay content and carbonate content of shale samples with different wetting characteristics were compared. The results demonstrated that the TOC content of shale samples with mixed wettability was greater than that of water-wettability samples. This finding indicates that with the increase in TOC content, pores can be changed from water-wetting to oil-wetting, and the inorganic pores become organic. The above analysis demonstrates that the existence of organic matter is the basic reason that shale porosity exhibits oil wettability. Further, the shale samples with mixed wettability were higher in mobile hydrocarbon content (S-1) than were those with only water wettability. The shale samples with mixed wettability showed higher clay content than did those with water wettability, indicating that organic matter is associated with clay minerals. However, the samples with water wettability had greater carbonate content than those with mixed wettability, indicating that inorganic pores are formed primarily by carbonate rock. In summary, shale with mixed wettability in the Zhanhua Sag can be used as an exploration target favorable for shale oil enrichment.",25,30,11
Inorganic Pores,,"Franco-Aguirre, Maribel; Zabala, Richard D.; Lopera, Sergio H.; Franco, Camilo A.; Cortes, Farid B.",Ca-DTPMP nanoparticles-based nanofluids for the inhibition and remediation of formation damage due to CaCO3 scaling in tight gas-condensate reservoirs,Calcium carbonate; Formation damage; Inhibition; Nanofluid; Phosphonate; Remediation,CALCIUM-CARBONATE PRECIPITATION; PHOSPHONATE; ADSORPTION; MEDIA; OIL,"The oil productivity of tight gas-condensate reservoirs can be affected by the precipitation/deposition of inorganic scales such calcium carbonate (CaCO3), which leads to a reduction mainly in permeability and porosity of the porous media. Therefore, the main objective of this study is to develop for the first time a nanofluid based on the interaction between active nanoparticles such as Ca-diethylenetriamine pentamethylene phosphonic (Ca-DTPMP) and remaining synthesis fluid (RSF) obtained from the synthesis process, to simultaneously inhibit and remove the formation damage due to the precipitation/deposition of CaCO3 scales. The synthesis of the Ca-DTPMP nanoparticles was performed varying the phosphonate concentration between 0.01 and 0.5 M. The obtained nanoparticles were characterized through N-2 physisorption at - 196 degrees C for obtaining the surface area (S-BET), field emission scanning electron microscopy (FESEM), and dynamic light scattering (DLS) measurements. The mean nanoparticles size of the obtained materials ranged between 36 and 69 nm and was lower for the nanoparticles synthesized with a lower concentration of DTPMP. Nanofluids containing the synthesized nanoparticles of Ca-DTPMP were prepared with RSF solutions in deionized water as a carrier fluid for different Ca-DTPMP/RSF ratios of 10, 50, 200 and 500. The ability of the nanoparticles and nanofluids to inhibit the CaCO3 scaling was evaluated in batch-mode experiments at 70 degrees C by measuring changes in the calcium ion (Ca2+) concentration in the solution. The nanofluid with better performance was that prepared with 50 mg/L of Ca-DTPMP/0.3 nanoparticles and a Ca-DTPMP/RSF ratio of 10, with an inhibition efficiency of 67%. Further, coreflooding tests were carried out using the nanofluid with better performance from the batch-mode experiments. Displacement tests were conducted under tight gas-condensate reservoir conditions at a temperature of 110 degrees C (230 degrees F) and confining and pore pressures of 34.47 MPa (5000 Psi) and 6.89 MPa (1000 Psi), respectively. Inhibition and remediation of CaCO3 scaling were evaluated. The nanofluid was soaked in the porous media for 8 h. Based on the results of the relative permeability and oil recovery curves, it is possible to conclude that the synthesized nanofluid promotes the inhibition and removal of the formation damage due to CaCO3 inorganic scales. The nanofluid injection leads to an increase of the oil permeability of 57% in comparison with the base system, suggesting that the nanofluid acts as inhibitor agent, as remediation treatment, and as stimulation product of oil wells. Also, the treatment showed a perdurability of more than 60 pore volumes and increasing of oil recovery of 4 and 24% regarding the base and the damaged systems, respectively.",16,16,1
Inorganic Pores,,"Chen, Fangwen; Lu, Shuangfang; Ding, Xue; He, Xipeng; Xing, Huilin",The splicing of backscattered scanning electron microscopy method used on evaluation of microscopic pore characteristics in shale sample and compared with results from other methods,Microscopic pore; Longmaxi Shale; Frequency; Pore volume; Specific surface area,SIZE DISTRIBUTION; GAS-ADSORPTION; MERCURY INTRUSION; SURFACE-AREA; POROSITY; RESERVOIRS; CHINA; PHYSISORPTION; USANS/SANS; DENSITY,"The splicing of backscattered scanning electron microscopy (SB-SEM) method was applied to evaluate the microscopic pore characteristics of the Lower Silurian Longmaxi Shale samples from Py1 well in Southeast Chongqing, China. The results from SB-SEM, including frequencies, volumes and specific surface areas of organic and inorganic pores with different sizes, were compared with those of low temperature nitrogen adsorption/ desorption (LTNA) and mercury intrusion porosimetry (MIP). The results show that the changes in organic and inorganic surface porosity with increasing image area estimated from the SB-SEM method become almost stable when the SB-SEM image areas are larger than 0.4 mm(2), which indicates that the heterogeneities of organic and inorganic pore volumes in shale samples can be largely overcome. This method is suitable for evaluating the microscopic pore characteristics of shale samples. Although the SB-SEM underestimates the frequencies, volumes and specific surface areas of pores smaller than its resolution, it can obtain these characteristics of pores larger than 100 nm in width, which are not effectively evaluated by the LTNA method and are underestimated by the MIP method.",15,17,2
Specific Surface Area,,"Simonsen, Galina; Strand, Mikael; Oye, Gisle",Potential applications of magnetic nanoparticles within separation in the petroleum industry,Magnetic nanoparticle; Emulsion; Crude oil; Separation; Oil droplet; Environment; Contents,IRON-OXIDE NANOPARTICLES; FLOW FRACTIONATION; WATER; REMOVAL; CATALYSIS; RECOVERY; METAL; FUNCTIONALIZATION; MICROPARTICLES; BEHAVIOR,"Magnetic nanoparticles have unique properties such as extremely large surface area per volume substance and strong magnetic response. In addition, the possibilities for surface functionalization make them exciting candidates for separation applications in oil and gas production and processing. Relevant separation applications discussed in this review are emulsion separation, oil spill clean-up, produced water purification, and mitigation of undesired phase separation. Surface coatings entailing polymers, surfactants, or inorganic compounds are typically used to protect and stabilize the nanoparticles and for further functionalization in targeting specific applications. The adsorption, or separation efficiency, of the functionalized nanoparticles in certain processes is found to reach as high as 99.99% and depends on the type of surface coating, proper nanoparticle dispersion in the target medium, and the chosen separation technique. Several magnetically driven methods available for nanoparticle recovery, or nanoparticle purification, are discussed with respect to their efficiency and possibilities for optimization. Safety concerns regarding the use of the nanoparticles in industrial work environments and potential risks of exposure are presented in the last section.",45,46,1
Specific Surface Area,,"Liu, Min; Shabaninejad, Mehdi; Mostaghimi, Peyman","Predictions of permeability, surface area and average dissolution rate during reactive transport in multi-mineral rocks",Pore-scale modelling; Reactive transport; Mineralogical heterogeneity; 3D imaging,PORE-SCALE SIMULATION; NUMERICAL-SIMULATION; WORMHOLE FORMATION; CARBONATE; COAL; POROSITY; IMPACT; FLOW; HETEROGENEITY; SEGMENTATION,"The interactions between minerals and reactive fluids have great impact on the pore structure and hydrologic properties of rocks. A 3D pore-scale reactive transport model is applied to predict multi-mineral reactions in porous rocks. Eight mineral phases are distinguished in 2D slices of a reservoir sandstone by using Quantitative Evaluation of Minerals by SCANning electron microscopy (QEMSCAN) imaging technique. The 2D image is then registered into the corresponding cross-section of the 3D rock image obtained from micro-computed tomography (CT) scanning. Reactive transport with chemical dissolution is simulated directly on the 3D image of the sandstone. In the simulations, each mineral is assigned with a specific intrinsic reaction rate constant. The dissolution-induced changes in the pore structure are measured. The pore size distribution of the rock is analysed to investigate the evolution of the pore space. The changes of surface area and permeability are compared with single mineral simulations to illustrate the importance of mineralogical heterogeneity on reactive transport. The results show that the 3D pore-scale mineralogical heterogeneity causes overestimation of the permeability variations during reactive transport. The average effective dissolution rates for the rock are also measured. The simulations with single mineral assumptions present an overall reaction rate which is 10 times higher than the predictions with multi-mineral dissolution at the start of reactions. Relationships between average reaction rate and time are proposed to characterise the evolution of dissolution rate. A correction is also suggested to reduce the errors in predictions of reaction rates with single mineral assumptions.",25,25,4
Specific Surface Area,,"Minde, Mona W.; Wang, Wenxia; Madland, Merete, V; Zimmermann, Udo; Korsnes, Reidar, I; Bertolino, Silvana R. A.; Andersen, Pal O.",Temperature effects on rock engineering properties and rock-fluid chemistry in opal-CT-bearing chalk,Chalk; Compaction; Dissolution/precipitation; Permeability; Opal-CT; Mineralogical changes,NORTH-SEA; POROSITY; PRECIPITATION; SEDIMENTS; MODEL; COMPACTION; SEAWATER; BEHAVIOR; DENMARK; EKOFISK,"In this study, eight tri-axial tests on Cretaceous age outcrop chalk from Aalborg have been performed systematically by injecting MgCl2 for the first time at different temperatures (25, 60, 92, 110 and 130 degrees C) and for comparison, NaCl at 130 degrees C. Whole-rock geochemistry, stable isotope measurements, pycnometry, Field Emission Gun Scanning Electron Microscopy with Energy-Dispersive X-ray Spectroscopy, X-Ray Diffraction (XRD) and measurements of Specific Surface Area (Brunauer-Emmett-Teller theory (N-2)) were applied to analyse unflooded and flooded cores. Based on analyses of changes in brine composition, mineralogy, specific surface area, solid density, porosity and permeability some conclusions can be drawn on temperature effects on rock engineering properties and rock-fluid chemistry. The MgCl2 flooded cores show systematically higher creep rates at higher temperature and the cores tested at 25 and 60 degrees C show similar creep rates as the two NaCl flooded cores at 130 degrees C. All fluid-rock interactions were more pronounced at higher temperature. After flooding with MgCl2 at 110 and 130 degrees C newly formed magnesite is observed. In the cores tested at 25, 60 and 92 degrees C magnesite crystals have not been positively identified, but minute increases in MgO in whole-rock geochemistry analyses are seen. Si4+ originating from the dissolution of silica bearing phases (mainly diagenetic opal-CT), has taken part in the re-precipitation of Si-Mg-bearing minerals during MgCl2 injection from 25 to 130 degrees C, leading to an increase of the specific surface area. This is partly balanced by opal-CT dissolution, which should lower the specific surface area. The flaky Si-Mg-bearing minerals, covering significant portions of the pore surfaces and throats are the main drivers to reduce permeability in cores flooded at high temperatures. Additionally, in NaCl flooded cores where mineralogical changes are minute, the dissolution of parts of the existing opal-CT has lowered the SSA. At high temperatures, the following chemical changes must be carefully acknowledged when porosity reduction is calculated: calcite and opal-CT dissolution and precipitation of new minerals, particularly Mg-bearing minerals. The presence of opal-CT strongly influences the mineralogical alterations in flooded cores, hence the geo-mechanical evolution.",20,20,0
Specific Surface Area,,"Chen, Fangwen; Lu, Shuangfang; Ding, Xue; He, Xipeng; Xing, Huilin",The splicing of backscattered scanning electron microscopy method used on evaluation of microscopic pore characteristics in shale sample and compared with results from other methods,Microscopic pore; Longmaxi Shale; Frequency; Pore volume; Specific surface area,SIZE DISTRIBUTION; GAS-ADSORPTION; MERCURY INTRUSION; SURFACE-AREA; POROSITY; RESERVOIRS; CHINA; PHYSISORPTION; USANS/SANS; DENSITY,"The splicing of backscattered scanning electron microscopy (SB-SEM) method was applied to evaluate the microscopic pore characteristics of the Lower Silurian Longmaxi Shale samples from Py1 well in Southeast Chongqing, China. The results from SB-SEM, including frequencies, volumes and specific surface areas of organic and inorganic pores with different sizes, were compared with those of low temperature nitrogen adsorption/ desorption (LTNA) and mercury intrusion porosimetry (MIP). The results show that the changes in organic and inorganic surface porosity with increasing image area estimated from the SB-SEM method become almost stable when the SB-SEM image areas are larger than 0.4 mm(2), which indicates that the heterogeneities of organic and inorganic pore volumes in shale samples can be largely overcome. This method is suitable for evaluating the microscopic pore characteristics of shale samples. Although the SB-SEM underestimates the frequencies, volumes and specific surface areas of pores smaller than its resolution, it can obtain these characteristics of pores larger than 100 nm in width, which are not effectively evaluated by the LTNA method and are underestimated by the MIP method.",15,17,2
Slug Length,,"Baba, Yahaya D.; Aliyu, Aliyu M.; Archibong, Archibong E.; Abdulkadir, Mukhtar; Lao, Liyun; Yeung, Hoi",Slug length for high viscosity oil-gas flow in horizontal pipes: Experiments and prediction,High viscosity oil; Gamma densitometer; Slug length; Translational velocity; Two phase flow,LIQUID SLUG; INTERMITTENT FLOW; MODEL; HOLDUP; TRANSITIONS; FREQUENCY; EVOLUTION; DIAMETER; TUBES,"An experimental investigation was carried out on the effects of high liquid viscosities on slug length in a 0.0762-m ID horizontal pipe using air-water and air-oil systems with nominal viscosities ranging from 1.0 to 5.5 Pa s. The measurements of slug length were carried out using two fast sampling gamma densitometers with a sampling frequency of 250 Hz. The results obtained show that liquid viscosity has a significant effect on slug length. An assessment of existing prediction models and correlations in the literature was carried out and statistical analysis against the present data revealed some discrepancies, which can be attributed to fluid properties in particular, low viscous oil data used in their derivation Hence, a new high viscous oil data presented here from which we derive a new slug length correlation was derived using dimensional analysis. The proposed correlation will improve prediction of slug length as well as provide a closure relationship for use in flow simulations involving heavy oil. This is important since most current fields produce highly viscous oil with some reaching 10 Pa s.",20,22,1
Slug Length,,"Archibong-Eso, A.; Baba, Y.; Aliyu, A.; Zhao, Y.; Yan, W.; Yeung, H.",On slug frequency in concurrent high viscosity liquid and gas flow,Multiphase flow; Slug frequency; Slug holdup; Slug film; Heavy oil; Pressure gradient,HORIZONTAL PIPES; 2-PHASE FLOW; OIL; PREDICTION; DIAMETER; MODEL,"Slug frequency is an important input parameter in most mechanistic and semi-mechanistic models used for estimating slug flow characteristics such as pressure gradient, slug length and slug holdup. It is also essential in the design and sizing of transport and/or production pipelines, process flow control, design and operation of process equipment, etc. This study experimentally investigates slug frequency in two horizontal pipelines with internal diameters (ID) of 0.0254 and 0.0764 m. Test liquids used in the study were mineral oil (with viscosity ranging from 1.0 to 4.0 Poise) and water while compressed air is the gas phase. Effects of liquid viscosity, gas superficial velocity, liquid superficial velocity, pipe internal diameter, pipe length and pressure gradient are discussed. Results indicate that slug frequency increased with increase in oil viscosity; decreased with increase in pipe diameter; and reduces along the length of the pipe. For gas Reynolds number, Re-SG <= 2500, slug frequency increased with increase in gas superficial velocity, when Re-SG > 2500, slug frequency decreased with increase in gas superficial velocity. A new slug frequency correlation that accounts for liquid viscosity and gas superficial velocity, hitherto not included in other correlations was proposed. A comparative analysis of the proposed models and existing slug frequency correlation on a high viscosity databank showed that the proposed correlation gave the best prediction with an average absolute percentage error (AAPE) of 19.91%.",17,17,0
Delta C-13,,"Feng, Ziqi; Dong, Dazhong; Tian, Jinqiang; Qiu, Zhen; Wu, Wei; Zhang, Cong","Geochemical characteristics of Longmaxi Formation shale gas in the Weiyuan area, Sichuan Basin, China",Geochemical characteristics; Shale gas; Longmaxi Formation; Carbon isotope; Weiyuan area; Sichuan Basin,CARBON-ISOTOPE RATIOS; MISSISSIPPIAN BARNETT; REVERSALS; SYSTEMS; ACCUMULATION; METHANE; TRENDS; TEXAS,"Recently, shale-gas exploration in the Lower Silurian has been conducted in the Weiyuan area, southwestern Sichuan Basin, which has a special symbolic significance for the development of shale gas in China. According to the first systematic analysis of its geochemical characteristics, methane accounts for the vast majority (95.7%) of the Longmaxi Formation shale gas in the Weiyuan area, with extremely low wetness (C2-3/C1-3%) of 0.57%. Non-hydrocarbon gases consist of small amounts of N-2 and inorganic-induced CO2. The delta C-13(-CH4) values of shale gas range from -36.9 parts per thousand to -34.0 parts per thousand, and the delta C-13(-C2H6) values range from -42.8 parts per thousand to -37.5 parts per thousand indicating that the gases originate from sapropelic kerogen. A reversal in carbon-isotopic composition, i.e., delta C-13(-CH4) > delta C-13-(C2H6) > delta C-13(-C3H8), results from combined secondary effects such as secondary cracking and diffusion under extremely high thermal maturity. Geologic features of organic-rich shale and secondary effects at the overmature stage together lead to differences in geochemical characteristics of shale gas in the Weiyuan and Changning and Fuling (CF) areas, which can be used to indicate the distribution of geochemical parameters and predict shalegas production.",21,25,3
Delta C-13,,"Su, Kaiming; Lu, Jungang; Zhang, Guangwu; Chen, Shijia; Li, Yong; Xiao, Zhenglu; Wang, Pan; Qiu, Wen","Origin of natural gas in Jurassic Da'anzhai Member in the western part of central Sichuan Basin, China",Gas geochemistry; Natural gas origins; Mixing ratio; Da'anzhai Member; Western part of central Sichuan basin,THERMOCHEMICAL SULFATE REDUCTION; STABLE CARBON ISOTOPES; TIGHT OIL ACCUMULATION; HYDROGEN; ORDOVICIAN; MATURITY; METHANE,"The distribution pattern of oil and gas in the western part of central Sichuan Basin is complicated, there are many different views on the sources of natural gas, which restrict further exploration and deployment of oilfields. Therefore, by analyzing geochemical characteristics and quantitative calculation of natural gas in study area, combined with the data of structure and gas-oil ratio, the origin and sources of gas are discussed and analyzed. The results show that the dryness coefficient of the natural gas ranges between 0.71 similar to 0.93, delta C-13 values range between -45.3 similar to -38.0% in methane, -32.0 similar to -25.6% in ethane and -30.0 similar to -25.3% in propane. Crossplots of isotope data and quantitative calculation indicate that natural gas in Da'anzhai Member is characterized by the mixture of sapropelic and humic natural gas, the humic gas largely occupies the proportion of 20-40%, up to 70%. It is the result of upward migration of natural gas in Triassic Xujiahe Formation. The abnormally high gas-oil ratio is an important manifestation of this upward intrusion. Based on the study of high gas-oil ratio wells, the distribution of humic natural gas that intruded from Xujiahe Formation and enriched in Da'anzhai Member is unevenly distributed. It inherits characteristics of ""Plaque accumulation"" of natural gas in Xujiahe Formation. The inhomogeneity of this plane distribution is controlled by fault location, fault scale and the size of underlying Xujiahe Formation gas reservoirs. The humic gas from Xujiahe Formation occupies a large proportion in blocks of Da'anzhai Member which are favorable for intrusion, accumulation and preservation of Xujiahe Formation natural gas, whereas for blocks without these conditions, natural gas is often associated gas.",16,16,4
Unconfined Compressive Strength,,"Atapour, Hadi; Mortazavi, Ali",The influence of mean grain size on unconfined compressive strength of weakly consolidated reservoir sandstones,Uniaxial compressive strength; Petrographical properties; Grain size; Porosity; Weakly consolidated reservoir sandstone,ENGINEERING PROPERTIES; MECHANICAL-BEHAVIOR; BRITTLE; STRESS; FAILURE; ROCK; PREDICTION; INITIATION; DOLOMITES; POROSITY,"The effects of mean grain size on unconfined compressive strength (UCS) of weakly consolidated reservoir sandstones are studied by series of unconfined compressive tests performed. According to previous studies, the influence of grain size on rock strength is not clear and inconsistent results are reported. In this study, categorizing the rocks studied in previous researches into two classes of non-porous crystalline and porous granular rocks, it was found that the compressive strength of all investigated crystalline rocks is inversely related to the mean grain size, while in the case of granular porous rocks (e.g. sandstones) different results are obtained by different researchers. In current investigation, the obtained experimental results indicated that grain size alone is not a suitable indicator of the compressive strength of porous sandstone. The reason for this is that except grain size, other textural characteristics such as pore spaces and cementation, play important roles in the strength of sandstones and should be considered along with the grain size. Based on these results, an empirical model was developed to estimate the unconfined compressive strength of porous sandstones based on grain size, porosity, and cement content. The validity of the suggested empirical model for natural sandstones was checked against data reported in the literature.",19,19,5
Unconfined Compressive Strength,,"Yu, Hongyan; Zhang, Yihuai; Lebedev, Maxim; Han, Tongcheng; Verrall, Michael; Wang, Zhenliang; Al-Khdheeawi, Emad; Al-Yaseri, Ahmed; Iglauer, Stefan",Nanoscale geomechanical properties of Western Australian coal,Nanoindentation test; Microstructure; Young's modulus; Enhanced coal bed methane,MECHANICAL-PROPERTIES; ELASTIC PROPERTIES; MINERAL MATTER; PERMEABILITY; CO2; SORPTION; FORCE; SHALE; FLOW; GASIFICATION,"Geomechanical properties are of great importance in coal mining exploration, (enhanced) coal bed methane production and carbon geosequestration in deep unmineable coal seams. However, coal highly heterogeneous rocks, and conventional experimental methods (e.g. acoustic, seismic or unconfined compressive strength tests) only measure the cm-m scale bulk properties. Thus, we measured the geomechanical properties at nanoscale of Western Australian Collie coal. We mapped the nanoscale mechanical heterogeneity and correlated it with the sample's morphology (measured by SEM-EDS). It was found that the quartz and siderite in the coal had higher Young's moduli (up to 28.6 GPa), while the organic coal matrix had lower Young's moduli (from 3 GPa to 5 GPa), while the soft material kaolinite had the lowest Young's moduli (<3 GPa). We conclude that it is necessary to measure the geomechanical coal properties at nano/micro scale reliably assess and eventually facilitate field scale CBM/ECBM or CO2 storage.",19,20,4
Other topics ,,"Zhang, Liehui; Kou, Zuhao; Wang, Haitao; Zhao, Yulong; Dejam, Morteza; Guo, Jingjing; Du, Jia",Performance analysis for a model of a multi-wing hydraulically fractured vertical well in a coalbed methane gas reservoir,Coalbed methane; Multi-wing fractured vertical well; Multiple transportation mechanisms; Production performance; Stimulated reservoir volume,PRESSURE TRANSIENT ANALYSIS; LAPLACE INVERSION METHODS; SINGLE MATRIX BLOCK; HORIZONTAL WELL; SHEAR DISPERSION; FLOW; MECHANISM; BEHAVIOR; VOLUME; TUBE,"This paper proposes a composite model to investigate the pressure behavior and production performance of a multi-wing hydraulically fractured multiple fractured vertical well (MFVW) in a coalbed gas reservoir with a stimulated reservoir volume (SRV). The model simultaneously considers adsorption-desorption, diffusion, and viscosity flow. The MFVW model combines line-source method with Laplace transformation and discretization method. Then, the Stehfest numerical inversion and the Gauss elimination are utilized to obtain the transient pressure responses and production dynamics. The results show that the main flow regimes for an MFVW in a coal seam gas reservoir are linear flow between hydraulic fractures, pseudo radial flow in the SRV, transition flow from the inner to the outer region, and radial flow in the outer region. Further, a slight ""hump"" is observed during the linear flow period, which could not be observed in the curves of MFVWs with two-wing hydraulic fractures. The effects on MFVW performance of permeability and size of the SRV, properties of hydraulic fractures (fracture angle asymmetry, different fracture angle, and fracture number), Langmuir volume, and Knudsen diffusion coefficient are discussed. The conclusions obtained in this paper will be helpful to understand the transient performance of MFVWs in coalbed gas reservoirs.",89,89,11
Other topics ,,"Ye, Qing; Wang, Geoff; Jia, Zhenzhen; Zheng, Chunshan; Wang, Weijun",Similarity simulation of mining-crack-evolution characteristics of overburden strata in deep coal mining with large dip,Similarity simulation; Deep coal seam; Coal mining face; Overburden strata; Mining-crack-evolution characteristics,FRACTURE; SUBSIDENCE; MOVEMENT; SEAM,"Figuring out the mining-crack-evolution characteristics of overburden strata is very important to roof control, gas drainage, disaster prevention and high efficient mining. In order to obtain the mining-crack-evolution characteristics of overburden strata in deep coal mining with large dip, in this study, No. 1221 coal mining face of Zhao coal mine is chosen as the research object to establish an in-house experiment system of similarity simulation. The experiments could measure the stress and displacement of overburden strata, which can provide useful information to investigate the mining-crack-evolution characteristics, displacement variations and movement characteristics of overburden strata associated the coal mining face. Experimental results show that with the advancing of coal mining face, the scope of gob increases gradually, and formation of the false roof of overburden strata basically reflects the evolution process of collapsing. The overburden strata weight is constantly transferred to the front and rear of coal mining face, which forms the supporting pressures on both sides of coal pillars, and causes the gangue's collapsing in gob. The large dip of coal seam results in pressure disequilibrium in stress-increasing zone. Thus, the stress on the underside of gob becomes larger and larger, while the stress on upper side of gob decreases. The strata separation appears in the overburden strata of roof. Pressure-relief zone is mainly concentrated in the side of outlet roadway. Along the inclination direction of coal mining face, the crack development and strata separation are obvious, which create the passages for gas flow and migration. The similarity simulation results provide fundamental information for better understanding those mining-crack-evolution characteristics of overburden strata, which has become more and more important to control the roadway stability in coal mining and optimize the layout of gas drainage boreholes for improving mining safety.",64,68,21
Other topics ,,"Zhao, Guang; You, Qing; Tao, Jiaping; Gu, Chenglin; Aziz, Hafiz; Ma, Liping; Dai, Caili",Preparation and application of a novel phenolic resin dispersed particle gel for in-depth profile control in low permeability reservoirs,Phenolic resin dispersed particle gel; Preparation parameters; Profile control; Oilfield application,SIZE; TIME,"Phenolic resin dispersed particle gel (PDPG) was successfully prepared from bulk gel by a mechanical shearing method. The effects of bulk gel strength, shearing time, shearing rate, and bulk gel-water ratio on the PDPG particles were systematically analyzed. The morphological results showed that the PDPG particles have a round shape with nano-size to micron-size distribution. The shearing rate is one of the most critical factors in the preparation, while the shearing time and bulk gel strength are secondary factors in preparing the PDPG particles. In addition, the bulk gel-water mixing ratio has a slight impact on the prepared PDPG particles. The PDPG particles had a good shearing resistance and expansion capacity which enhances their application performance in oilfields. Sand pack flowing experiments indicated that PDPG particles can easily enter the in-depth formations and effectively plug high permeability channels. The higher the formation permeability ratio of sand packs, the better the profile improvement rate. By retention or adsorption in large permeability zones, trapping and bridging across pore throats or large channels, the prepared PDPG particles can effectively improve the formation profile and divert the following water into low permeability zones, and then the oil is enhanced. The injection of PDPG particles was first successfully applied to Changqing Oilfield in China which provided a reference to control water production in other similar low permeability mature oilfields.",48,48,5
Other topics ,,"Hu, Jun; Chen, Jie; Chen, Zheng; Cao, Junxing; Wang, Quanfeng; Zhao, Libo; Zhang, Hui; Xu, Bin; Chen, Guodong","Risk assessment of seismic hazards in hydraulic fracturing areas based on fuzzy comprehensive evaluation and AHP method (FAHP): A case analysis of Shangluo area in Yibin City, Sichuan Province, China",AHP method; Fuzzy evaluation; Degree of membership; Hydraulic fracturing; Seismic risk assessment,FREQUENCY-MAGNITUDE RELATION; B-VALUE; REGIONAL SEISMICITY; WESTERN CANADA; GROUND MOTIONS; EARTHQUAKES; RESERVOIR; CALIFORNIA; VALUES; DEFORMATION,"In this paper, a fuzzy comprehensive evaluation (FCE) based on the analytic hierarchy process (AHP) model (FAHP) has been established to quantitatively evaluate the seismic risk of the region with covers 3080.25 km(2) including hydraulic fracturing operation areas. Taking into account the combined effect exerted by influencing factors such as geological structures, the seismic history and the stress accumulation, etc., six major factors are identified, namely, seismicity rates (Z value), magnitude-frequency coefficients (b value), salt mines, reservoirs, regional geotectonic (distribution of active faults), stress fields and the spatial distribution of fracturing platforms. In addition to using massive raw data as objective information, this model takes experts' assessments as the subjective judgment of expertise. According to the maximum membership principle, the most favorable risk evaluation have been made in 625 grids with optimized results through methods of the weighted average and the interpolation. Comprehensive evaluation maps have been drawn based on the seismic data from 2008 to 2016 used in modeling and have been validated by the seismic data in 2017. Results show that most of the seismic events in 2017 have fit into the high-risk area, especially those felt earthquakes larger than magnitude 3 have entirely fit into the medium-high risk area after the interpolation, indicating that the assessment results have certain objectivity and accuracy.",31,32,3
Other topics ,,"Liu, Zhe; Forouzanfar, Fahim; Zhao, Yu",Comparison of SQP and AL algorithms for deterministic constrained production optimization of hydrocarbon reservoirs,SQP; Augmented Lagrangian; Nonlinear constrains; Production optimization; Adjoint gradient; Net present value (NPV),CYCLE PRODUCTION OPTIMIZATION,"Reservoir production optimization involves the determination of well control settings which maximize a pre-defined reservoir production preference such as ultimate oil recovery or net present value (NPV). Honoring the nonlinear constraints, such as producer's water cut and bottom hole pressure (BHP) constraints for rate specified wells, is the most challenging part of the production optimization. This work entails a comparative study of the augmented Lagrangian (AL) and sequential quadratic programming (SQP) algorithms for constrained reservoir optimization. Both methods have been widely used to solve the nonlinear constrained optimization problems in the numerical optimization community. The optimization of PUNQ reservoir model is considered in order to compare the performance and robustness of the AL and the SQP, where the gradients of the objective function and nonlinear constraints are estimated using the adjoint method. The computational results showed that with properly tuned parameters and good initial points, the AL could yield a slightly higher ultimate NPV in some cases. However, the SQP generally has better performance regarding efficiency, robustness and constraints handling. For example, under the SQP generated optimal well controls, the watercut of each producer would strictly obey the constraint, while the optimal well controls generated by AL would lead some minor valuations. Moreover, an SQP-AL algorithm is also proposed to solve the constrained production optimization problem by applying the AL search direction on the convergence of SQP. The results showed that the SQP-AL algorithm is able to achieve a higher NPV with slightly more iterations compared with the SQP method.",31,31,1
Other topics ,,"Adedigba, Sunday A.; Oloruntobi, Olalere; Khan, Faisal; Butt, Stephen",Data-driven dynamic risk analysis of offshore drilling operations,Dynamic failure probability; Risk analysis; Blowouts; Drilling; Bayesian tree augmented naive Bayes (TAN),PROCESS ACCIDENT MODEL; PROCESS INDUSTRIES; SAFETY ANALYSIS; FAULT-TREE; NETWORKS; BLOWOUTS; OIL,"A data-driven dynamic risk analysis methodology is proposed here. The methodology is applied to offshore drilling operations. Modern drilling rigs are highly instrumented to monitor real time operational data. This provides sufficient data for time dependent risk analysis of drilling operations. The probabilistic relationships (structure) among the primary operational (drilling) parameters are modelled using the Bayesian Tree Augmented Naive Bayes (TAN) algorithm. The developed model is used to predict time dependent probability of kick, and is continuously updated based on the current state of the key drilling parameters. The real-time probability of kick is used to model blowout risk as a function of time. The dynamic risk profile generated from the model is useful in operational decision making to prevent accidents and enhance the safety of drilling operations. The proposed dynamic risk methodology is tested and verified using actual drilling operational data.",28,28,4
Other topics ,,"Yaseen, Salah; Mansoori, G. Ali",Asphaltene aggregation due to waterflooding (A molecular dynamics study),Asphaltene aggregation; Hydrogen bonds; Molecular dynamics; Salinity; Water miscibility; Waterflooding,PETROLEUM ASPHALTENES; SIMULATION; BEHAVIOR; MODEL; OILS; PRECIPITATION; FLOCCULATION; SALINITY; SOLVENT; TOLUENE,"In the present study, we report our findings on various asphaltenes-water interactions at a high reservoir condition (550 K and 200 bar) and the role of water in asphaltene association during the waterflooding process. Molecular dynamics simulations are performed on oil/water and oil/brine systems. The oil phase is composed of asphaltenes (10 wt%) and ortho-xylene in which asphaltenes are entirely soluble. Seven different model-asphaltenes with diverse molecular weights, architectures, and heteroatom contents are employed. Interestingly, Results indicate that asphaltenes become less soluble in oil when water is partially misciblized in the oil phase. All model-asphaltenes containing nitrogen and/or oxygen atoms in their structures are prone to association. The driving force behind asphaltene aggregation is shown to be an asphaltene-water hydrogen bond. The utilization of the brine (3.5 wt% NaCl) instead of pure water induces a slight decrease in asphaltene propensity for aggregation due to salt-in effect. Results also suggest that face-to-face contact is the prominent stacking of asphaltene molecules in their aggregates.",28,28,2
Other topics ,,"Phillips, A. J.; Troyer, E.; Hiebert, R.; Kirkland, C.; Gerlach, R.; Cunningham, A. B.; Spangler, L.; Kirksey, J.; Rowe, W.; Esposito, R.",Enhancing wellbore cement integrity with microbially induced calcite precipitation (MICP): A field scale demonstration,Wellbore integrity; Calcium; Ureolysis; Leakage pathways; Well cement; Calcium carbonate,CARBONATE PRECIPITATION; POROUS-MEDIA; CUBIC LAW; IMPROVEMENT; REDUCTION; INJECTION; LEAKAGE; FLOW,"The presence of delaminations, apertures, fractures, voids and other unrestricted flow channels in the wellbore environment substantially reduces wellbore integrity. Compromised cement may cause a loss of zonal isolation leading to deleterious flow of fluids between zones or to the surface with multiple potential negative impacts including: loss of resource production, reduction of sweep efficiency in EOR operations, and regulatory noncompliance. One potential solution to enhance wellbore integrity is microbially induced calcite precipitation (MICP) to plug preferential flow pathways. MICP is promoted with micrometer-sized organisms and low viscosity (aqueous) solutions thereby facilitating fluid transport into small aperture, potentially tortuous leakage flow paths within the cement column. In this study, MICP treatment of compromised wellbore cement was demonstrated at a depth interval of 310.0-310.57m (1017-1019 feet) below ground surface (bgs) using conventional oil field subsurface fluid delivery technologies (packer, tubing string, and a slickline deployed bailer). After 25 urea/calcium solution and 10 microbial (Sporosarcina pasteurii) suspension injections, injectivity was reduced from the initial 0.29 cubic meters per hour (m(3)/h) (1.28 gallons per minute (gpm)) to less than 0.011m(3)/h (0.05 gpm). The flow rate was decreased while maintaining surface pumping pressure below a maximum pressure of 81.6 bar (1200 psi) to minimize the potential for fracturing a shale formation dominant in this interval. The pressure decay immediately after each injection ceased decreased after MICP treatment. Comparison of pre- and post-test cement evaluation logs revealed substantial deposition of precipitated solids along the original flow channel. This study suggests MICP is a promising tool for enhancing wellbore cement integrity.",27,32,2
Other topics ,,"Zsirai, T.; Qiblawey, H.; Buzatu, P.; Al-Marri, M.; Judd, S. J.",Cleaning of ceramic membranes for produced water filtration,Produced water; Ceramic membranes; Chemical cleaning; Footprint; Flux,OIL-FIELD; REINJECTION,"The application of ceramic microfiltration membranes to the tertiary treatment of produced water from an Arabian Gulf oilfield has been studied using a dedicated pilot plant. Studies were based on a previously published protocol in which the retentate stream was recycled so as to successively increase the feed concentration throughout the experimental run. Chemical cleaning in place (CIP) was applied between each run and the flux and permeability recovery recorded for various cleaning protocols studied, the CIP being based on the combination of caustic soda (NaOH) and citric acid. Surface analysis of the membrane, and specifically its hydrophilicity, was also conducted. Results indicated the main influencing factor on permeability recovery from the CIP to be the employment of backflushing during the CIP itself. A final flux of 700 Lm(-2) h(-1) was sustained through the application of 6 wt% NaOH with 6 wt% citric acid combined with backflushing at approximately twice the rate of the filtration cycle flux. A consideration of the impact of this flux value on the viability of two commercially-available ceramic membrane technologies indicated the footprint incurred to be slightly lower than that of the upstream induced gas flotation technology and corroborated a previously published estimate. The flux was sustained despite surface analysis indicating a loss of the innate hydrophilicity of the ceramic membrane.",24,25,2
Other topics ,,"Liu, Kouqi; Ostadhassan, Mehdi; Bubach, Bailey",Application of nanoindentation to characterize creep behavior of oil shales,Oil shales; Creep; Nanoindentation; Deconvolution; Mechanical properties,NANOSCALE MECHANICAL-PROPERTIES; UNCONSOLIDATED RESERVOIR SANDS; NANO-INDENTATION METHODS; BAKKEN SHALE; DEFORMATION; TIME; CONCRETE; ROCKS; DRY,"In petroleum industry, creep behavior of rocks can affect the fracture conductivity, well productivity and ultimate recovery of the reservoir, in shale formations in particular. To get a better insight into this phenomenon, in this study, we applied grid nanoindentation method as a function of time to quantify creep behavior of shale rocks which is a complex material. The deconvolution results from statistical analysis of the data showed that shale samples could be distinguished by three mechanical phases where the mechanical phase with the largest hardness value exhibits the least creep deformation. Burgers models was applied to characterize the creep behavior of our shale samples. We realized as creep time increases, the creep time constant value increases, therefore, a logarithmic function can be used to quantify their correlations. This study showed that as the creep time increases, Young's modulus, hardness, and fracture toughness will decrease. Finally, we concluded, shale samples become softer and more prone to fracture growth as the creep time increases.",23,24,12
Other topics ,,"Luo, Wanjing; Tang, Changfu; Feng, Yin; Zhu, Mengyuan",Mechanism of fluid flow along a dynamic conductivity fracture with pressure-dependent permeability under constant wellbore pressure,Mechanism of fluid flow; Dynamic-conductivity fracture; Pressure-dependent permeability; Semi-analytical solution; Closed rectangular reservoir,TRANSIENT ANALYSIS; HORIZONTAL WELLS; SHALE RESERVOIRS; PRODUCTIVITY; DRAINAGE; BEHAVIOR; VOLUME; MODEL,"With the production of hydrocarbons from reservoirs, fractures will gradually close, resulting in dynamic conductivities along the fracture. The main objective of this study is to develop a new semi-analytical model in Laplace domain to reveal the mechanism of fluid flow in a dynamic conductivity fracture with pressure-dependent permeability under constant wellbore pressure condition. A new model of dynamic conductivity fracture with pressure-dependent permeability has been established, which has the same form as the model of dynamic conductivity fracture with non-Darcy flow. Thus, the solution procedure of a dynamic conductivity fracture with non-Darcy flow can be introduced to obtain the distributions of dimensionless pressure, flow rate and fracture conductivity along the fracture. Results show that the fracture conductivity is a function of pressure, which varies along the fracture dynamically. During the production, the flow rate will change along the fracture as a function of the fracture conductivity and production time. With the increase of initial conductivity, the dimensionless flow rate increases dramatically, but increasing rate will slow down. For the same initial conductivity, as the dimensionless fracture permeability modulus increases, pressure difference drops along the fracture, which results in the reduction of production rate.",22,22,4
Other topics ,,"Jung, Hyungsik; Jo, Honggeun; Kim, Sungil; Lee, Kyungbook; Choe, Jonggeun",Geological model sampling using PCA-assisted support vector machine for reliable channel reservoir characterization,Support vector machine (SVM); Principal component analysis (PCA); Multi-dimensional scaling (MDS); Ensemble kalman filter (EnKF); Channel reservoir characterization,ENSEMBLE KALMAN FILTER,"History matching is a crucial procedure for predicting reservoir performances and making decisions. However, it is difficult due to uncertainties of initial reservoir models. Therefore, it is important to have reliable initial models for successful history matching of highly heterogeneous reservoirs such as channel reservoirs. In this paper, we proposed a novel scheme for sampling good geological models using support vector machine (SVM) and principal component analysis (PCA). First, we perform PCA for figuring out main geological characteristics of reservoir models. By the procedure, permeability values of each model are transformed to new parameters by principal components, which have eigenvalues of large magnitude. Secondly, the parameters are projected into two-dimensional plane by multidimensional scaling (MDS) based on Euclidean distances. Finally, we train a SVM classifier using 10% models which show the most similar or dissimilar well oil production rates (WOPR) with the true values (5% for each category). Then, the other 90% models are classified by the trained SVM. We select models on the side of lower WOPR errors. By repeating the classification process, we can select reliable models which have similar geological trend with the true reservoir model. The two channel fields are analyzed to demonstrate the superiority of the proposed sampling scheme. History matching results with 400 initial models cannot provide trustworthy results. It fails to find out correct geological features of the true model. In addition, since it uses all the models, it takes long computational time. However, history matching with the sampled ensemble offers reliable characterization results by figuring out proper channel trend and gives dependable prediction of future performances. Furthermore, it increases computational efficiency by using only selected geological models in history matching.",22,22,2
Other topics ,,"Li, Haitao; Tan, Yongsheng; Jiang, Beibei; Wang, Yongqing; Zhang, Nan",A semi-analytical model for predicting inflow profile of horizontal wells in bottom-water gas reservoir,Semi-analytical model; Inflow profile; Horizontal well; Gas reservoir; Bottom-water zone,PRESSURE-DROP; PRODUCTIVITY; FLOW; HETEROGENEITY; PERFORMANCE,"In this study, a semi-analytical model which couples the reservoir and wellbore, is developed to predict the inflow profile of horizontal wells in a box-shaped gas reservoir with a bottom water zone. The developed gas reservoir flow model is based on a 3D volumetric source model which considers the reservoir properties in the region near the wellbore, in terms of anisotropy, heterogeneity and formation damage. Meanwhile, pressure drops in the wellbore flow model was also considered, due to fluid flow in the horizontal wellbore. The model was calculated by a field case, and the results of the calculation were compared with a commercial simulator: ECLIPSE (Schlumberger, 2011). The comparison between the developed model and ECLIPSE indicates that, a good match was obtained, so that, the model derived in this study can be applied to predict the inflow profile of horizontal well in a gas reservoir with bottom water zone. Moreover, sensitivity analysis is conducted by using various wellbore pressure drops, wall roughness, skin factors, wellbore diameters, anisotropy and producing pressure drops.",22,24,1
Other topics ,,"Wang, Shuyan; Yang, Shanwen; Wang, Ruichen; Tian, Ruichao; Zhang, Xiaoyu; Sun, Qiji; Liu, Lili",Dissipative particle dynamics study on the temperature dependent interfacial tension in surfactant-oil-water mixtures,Dissipative particle dynamics (DPD); Repulsion parameters; Molecular dynamics (MD); Interfacial tension; Surfactant/oil/water system,NONIONIC SURFACTANTS; PHASE-BEHAVIOR; INTERACTION PARAMETERS; MESOSCOPIC SIMULATION; MORPHOLOGY; DPD,"Effects of cationic (CATB) and anionic (SDBS) surfactants on the interfacial tension (IFT) of surfactant/oil/water system at different temperatures are predicted using coarse-grained dissipative particle dynamics (DPD) at the mesoscopic scale. The DPD repulsive interaction parameters, a(ij), as a function of temperature (T) are calculated from the T dependent Flory-Huggins parameter chi for different components using all-atom molecular dynamics (MD). This paper provides a method based on DPD dynamics to obtain linear correspondences between the Flory-Huggins parameter chi and the excess repulsion parameter Delta alpha at different temperatures, which is a bridge between DPD and MD. The IFTs are measured in surfactant/oil/water systems at different temperatures to validate simulated results, they are in good agreement. Both experiments and simulations indicate that the interfacial tension decreases with an increase of temperature. Meanwhile, the interfacial information including equilibrated interface morphology, mean interfacial density and RMS end-to-end distance is obtained, by which the capacities of different surfactants to regulate oil-water interfacial properties at different temperatures are evaluated. Compared with CTAB and SDBS, SDBS has a good resistance to a higher temperature, and can maintain a lower interfacial tension in the range of 343-358 K. This indicates that the interfacial tension decreases with the increase of temperature in a certain range and the sensitivity of different surfactants to temperature is different. Furthermore, the impact of inorganic salt (NaCl) on interfacial properties of ionic surfactant (CTAB) is analyzed. It demonstrates that the modified DPD method is a good alternative to study the interfacial characteristics of surfactant/oil/water system at different temperatures.",21,21,7
Other topics ,,"Wang, Yingying; Tuo, Haohu; Li, Liwei; Zhao, Yu; Qin, Hua; An, Chen",Dynamic simulation of installation of the subsea cluster manifold by drilling pipe in deep water based on OrcaFlex,Installation of subsea manifold; Drill pipes; Theoretical model; Simulation on OrcaFlex,WELLS; MODEL,"The external environment in deep water is quite complicated, during the installation process of subsea cluster manifolds by the drill pipe, the safety and precise localization need to be addressed desperately. In this paper, based on small deformation theory, basic theoretical model on the drill pipe installation of subsea manifolds is proposed and OrcaFlex software is used to make a simulation on setting up the corresponding numerical model in which the installation process is divided into three main phases. Its main purpose is to make a simulation research in guiding for engineers before the practical installation. The displacement and stress state of drill pipe are simulated and their curves in the different phases are obtained. In the different phases of lowering subsea cluster manifold, three factors: current velocity, wave height and manifold weight have an evident impact on tension, bent moment, Mises stress of drill pipe and displacement of subsea manifold, which are quite useful for actual installation in deep water.",19,21,2
Other topics ,,"Wang, Chen; Li, Tiantai; Gao, Hui; Zhao, Jinsheng; Gao, Yuan",Quantitative study on the blockage degree of pores due to asphaltene precipitation in low-permeability reservoirs with NMR technique,Low-permeability reservoir; Asphaltene precipitation; Blockage; Permeability reduction; NMR technique,CO2 FLOODING PROCESSES; POROUS-MEDIA; OIL; DEPOSITION; VISUALIZATION; MECHANISMS; ADSORPTION; INJECTION; PRESSURE; BEHAVIOR,"With the nuclear magnetic resonance (NMR) technology, a new experimental method was proposed to study the blockage degree of pores due to asphaltene precipitation during CO2 flooding in Low-Permeability Reservoirs. By comparing the T-2 spectrum measured before and after CO2 flooding, the blockage degree by asphaltene precipitation was quantitatively determined for the pores with different sizes. It was found that, at the immiscible flooding stage, oil was mainly recovered from the larger pores (1.0-100.0 mu m) and the asphaltene tended to precipitate in such pores. Compared with the larger pores, nearly no asphaltene precipitation was formed in the smaller pores (0.1-1.0 mu m) at the immiscible stage. At CO2 injection pressures above the minimum miscibility pressure (MMP), asphaltene precipitation formed in the lager pores; precipitation also took place in the smaller pores, filling up a significant portion of space in the smaller pores. At the miscible flooding stage, the total amount of asphaltene precipitation was reduced. The observed permeability reductions correlate reasonably with the amount of asphaltene precipitation for all flooding stages. By analyzing the T-2 spectrum in different pores before and after CO2 flooding, it was observed that the smaller pores were more apt to be blocked by the asphaltene precipitation than the larger pores. Since the asphaltene-blocking phenomena significantly affect the smaller pores, the core permeability may be substantially compromised after CO2 flooding.",18,20,5
Other topics ,,"Liu, Yueliang; Li, Huazhou Andy; Okuno, Ryosuke",Phase behavior of N-2/n-C4H10 in a partially confined space derived from shale sample,Partially confined space; Sorption; Bubble-point pressure; Shale sample,EQUATION-OF-STATE; ADSORPTION; NANOPORES; PRESSURE; EQUILIBRIA; MIXTURES; FLUIDS; MEDIA,"Phase behavior of shale fluids in small pores is not well understood. One complexity comes from the fact that sorption of components by organic-rich shale can be significant and selective. In an attempt to elucidate the effect of sorption on phase behavior of shale fluids, we present a new experimental method that can be used to measure the bubble-point pressures of N-2/n-C4H10 mixtures in the presence of an actual shale sample. Pressure/volume (P/V) isotherms for a given mixture were firstly measured in a PVT cell. Then, the measurements of the P/V isotherms for the same mixture were repeated in a partially confined space by opening a valve between the PVT cell and a shale container. The so-called partially confined space consists of the pore space inside the shale sample, the bulk space in the PVT cell and in the connecting tubing, and the non-cementing pore spaces among the shale particles. Results show that, the measured bubble-point pressure of the N-2/n-C4H10 mixture in the partially confined space was higher than the corresponding bubble-point pressure in the bulk space. A detailed analysis indicates that, when loaded in the partially confined space, n-C4H10 exhibits a higher level of sorption capacity on the shale sample than N-2, resulting in a higher concentration of N-2 left in the free fluid than that in the initial mixture, which is the so-called selective sorption. The higher concentration of N-2 led to the higher bubble-point pressure as observed in the measurements. The increase of the bubble-point pressure due to the selective sorption was observed to be greater at a lower temperature. This is because the sorption of n-C4H10 relative to that of N-2 is more significant at a lower temperature. A higher temperature did not lead to a higher increment in the bubble-point pressure likely because bubble-point is more sensitive to composition than to temperature for these mixtures at the conditions tested. This emphasizes the importance of considering sorption in phase behavior for small pores.",18,18,4
Other topics ,,"Labus, Malgorzata; Lempart, Malgorzata",Studies of Polish Paleozoic shale rocks using FTIR and TG/DSC methods,,INFRARED-SPECTROSCOPY; MINERAL MATRIX; ORGANIC-MATTER; PYROLYSIS; DSC,"The presented investigation is focused on fine-grained Palaeozoic (Silurian and Carboniferous) rocks collected from several wellbores in Poland. The implemented methods are: diffuse reflectance infrared fourier transform spectroscopy (DRIFT) thermal methods (TG/DSC), as well as XRD and Rock-Eval pyrolysis. These methods made it possible to determine the composition of the samples tested, including the presence of minerals and organic matter. The DRIFT technique of FTIR analysis was implemented, because in case of DRIFT technique the high frequency bands are usually more informative with respect to detection of aromatic and aliphatic bands in the examined rocks, compared to other techniques of IR (e.g. ATR). The occurrence of aromatic groups in the samples is the evidence of higher kerogen maturity. Thermal methods (TG/DSC) made it possible to trace the reactions during heating the samples in an oxidizing and inert atmosphere. The pyrolysis peaks in DSC curves indicate kerogen of type II, which agrees with a classification based on Rock-Eval measurement. Basing on the DTG curves the maximum temperature of the pyrolysis peak could be determined, and in a consequence - the thermal maturity of the organic matter in the sample. The enthalpy of organic matter in examined samples, calculated from DSC curves correlates very well with TOC value (Rock Eval), what demonstrates that thermal analysis can be successfully used to determine the content of organic matter in fine grained rocks, such as gas-shales or similar ones.",17,18,4
Other topics ,,"He, Youwei; Cheng, Shiqing; Qin, Jiazheng; Chai, Zhi; Wang, Yang; Patil, Shirish; Li, Meng; Yu, Haiyang",Analytical interference testing analysis of multi-segment horizontal well,Interference testing analysis; Multi-segment horizontal well; Pressure-transient behavior; Well interference; Water injection; Type curves,PRESSURE-TRANSIENT ANALYSIS; TIGHT GAS-RESERVOIR; CHANGQING OIL-FIELD; FRACTURE; FLOW; OPTIMIZATION; METHODOLOGY; WATERFLOOD; PATTERN; CHINA,"Most interference-testing analysis of horizontal well ignores fluid flow in and out of the horizontal observation well and represent it by a point. Moreover, even if the observation well is considered to produce fluids during the field test, the production distribution is assumed to be uniform along horizontal wellbore. In fact, production logging tests have shown that only partial horizontal segments are productive and the production contribution is non-uniform along horizontal wellbore. The aim of this paper is to develop a novel interference testing model of a multi-segment horizontal well (MSHW). Analytical solutions are derived to incorporate the interference of injection wells and consider the effect of non-uniform production on pressure response of the MSHW. There is no need to shut in the horizontal observation well, and the horizontal well is composed of multiple segments with arbitrary rate, length, skin, etc. The type cures of the interference testing model are developed to discuss the effect of both active wells and observation well on pressure behavior (e.g., injection rates, well spacing, rate distribution of horizontal observation well, number and length of horizontal producing segments, permeability anisotropy, horizontal wellbore location in vertical and horizontal plan). Results indicate that the pressure and pressure derivative curves move down during the middle and late flow regime due to the effect of surrounding injectors. The pseudo-radial flow regime may disappear due to the interference caused by adjacent wells. The interference flow regime (IFR) may stabilize at 0.5*(1-Sigma q(jD)) on pressure derivative curve when the total injection rates are less than the production rates. The pressure-derivative curve shows the similar characteristic with bottom-water drive when injection rates are much higher than the production rates. The proposed model is more realistic and enables us to better understand the interference of injection wells when the horizon observation well is open to produce. With the help of interference tests, this model can be applied to evaluate the communication between wells, diagnose the water-inflow direction, and optimize well pattern, which ensure the success of a secondary or an enhanced recovery process.",17,18,2
Other topics ,,"Sun, Zhuang; Tang, Hewei; Espinoza, D. Nicolas; Balhoff, Matthew T.; Killough, John E.",Discrete element modeling of grain crushing and implications on reservoir compaction,Discrete element method; Bonded-particle model; Grain crushing test; Uniaxial strain test; Permeability evolution,BONDED-PARTICLE MODEL; MECHANICAL COMPACTION; NUMERICAL-SIMULATION; ROLLING RESISTANCE; GRANULAR-MATERIALS; CEMENTED SAND; DEM; BEHAVIOR; FRACTURE; SANDSTONE,"Depletion-induced formation compaction is a concern for production in hydrocarbon reservoirs. In this study, numerical mechanical tests and digital samples are proposed as an alternative to uniaxial strain experiments for investigating the effects of compaction. We propose a grain crushing model with two-sized subgrains based on the discrete element method and bonded-particle model (DEM-BPM) and perform numerical single grain crushing tests to calibrate the model parameters against the experimental sand grain characteristic strength. Numerical uniaxial strain tests are used to predict porosity and permeability reduction caused by reservoir compaction. Grain crushing incurs a significant reduction of porosity under the uniaxial strain stress path, which becomes more evident for digital samples consisting of larger grains. The stress-dependent changes in porosity and permeability obtained from the DEM simulations can be used as inputs for a reservoir-scale correlation to predict the productivity loss due to reservoir compaction.",16,16,3
Other topics ,,"Zhang, Quanying; Zhang, Feng; Liu, Juntao; Wang, Xinguang; Chen, Qian; Zhao, Liang; Tian, Lili; Wang, Yang",A method for identifying the thin layer using the wavelet transform of density logging data,Wavelet transform; Density logging; Mother wavelet; Decomposition level; Thin-layer identification,WELL-LOG DATA; FORMATION INTERFACES; FOURIER-TRANSFORMS; ORTHONORMAL BASES; IDENTIFICATION; SIMULATION; SEQUENCE,"In the late stage of oilfield development, thin reservoirs become particularly important for oil and gas exploration. However, current density logging, as a primary method of reservoir identification, has a lower resolution in identifying thin-layers. In this study, a discrete wavelet transform (DWT) is utilized in density logs to identify thin-layers. By adopting different Daubechies (dbN) wavelets and decomposition levels, we analyze the approximation coefficients (cA) and detailed coefficients (cD) and identify the thin-layer signal from detailed coefficients. And then, we reconstruct a new density curve with enhanced thin-layer signal for identifying the thin layer. Results show that db4 wavelet and 3 level are the optimum mother wavelet and decomposition level for the density logging. Detailed coefficients (cD3) from 3rd level decomposition are highly consistent with the thin-layer information, which is suitable for thin-layer identification. Besides, the reconstructed density curve shows a higher thin-layer resolution. This method is successfully applied in the oilfield, and the thin-layer resolution of density curve is improved from 30 cm to 15 cm in accordance with microspherically focused logging (RXO).",16,18,2
Other topics ,,"Wang, Peng; Ni, Hongjian; Wang, Ruihe",A novel vibration drilling tool used for reducing friction and improve the penetration rate of petroleum drilling,Complex structural well; Friction reduction by vibrating; Enhancement in ROP; Field tests,FLOW; LES,"A novel self-resonating oscillator which can be used for reducing the friction between drill-pipe and borehole wall and improving the rate of penetration is proposed. Several key issues of this tool are discussed in this paper, including the structure and principle of the modulating tool, the modulation mechanism of the vibration, the optimization method and the optimal structural parameters of the modulating tool. An engineering prototype is developed based on the above research works and site conditions. Field tests of the prototype are performed. The application effect is compared with actual drilling data of adjacent wells in the same formation and interval. The results are a good reference for the subsequent drilling.",16,18,2
Other topics ,,"Alrefaee, Hamed A.; Ghosh, Sayantan; Abdel-Fattah, Mohamed I.","3D seismic characterization of the polygonal fault systems and its impact on fluid flow migration: An example from the Northern Carnarvon Basin, Australia",Polygonal faults; 3D seismic; Seismic attributes; Migration of fluid flow; Carnarvon basin; Australia,FINE-GRAINED SEDIMENTS; WEST SHELF; COMPACTION; ATTRIBUTES; MUDROCKS; SURFACES; GEOMETRY; ORIGIN; FIELD; SEA,"We used high-resolution 3D seismic data and applied seismic attribute analysis to geometrically interpret and characterize the polygonal fault systems in the Paleocene-Eocene sequence of the Rankin Platform Sub-basin, Northern Carnarvon Basin, Australia. The polygonal faults were identified in a stratigraphic sequence dominated by calcareous clay with minor calcilutite at its lower section that changes to argillaceous calcilutite and calcareous claystone at its upper section. Seismic sections and time slices, through multi-attribute (coherence, energy ratio similarity, and curvature) volumes display a dense distribution of normal faults with polygonal shape and small throws in the plain view. The polygonal fault systems (PFS) exist in two well-defined tiers, which can act as pathways for the fluid flow migration. The first tier coincides with the upper section (Early-Middle Eocene Wilcox Formation) with a few faults and the second one coincides with the lower section of the sequence (Paleocene Lambert and Dockrell formations) with a greater number of faults. Proper understanding and interpretation of the polygonal fault systems as non-tectonic extensional faults are a critical issue in assessing the migration pathway for hydrocarbon (gas) through the Paleocene-Eocene sequence in the Northern Carnarvon Basin, and elsewhere in the world.",16,16,1
Other topics ,,"Qu, Fengzhong; Zhang, Zhujun; Hu, Junwei; Xu, Jiangming; Wang, Shiyuan; Wu, Yezhou",Adaptive dual-sensor noise cancellation method for continuous wave mud pulse telemetry,Mud pulse telemetry; Noise cancellation; Adaptive filtering; Signal detection,,"Mud pulse telemetry is the most commonly used method for transmitting data from downhole to the surface in measurement while drilling (MWD) systems. During the drilling process, the signal received on surface is seriously disturbed by various noise sources, among which the pump noise is the most damaging. The effective cancellation of pump noise is very essential for obtaining correct downhole information and achieving higher data transmission rates. In this paper, an adaptive noise cancellation method using two pressure transducers is studied. The method aims at complex noise environments when two or more mud pumps are used. The fundamental of the method lies on the difference in propagation direction between information signal and pump noise. An adaptive noise cancelling structure is introduced to dynamically estimate the channel characteristics between the two transducers and optimize the noise cancellation output. Both simulations and field experiments were carried out to verify the performance of the proposed method. Simulation results indicate that the method can successfully extract the information signal from pump noise with the interference of random noise from both transducers. Field experiments were carried out during a 3000-meter drilling operation. In the experiment, the major components of pump noise in frequency domain have been reduced by 49%-92%. The successful demodulation of the received data indicates that the proposed method can be used to extract downhole information in complex pump noise environment created by two triplex piston pumps.",16,19,0
Other topics ,,"Santos, Susana M. G.; Gaspar, Ana T. F. S.; Schiozer, Denis J.",Managing reservoir uncertainty in petroleum field development: Defining a flexible production strategy from a set of rigid candidate strategies,Decision analysis; Uncertainty management; Expected value of flexibility; Field development; Production strategy; Reservoir simulation,DISCRETE LATIN HYPERCUBE; REPRESENTATIVE MODELS; DECISION-ANALYSIS; FLEXIBILITY; OPTIMIZATION; RISK; REALIZATIONS; EXPLORATION; MANAGEMENT; SELECTION,"Decisions in petroleum field development are typically complex because of high investments under high uncertainty. To improve project performance, decision makers study the effects of uncertainty and consider actions to both mitigate risks and exploit upsides. Uncertainty can be managed with flexibility, which has high potential to manage the long-term systems in petroleum field development, reacting to uncertainty as it unfolds over time. Although increasingly popular in the petroleum industry, the literature still lacks systematic, objective approaches to quantitatively estimate the expected value of flexibility (EVoF). This work sets out a decision structure applied to petroleum field development that (1) uses a predefined set of rigid candidate production strategies (robust and specialized strategies) to define the flexible strategy, (2) establishes probabilistic-based implementation rules, and (3) improves estimates of EVoF by both accounting for the purpose of flexibility (to mitigate the risks or exploit the upsides of uncertainty) and weighting the decision maker's attitude. We show that our proposed method is applicable to complex reservoirs in the development phase, with multiple uncertainties affecting the production strategy selection. Finally, we assessed the effects of delayed implementation on EVoF.",15,15,1
Other topics ,,"Soleymanzadeh, Aboozar; Jamialahmadi, Mohammad; Helalizadeh, Abbas; Soulgani, Bahram Soltani",A new technique for electrical rock typing and estimation of cementation factor in carbonate rocks,Formation resistivity factor; Cementation factor; Electrical quality index; Tortuosity,MAGNETIC-RESONANCE NMR; TORTUOSITY; LOGS,"Natural heterogeneity of carbonate rocks causes difficulties in estimation of their petrophysical properties such as cementation factor. These problems are mainly caused by complex pore structure of carbonate rocks and presence of various types of pore in them. Generally, when analyzed versus porosity, formation resistivity factor (F) data are highly scattered in carbonate reservoirs. Several methods have been reported in literature to decrease such data scattering such as data classification by permeability, pore types and reservoir rock types. However, outcomes of these techniques have exhibited still some degree of the data scattering. Besides, many correlations have been developed to relate cementation factor to porosity such as Borai's and Shell correlations. Indeed, these correlations take into account the porosity rather than further considering rock quality in terms of electrical conductivity. In this paper, Electrical Quality Index (EQI) is proposed as a new parameter for classification of F data in an attempt to improve estimation of cementation factor. Rock samples with similar EQIs have similar electrical behavior. In other words, EQI can be used to group rock samples into distinctive groups with specific equations of formation resistivity and cementation factors versus porosity. The proposed technique was applied to the 112 carbonate rock samples reported in Ragland's work. EQI divided these samples into 9 groups which have different equations of F versus porosity with high values of determination coefficients. Also, cementation factor versus porosity plots showed linear trends with high determination coefficients for all of the EQI groups.",15,15,0
Other topics ,,"Guan, Q.; Goharzadeh, A.; Chai, J. C.; Vargas, F. M.; Biswal, S. L.; Chapman, W. G.; Zhang, M.; Yap, Y. F.",An integrated model for asphaltene deposition in wellbores/pipelines above bubble pressures,Asphaltene deposition; Integrated transport and thermodynamic models; Evolving deposit layer,REGULAR SOLUTION MODEL; PARTICLE DEPOSITION; TURBULENT-FLOW; TOOL ADEPT; HEAVY OILS; PRECIPITATION; PREDICTION; VISCOSITY; BITUMENS,"Asphaltene has been recognized as the cholesterol of petroleum for decades due to its precipitation and deposition in oil production, transportation and processing facilities, causing tremendous losses to the oil industry each year. This work presents a numerical model to predict asphaltene deposition in wellbores/pipelines. A Thermodynamic Module is developed to model asphaltene precipitation, based on the sequential stability-testing-and-phase-split-calculation method using Peng-Robinson equation of state with Peneloux volume correction. A Transport Module is developed to model fluid transport, asphaltene particle transport and asphaltene deposition, according to basic conservation laws. Using a thermodynamic properties look-up table, these two modules are linked to each other to account for the effects of a finite deposit layer thickness on the coupled flow fields and deposition process. In this article, verification and validation of the Thermodynamic Module are first carried out. Then, the integrated model is utilized to study asphaltene deposition problems in an actual oilfield where the asphaltene deposit layer profile is reasonably accurately predicted. This case shows that the presented model has great potential as a predicting tool to assist reservoir engineers in assessing asphaltene deposition risks in wellbores/pipelines.",15,15,0
Other topics ,,"Lim, M. W.; Lau, E. V.; Poh, P. E.",Micro-macrobubbles interactions and its application in flotation technology for the recovery of high density oil from contaminated sands,Marine oil spills; Bubble-bubble interaction; Microbubble; Oil removal efficiency; Coalescence; Integrated flotation system,BUBBLE; PARTICLE; BITUMEN; MICROBUBBLE; ATTACHMENT; FINE; COAL; CAVITATION; TIME,"The integration of microbubbles (Sauter diameter: 80 mu m) and macrobubbles (Sauter diameter: 0.9 mm) in a flotation system were proposed to enhance oil removal efficiencies. The role of the microbubbles as a secondary collector for macrobubbles was studied in the static bubble interaction studies in terms of attachment time, contact angle and visualization of contact area. Results showed that the presence of microbubbles could decrease the attachment time between macrobubbles and oil layer by 82%, and improve the contact angle and surface area of attachment by 40.3% and 54.5% respectively. Macrobubbles, on the other hand were able to improve the floatability of oil contaminant as suggested from the dynamic bubble interaction study. The presence of macrobubbles was able to increase the volumetric rate of micro-macrobubbles captured from 0.47 mu L/s to 4.5 mu L/s. The results demonstrated that the coalescence phenomena between bubbles could provide the necessary lifting force to further aid the oil flotation. The interaction between microbubbles and macrobubbles is particularly advantageous in an integrated bubble flotation system. Application of the integrated micro-macrobubbles demonstrated a significant increase in oil removal to 68.6% under oil-wet conditions while almost all of the oil contaminants were removed from water-wet sands. An increase of 28% was observed upon implementation of integrated micro-macrobubble flotation compared to the single bubble flotation for oil removal. Results indicated that the integration of microbubbles and macrobubbles in the flotation cell is a simple modification to a flotation system that would enhance the removal of oil contaminant from contaminated sand.",14,16,5
Other topics ,,"Oliveira Camara, Marcus Vinicius; Ribeiro, Glaydston Mattos; Ribeiro Tosta, Marielce de Cassia",A pareto optimal study for the multi-objective oil platform location problem with NSGA-II,Platform location; Oil field development; Multi-objective problem; Petroleum engineering,OFFSHORE PLATFORMS; OPTIMIZATION; ALGORITHM; SELECTION,"Offshore production has a high level of complexity inherent to its development and exploration. This context leads to the need for the Multi-objective and Multi-level Capacitated Oil Platform Location Problem (MMCOPLP), which is used for the definition of places for platforms and drilling of wells, given a set of possible candidate points. The conflict between objectives is commonly present in the multi-objective problems and, consequently, there is a set of optimal solutions called the Pareto Optimal. The Pareto Optimal is hard to be determined by exact methods, and heuristics and/or metaheuristics are implemented as alternative methods. Considering the above, the main objective of this study is to propose a Non-dominated Sorting Genetic Algorithm (NSGA-II) to solve the MMCOPLP. Instances are also proposed and the e-Constraint exact method is used to find the Pareto Optimal. Based on the error ratio, on generational distance and on hypervolume metrics, computational experiments show that the NSGA-II provides good solutions, close to Pareto Optimal and better than a Greedy Randomized Adaptive Search Procedure (GRASP) metaheuristic proposed in the literature.",14,18,3
