Cluster Level 1,Cluster Level 2,AF,TI,DE,"ID",AB,TC,Z9,U1
Fracture,Natural Fractures,"Sheng, Guanglong; Su, Yuliang; Wang, Wendong",A new fractal approach for describing induced-fracture porosity/permeability/ compressibility in stimulated unconventional reservoirs,Stimulated unconventional reservoirs; Fractal induced-fracture spacing; Fractal induced-fracture aperture; Tortuosity index; Fracture porosity/permeability/compressibility,HORIZONTAL WELLS; GAS-FLOW; MATRIX PERMEABILITY; OIL; MODEL; SIMULATION; PREDICTION; DIFFUSION; VOLUME; MEDIA,"The stimulated reservoir volume (SRV) with complex induced-fracture governs dominant flow rates in unconventional reservoirs. The induced-fracture spacing and aperture greatly affect the fracture properties. In this study, a new method to calculate tortuosity index of fractal induced-fracture is proposed, and the fractal dimension of induced-fracture aperture (d(fa)) is presented to describe the distribution of fractal induced-fracture aperture (FFAD). Combined with fractal induced-fracture spacing (FFSD) and FFAD, the fractal fracture porosity/permeability/compressibility models are given. The FFSD and FFAD influenced by fractal dimensions and their influences on fracture properties are analyzed. The results show that the d(fs) has a wider range than that of natural fractures, and it may be larger than 2 in 2D system in some special reservoirs, e.g. re-stimulated reservoirs. As the distance from the reference point increases, the tortuosity index gradually decreases. The larger the fractal dimension (d(fs) or d(fa)) is, the larger the fracture porosity/compressibility will be. In the cases of d(fs) < 2 (or d(fa) < 2), the fracture porosity/compressibility of the uniformly induced-fracture is smaller than the fractal induced-fracture near the reference point, and larger than that far away from the reference point. While in the cases of d(fs) > 2 (or d(fa) > 2), the fracture porosity/compressibility of the uniformly induced-fracture is larger than the fractal induced-fracture near the reference point, and smaller than that far away from the reference point. When d(fa) > 2, the fracture permeability increases first and then decreases as the distance from the reference point increases. In other cases, the fracture permeability decreases as the distance from the reference point increases. The permeability influenced by distribution of induced-fracture aperture is greater than that influenced by induced-fracture spacing.",92,94,8
Fracture,Natural Fractures,"Meng, M.; Baldino, S.; Miska, S. Z.; Takach, N.",Wellbore stability in naturally fractured formations featuring dual-porosity/single-permeability and finite radial fluid discharge,Wellbore stability; Fractures; Dual-porosity/single-permeability; Hemisphere plot,MECHANICAL-PROPERTIES; CONSOLIDATION; SHALE; BOREHOLE; MEDIA,"This work presents an analytical solution for an inclined wellbore drilled in a fractured formation displaying a high contrast between the diffusion rates in the fractures and in the porous matrix, with the latter treated as a storage phase and thus not participating in the fluid transport. This scenario may result from different mud cake building rates, and/or adverse wettability of the rock matrix with respect to the drilling fluid being used. Different from the models available in the literature, the fractures are characterized by a more realistic finite radial fluid discharge (namely, the fractures network hydraulically connected to the wellbore is of limited extent). The models output in terms of pore pressures, total stresses and effective stresses response has been compared with the results of a widely accepted dual-porosity/dual-permeability model. Major differences and asymptotic behaviors have been analyzed. Subsequently, the results of the model have been used to perform a comprehensive wellbore stability analysis. The effect of time dependency, fractures network length and rock properties on the instability of the borehole have been investigated, and upper and lower mud weight bounds have been determined using several failure criteria. This investigation shows that under the specified conditions where dual-porosity/single-permeability conditions arise, the proposed model provides with theoretically more conservative mud weights predictions.",48,50,6
Fracture,Natural Fractures,"Xu, Jianchun; Sun, Baojiang; Chen, Bailian",A hybrid embedded discrete fracture model for simulating tight porous media with complex fracture systems,Numerical simulation; Discrete fracture model; Naturally fractured tight oil reservoir; Transient transfer; Stochastic permeability,SHALE-GAS-RESERVOIRS; SHAPE FACTORS; NUMERICAL-SIMULATION; FLOW; PRESSURE; TRANSPORT; FLUIDS; OIL; FRAMEWORK,"Numerical simulation considering complex fracture networks in tight oil reservoir becomes a hot issue during these years. Recently, embedded discrete fracture model (EDFM) shows great advantages over the DFM approaches in both calculation efficiency and simplicity of simulation workflow. EDFM has been widely used in tight oil/gas natural energy or enhanced oil recovery (EOR) development. If a large number of small-scale natural fractures exist in reservoir, the calculation efficiency of EDFM method may decrease. In this paper, a new hybrid simulation model combining the EDFM and dual porosity (DP) model is proposed. The large-scale fractures are dealt with EDFM method while small scale fractures are dealt with DP model. Considering the low permeability of matrix, transient transfer between matrix and natural fracture is considered. The proposed hybrid model is validated compared with the local grid refinement (LGR) model and EDFM-MINC model, and the difference between transient transfer and pseudo-steady-state transfer effect on production is presented. Finally, two test cases are presented, and the sensitivity of some key parameters are investigated. Result shows that the new simulation model has higher calculation efficiency than LGR and EDFM-MINC models. Meanwhile, it honors a good accuracy. The pseudo-steady-state transfer between matrix and natural fracture leads to big error in tight oil production performance analysis both in single phase and two phases flow. Low matrix permeability and big matrix size increase the production difference between pseudo-steady-state transfer and transient transfer models. The proposed model can simulate reservoirs considering stochastic permeability distribution.",29,30,6
Fracture,Natural Fractures,"Wang, Bo; Zhou, Fujian; Zou, Yushi; Liang, Tianbo; Wang, Daobing; Xue, Yanpeng; Gao, Liyang",Quantitative investigation of fracture interaction by evaluating fracture curvature during temporarily plugging staged fracturing,Temporarily plugging staged fracturing; XFEM-Based CZM; Plugging efficiency; Propagation path,HYDRAULIC-FRACTURE; NUMERICAL-SIMULATION; HORIZONTAL WELL; FINITE-ELEMENT; NATURAL FRACTURES; SHALE FORMATIONS; PROPAGATION; STIMULATION; MODEL,"Temporarily plugging staged fracturing (TPSF) technique has been successfully applied in unconventional reservoirs. This paper quantificationally investigates fracture interaction between previous and subsequent fractures during TPSF through numerical experiments. Using XFEM-based CZM (the cohesive zone model based on the extended finite element method), a 2D fully fluid-solid coupling model is established to perform the investigation. Typically, the concept of ""turning angle"" is proposed to quantify the degree of fracture interaction under different conditions. Moreover, the opening of the previously created fracture is simulated by truss model, which indicates truss elements distributed on the fracture surfaces; the effects of formation heterogeneity are investigated by changing rock mechanical properties surrounding the subsequent fractures. Simulation results reveal that the previously created and propped fracture will generate induced stresses, which cause the subsequent fracture to propagate with curvature. Factors influencing the subsequent fracture propagation curvature during TPSF, are sorted by sensitivity (strong to weak): plugging efficiency, Young's modulus, percent of initial aperture propped, fracture spacing, horizontal stress contrast, rock tensile strength, and formation permeability. The investigations provide a deep understanding of fracture interaction between previous and subsequent fractures during TPSF.",28,31,4
Fracture,Natural Fractures,"Zhao, Peiqiang; Wang, Xixin; Cai, Jianchao; Luo, Miao; Zhang, Jin; Liu, Yuming; Rabiei, Minou; Li, Chuncheng",Multifractal analysis of pore structure of Middle Bakken formation using low temperature N-2 adsorption and NMR measurements,Middle Bakken; Multifractal analysis; N-2 adsorption; Nuclear magnetic resonance (NMR),NUCLEAR-MAGNETIC-RESONANCE; RATE-CONTROLLED POROSIMETRY; FORD SHALE SAMPLES; SICHUAN BASIN; GAS-RESERVOIR; FRACTAL CHARACTERIZATION; ORGANIC-MATTER; OIL; SANDSTONE; DIMENSION,"Understanding the complexity and heterogeneity of pore structure can improve the comprehensive characterization for complex unconventional reservoirs and better exploit those resources. In this paper, multifractal analysis was conducted on low temperature N-2 adsorption and NMR T-2 distribution for the pore structure investigation in Middle Bakken formation in Williston Basin, USA. Results show that the averages of specific surface area, total pore volume, the average pore size of five N-2 adsorption samples are 3.31 m(2)/g, 0.008 cm(3)/g, and 19.57 nm, respectively. Six NMR T(2 )distributions are bimodal and the signals of left dominant peaks are mainly distributed between 0.3 ms and 10 ms. The T-2 logarithmic mean value ranges from 2.18 ms to 2.95 ms with an average value of 2.57 ms. Both N-2 adsorption isotherms and T-2 distribution demonstrated the multifractal nature of different pore sizes. The key multifractal parameter, singularity strength range (Aa) calculated from N-2 adsorption and T-2 distribution are respectively distributed in scopes of 0.72-1.54 and 1.63-2.89, indicating that the heterogeneity of pore space from T-2 distribution is stronger than that from N-2 adsorption. It was observed that the specific surface, micro pore volume, and average pore size are correlated well with Delta alpha. There are no any correlations between Delta alpha and porosity and T-21m, but the cumulative porosity and width of right secondary peaks have an impact on the Delta alpha, which means that the heterogeneity difference between the two methods is attributed by larger pore and micro fractures.",27,27,7
Fracture,Natural Fractures,"Zhang, Lufeng; Zhou, Fujian; Mou, Jianye; Pournik, Maysam; Tao, Shaodan; Wang, Daobing; Wang, Yuechun",Large-scale true tri-axial fracturing experimental investigation on diversion behavior of fiber using 3D printing model of rock formation,Temporary plugging; Diversion; Fibers; Acid fracturing; Stimulated reservoir volume (SRV),BALL DRILLING-FLUIDS; SHALE; PROPAGATION; MECHANISM,"The complex carbonate reservoir is characterized by strong heterogeneity, developed natural fractures, and high temperature. In order to enhance its stimulation effect and hydrocarbon production, temporary plugging and diverting acid fracturing technology was proposed. However, using traditional downhole tools is high-risk and costly, sometimes even ineffective to achieve diversion of fractures. Compared with mechanical diversion assisted with tools, fibers diversion has become an effective and low-cost alternative for safe, tool-free and convenient operation. It has been pilot applied in some fields and the stimulation results are favorable. However, the temporary plugging and diversion behavior of fibers has not been systemically studied. Hence, based on the reproduced fracture model by 3D printing technology, a series of experiments were performed to investigate the effect of carrier fluid type, the length and concentration of fibers, and injection rate on temporary plugging. Furthermore, based on the modified true tri-axial fracturing system, four groups of experiments were also conducted to verify the feasibility of fiber-assisted diverting acid fracturing, in which natural carbonate outcrop cubic blocks with the dimension of 300 mm x 300 mm x 300 mm were used. The results of temporary plugging experiments show that the temporary plugging effect of HPG fracturing fluid is better than that of slick water. In addition, the effect of temporary plugging increases with increase of fiber length, concentration, and injection rate. Under experiment condition, the fibers with the length of 6 mm and the concentration of 1 wt%, and the injection rate of 60 mL/min are recommended. When the horizontal principle stress difference was below 5 MPa, the results of true tri-axial diverting fracturing experiments show that two mutually perpendicular fractures was created on the end face of the cubic core, which verifies the validity of fiber-assisted diverting fracturing. However, it's difficult for the fracture created during fiber-assisted acid fracturing to divert when the horizontal principle stress exceeds 7.5 MPa. Moreover, it can produce a fracture that is nearly parallel to the previously created fracture. This study deepens the understanding on the mechanisms of fiber-assist diverting acid fracturing and provides fundamental for field treatment design.",27,27,2
Fracture,Natural Fractures,"Heng, Shuai; Liu, Xiao; Li, Xianzhong; Zhang, Xiaodong; Yang, Chunhe",Experimental and numerical study on the non-planar propagation of hydraulic fractures in shale,Shale; Bedding plane; Hydraulic fracturing; Non-planar propagation; Fracture network,ROCK FAILURE; BEHAVIOR; STRESS; GROWTH; DISCONTINUITIES; INITIATION; INTERFACE,"To better understand the non-planar propagation and geometry of fracture networks, hydraulic fracturing simulation tests on shale specimens were conducted using an established true triaxial hydraulic fracturing simulation test system. A two-dimensional numerical model of hydraulic fracturing was developed to clarify the evolution of hydraulic fractures and their non-planar behaviour at bedding planes. The numerical model with the alternating rock matrix and bedding planes considered the coupling effect of stress, fluid flow, and damage. The mechanisms by which hydraulic fractures penetrate or become arrested/deflected at bedding planes were then revealed as per the physical and numerical simulation results. The results revealed that the typical severe fluctuation of the injection pressure, which is closely related to the growth of sub-fractures along bedding planes or natural fractures, is a clear characteristic of the non-planar propagation of hydraulic fractures. The mechanical properties of the bedding primarily determine whether a hydraulic fracture penetrates or is deflected at the bedding. Strong beddings favour hydraulic fracture penetration; whereas, weak beddings favour hydraulic fracture deflection along the beddings. The hydraulic fractures typically extend along the path of least resistance, and therefore, induce the non-planar propagation behaviour at bedding planes. Tensile failure is a major fracture mechanism of the hydraulic fractures that penetrate or deviate at bedding planes. The experimental and numerical findings provide a basis for the optimum design of hydraulic fracturing and control of the fracture growth geometry in shale gas reservoirs.",25,25,13
Fracture,Natural Fractures,"Zhang, Ruxin; Hou, Bing; Han, Huifen; Fan, Meng; Chen, Mian",Experimental investigation on fracture morphology in laminated shale formation by hydraulic fracturing,Shale; Fracture propagation; Discontinuities; Fracturing energy; Horizontal stress difference,PROPAGATION BEHAVIOR; INITIATION; CRITERION,"A complex fracture network, which is the precondition of stimulated reservoir volume for shale formation, depends on the interaction between hydraulic fractures and discontinuities, such as bedding planes and natural fractures. However, the fracture propagation behavior in laminated shale formation still maintains ambiguous and the formation mechanism of complex fracture network has not been well understood. Therefore, hydraulic fracturing simulated experiments were conducted on shale outcrops to clarify above issues under the effects of multiple factors, such as horizontal stress difference, pump rate, and fluid viscosity. The results reveal that dilation and crossing are two main hydraulic fracture propagation behaviors because of discontinuities influencing, resulting in three categories of the ultimate fracture morphologies. Simple fracture is a single induced fracture. Complex fracture is consisted of two or more induced fractures which do not link up with each other. However, network fracture includes induced fractures which interweave with each other like a network. All the fracture geometries are generated under the mutual interaction of natural factors and engineering factors. A large horizontal stress difference and a high fracturing energy reduce the complexity of fracture geometry, whereas, a small horizontal stress difference and a low fracturing energy enhance the activated probability of discontinuities, resulting in a complex fracture network. Furthermore, weak cementing strength and large opening degree of discontinuities increase the complexity of the fracture. In addition, the fracturing curve reflects fracture morphology indirectly. Simple fracturing curve and steady extensive pressure indicate the simple fracture. The rising extensive pressure implies the complex fracture, whereas, the fluctuation of fracturing curve suggests the network fracture. In the meantime, each fracture morphology has its own dimensionless net pressure features, which could be applied to judge fracture morphology in shale formation.",24,26,8
Fracture,Natural Fractures,"Xiao, Zikang; Ding, Wenlong; Liu, Jingshou; Tian, Mingzhi; Yin, Shuai; Zhou, Xuehui; Gu, Yang","A fracture identification method for low-permeability sandstone based on R/S analysis and the finite difference method: A case study from the Chang 6 reservoir in Huaqing oilfield, Ordos Basin",Resealed range analysis; Fracture identification; Low-permeability sandstone; Yanchang formation; Huaqing oilfield,TRIASSIC YANCHANG FORMATION; SHANXI FORMATION; ZONES DETECTION; NORTH CHINA; LOGS; IMAGE,"Low-permeability reservoirs are characterized by poor physical properties, strong heterogeneity and natural fractures. Accurate identification of the fracture distribution is of great significance for the exploration and development of low-permeability reservoirs. Field outcrop, core and imaging log analyses show that stratabound vertical and high-angle structural fractures are the main types of fractures in the Chang 6 formation in the Huaqing oilfield. The fracture orientations include NE-SW, NNE-SSW, NW-SE, and NNW-SSE. The NE-SE-oriented fractures formed in the Himalayan stage, while the NW-SE fractures formed in the Yanshan period, and the other fractures derived from the fracturing in the Yanshan period during the Himalayan tectonic activity. The traditional resealed range (R/S) analysis method is upgraded by introducing the finite difference (FD) method in this research, and the newly proposed method is called the R/S-FD method. Core data show that the R/S-FD method can accurately recognize vertical fractures and high-angle fractures. By comparing the fracture development section on the imaging log, it is found that fractures discrimination parameter F has a good linear relationship with both the fracture linear density and the fracture surface density. This method is verified by dynamic data (water injection profiles) and static data (image logging), and the results show that the recognition error is eliminated when the lower limit of F is 0.5, resulting in a crack identification accuracy of 76.9%. Combining the R/S and finite difference methods reduces the artificial recognition error of the traditional R/S method, and the recognition process is automated and intelligent. The R/S-FD method can be used in combination with multiple logging curves. A high fracture recognition accuracy could be accomplished by using this proposed method with only conventional logging curves, of great practical significance to some low-permeability oilfields that lack image logging data.",22,24,7
Fracture,Natural Fractures,"Tang, Hewei; Sun, Zhuang; He, Youwei; Chai, Zhi; Hasan, A. Rashid; Killough, John",Investigating the pressure characteristics and production performance of liquid-loaded horizontal wells in unconventional gas reservoirs,Liquid loading; Horizontal well; Unconventional gas reservoir; Coupled wellbore-reservoir simulation; Natural cyclical production,WELLBORE-FLOW MODEL; 2-PHASE FLOW; TRANSIENT ANALYSIS; FRACTURE,"The increasing exploiting activities in unconventional gas reservoirs renew the interests of investigating liquid loading phenomenon, a common production issue for gas wells. Most previous studies focused on predicting the onset of liquid loading. The reservoir pressure characteristics and wellbore production performance after the onset of liquid loading have not been systematically investigated. This work introduces a newly developed fully implicitly coupled wellbore reservoir model to investigate the liquid loading effects on horizontal wells in low permeability gas reservoirs. The model honors the mass and momentum balances in both reservoir and wellbore systems, and thus allows us to analyze both wellbore and reservoir dynamics after the onset of liquid loading. The simulation results reveal that horizontal gas wells in low permeability reservoirs might experience natural cyclical production after the onset of liquid loading, which coincides with field observations. Both uniform stimulation and hydraulic fracturing help mitigate the cyclical production phenomenon. The near-wellbore reservoir pressure buildup and wellbore fluid reinjection are also evaluated. This work demonstrates the successful application of the coupled wellbore reservoir model in predicting the rich production phenomena of stimulated horizontal wells after the onset of liquid loading.",22,22,4
Fracture,Natural Fractures,"Guo, Xueli; Li, Jun; Liu, Gonghui; Xi, Yan; Zeng, Yijin; He, Miao; Yan, Hui",Numerical simulation of casing deformation during volume fracturing of horizontal shale gas wells,Casing deformation; Stage finite element model procedure; Volume fracturing; Fault slip; Transient temperature; Cement property,UNCONVENTIONAL RESOURCE EXPLOITATION; INTEGRITY IMPLICATIONS; FINITE-ELEMENT; OIL; EARTHQUAKES; MECHANICS; MODEL; LAW,"Casing deformation problems occur frequently during volume fracturing of shale gas wells. It is crucial to assess the casing deformation near heel (the beginning of the horizontal wellbore trajectory) where natural faults exist among 84.6% of the deformation positions in some shale plays. Based on the source mechanism, the fault slip distance was derived from microseismic inversion. Then, three-dimensional physical and finite element models were established using a stage finite element model procedure to investigate the influences of fault slippage on casing stress and displacement. Other factors such as pump rate, fracturing pressure, formation anisotropy, formation elastic modulus, cement sheath elastic modulus, casing size, and cement sheath thickness were taken into consideration. The results show that (1) fault slippage is an important mechanism of casing deformation near heel. The casing has a higher risk of deformation under the conditions of fault slippage combined with high external stress and internal pressure. (2) Under different slip distances, the casing Mises stress dramatically increases with an increase in the cement sheath and formation elastic moduli and the ratio of the casing diameter to the thickness D-out/t. (3) The high pump rate, high inner casing pressure, large formation anisotropy, and small cement sheath thickness can aggrandize casing stress. The calculated casing displacements using this model obtained good agreement when compared to the deformations of the actual wells. Countermeasures such as avoiding natural fault areas, using cement with an elastic modulus smaller than 10 GPa, using a higher grade and smaller diameter casing with a value of D-out/t smaller than 12.7 can be effective to prevent casing deformation during multi-fracturing operation.",21,21,2
Fracture,Natural Fractures,"Jia, Bao; Tsau, Jyun-Syung; Barati, Reza",Measurement of CO2 diffusion coefficient in the oil-saturated porous media,Molecular diffusion; CO2; Single-porosity; Grid sensitivity,CARBON-DIOXIDE; GAS INJECTION; RECOVERY; PRESSURE; BITUMEN; STORAGE,"Molecular diffusion is an important EOR mechanism in naturally fractured reservoirs. However, the laboratory-measured diffusion coefficient in the fractured porous media is still limited; and grid sensitivity analysis is missing in the literature when the single-porosity system is applied to history match the pressure decline curve. We aimed to fill the gaps using Radial Constant Volume Diffusion (RCVD) method experimentally to investigate diffusion coefficients at different pressures in hydrocarbon saturated porous media. A special in-house cell is designed to hold the core sample in the center with the annulus around simulating the fracture. The core is initially saturated with oil while the annulus is filled with CO2 at the same pressure. During the measurements, the system pressure declines as gas diffuses into the oil phase until it reaches chemical equilibrium. The pressure decline curve is history matched to determine the diffusion coefficient. The initial pressure is 597 psi, and the diffusion coefficient is determined in numerical models accordingly. Molecular diffusion coefficients are estimated at different experiment periods to reveal the pressure-dependency. A workflow is proposed to obtain effective diffusion coefficients in dual-porosity models that could be extended to multi-component systems. Besides, flow characteristics in the RCVD system are characterized and capillary pressure effect is investigated in this study.",20,20,2
Fracture,Natural Fractures,"Ren, Long; Su, Yuliang; Zhan, Shiyuan; Meng, Fankun; Zhao, Guangyuan",Fully coupled fluid-solid numerical simulation of stimulated reservoir volume (SRV)-fractured horizontal well with multi-porosity media in tight oil reservoirs,Tight oil reservoir; SRV-fractured horizontal well; Multi-porosity media; Fully coupled fluid-solid; Numerical simulation,HYDROMECHANICAL PROCESSES; HYDRAULIC FRACTURE; MODEL; SYSTEM; FLOW,"A mutual coupling effect exists between the flow and stress fields in tight oil reservoir development. In terms of the characteristics of multi-porosity media (the matrix, natural fractures and network fractures) for stimulated reservoir volume (SRV)-fractured horizontal wells in tight oil reservoirs, considering the dual porosities of matrix and natural fractures, and based on the flowing feature of a discrete-fracture mode (DFM) fracture network stimulated system, a numerical simulation method based on fully coupled fluid-solid is introduced. According to the effective stress principle and regional flow characteristics, the fully coupled fluid-solid mathematical model considering the multi-porosity media characteristics of complex fracture networks is presented. The fully coupling numerical solution for the stress and flow fields is solved by the finite element method. The accuracy of this model is verified by comparing the finite differential model, non-coupled model and actual production data, respectively. And analyzing the computational time needed to solve the model under different solution methods and complexity levels. The variation of stress-strain and reservoir physical property parameters is revealed. For the non-coupled and fully coupled model, the productivity and formation pressure differences are compared and analysed. The results show that when considering the stress field, the initial production rate of an SRV-fractured horizontal well is large but declines quickly, and it has fundamentally different characteristics from the traditional flow model. Our research provides theoretical and technical guidance for the efficient development of unconventional resources.",20,23,1
Fracture,Natural Fractures,"Lai, Jin; Pang, Xiaojiao; Xiao, Qiyao; Shi, Yujiang; Zhang, Haitao; Zhao, Taiping; Chen, Jing; Wang, Guiwen; Qin, Ziqiang",Prediction of reservoir quality in carbonates via porosity spectrum from image logs,Reservoir quality; Carbonate; Image log; Porosity spectrum; Majiagou formation,TRIASSIC YANCHANG FORMATION; JINGBIAN GAS-FIELD; NORTHERN ORDOS BASIN; TIGHT-OIL SANDSTONES; GEOCHEMICAL CHARACTERISTICS; BOREHOLE IMAGE; SICHUAN BASIN; NATURAL-GAS; FEIXIANGUAN FORMATION; XUJIAHE FORMATION,"The Majiagou Formation is an important gas-bearing stratigraphic unit in the Ordos basin of west China. The highly complex lithology and heterogeneous pore systems make it difficult to predict the reservoir quality via petrophysical and image logs. This study investigates the lithology, pore systems and well log responses of the Majiagou Formation Member 5 (Ma 5) carbonate reservoirs using a comprehensive analysis of cores, thin sections, routine core analysis, conventional and porosity spectrum derived from image logs. The results show that the lithologies of the Ma 5 are dominantly of mud-sized to silt-sized crystalline dolomite, and there are some dolomites containing gypsums mudstones and limestone. The pore systems include vugs, intercrystalline pores, dissolution pores and microfractures. The vuggy dolomites and the fractured dolomites are the best quality reservoir rocks, and the mud-sized to silt-sized crystalline dolomites containing intercrystalline pores are good quality reservoirs with high porosity and permeability. Open fractured zones are recognized as dark sinusoidal waves, and the vuggy dolomites can be recognized by the dark spots on the image logs. However, the fractured and vuggy dolomites are only occasionally detected, and most of the dolomite reservoirs in Ma 5 contain only intercrystalline pores, which are difficult to be recognized by image logs. In addition, good quality reservoirs have very similar log responses (low natural gamma-ray (GR), low-moderate bulk density (DEN), and moderate-high resistivity) with the poor reservoir quality intervals. By applying the Archie's formula to the flushed zone, a total of 150 porosity curves can be obtained from the XRMI image logs. Then the porosity spectrum is derived from the histogram of porosity distribution for a certain interpretation interval. The best quality reservoir rocks (fractured or vuggy dolomites) have very broad porosity spectrums with long tails due to the presence of vugs and fractures. The abundance of intercrystalline pores containing in the mud-sized to silt-sized crystalline dolomites also result in the broad porosity spectrums without any tails. In contrast, the very narrow porosity spectrums correspond to the poor reservoir quality intervals. The interpretation results are verified by core observations and thin section analysis. By using the porosity spectrum analysis derived from the image logs, the reservoir quality can be predicted. The results can help improve the understanding and prediction of the reservoir quality in carbonates using well logs.",19,20,5
Fracture,Natural Fractures,"Harimi, Behrouz; Masihi, Mohsen; Mirzaei-Paiaman, Abouzar; Hamidpour, Esmaeil",Experimental study of dynamic imbibition during water flooding of naturally fractured reservoirs,Spontaneous imbibition; Dynamic imbibition; Fractured reservoirs; Water flooding,COCURRENT SPONTANEOUS IMBIBITION; OIL-RECOVERY; POROUS-MEDIA; PETROPHYSICAL PROPERTIES; ANALYTICAL-MODEL; WET; INJECTION; SATURATION; GLYCEROL; GRAVITY,"Capillary imbibition is an important recovery mechanism in naturally fractured reservoirs when water-filled fractures surround water-wet matrix blocks. A large amount of studies of imbibition process is simply total or partial immersion of nonwetting phase saturated rock in aqueous wetting phase. However, water advance in fractures during water flooding or water encroachment from an active aquifer introduces time dependent boundary conditions where invariant exposure of rock surface to water is not representative. In this work, a laboratory simulated matrix-fracture system was used to investigate different aspects of imbibition in the presence of fracture fluid flow (namely dynamic imbibition). A limestone and a sandstone core plug samples were selected as porous media. A total number of 11 dynamic imbibition and one static imbibition experiments were performed. Core plugs were strongly water-wet to maximize the role of capillary forces. Kerosene and air were the nonwetting fluids in experiments. The impact of water injection rate in the fracture was examined and the results revealed that as the injection rate increases above a critical rate, breakthrough recovery declines, however when injection rate is less than the critical rate increasing injection rate enhances recovery rate without any loss in recovery. Increasing wetting phase viscosity by means of glycerol solution was examined, as well. This reduced the imbibition rate and breakthrough recovery in both water-oil and water-air systems. Furthermore, comparing dynamic imbibition recovery data with a conventional immersion static experiment showed clear discrepancy which is due to different counter- and co-current flow modes. This emphasizes that static imbibition results should not be used for prediction of fractured reservoir performance under water flooding.",19,19,2
Fracture,Natural Fractures,"Li, Yong; Chen, Shijia; Wang, Yuexiang; Qiu, Wen; Su, Kaiming; He, Qingbo; Xiao, Zhenglu","The origin and source of the Devonian natural gas in the Northwestern Sichuan Basin, SW China",Oil cracking gas; Reservoir solid bitumen; Geochemical characteristics; Gas-source correlation; Devonian system; Northwestern Sichuan Basin,PALEO-UPLIFT; DALONG FORMATION; CRUDE OILS; EVOLUTION; RESERVOIR; BITUMEN; GEOCHEMISTRY; DISCOVERY; STRATA; FIELD,"Industrial gas flows have recently been discovered from the Guanwushan Formation (D(2)g) in the Northwestern Sichuan Basin for the first time, thus ushering in the prelude of Devonian natural gas exploration in the Sichuan Basin. However, the source and origin of the Devonian natural gas is not clear and this seriously restricts the next exploration and development stages. Based on geochemical experimental analyses, this study aimed to comprehensively research the geochemical characteristics of the Devonian natural gas, reservoir solid bitumen, and source rocks. The results showed that (1) the Devonian natural gas is mainly composed of hydrocarbon gas and is oil cracking gas. (2) The Devonian natural gas has relatively light ethane carbon isotopes ranging from -31.82 parts per thousand and -29.93 parts per thousand, between the Cambrian and Permian natural gas values, indicating it is a mixed gas, but is more similar to the Cambrian natural gas. (3) The carbon isotopes of the Devonian reservoir solid bitumen were less than -29 parts per thousand and C-29 sterane had an absolute predominance among the sterane compounds, thus showing that it is derived from the source rocks of the Qiongzhusi Formation. (4) During the late Permian, the Lower Cambrian source rocks entered the high peak period of hydrocarbon generation and the crude oil migrated down the fractures to the Devonian reservoirs. During the later stage of deep burial, the crude oil cracked into the dry gas and the heavy contents formed pyrobitumen through polycondensation. Meanwhile, gas from the Permian source rocks mixed to form the present Devonian reservoirs. These research results play an important guiding role in the natural gas exploration and development in the marine stratum of the ultra-deep Devonian System in the Sichuan Basin.",18,19,7
Fracture,Natural Fractures,"Li, Ziyan; Elsworth, Derek",Controls of CO2-N-2 gas flood ratios on enhanced shale gas recovery and ultimate CO2 sequestration,CO2-Enhanced shale gas recovery; N-2- enhanced shale gas recovery; Adsorption and desorption; CO2 sequestration; Permeability evolution,STORAGE,"Primary production of less than 25% of original gas in place (OGIP) may be elevated by enhanced shale gas recovery (ESGR) using either pure CO2 or N-2 as injected stimulants. Alternatively, injecting mixtures of CO2 and N-2 may potentially optimize recovery of natural gas and beneficially sequester CO2. We develop a dual-porosity, dual-permeability finite element (FEM) model coupled with multi-component gas flow and sorption behavior to 1) explore the evolution of sorption-induced strain resulting from competitive adsorption and its influence on the matrix and fracture permeability; 2) define cumulative production of CH4 and 3) evaluate the amount of CO2 sequestered in the reservoir; Results show that pure-CO2 injection can increase shale gas recovery by similar to 20%. Conversely, pure-N-2 injection can increase shale gas recovery by similar to 80%. Injecting mixtures of CO2 and N-2 can increase shale gas recovery between these end-member magnitudes of similar to 20%-similar to 80% depending on the gas composition. We show that a higher proportion of CO2 in the injected CO2-N-2 mixture will result in the decreased recovery of shale gas. However, at the same injection pressure, injecting CO2-N-2 mixtures with a higher proportion of CO2 does not always result in more CO2 sequestered in the reservoir. Indeed, when the CO2 injection ratio is > 70%, as explored in this study, increasing the CO2 injection ratio will result in less CO2 sequestered. This is because, as the CO2-N-2 gas ratio increases, shale gas recovery decreases and results in more CH4 left in the reservoir to compete with CO2 for sorption sites and finally resulting in less CO2 sequestered.",18,18,3
Fracture,Natural Fractures,"Wang, Deqiang; Cheng, Linsong; Cao, Renyi; Jia, Pin; Fang, Sidong; Rao, Xiang; Wu, Yonghui; Dai, Dan",The effects of the boundary layer and fracture networks on the water huff-n-puff process of tight oil reservoirs,Tight reservoir; Water huff-n-puff; Volume fracture; Boundary layer; Embedded discrete fracture model,PERMEABILITY STRESS SENSITIVITY; HORIZONTAL WELLS; RELATIVE PERMEABILITY; SEMIANALYTICAL MODEL; FLOW BEHAVIOR; SHALE; PERFORMANCE; SIMULATION; SCALE,"Application of multi-fractured horizontal wells has led to significant progress in the development of tight oil reservoirs. However, oil production rapidly decreases and the estimated ultimate recovery is still low when the well is in production and approaching depletion. Water huff-n-puff is regarded as a useful measure to improve oil recovery due to oil-water imbibition and drainage. Additionally, complex fracture networks consisting of natural fractures (NF) and hydraulic fractures can significantly enhance oil recovery in the process of water huff-n-puff after multi-stage hydraulic fracturing. However, there is a non-flowing thin film on the solid-liquid wall surface in the pore-throats of the matrix, and the so-called boundary layer effect (BLE) is quite significant at the nanoscale. This effect reduces the effective flow space and effective permeability of the reservoir, leading to production damage. To date, few numerical simulation studies have considered the impact of the BLE and complex fracture networks in water huff-n-puff process simulation studies. In this study, the process of water huff-n-puff is evaluated considering complex fracture networks and formation damage in a matrix. The embedded discrete fracture model (EDMF), validated by local grid refinement (LGR), is applied to describe the distribution of hydraulic fractures and NF. The well performance considering the BLE is analyzed by a vectorization programming. The results show that the BLE reduces production and accelerates the production decline, so the BLE should be considered in reservoir simulations and productivity evaluations of water huff-n-puff processes. A certain degree of natural fracture development is conducive to improving the sweep efficiency of the water huff-n-puff, which could significantly improve oil recovery compared to depletion. By considering the impact of the BLE in water huff-n-puff simulations in tight oil reservoirs, it is possible to accurately evaluate the well performance and provide a theoretical basis for the optimization of water huff-n-puff.",17,16,5
Fracture,Natural Fractures,"Feng, Qihong; Xu, Shiqian; Wang, Sen; Li, Yuyao; Gao, Fangfang; Xu, Yajuan",Apparent permeability model for shale oil with multiple mechanisms,Shale oil; Apparent permeability; Natural fracture; Noncircular pore; Production prediction; Embedded discrete fracture model,PORE-SIZE DISTRIBUTION; FAST MASS-TRANSPORT; LIQUID PERMEABILITY; ORGANIC NANOPORES; POROUS-MEDIA; GAS-FLOW; NETWORK; SIMULATION; ROCK; ENHANCEMENT,"Accurate apparent permeability (AP) model for oil transport in shale must consider natural fractures and micro/nano-pores within organic matter and inorganic matrix. Furthermore, the effect of pore geometry, tortuosity, pore size distribution (PSD), the spatial distribution of different pores, total organic content (TOC), and liquid slip should also be taken into account. However, all of the aforementioned factors are not simultaneously considered in one AP model. In this work, we develop an AP model in 3D for shale oil to overcome this drawback. We first validate our model by comparing with the published data. Then sensitivity analysis for some parameters is investigated. After that, shale oil APs are used in a macro-scale reservoir simulation model. In this way, the effect of some micro-scale factors on production performance can be quantitatively evaluated. Notably, on the basis of embedded discrete fracture model (EDFM), our reservoir simulation model considers non-linear flow in shale matrix, complex hydraulic fracture geometry, and pressure-dependent permeability of hydraulic fractures. Results show that natural fractures contribute the most to AP, followed by organic pores and inorganic pores. In general, the AP in the horizontal direction is approximately twice that in the vertical direction in shale. Furthermore, the maximum error caused by the pore type on shale oil production is similar to 31%, followed by tortuosity (similar to 25%), pore shape (similar to 13%) and slip effect (similar to 4.8%). In conclusion, it is necessary to simultaneously incorporate the influences of the aforementioned factors. Our stochastic permeability model can serve as an efficient tool to determine shale oil AP.",17,19,3
Fracture,Natural Fractures,"Rueda Cordero, Julio Alberto; Mejia Sanchez, Eleazar C.; Roehl, Deane",Integrated discrete fracture and dual porosity - Dual permeability models for fluid flow in deformable fractured media,Naturally fractured reservoirs; Multiscale fractures; Dual porosity; Discrete fracture,COUPLED HYDROMECHANICAL MODEL; FINITE-ELEMENT; PROPAGATION; SIMULATION,"Aiming at accuracy and computational efficiency, integrating discrete fracture and dual porosity-dual permeability models is a viable alternative to simulate flow in naturally fractured reservoirs with discontinuities of multiple lengths. However, previous works focus on the hydraulic problem only and do not take into account geomechanical effects. This study proposes a hydro-mechanical model using the finite element method (FEM) to represent the behavior of fracture networks with fractures of large, medium and small lengths. The methodology integrates the discrete fracture model (DFM) using interface elements, and the dual porosity/dual permeability (DPDP) model. Some synthetic applications compare the results of the models. A case study integrating both approaches is also performed. The results show that fractures of small and medium length enhance the permeability of naturally fractured reservoirs. Their presence within the porous medium results in greater fluid drainage and faster rate of pore pressure dissipation. The fractures contributed significantly to the mechanical behavior with impact on the stiffness of the rock mass system. Aperture variation of the fracture network influences fracture permeability and shows the stress shadowing effect. The results support the application of the proposed large-medium-small length fracture model to represent enhanced permeability of naturally fractured media.",17,17,2
Fracture,Natural Fractures,"Wei, Shiming; Xia, Yang; Jin, Yan; Chen, Mian; Chen, Kangping",Quantitative study in shale gas behaviors using a coupled triple-continuum and discrete fracture model,Shale gas; Hydraulic fracture network; Non-equilibrium desorption/adsorption mechanism; Gas behavior,HORIZONTAL WELLS; PRACTICAL METHOD; TIGHT OIL; FLOW; RESERVOIR; SIMULATION; FLUID; DIFFUSION; TRANSPORT; FRAMEWORK,"The shale has ultra-low permeability wherein multi-scale natural fractures are well-developed. The success of providing high diversion channels makes multi-stage fractured horizontal wells (MFHWs) become the powerful technique for economically producing gas from shale. This study presents a triple-continuum and discrete fracture model to describe a fractured shale reservoir embedded with a MFHW. The model incorporates non-equilibrium desorption/adsorption mechanism (NEDAM), viscous flow, Knudsen diffusion, and surface diffusion. The discrete fracture networks (DFNs) is quantitatively constructed according to the fracture density and stimulated reservoir area (SRA). This model is used to analyze the temporal/spatial evolution of the gas pressure and the net desorption rate. NEDAM is compared with the conventional equilibrium desorption mechanism (EDM) and its found that NEDAM uncovers the delayed phenomenon during gas desorption, and the use of EDM overestimates the production contributed from the adsorbed gas. The maximum net desorption rate of adsorbed gas gradually spread from the SRA region to the nonSRA region. The complete flow stages are clearly interpreted in a semi-logarithmic curve of well testing, and the flow stage controlled by the hydraulic fractures is clearly presented. Finally, the instructions on hydraulic fracturing treatment are given based on the production analysis.",17,18,2
Fracture,Natural Fractures,"Gong, Lei; Su, Xiaocen; Gao, Shuai; Fu, Xiaofei; Jabbari, Hadi; Wang, Xixin; Liu, Bo; Yue, Wenting; Wang, Zhaosheng; Gao, Ang","Characteristics and formation mechanism of natural fractures in the tight gas sandstones of Jiulongshan gas field, China",Tight gas sandstone; Natural fractures; Fracture characteristics; Formation mechanism; Jiulongshan gas field,SICHUAN BASIN; STRATIGRAPHY; RESERVOIRS; POROSITY,"Natural fractures control the migration and accumulation of oil and gas in the tight sandstones. Understanding the characteristics and formation mechanism of natural fractures has important guiding significance to the comprehensive prediction and evaluation of the fracture distribution. Focusing on the tight sandstones of the Xujiahe Formation (T(3)x) of Jiulongshan gas field, northwest Sichuan Basin, China, the characteristics of natural fractures were characterized quantificationally, and a comprehensive evaluation method of fracture formation mechanism is proposed. Two types of natural fractures were identified in the T(3)x, namely tectonic fractures and diagenetic fractures. Most of the natural fractures are tectonic shear fractures, which can be subdivided into steep fractures and nearly horizontal fractures according to their dip angles. Three sets of tectonic fractures were identified in the study area, namely: NW-SE trending, NNE-SSW trending and NEE-SWW trending fractures. According to the characteristics of fracture sets, crosscutting relationships, acoustic emission tests and fluid inclusion analysis, and combined with the tectonic evolution history of the study area, the natural fractures were formed in four periods. Among them, the diagenetic fractures formed at the process of diagenesis are the first period fractures. The second to fourth periods are tectonic fractures formed at the end of the Triassic to the Early Jurassic, the Late Cretaceous and the end of Pliocene to the early of Pleistocene, respectively. Horizontal tectonic compression, uplift denudation and overpressure were the main force sources for the formation of the steep tectonic fractures. The formation of nearly horizontal fractures is related with the thrusting or inter-formational sliding caused by tectonic compression.",17,19,2
Fracture,Natural Fractures,"Jiang, Guancheng; Deng, Zhengqiang; He, Yinbo; Li, Zhong; Ni, Xiaoxiao",Cross-linked polyacrylamide gel as loss circulation materials for combating lost circulation in high temperature well drilling operation,Gel plugging; Initiator capsule; Delayed gelation; Serious loss; Lost circulation,ACRYLONITRILE-BUTADIENE-STYRENE; PERFORMANCE; KINETICS; MICROENCAPSULATION; NANOPARTICLES; LINKING; PILL,"Cross-linked polymer gel has been broadly used to plug severe lost circulation and to improve the strength of the near-wellbore in natural fracture or carbonate cave strata. Gelation time and gel strength are the key factors for gel plugging. In this study, a cross-linked polymer gel with controlled gelation time and high gel strength was fabricated at high temperature, named HTCMG. It was prepared from an acrylamide monomer, crosslinking agent and initiator by free radical polymerization. To extend gelation time at high temperature, colophony was used here to encapsulate the initiator. This complex was characterized under the Fourier transform infrared spectroscopy (FT-IR), by thermogravimetric analysis (TGA) and under the scanning electronic microscopy (SEM). The effects of pH, temperature, monomer concentration and salt concentration on gelation time were assessed. To examine the viscoelastic property and tensile strength of HTCM, HAKKE Mars 40 and uniaxial compression apparatus were employed, respectively. The plugging property of HTCMG was tested by the core displacement test and high-temperature and high-pressure (HTHP) fracture plugging test. According to the results, HTCMG can form gel in temperature range of 80-150 degrees C, and the gelation time can be practically adjustable. The results of the core displacement test revealed that the bearing capacity of HTCMG can reach a peak of 9.8 MPa at 150 degrees C, and it can effectively plug 3 mm-width slot. HTCMG is characterized by a lower plugging time, a higher successful plugging ratio and lower economic cost than normal loss circulation materials, suggesting that HTCM is useful for addressing the lost circulation of high-temperature well, and it is of huge significance to engineering application.",16,17,11
Fracture,Natural Fractures,"Lyu, Shuaifeng; Wang, Shengwei; Chen, Xiaojun; Shah, S. M.; Li, Rui; Xiao, Yuhang; Dong, Qingxiang; Gu, Yuanyuan",Experimental study of a degradable polymer drilling fluid system for coalbed methane well,Degradable polymer drilling fluid; Bio-enzymes; Permeability recovery; Polymer removal; Coal cuttings carrying; South Qinshui Basin,WATER; NANOPARTICLES; PERFORMANCE; PRESSURE; BENTONITE; SEAM,"Drilling along the coal seam is an effective way to improve gas recovery. Due to complex coal body structure and natural fractures, there are many difficulties, including a low abilities of cutting carrying, leakage while crossing the fracture zone and reservoir damage. In this work, a low density degradable polymer drilling fluid system is developed to solve these difficulties to enhance coalbed methane (CBM) production. In the laboratory, the properties of the polymer drilling fluid were evaluated using the coal cuttings suspension experiment, borehole stability simulation test, viscosity attenuation method, laser particle size analysis, polymer removal and core permeability recovery method. The experimental result indicates that the developed drilling fluid has good rheology and filtration, a high yield point and a strong inhibition, thereby meeting conventional drilling requirements and carrying coal cuttings effectively. Under the bio-enzymes, the viscosity of degradable drilling fluid can be initially reduced to 16%. The optimum temperature and pH for the enzyme activity is obtained, and enzymes with small weight fraction of 0.01% can dramatically alter rheological properties of drilling fluid and thereby the high biological activity. After degradation, the particle size in drilling fluid decreases greatly. During immersion test, the polymer film on the surface of the lump coal and thin sections is almost removed by enzyme solution. The reservoir's permeability damage rate may be reduced from 50% to 25% via the functionality of the enzymes, and it is noticeable that the relationships between effective stress and gas permeability treated by the drilling fluid and enzyme still obey the exponential function. Field applications show that the drilling fluid has a good coal fines resistance and compatibility with conventional plugging materials, which ensures the long horizontal footage of 901 m with the short construction period. The later decreased viscosity of the drilling fluid by the enzymes is conducive to reduce the damage to the coal reservoirs.",16,16,7
Fracture,Natural Fractures,"Yan, Xiaopeng; Kang, Yili; You, Lijun; Xu, Chengyuan; Lin, Chong; Zhang, Jingyi","Drill-in fluid loss mechanisms in brittle gas shale: A case study in the Longmaxi Formation, Sichuan Basin, China",Brittle gas shale; Drill-in fluid loss; Plugging zone stability; Dynamic fracture width; Case study,CIRCULATION; DAMAGE; COEFFICIENT; STABILITY; IMPACT; WELLS,"Brittle gas shale consists of a high content of brittle mineral and developed natural fractures and has become the focus of petroleum industry in recent years. Lost circulation may easily occur due to the long soaking time and an overbalanced pressure difference during the drill-in process of the horizontal long section. The dynamic fracture width simulation induced by drill-in fluid invasion, plugging zone pressure containment test, friction coefficient test between lost circulation materials and shale surface, oil based drill-in fluid filtrate immersion test were conducted to investigate the drill-in fluid loss mechanisms in the brittle Longmaxi Shale in the Sichuan Basin of China. Results show that the fracture width at the fracture mouth increased from 2 mu m to 239 mu m for the two mutually perpendicular fractures connecting to the wellbore due to drill-in fluid invasion. Effective plugging for dynamic fractures was failed to be achieved for the original drill-in fluid. Fracture width increase induced by drill-in fluid invasion is the major cause of plugging failure of brittle gas shale. Instability of the brittle shale induced by oil phase lubrication and high pH drill-in fluid erosion further exacerbates lost circulation problems. Optimized LCMs considering the dynamic apertures of fractures should be selected and added into drill-in fluid to rapidly seal pre-exiting fractures and induced fractures for lost circulation control in brittle shale. The results serve as a guide for the drill-in fluid design of shale gas in brittle gas shale formation.",16,19,3
Fracture,Natural Fractures,"Chen, Ya-fei; Pu, Wan-fen; Liu, Xue-li; Li, Yi-bo; Varfolomeev, Mikhail A.; Hui, Jian",A preliminary feasibility analysis of in situ combustion in a deep fractured-cave carbonate heavy oil reservoir,In-situ combustion; Heavy oil; Adiabatic oxidation; Deposited coke; Thermal analysis; FTIR,LOW-TEMPERATURE OXIDATION; PRESSURE AIR INJECTION; KINETIC-ANALYSIS; RECOVERY; MODELS; PYROLYSIS; SYSTEM; LIGHT,"As an effective thermal-enhanced oil recovery technique, in-situ combustion (ISC) can achieve large oil displacement efficiency and upgrade the heavy oil technically, but there are still various barriers for ISC application in naturally fractured carbonate heavy reservoirs. In addition, the potential risk of wellbore plugging and formation collapse, caused by the possibility of carbonate rock decomposition at high temperatures, furtherly hinders the application of ISC technique and focuses more attention on feasibility evaluation. Hence, this paper attempted to estimate the preliminary feasible application of ISC in Tahe oilfield, characterized with fractured-cave carbonate heavy reservoir. From macro and micro aspects, results indicated that owing to large microscopic surface area and high oxygen contact ability between the deposited coke and oxygen, the oxidized ultra-heavy oil, under adiabatic condition, in simulative fractured-cave carbonate oil reservoir was successfully ignited and maintained the combustion process with the combustion front temperature. Besides, a large amount of heat generation from the combustion front can activate the ultra-heavy oil with better mobility ability. Additionally, in this process, the decomposition process of Tahe carbonate rock was not triggered ( similar to 631.6 degrees C) where the decomposition risk of running in-situ combustion process in Tahe carbonate reservoir can be neglected. Preliminarily, it implied that ISC is a feasible technique to upgrade the ultra-heavy oil for Tahe oilfield.",15,15,1
Fracture,Natural Fractures,"Aghli, Ghasem; Moussavi-Harami, Reza; Mortazavi, Saiedollah; Mohammadian, Roohangiz",Evaluation of new method for estimation of fracture parameters using conventional petrophysical logs and ANFIS in the carbonate heterogeneous reservoirs,ANFIS; Fractures; Image and core data; Petrophysical logs; Statistical methods,DENSITY-ESTIMATION; NEURAL-NETWORKS; OIL-FIELD; ZONES; CORE,"Fractures and their parameters are considered as being the most important features in evaluation of the fractured reservoirs. This may be of more importance in the heterogeneous reservoirs, when primary porosity cannot explain the high production capacity. Cores and image logs are two direct methods for fractures evaluation. However, these methods have high cost drawback. So, petrophysical logs are useful tools for fractures detection due to their low cost and accessibility in all wells. This paper proposes a reliable and inexpensive method for the evaluation of fracture parameters in the carbonate heterogeneous reservoir using the preprocessed petrophysical logs and ANFIS (Adaptive Neuro-Fuzzy Inference System). This study indicates that there are two vital limitations when using petrophysical logs for fractures evaluation; firstly, fracture distribution is a complicated process to be predicted by classical methods and none of intelligent systems can be considered as a magic for fracture parameters estimation from raw conventional logs. Secondly, fractures determination is not valuable alone, unless they are used for evaluation of porosity and permeability systems. To solve these problems, a log preprocessing method and a new statistical equation are implemented on the raw conventional logs. Also, ANFIS is used as a powerful method for fracture parameters estimation using preprocessed logs. It is shown that sonic and porosity logs are the best tools for fracture studies. Also, resistivity and gamma ray family logs may have a good evaluation of fractures in the fractured zones. Results confirm that conventional logs could be more useful tools for fractures evaluation if they preprocessed by some statistical methods and correlated by image logs or core data. Proposed method may also be usable for estimation of fractures aperture in some image tools which they are not traditionally able to measure fractures aperture (e.g., sonic image tools). Undoubtedly, fracture aperture is the most important parameter for determination of fractures effect on the porosity and permeability systems. Due to high correlation between petrophysical logs and images/cores results (R2 approximate to 0.8), the results are dependable and extensible for other carbonate and naturally fracture reservoirs.",14,13,4
Fracture,Natural Fractures,"Al-Busaidi, Intisar K.; Al-Maamari, Rashid S.; Karimi, Mahvash; Naser, Jamil",Effect of different polar organic compounds on wettability of calcite surfaces,Wettability; Calcite; Double bond; Benzene ring; Carboxylic acids; Asphaltene,FATTY-ACIDS; CRUDE-OIL; WATER; ADSORPTION; CHALK; ASPHALTENES; SOLUBILITY; PETROLEUM,"The average oil recovery by conventional water flooding from oil-wet and naturally fractured carbonate reservoirs is often less than 30%. Removal of adsorbed acidic components and/or asphaltene from the carbonate surface results in wettability alteration towards water-wet which is an effective approach to enhance oil recovery. Long chain fatty acids, long chain naphthenic acids and asphaltene are major components in crude oil which are responsible for wettability alteration in carbonate reservoirs while unsaturated acids have minor effect. In this study, a more accurate quantification of the effects of different types and structures of polar components that contribute to the initial oil-wetting extent of the reservoir rocks were used (aliphatic saturated acids, aliphatic unsaturated acids, naphthenic acids, aromatic acids and asphaltene). Different analytical tools (contact angle, zeta potential, Fourier transform infrared spectroscopy and thermal analysis) were utilized for all acids in order to study surface characteristics. The results indicated that polar organic compounds act in different ways according to their structure and properties. Presence of double bond could make the acid molecule more polar, reactive and less hydrophobic. In addition, it can affect the spatial arrangement of the molecule and hence its orientation on the surface. Presence of benzene ring increases the reactivity and polarity of carboxylic group. Moreover, it enhances hydrophilic properties of the acid due to electrons of pi double bonds that can resonate over aromatic carbon atoms. The results revealed that, in the presence of water film, combination of acid dissociation in water, surface activity of acid and water solubility controls the acid adsorption and hence wettability alteration of the surface during aging process. Chemisorption of carboxylic acids/asphaltene changes the wettability of calcite surface. In addition to chemical adsorption, some acids adsorb physically on the surface. Physical adsorption of polar compounds may happen via hydrogen bonding between carboxylic groups and carbonate ions on the surface. Although physical adsorption is reversible and forms weak bonds between adsorbate and adsorbent, it may partially contribute to wettability alteration.",14,14,2
Fracture,Natural Fractures,"Zhou, Lei; Shen, Zhonghui; Wang, Jiandong; Li, Honglian; Lu, Yiyu",Numerical investigating the effect of nonuniform proppant distribution and unpropped fractures on well performance in a tight reservoir,,THEORETICAL CONDUCTIVITY ANALYSIS; LIGHT-WEIGHT PROPPANTS; LONG-TERM CONDUCTIVITY; NATURAL FRACTURES; PERMEABILITY; SIMULATION; EMBEDMENT; TRANSPORT; CLOSURE,"Distribution of the propped and unpropped fracture is an important factor affecting well performance that is necessary to study. This paper presents new numerical proppant and rock fracture conductivity models. The models are based on the results of physical experiments conducted for this study and the models consider proppant deformation, embedding, and loading paths. The models were implemented in a 3D hydromechanical coupled numerical simulator to model well production. A 3D hydraulic fracturing simulator was used to generate an artificial fracture with nonuniform proppant distribution using reservoir and operational parameters from a tight oil reservoir in northwestern China. The fracture generated by the model was further used to investigate the influence of the nonuniform propped fracture on well performance. According to the study, proppant distribution can significantly affect well performance, a decreased aperture distribution from the well to the fracture front is preferred when using certain amounts of proppant. A parameter sensitivity study was carried out during which the influence of proppant deformation, proppant embedment, proppant permeability, proppant volume, reservoir damage, in-situ stress, and the loading path effect were investigated. Based on the results, suggestions were given to improve the well performance.",13,14,5
Fracture,Fracture Networks,"Li, Yuwei; Long, Min; Zuo, Lihua; Li, Wei; Zhao, Wanchun",Brittleness evaluation of coal based on statistical damage and energy evolution theory,Coal; Statistical damage theory; Energy evolution; Brittleness,IN-SITU STRESS; CONSTITUTIVE MODEL; ROCK; CONTINUUM; PRESSURE; SHALE,"Coal brittleness is an important index for evaluating whether coal can be fractured effectively. Coal with high brittleness can form a large complex network after fracturing, and also has better productivity and ultimate recovery. Therefore, accurate evaluation of coal brittleness can provide theoretical guidance for well and layer selection of coal seam fracturing. In this paper, first, uniaxial compression experiments have been carried out. According to the measured stress-strain curves and the core failure form, the brittleness of different coal cores have been analyzed. Considering the damage evolution of coal in loading process, a theoretical evaluation model of coal brittleness has been established based on the statistical damage theory and the energy evolution law of rock failure process. Brittleness indexes of experimental coal cores have been calculated by this model, the calculated results were in good agreement with the experimental results, which proved that the theoretical analysis method of coal brittleness proposed in this paper can be used to analyze the applicability of coal seam fracturing. This paper presents an evaluation method of coal brittleness and establishes a relevant theoretical model. The research results of this study have important academic merits by filling in the blank of theoretical study on the brittleness of coal, and could also further facilitate the field operations of coal fracturing.",70,72,21
Fracture,Fracture Networks,"Meng, M.; Baldino, S.; Miska, S. Z.; Takach, N.",Wellbore stability in naturally fractured formations featuring dual-porosity/single-permeability and finite radial fluid discharge,Wellbore stability; Fractures; Dual-porosity/single-permeability; Hemisphere plot,MECHANICAL-PROPERTIES; CONSOLIDATION; SHALE; BOREHOLE; MEDIA,"This work presents an analytical solution for an inclined wellbore drilled in a fractured formation displaying a high contrast between the diffusion rates in the fractures and in the porous matrix, with the latter treated as a storage phase and thus not participating in the fluid transport. This scenario may result from different mud cake building rates, and/or adverse wettability of the rock matrix with respect to the drilling fluid being used. Different from the models available in the literature, the fractures are characterized by a more realistic finite radial fluid discharge (namely, the fractures network hydraulically connected to the wellbore is of limited extent). The models output in terms of pore pressures, total stresses and effective stresses response has been compared with the results of a widely accepted dual-porosity/dual-permeability model. Major differences and asymptotic behaviors have been analyzed. Subsequently, the results of the model have been used to perform a comprehensive wellbore stability analysis. The effect of time dependency, fractures network length and rock properties on the instability of the borehole have been investigated, and upper and lower mud weight bounds have been determined using several failure criteria. This investigation shows that under the specified conditions where dual-porosity/single-permeability conditions arise, the proposed model provides with theoretically more conservative mud weights predictions.",48,50,6
Fracture,Fracture Networks,"Wang, Shuhua; Chen, Shengnan",Insights to fracture stimulation design in unconventional reservoirs based on machine learning modeling,Fracture stimulation design; Data mining; Feature selection; Machine learning; Montney tight reservoirs,ARTIFICIAL NEURAL-NETWORKS; GAS-PRODUCTION; NATURAL-GAS; TIGHT OIL; SHALE; OPTIMIZATION,"With rapid development of unconventional tight and shale reservoirs, considerable amounts of data sets are increasing rapidly. Data mining techniques are becoming attractive alternatives for well performance evaluation and optimization. This paper develops a comprehensive data mining process to evaluate well production performance in Montney Formations in western Canadian sedimentary basin. The general data visualization and statistical data evaluation are used to qualitatively and quantitatively evaluate the relationships between the stimulation parameters and first-year oil production. Then, the recursive feature elimination with cross validation (RFECV) is used to identify the most important factors on the first-year oil production in unconventional reservoirs. In addition, four commonly used supervised learning approaches including random forest (RF), adaptive boosting (AdaBoost), support vector machine (SVM), and neural network (NN) are compared to estimate the first-year well production. The results show that 6 features are the most important variables for constructing an accurate prediction model: well latitude, longitude, well true vertical depth (TVD), proppant pumped per well, well lateral length, and fluid injected per well. Compared to other algorithms, RF has the best prediction performance for the first-year oil production. Furthermore, such data-driven models are found to be very useful for reservoir engineers when designing hydraulic fracture treatments in Montney tight reservoirs.",45,46,5
Fracture,Fracture Networks,"Wang, Shuhua; Chen, Zan; Chen, Shengnan",Applicability of deep neural networks on production forecasting in Bakken shale reservoirs,Production forecasting; Bakken formation; Deep neural networks; Hyperparameter optimization; Global sensitivity analysis,NEWTON OPTIMIZATION METHOD; TIGHT-OIL; GAS-PRODUCTION; MODEL; PREDICTION; DESIGN; STEAM,"The unconventional shale and tight formations, such as the Bakken in Williston Basin, are becoming an important hydrocarbon sources since the development of advanced horizontal drilling and multi-stage stimulation techniques. The appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery. Although reservoir simulations are commonly used for production analysis, the modeling of hydraulic fractures and intrinsic complexity of shale have restricted an understanding of the fluid flow behavior. Owing to the available of a large amount of data in unconventional tight and shale reservoirs, data-driven approaches, such as deep neural networks (DNNs), provide an alternative approach for production analysis in these formations. In this study, a total of 2919 wells including 2780 multi-stage hydraulic fractured horizontal wells and 139 vertical wells in Bakken Formation were collected and analyzed using a deep learning method and Sobol's global sensitivity analysis. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, and batch normalization were evaluated to develop a reliable deep neural network model. Moreover, k -fold cross validation was used to evaluate the prediction ability and robustness of models. Prior to the performance evaluation of DNN algorithms, an optimum DNN model was achieved by optimizing the dropout layer, activation function, and hyperparameters of DNN models. It is found that the number of hidden layers and neurons in each layer have significant effects on the performance of models. The optimized DNN model has 3 hidden layers and 200 neurons for each layer. The prediction performance of DNN models is acceptable with the low mean squared errors for both 6- and 18-months cumulative oil productions. Furthermore, the importance of each parameter was studied using the Sobol's analysis. Results show that the average proppant placed per stage is the most important parameter, which accounts for more than 35% of variability in both 6- and 18-months cumulative oil productions. These data-driven models can be readily updated when the new well information becomes available. It is worth mentioning that the proposed DNN models can be directly integrated into existing hydraulic fracturing design routines.",35,37,5
Fracture,Fracture Networks,"Xu, Jianchun; Sun, Baojiang; Chen, Bailian",A hybrid embedded discrete fracture model for simulating tight porous media with complex fracture systems,Numerical simulation; Discrete fracture model; Naturally fractured tight oil reservoir; Transient transfer; Stochastic permeability,SHALE-GAS-RESERVOIRS; SHAPE FACTORS; NUMERICAL-SIMULATION; FLOW; PRESSURE; TRANSPORT; FLUIDS; OIL; FRAMEWORK,"Numerical simulation considering complex fracture networks in tight oil reservoir becomes a hot issue during these years. Recently, embedded discrete fracture model (EDFM) shows great advantages over the DFM approaches in both calculation efficiency and simplicity of simulation workflow. EDFM has been widely used in tight oil/gas natural energy or enhanced oil recovery (EOR) development. If a large number of small-scale natural fractures exist in reservoir, the calculation efficiency of EDFM method may decrease. In this paper, a new hybrid simulation model combining the EDFM and dual porosity (DP) model is proposed. The large-scale fractures are dealt with EDFM method while small scale fractures are dealt with DP model. Considering the low permeability of matrix, transient transfer between matrix and natural fracture is considered. The proposed hybrid model is validated compared with the local grid refinement (LGR) model and EDFM-MINC model, and the difference between transient transfer and pseudo-steady-state transfer effect on production is presented. Finally, two test cases are presented, and the sensitivity of some key parameters are investigated. Result shows that the new simulation model has higher calculation efficiency than LGR and EDFM-MINC models. Meanwhile, it honors a good accuracy. The pseudo-steady-state transfer between matrix and natural fracture leads to big error in tight oil production performance analysis both in single phase and two phases flow. Low matrix permeability and big matrix size increase the production difference between pseudo-steady-state transfer and transient transfer models. The proposed model can simulate reservoirs considering stochastic permeability distribution.",29,30,6
Fracture,Fracture Networks,"Wang, Xiaoyu; Yao, Jun; Gong, Liang; Sun, Hai; Yang, Yongfei; Zhang, Lei; Li, Yang; Liu, Wenchao",Numerical simulations of proppant deposition and transport characteristics in hydraulic fractures and fracture networks,Proppants; Fractures and fracture networks; CFD-DEM coupling,PARTICLE-TRANSPORT; SHEAR DISPERSION; PRESSURE-DRIVEN; VERTICAL WELL; FLUID-FLOWS; MODEL; PLACEMENT; CHANNEL; GAS,"Proppants are used to resist fracture closure during hydraulic fracking treatments. Understand the proppant transport and distribution characteristics in fracture and fracture network become a meaningful topic for its effects on the conductivities of fractures. Since experiments are expensive, and it is also difficult to consider various conditions and detect the movement of particles during experiments, numerical simulation methods are often applied. In this work, the coupled Computational Fluid Dynamics-Discrete Element Method (CFD-DEM) was implemented to investigate the factors affecting proppant distribution in fracture and fracture networks. First, the CFD-DEM model was built for proppant flow and settlement. We validated the model by comparing with the published numerical simulation result. After that, we designed a series of cases to investigate the effects of fracture closure, injection velocity and no-uniform opening of the inlet on proppant distribution in a single fracture. Then, the effects of proppant diameter, density and perforation height differences on proppant sorting were studied. Next, we computed the proppant transport in fracture networks considering the aperture difference, the orientation of branch fractures and leak-off in fracture tips. The simulation results in this paper can help engineers to understand the transport and distribution of proppants visually in the fracture and fracture networks in unconventional reservoirs.",28,28,8
Fracture,Fracture Networks,"Jiang, Changbao; Niu, Binwei; Yin, Guangzhi; Zhang, Dongming; Yu, Tang; Wang, Pei",CT-based 3D reconstruction of the geometry and propagation of hydraulic fracturing in shale,Shale; True triaxial testing; Hydraulic fracturing; CT scanning; 3D reconstruction; Fracture distribution,TIGHT,"Hydraulic fracturing is one of the primary techniques which has been widely implemented in order to allow for the stimulation of shale gas reservoirs. To accurately distinguish the extension characteristics and the spatial distribution of fractures during the hydraulic fracturing of the Longmaxi shale reservoirs in Changning, a self-developed, multifunctional, true triaxial experimental process (utilizing a fluid-solid coupling testing system) was used to simulate the horizontal well hydraulic fracturing. The CT technique was used to scan the samples prior to and following the conduction of the experiments; the CT scanning images of internal fractures were reconstructed and visualized via 3D reconstruction. The influence of in-situ stress, the displacement of the fracturing fluid upon the fracture morphology and the resultant fractural extensions caused by hydraulic fracturing were discussed. The study shows that the reconstructed 3D model based on the different CT values corresponding to the shale matrix, minerals and fractures can accurately characterize the internal structure and fracture distribution of shale. Shale hydraulic fracturing fractures can be divided into 3 categories: single transverse fractures, main arc fractures and complex fractures. The ""fluctuation phenomenon"" of a water pressure curve is related to the formation and extension of reservoir fractures, and is a discernible characteristic of complex fractures formed by the volume fracturing of shale. Stress differences and the stress difference coefficient are the governing factors in terms of the complexity of shale hydraulic fracturing networks. Displacement has a particular range of influence on the manifestation of fracture complexity; a low displacement may not result in a complete fracture, but too high a displacement tends to culminate a single fracture in the formation, which to a certain extent reduces fractural complexity.",26,27,4
Fracture,Fracture Networks,"Heng, Shuai; Liu, Xiao; Li, Xianzhong; Zhang, Xiaodong; Yang, Chunhe",Experimental and numerical study on the non-planar propagation of hydraulic fractures in shale,Shale; Bedding plane; Hydraulic fracturing; Non-planar propagation; Fracture network,ROCK FAILURE; BEHAVIOR; STRESS; GROWTH; DISCONTINUITIES; INITIATION; INTERFACE,"To better understand the non-planar propagation and geometry of fracture networks, hydraulic fracturing simulation tests on shale specimens were conducted using an established true triaxial hydraulic fracturing simulation test system. A two-dimensional numerical model of hydraulic fracturing was developed to clarify the evolution of hydraulic fractures and their non-planar behaviour at bedding planes. The numerical model with the alternating rock matrix and bedding planes considered the coupling effect of stress, fluid flow, and damage. The mechanisms by which hydraulic fractures penetrate or become arrested/deflected at bedding planes were then revealed as per the physical and numerical simulation results. The results revealed that the typical severe fluctuation of the injection pressure, which is closely related to the growth of sub-fractures along bedding planes or natural fractures, is a clear characteristic of the non-planar propagation of hydraulic fractures. The mechanical properties of the bedding primarily determine whether a hydraulic fracture penetrates or is deflected at the bedding. Strong beddings favour hydraulic fracture penetration; whereas, weak beddings favour hydraulic fracture deflection along the beddings. The hydraulic fractures typically extend along the path of least resistance, and therefore, induce the non-planar propagation behaviour at bedding planes. Tensile failure is a major fracture mechanism of the hydraulic fractures that penetrate or deviate at bedding planes. The experimental and numerical findings provide a basis for the optimum design of hydraulic fracturing and control of the fracture growth geometry in shale gas reservoirs.",25,25,13
Fracture,Fracture Networks,"Zhang, Ruxin; Hou, Bing; Han, Huifen; Fan, Meng; Chen, Mian",Experimental investigation on fracture morphology in laminated shale formation by hydraulic fracturing,Shale; Fracture propagation; Discontinuities; Fracturing energy; Horizontal stress difference,PROPAGATION BEHAVIOR; INITIATION; CRITERION,"A complex fracture network, which is the precondition of stimulated reservoir volume for shale formation, depends on the interaction between hydraulic fractures and discontinuities, such as bedding planes and natural fractures. However, the fracture propagation behavior in laminated shale formation still maintains ambiguous and the formation mechanism of complex fracture network has not been well understood. Therefore, hydraulic fracturing simulated experiments were conducted on shale outcrops to clarify above issues under the effects of multiple factors, such as horizontal stress difference, pump rate, and fluid viscosity. The results reveal that dilation and crossing are two main hydraulic fracture propagation behaviors because of discontinuities influencing, resulting in three categories of the ultimate fracture morphologies. Simple fracture is a single induced fracture. Complex fracture is consisted of two or more induced fractures which do not link up with each other. However, network fracture includes induced fractures which interweave with each other like a network. All the fracture geometries are generated under the mutual interaction of natural factors and engineering factors. A large horizontal stress difference and a high fracturing energy reduce the complexity of fracture geometry, whereas, a small horizontal stress difference and a low fracturing energy enhance the activated probability of discontinuities, resulting in a complex fracture network. Furthermore, weak cementing strength and large opening degree of discontinuities increase the complexity of the fracture. In addition, the fracturing curve reflects fracture morphology indirectly. Simple fracturing curve and steady extensive pressure indicate the simple fracture. The rising extensive pressure implies the complex fracture, whereas, the fluctuation of fracturing curve suggests the network fracture. In the meantime, each fracture morphology has its own dimensionless net pressure features, which could be applied to judge fracture morphology in shale formation.",24,26,8
Fracture,Fracture Networks,"Cui, Ronghao; Feng, Qihong; Chen, Hongwei; Zhang, Wei; Wang, Sen",Multiscale random pore network modeling of oil-water two-phase slip flow in shale matrix,Pore network model; Shale oil; Two-phase flow; Slip effect; Computational fluid dynamics,FRACTURED HORIZONTAL WELL; FAST MASS-TRANSPORT; POROUS-MEDIA; RELATIVE PERMEABILITY; DYNAMIC PROPERTIES; CO2 SEQUESTRATION; ORGANIC-MATTER; GAS-FLOW; NANOPORES; RESERVOIR,"The large-scale hydraulic fracturing technology is commonly employed to significantly improve oil recovery in shale. An exceptional phenomenon from many field tests is worthy of attention that the majority of fracturing fluid (mainly water) does not return to the surface during hydraulic fracturing, but flows into shale matrix. As a consequence of this phenomenon, oil-water two-phase flow would happen. However, the fluid transportation in nano-pores is different from that of the conventional sandstone reservoirs. To understand oil-water two-phase flow in shale, an integrated pore network model (PNM) framework including network construction and flow simulation is developed. In the network construction, combined with a pore-size distribution (PSD) curve of shale system, a shale multiscale random pore network model is proposed, where organic pores and inorganic pores can be distinguished appropriately. In the flow simulation, considering that the traditional Hagen-Poiseuille equation may not be applicable in shale system, new bulk fluid and corner film flow models with slip length in various geometric pores (circular, square, equilateral triangle) are developed using the computational fluid dynamic (CFD) method. Through the quasi-static simulation technique, we estimate the flow properties in shale including capillary pressure and relative permeability. Simulation results confirm the slip effect would significantly affect oil-water two-phase flow in shale. And then, influences of shale pore structure on two-phase flow are further investigated. Through coupling network construction and two-phase flow simulation, we believe our work could shed light on the further research for multi-phase transportation in shale.",23,24,9
Fracture,Fracture Networks,"Zhu, Jingyi; Yang, Zhaozhong; Li, Xiaogang; Song, Zhichao; Liu, Ziwei; Xie, Shiyi",Settling behavior of the proppants in viscoelastic foams on the bubble scale,Proppant; Settling behavior; Viscoelastic foam; Drag force; Bubble structure,FRACTURING FLUID; HIGH-TEMPERATURE; PARTICLES; SHEAR; SURFACTANT; STABILITY; SOLIDS; MODEL; SEDIMENTATION; TRANSPORT,"Liquid foam is an alternative to water-based fracturing fluid due to its great proppant suspension ability. In this work, theoretical and experimental investigations on the settling behavior of the proppants in viscoelastic foams were analyzed on bubble scale. Settling trajectory was captured over time by optical microscope to calculate proppant settling velocity. At room temperature, proppants kept suspended well, but noticeable changes in proppant position could be observed at 70 degrees C. We concluded that the sedimentation of the proppants at high temperature was divided into three stages, that were drainage-dominated, structure-dominated and fluid-dominated regimes. For the large proppants, quick settling velocity was seen at first due to fast drainage rate. Then bubble pressure force and network force served as drag force exerting on the proppants when the proppants stretched or squeezed the liquid films. During this regime, bubble distribution, the existence of nodes, the length and the orientation of Plateau border leaded to the fluctuation in settling velocity. Lastly, the proppants would also flow freely along Plateau border over time, and the properties of the foam fluid such as viscosity and elasticity provided the drag force to prevent the proppants from settling. It's more likely for small proppants to change to this stage called fluid-dominated regime, but elasticity also guaranteed their low settling velocity. Moreover, in the existence of proppants, the analysis into drainage rate and bubble structure demonstrated the high stability of viscoelastic foams. These results helped understand the sedimentation of proppants in wet foams and broadened the application of viscoelastic foams in hydraulic fracturing.",20,21,3
Fracture,Fracture Networks,"Ren, Long; Su, Yuliang; Zhan, Shiyuan; Meng, Fankun; Zhao, Guangyuan",Fully coupled fluid-solid numerical simulation of stimulated reservoir volume (SRV)-fractured horizontal well with multi-porosity media in tight oil reservoirs,Tight oil reservoir; SRV-fractured horizontal well; Multi-porosity media; Fully coupled fluid-solid; Numerical simulation,HYDROMECHANICAL PROCESSES; HYDRAULIC FRACTURE; MODEL; SYSTEM; FLOW,"A mutual coupling effect exists between the flow and stress fields in tight oil reservoir development. In terms of the characteristics of multi-porosity media (the matrix, natural fractures and network fractures) for stimulated reservoir volume (SRV)-fractured horizontal wells in tight oil reservoirs, considering the dual porosities of matrix and natural fractures, and based on the flowing feature of a discrete-fracture mode (DFM) fracture network stimulated system, a numerical simulation method based on fully coupled fluid-solid is introduced. According to the effective stress principle and regional flow characteristics, the fully coupled fluid-solid mathematical model considering the multi-porosity media characteristics of complex fracture networks is presented. The fully coupling numerical solution for the stress and flow fields is solved by the finite element method. The accuracy of this model is verified by comparing the finite differential model, non-coupled model and actual production data, respectively. And analyzing the computational time needed to solve the model under different solution methods and complexity levels. The variation of stress-strain and reservoir physical property parameters is revealed. For the non-coupled and fully coupled model, the productivity and formation pressure differences are compared and analysed. The results show that when considering the stress field, the initial production rate of an SRV-fractured horizontal well is large but declines quickly, and it has fundamentally different characteristics from the traditional flow model. Our research provides theoretical and technical guidance for the efficient development of unconventional resources.",20,23,1
Fracture,Fracture Networks,"Huang, Jingwei; Jin, Tianying; Chai, Zhi; Barrufet, Maria; Killough, John",Compositional simulation of fractured shale reservoir with distribution of nanopores using coupled multi-porosity and EDFM method,Pore size distribution; Multi-porosity coupled EDFM; Fractured shale reservoir; Phase behavior under confinement,CAPILLARY-PRESSURE; PHASE-BEHAVIOR; TIGHT-OIL; GAS; MODEL,"Shale reservoir contains highly heterogenous pore systems due to the wide-range distributions of nanopores in shale matrix and hydraulic/natural fractures. To explicitly include pore size distribution in simulation of shale reservoir, a multi-porosity model is applied to subdivide the matrix into multiple continua based on experimental pore size data. Each continuum has its own pore size, porosity and permeability, as well as other petrophysical properties. Besides, the embedded discrete fracture model (EDFM) is coupled with multi-porosity model to describe the complex fractures networks with any angles and intersections. To evaluate effects of pore size distribution on production, compositional simulation is conducted in a fractured shale reservoir using different number of continua in shale matrix. Simulation results show that the use of multiple continua results in lower oil and gas production. Different pressures, oil and gas saturations and compositions are observed in different continua. To further investigate the effects of distribution of nanopores, oil-gas capillary pressure is rigorously calculated in every continuum. The existence of large capillary pressure leads to different fluid properties in different size of nanopores. Moreover, capillary pressure reduces oil and gas recovery and alters compositions of residuals. The effects of capillary pressure are more significant in the low permeable continua due to smaller pore sizes.",19,19,0
Fracture,Fracture Networks,"Zhao, Yan-long; Wang, Zhi-ming; Qin, Xing; Li, Jiang-tao; Yang, Hu",Stress-dependent permeability of coal fracture networks: A numerical study with Lattice Boltzmann method,Coal fracture networks; Lattice Boltzmann method; Fracture roughness; Effective stress; Stress sensitivity,GAS-FLOW; TRANSPORT-PROPERTIES; PREDICTION; SIMULATION; PRESSURE; MICROSTRUCTURE; MODEL,"Since coal permeability is sensitive to stress, fundamental understanding of gas flow in coal fracture networks and permeability change with varying effective stress are necessary in the processes of CBM production. Based on the rock elastic theory and finite difference method, the stress-strain model of reconstructed coal fracture networks is established. It has provided a more accurate geometry model under stress condition. For comparison purposes, gas permeability and porosity of coal sample with artificially generated fracture are measured under varying effective stress. Based on the experimental results and the Walsh model, fracture width and roughness are estimated. Lattice Boltzmann methods are implemented to model the flows in a single rough fracture under stress condition and the stress-dependent permeability is predicted. Compared with laboratory measurement, the maximum relative error is 25%. Furthermore, applications and case studies are performed for the flows in the 2D and 3D fracture networks. The effects of stress, fracture density, surface roughness and aperture on the associated permeability are discussed. The present study provides an alternative to investigate the microcosmic stress sensitivity mechanism of coal permeability.",18,18,3
Fracture,Fracture Networks,"Chen, Yulong; Zhang, Yuning; Li, Xuelong",Experimental study on influence of bedding angle on gas permeability in coal,Bedding plane orientation; Coal; Gas; Permeability,MECHANICAL-BEHAVIOR; HYDRAULIC-GRADIENT; FRACTURE NETWORKS; WAVE VELOCITY; FLUID-FLOW; MODEL; SHALE; STRESS; ANISOTROPIES,"The gas permeability of coalbeds is of critical significance to gas exploitation and recovery in coal seams. These properties are affected by bedding plane orientation. In this paper, the influence of different bedding angles in coal on mechanical properties, and gas permeability behavior in a complete stress-strain process is investigated. Experimental results reveal that with an increase in the bedding angle, the number of channels was found to increase along with the initial permeability. The increased bedding angle also caused the compression strengths of the coal sample to decrease initially and then increase. The corresponding compression strength was highest at a bedding angle of 0 degrees followed by a bedding angle of 90 degrees. Under these two conditions, the failure surface of coal was usually due to tensile splitting. The coal strength was lowest at a bedding angle of 60 degrees, where the coal mass experienced shear failure during the bedding plane. The coal sample at a bedding angle of 30 degrees exhibited compound split-shear failure.",17,17,10
Fracture,Fracture Networks,"Wang, Deqiang; Cheng, Linsong; Cao, Renyi; Jia, Pin; Fang, Sidong; Rao, Xiang; Wu, Yonghui; Dai, Dan",The effects of the boundary layer and fracture networks on the water huff-n-puff process of tight oil reservoirs,Tight reservoir; Water huff-n-puff; Volume fracture; Boundary layer; Embedded discrete fracture model,PERMEABILITY STRESS SENSITIVITY; HORIZONTAL WELLS; RELATIVE PERMEABILITY; SEMIANALYTICAL MODEL; FLOW BEHAVIOR; SHALE; PERFORMANCE; SIMULATION; SCALE,"Application of multi-fractured horizontal wells has led to significant progress in the development of tight oil reservoirs. However, oil production rapidly decreases and the estimated ultimate recovery is still low when the well is in production and approaching depletion. Water huff-n-puff is regarded as a useful measure to improve oil recovery due to oil-water imbibition and drainage. Additionally, complex fracture networks consisting of natural fractures (NF) and hydraulic fractures can significantly enhance oil recovery in the process of water huff-n-puff after multi-stage hydraulic fracturing. However, there is a non-flowing thin film on the solid-liquid wall surface in the pore-throats of the matrix, and the so-called boundary layer effect (BLE) is quite significant at the nanoscale. This effect reduces the effective flow space and effective permeability of the reservoir, leading to production damage. To date, few numerical simulation studies have considered the impact of the BLE and complex fracture networks in water huff-n-puff process simulation studies. In this study, the process of water huff-n-puff is evaluated considering complex fracture networks and formation damage in a matrix. The embedded discrete fracture model (EDMF), validated by local grid refinement (LGR), is applied to describe the distribution of hydraulic fractures and NF. The well performance considering the BLE is analyzed by a vectorization programming. The results show that the BLE reduces production and accelerates the production decline, so the BLE should be considered in reservoir simulations and productivity evaluations of water huff-n-puff processes. A certain degree of natural fracture development is conducive to improving the sweep efficiency of the water huff-n-puff, which could significantly improve oil recovery compared to depletion. By considering the impact of the BLE in water huff-n-puff simulations in tight oil reservoirs, it is possible to accurately evaluate the well performance and provide a theoretical basis for the optimization of water huff-n-puff.",17,16,5
Fracture,Fracture Networks,"Feng, Qihong; Xu, Shiqian; Wang, Sen; Li, Yuyao; Gao, Fangfang; Xu, Yajuan",Apparent permeability model for shale oil with multiple mechanisms,Shale oil; Apparent permeability; Natural fracture; Noncircular pore; Production prediction; Embedded discrete fracture model,PORE-SIZE DISTRIBUTION; FAST MASS-TRANSPORT; LIQUID PERMEABILITY; ORGANIC NANOPORES; POROUS-MEDIA; GAS-FLOW; NETWORK; SIMULATION; ROCK; ENHANCEMENT,"Accurate apparent permeability (AP) model for oil transport in shale must consider natural fractures and micro/nano-pores within organic matter and inorganic matrix. Furthermore, the effect of pore geometry, tortuosity, pore size distribution (PSD), the spatial distribution of different pores, total organic content (TOC), and liquid slip should also be taken into account. However, all of the aforementioned factors are not simultaneously considered in one AP model. In this work, we develop an AP model in 3D for shale oil to overcome this drawback. We first validate our model by comparing with the published data. Then sensitivity analysis for some parameters is investigated. After that, shale oil APs are used in a macro-scale reservoir simulation model. In this way, the effect of some micro-scale factors on production performance can be quantitatively evaluated. Notably, on the basis of embedded discrete fracture model (EDFM), our reservoir simulation model considers non-linear flow in shale matrix, complex hydraulic fracture geometry, and pressure-dependent permeability of hydraulic fractures. Results show that natural fractures contribute the most to AP, followed by organic pores and inorganic pores. In general, the AP in the horizontal direction is approximately twice that in the vertical direction in shale. Furthermore, the maximum error caused by the pore type on shale oil production is similar to 31%, followed by tortuosity (similar to 25%), pore shape (similar to 13%) and slip effect (similar to 4.8%). In conclusion, it is necessary to simultaneously incorporate the influences of the aforementioned factors. Our stochastic permeability model can serve as an efficient tool to determine shale oil AP.",17,19,3
Fracture,Fracture Networks,"Rueda Cordero, Julio Alberto; Mejia Sanchez, Eleazar C.; Roehl, Deane",Integrated discrete fracture and dual porosity - Dual permeability models for fluid flow in deformable fractured media,Naturally fractured reservoirs; Multiscale fractures; Dual porosity; Discrete fracture,COUPLED HYDROMECHANICAL MODEL; FINITE-ELEMENT; PROPAGATION; SIMULATION,"Aiming at accuracy and computational efficiency, integrating discrete fracture and dual porosity-dual permeability models is a viable alternative to simulate flow in naturally fractured reservoirs with discontinuities of multiple lengths. However, previous works focus on the hydraulic problem only and do not take into account geomechanical effects. This study proposes a hydro-mechanical model using the finite element method (FEM) to represent the behavior of fracture networks with fractures of large, medium and small lengths. The methodology integrates the discrete fracture model (DFM) using interface elements, and the dual porosity/dual permeability (DPDP) model. Some synthetic applications compare the results of the models. A case study integrating both approaches is also performed. The results show that fractures of small and medium length enhance the permeability of naturally fractured reservoirs. Their presence within the porous medium results in greater fluid drainage and faster rate of pore pressure dissipation. The fractures contributed significantly to the mechanical behavior with impact on the stiffness of the rock mass system. Aperture variation of the fracture network influences fracture permeability and shows the stress shadowing effect. The results support the application of the proposed large-medium-small length fracture model to represent enhanced permeability of naturally fractured media.",17,17,2
Fracture,Fracture Networks,"Wei, Shiming; Xia, Yang; Jin, Yan; Chen, Mian; Chen, Kangping",Quantitative study in shale gas behaviors using a coupled triple-continuum and discrete fracture model,Shale gas; Hydraulic fracture network; Non-equilibrium desorption/adsorption mechanism; Gas behavior,HORIZONTAL WELLS; PRACTICAL METHOD; TIGHT OIL; FLOW; RESERVOIR; SIMULATION; FLUID; DIFFUSION; TRANSPORT; FRAMEWORK,"The shale has ultra-low permeability wherein multi-scale natural fractures are well-developed. The success of providing high diversion channels makes multi-stage fractured horizontal wells (MFHWs) become the powerful technique for economically producing gas from shale. This study presents a triple-continuum and discrete fracture model to describe a fractured shale reservoir embedded with a MFHW. The model incorporates non-equilibrium desorption/adsorption mechanism (NEDAM), viscous flow, Knudsen diffusion, and surface diffusion. The discrete fracture networks (DFNs) is quantitatively constructed according to the fracture density and stimulated reservoir area (SRA). This model is used to analyze the temporal/spatial evolution of the gas pressure and the net desorption rate. NEDAM is compared with the conventional equilibrium desorption mechanism (EDM) and its found that NEDAM uncovers the delayed phenomenon during gas desorption, and the use of EDM overestimates the production contributed from the adsorbed gas. The maximum net desorption rate of adsorbed gas gradually spread from the SRA region to the nonSRA region. The complete flow stages are clearly interpreted in a semi-logarithmic curve of well testing, and the flow stage controlled by the hydraulic fractures is clearly presented. Finally, the instructions on hydraulic fracturing treatment are given based on the production analysis.",17,18,2
Fracture,Fracture Networks,"Cai, Can; Kang, Yong; Wang, Xiaochuan; Hu, Yi; Huang, Man; Liu, Yiwei; Liu, Jiawei; Chen, Hao; Li, Xiaohong",Experimental study on shale fracturing enhancement by using multi-times pulse supercritical carbon dioxide (SC-CO2) jet,Supercritical carbon dioxide; Shale gas; Pulse jet fracturing; Fracture morphology; Fracturing enhancement,ADSORPTION CHARACTERISTICS; CO2 INJECTION; FLOW-FIELD; GAS; PRESSURE; LIQUID; COAL; TEMPERATURE; PROPAGATION; SIMULATION,"Supercritical Carbon Dioxide (SC-CO2) fracturing can increase shale gas production and reduce carbon dioxide (CO2) emission. In order to enhance shale fracturing, a new method of multi-times pulse SC-CO2 jet fracturing is proposed and comprehensively studied. The results demonstrate there are more initiation positions and more complex fracture network after pulse SC-CO2 jet fracturing due to strong impingement and pressurization. Furthermore, three types of main fracture and four types of fracture branch are observed. The main fractures mostly initiate from perforation and propagate with irregular path to the specimen edge. CO2 absorption and fracture volume increase 77.72% and 2283%, respectively, more than that of single-pulse SC-CO2 jet fracturing. The comparison indicates that SC-CO2 creates more complex fracture morphology, larger fracture volume and CO2 absorption than that of water. Moreover, the effect of influential factors, including pulse jet frequency, pulse jet pressure and pulse jet distance, are discussed thoroughly. Thus, this study provides a method of jet fracturing enhancement, and is instructive for understanding and tackling pulse jet fracturing issue related to CO2 utilization and fracturing of shale reservoir.",16,16,11
Fracture,Fracture Networks,"Cao, Renyi; Fang, Sidong; Jia, Pin; Cheng, Linsong; Rao, Xiang",An efficient embedded discrete-fracture model for 2D anisotropic reservoir simulation,Embedded discrete fracture model; Boundary element method; Reservoir simulation; Coupled method,FLOW BEHAVIOR; NUMERICAL-SIMULATION; FINITE-ELEMENT; BLACK-OIL; PERMEABILITY; TRANSPORT; WELL,"In this study, we present an embedded discrete fracture model (EDFM) for an in-house reservoir simulator that incorporates the effect of each fracture with arbitrary orientations, lengths and fracture conductivities. Instead of using the linear flow approximation for the EDFM, the interflows between local matrix grids and fracture elements are derived using boundary element method, which considers the effect of local grid geometry and boundary pressure on the flow into the fracture. The implementation is generally compatible with existing finite-difference reservoir simulators, and the accuracy of the EDFM is validated by comparing the results of analytical/semi-analytical models for fracture flow, LGR modules for fracture flow in commercial reservoir simulators and complex fracture flow in discrete fracture network using finite element method. A grid-sensitivity study is conducted to show the convergence of the new method. Moreover, the cases of multiple bi-wing fractures and complex fracture systems are presented to demonstrate the robustness, applicability and computational convenience of the novice approach for simulating the fracture flow in anisotropic reservoir.",16,17,5
Fracture,Fracture Networks,"Jia, Pin; Cheng, Linsong; Huang, Shijun; Xue, Yongchao; Clarkson, Christopher R.; Williams-Kovacs, Jesse D.; Wang, Suran; Wang, Deqiang",Dynamic coupling of analytical linear flow solution and numerical fracture model for simulating early-time flowback of fractured tight oil wells (planar fracture and complex fracture network),Linear flow; Flowback; Flow regimes; Tight oil reservoir,MULTIFRACTURED HORIZONTAL WELLS; 2-PHASE FLOWBACK; SEMIANALYTICAL MODEL; SECONDARY FRACTURES; HYDRAULIC FRACTURE; TRANSIENT-BEHAVIOR; GAS; SYSTEM,"Quantitative analysis of flowback data provides an early opportunity to interpret hydraulic fracture properties of fractured wells in unconventional reservoirs. In recent years, a number of studies have been dedicated to the analysis of single-phase flow data prior to hydrocarbon breakthrough and multi-phase flow data after hydrocarbon breakthrough during flowback. This study provides a new model to simulate flowback of fractured tight oil wells with planar fractures or a complex fracture network. In the model, fractures are discretized into a number of segments and the fully numerical method is used to model fracture flow. It is assumed that the pressure interference in the matrix caused by these fracture segments can be accounted using a no-flow boundary condition and that the drainage volumes of fracture segments form isolated regions to allow for linear flow from the matrix to each segment. To model this behavior, matrix flow is simulated using the analytical transient linear flow solution which is dynamically coupled with the fracture flow model by imposing continuity of pressure and flux on the fracture surfaces. The model is simple, but rigorous enough to take into account the important physics of the fracture system, including arbitrary fracture geometries and fracture conductivity distributions. The pressure and saturation gradients of each phase in fractures are accounted for. The ease of model setup and improved computational performance makes it convenient for practical application. The new model is verified with a commercial reservoir simulator. Investigation of the assumption of no-flow boundary condition for the pressure interference in the matrix caused by the fracture segments reveals that the assumption becomes poorer with increasing matrix permeability and decreasing fracture permeability. Flow regime analysis demonstrates that, for planar fractures, water exhibits an early transient linear flow period (first linear flow in the fracture) followed by boundary-dominated flow (first boundary-dominated flow in the fracture) prior to hydrocarbon breakthrough, after which a second transient linear flow in the fracture develops. The final flow period is boundary-dominated flow (second boundary-dominated flow in the fracture), indicating the end time of the flowback period. At this stage, oil will be the dominant phase in the fracture, and will exhibit transient linear flow in the matrix, which is the first flow-regime typically observed during the long-term production period. The case of a complex fracture network exhibits a similar sequence of flow regimes. The second transient linear flow for this case has not been discussed in the literature. The development of this flow period may be caused by the maintenance of fracture pressure, and decrease of water relative permeability due to hydrocarbon contribution from the matrix. A field example from western Canada exhibits the flow regimes noted above and is history-matched successfully using the new model. The results demonstrate the practical application of the new model for deriving reservoir/fracture properties from flowback data and for forecasting.",15,15,3
Fracture,Fracture Networks,"Wu, Yonghui; Cheng, Linsong; Huang, Shijun; Bai, Yuhu; Jia, Pin; Wang, Suran; Xu, Bingxiang; Chen, Ling",An approximate semianalytical method for two-phase flow analysis of liquid-rich shale gas and tight light-oil wells,Two-phase; Multistage fractured horizontal well; Liquid-rich shale gas; Tight oil; Semianalytical method,FRACTURED HORIZONTAL WELLS; INTEGRATED WORKFLOW; CURVES,"Two-phase flow of oil and gas is quite common in the reservoir during the depletion of liquid-rich shale gas and tight light-oil. Many analytical models proposed for multistage fractured horizontal wells completed in unconventional reservoirs are restricted to single phase flow problem. In this paper, an approximate semianalytical method is proposed to handle the complexities of phase change, pressure dependent PVT properties, two-phase flow behavior and complex fracture networks. The black oil model is used to model phase change and two-phase flow of oil and gas. The secondary fractures in the stimulated reservoir volume and the reservoir beyond the main fractures are considered in the physical model to make long-term production forecasts. The forecasted producing GOR is used to decrease the equations of the two-phase flow model, so only the flow equations of primary phase are used to develop the mathematic model. Then an approximate method is used to linearize the model and the analytical solution is obtained in Laplace space for constant pressure inner boundary problem. The Duhamel's principle is applied to correct the production rate under variable flowing pressure inner boundary, and a procedure is proposed for history matching of field production data and making forecasts. Finally, the semianalytical model is validated with two simulation examples, the average relative error is shown to be less than 10%. After that, two field examples are used to show its utility.",15,16,0
Fracture,Fracture Networks,"Rao, Xiang; Cheng, Linsong; Cao, Renyi; Jia, Pin; Wu, Yonghui; Liu, Hao; Zhao, Yuying; Chen, Ying",A modified embedded discrete fracture model to study the water blockage effect on water huff-n-puff process of tight oil reservoirs,Water blockage effect; Water huff-n-puff process; Embedded discrete fracture model; Tight oil reservoirs,INDUCED FORMATION DAMAGE; WELL PERFORMANCE; POROUS-MEDIA; SIMULATION; FLOW; IMPACT; EDFM; NETWORKS; BLOCKING; BASIN,"This paper constructs a numerical model to study the water blockage effect on water huff-n-puff process of tight oil reservoirs, by borrowing the conception of ""fracturing fluid layer"" and modifying embedded discrete fracture model (EDFM). Based on the proposed model, the effects of the permeability, initial water saturation and width of the fracturing fluid layer on water huff-n-puff process are detailly studied. It is found that, (i) initial water saturation of FFL makes little effect on water huff-n-puff process, because the water injection can refresh the water saturation distribution near fractures, and this 'refreshment effect' significantly reduce the effect of the initial water saturation of FFL. Moreover, the longer water injection time is, the stronger ` refreshment effect' will be, then the smaller effect the initial water saturation of FFL will make. (ii) both of width and permeability of FFL make a significant negative effect on the oil production rate of water huff-n-puff process, and permeability is more influencing than width. These results may give theoretical instructions to optimize the water huff-n-puff process while considering the water blockage effect.",14,13,5
Fracture,Fracture Networks,"Yao, C.; Shao, J. F.; Jiang, Q. H.; Zhou, C. B.",A new discrete method for modeling hydraulic fracturing in cohesive porous materials,Hydraulic fracturing; Hydromechanical coupling; Porous materials; Rigid block spring method; Discrete fracture network; Discrete models,MECHANICAL-PROPERTIES; NUMERICAL-SIMULATION; PARTICLE MODEL; FREE-SURFACE; BRITTLE; DAMAGE; PROPAGATION; SEEPAGE; FAILURE; GROWTH,"A new 2D hydromechanical rigid block spring method is developed for studying hydraulic fracturing in cohesive porous materials. The continuum medium is discretized into an assembly of discrete rigid blocks. Macroscopic deformation and failure are related to local properties of interfaces between blocks. Fluid flow in porous continuum is described by an equivalent discrete fracture network model. Biot's theory is extended to discrete porous interfaces for studying interactions between fluid flow and mechanical behavior. Further, the hydraulic conductivity evolution due to fracture propagation is taken into account through the change of aperture of interfaces. The proposed discrete hydromechanical model is first verified through the response of an elastic isotropic thick-walled cylinder subjected to an inner pressure under the steady state flow condition. The obtained numerical results agree well with the corresponding analytical solutions. Further, the numerical model is applied to studying the hydraulic fracturing of the thick-walled cylinder. The effect of transient flow on fracturing pressure is highlighted. The effect of materials strength anisotropy on fracturing process is also studied. It is shown that the proposed discrete model provides an efficient tool for modeling hydraulic fracturing in cohesive rock-like materials.",14,14,2
Fracture,Fracture Networks,"Wang, Fei; Li, Baoman; Chen, Qiaoyun; Zhang, Shicheng",Simulation of proppant distribution in hydraulically fractured shale network during shut-in periods,Shale; Fracture network; Proppant transport; Well shut-in; Proppant-carrying fluid flow,NUMERICAL-SIMULATION; TRANSPORT,"Proppant distribution is an important topic, because it is closely related to the success or failure of hydraulic fracturing treatment. Although, many proppant transport models have been published, there is still relatively limited research on proppant distribution between the created fracture network in shale especially during the post-treatment shut-in periods. In this paper, based on the intercoupling of particle hydrodynamics, fluid hydrodynamics, and poro-elastic rock mechanics, a mathematical model regarding the transport of liquid-solid phases has been established to simulate the behavior of the proppant transport and the carrying fluid migration in the fractured shale network during the well shut-in. The coupled model takes main hydraulic fractures, secondary induced fractures and matrix into account, namely a three-dimensional triple-porosity medium. All the important processes in fractured shale network can be explained by the liquid-solid transport simulation with the coupled model, including (1) liquid transport driven by viscous and gravity forces, (2)proppant particle transport driven by the horizontal forces of drag, inertia and collision, and the vertical gravity and buoyancy, and (3) hydraulic-fracture closure, which is considered as a poro-elastic rock deformation during the shut-in periods. Based on the conservation of mass and momentum, the liquid-solid transport coupled with rock deformation, are described by a set of partial differential equations, which are solved by the semi-implicit finite-difference method. The evolution of the proppant concentration and fluid pressure profiles is calculated. The fluxes of the proppant and proppant-carrying fluids between the main fracture and secondary fracture during the post-stimulation well shut-in are also calculated. The influences of proppant properties (concentration, density and size) and proppant-carrying fluid properties (viscosity and density) on the proppant distribution are investigated. The results of this study are expected to provide a better understanding of the proppant and proppant-carrying fluid distribution for different physical properties of proppant and carrying fluids, and explain which is the predominant factor influencing the proppant distribution during the shut-in periods.",13,13,7
Fracture,Fracture Networks,"Zhao, Haifeng; Wang, Xiaohua; Liu, Zhiyuan","Experimental investigation of hydraulic sand fracturing on fracture propagation under the influence of coal macrolithotypes in Hancheng block, China",Coalbed methane; Hydraulic fracturing; Fracturing experiment; Coal macrolithotypes; Perforation location,EASTERN MARGIN; ORDOS BASIN; NUMERICAL-SIMULATION; NETWORK PROPAGATION; RESERVOIR; METHANE; SHALE; ROCK; MODEL; GEOMECHANICS,"The mechanical properties, brittleness and micro-fracture development of different coal macrolithotypes (bright coal, semi-bright coal, semi-dull coal and dull coal) are different, and these differences have an impact on the propagation of hydraulic fractures. To understand the influence of coal macrolithotypes on fractures propagation, several hydraulic sand fracturing experiments considering the classification of coal macrolithotypes were carried out by taking No. 11 coal seam of the Taiyuan formation in Hancheng block, China. We mainly investigated the influence of coal macrolithotypes and perforation location on the propagation of hydraulic fractures. Combined with observation results of mining excavation, the experimental results are verified. The research finds that fractures morphology and proppants distribution in bright-type coal is better than dull-type coal. Thus, bright-type coal is the fracturing sweet-spot section in coal seam. We also find that hydraulic fractures are prone to propagate along the stratigraphic interfaces or lithologic interfaces to form horizontal major-fractures, and the overall stimulation effect of coal seam is dependent on the fractures morphology and proppants placement of these horizontal major-fractures. The stimulation effect of horizontal major-fractures for coal seam is better when perforation location is selected near the weak planes instead of the middle of coal seam. The research results provide theoretical guidance for efficient fracturing of coal seam.",13,15,4
Fracture,Horizontal Wells,"Sheng, Guanglong; Su, Yuliang; Wang, Wendong",A new fractal approach for describing induced-fracture porosity/permeability/ compressibility in stimulated unconventional reservoirs,Stimulated unconventional reservoirs; Fractal induced-fracture spacing; Fractal induced-fracture aperture; Tortuosity index; Fracture porosity/permeability/compressibility,HORIZONTAL WELLS; GAS-FLOW; MATRIX PERMEABILITY; OIL; MODEL; SIMULATION; PREDICTION; DIFFUSION; VOLUME; MEDIA,"The stimulated reservoir volume (SRV) with complex induced-fracture governs dominant flow rates in unconventional reservoirs. The induced-fracture spacing and aperture greatly affect the fracture properties. In this study, a new method to calculate tortuosity index of fractal induced-fracture is proposed, and the fractal dimension of induced-fracture aperture (d(fa)) is presented to describe the distribution of fractal induced-fracture aperture (FFAD). Combined with fractal induced-fracture spacing (FFSD) and FFAD, the fractal fracture porosity/permeability/compressibility models are given. The FFSD and FFAD influenced by fractal dimensions and their influences on fracture properties are analyzed. The results show that the d(fs) has a wider range than that of natural fractures, and it may be larger than 2 in 2D system in some special reservoirs, e.g. re-stimulated reservoirs. As the distance from the reference point increases, the tortuosity index gradually decreases. The larger the fractal dimension (d(fs) or d(fa)) is, the larger the fracture porosity/compressibility will be. In the cases of d(fs) < 2 (or d(fa) < 2), the fracture porosity/compressibility of the uniformly induced-fracture is smaller than the fractal induced-fracture near the reference point, and larger than that far away from the reference point. While in the cases of d(fs) > 2 (or d(fa) > 2), the fracture porosity/compressibility of the uniformly induced-fracture is larger than the fractal induced-fracture near the reference point, and smaller than that far away from the reference point. When d(fa) > 2, the fracture permeability increases first and then decreases as the distance from the reference point increases. In other cases, the fracture permeability decreases as the distance from the reference point increases. The permeability influenced by distribution of induced-fracture aperture is greater than that influenced by induced-fracture spacing.",92,94,8
Fracture,Horizontal Wells,"Wu, Zhongwei; Cui, Chuanzhi; Lv, Guangzhong; Bing, Shaoxian; Cao, Gang",A multi-linear transient pressure model for multistage fractured horizontal well in tight oil reservoirs with considering threshold pressure gradient and stress sensitivity,Multi-linear transient pressure model; Multistage fractured horizontal well; Stress sensitivity; Threshold pressure gradient; Pedrosa's transformation; Perturbation theory,NON-DARCY FLOW; SHALE; PERMEABILITY; PERFORMANCE,"In general, tight oil reservoirs has a numerous tiny and complicated throats, and ultra-low permeability, which leads to a low-velocity non-Darcy flow when the fluid flows in tight reservoirs. The permeability of tight oil reservoirs is no longer a constant, but a variable, which is dependent on reservoir pressure. In other word, the tight oil reservoir is stress sensitive media. The low-velocity non-Darcy flow and stress sensitivity will greatly affect the bottom hole pressure response. So, the low-velocity non-Darcy flow and stress sensitivity should be taken into consideration when researching the transient pressure behaviors of multistage fractured horizontal wells. Currently, there are many researches on transient pressure behaviors of the multistage fractured horizontal well, but none of these researches has taken the low-velocity non-Darcy flow and stress sensitivity into consideration simultaneously. In this paper, threshold pressure gradient and permeability modulus are used to characterize the low-velocity non-Darcy flow and stress sensitivity, respectively. And, a multi-linear transient pressure model of multistage fractured horizontal well with considering low-velocity non-Darcy flow and stress sensitivity is established. The Pedrosa's transformation, perturbation theory, Laplace transformation and stehfest numerical inverse are used to solve this transient pressure model. The novel model is verified by comparing the result of proposed model with that of Ekaterina Stalagorova's model. According to the dimensionless pressure derivative curve, the flow process can be identified as six regimes: (1)the main fracture linear flow stage, (2)the first transition flow stage, (3)dual-linear flow stage,(4)the second transition flow stage, (5)the formation linear flow stage, (6)the boundary flow stage. Finally, the effects of threshold pressure gradient, permeability modulus and fracture density of stimulated reservoir on dimensionless pressure derivative are analyzed. This research provides theoretical support for correctly understanding the flow law of multistage fractured horizontal well.",42,44,6
Fracture,Horizontal Wells,"Wang, Shuhua; Chen, Zan; Chen, Shengnan",Applicability of deep neural networks on production forecasting in Bakken shale reservoirs,Production forecasting; Bakken formation; Deep neural networks; Hyperparameter optimization; Global sensitivity analysis,NEWTON OPTIMIZATION METHOD; TIGHT-OIL; GAS-PRODUCTION; MODEL; PREDICTION; DESIGN; STEAM,"The unconventional shale and tight formations, such as the Bakken in Williston Basin, are becoming an important hydrocarbon sources since the development of advanced horizontal drilling and multi-stage stimulation techniques. The appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery. Although reservoir simulations are commonly used for production analysis, the modeling of hydraulic fractures and intrinsic complexity of shale have restricted an understanding of the fluid flow behavior. Owing to the available of a large amount of data in unconventional tight and shale reservoirs, data-driven approaches, such as deep neural networks (DNNs), provide an alternative approach for production analysis in these formations. In this study, a total of 2919 wells including 2780 multi-stage hydraulic fractured horizontal wells and 139 vertical wells in Bakken Formation were collected and analyzed using a deep learning method and Sobol's global sensitivity analysis. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, and batch normalization were evaluated to develop a reliable deep neural network model. Moreover, k -fold cross validation was used to evaluate the prediction ability and robustness of models. Prior to the performance evaluation of DNN algorithms, an optimum DNN model was achieved by optimizing the dropout layer, activation function, and hyperparameters of DNN models. It is found that the number of hidden layers and neurons in each layer have significant effects on the performance of models. The optimized DNN model has 3 hidden layers and 200 neurons for each layer. The prediction performance of DNN models is acceptable with the low mean squared errors for both 6- and 18-months cumulative oil productions. Furthermore, the importance of each parameter was studied using the Sobol's analysis. Results show that the average proppant placed per stage is the most important parameter, which accounts for more than 35% of variability in both 6- and 18-months cumulative oil productions. These data-driven models can be readily updated when the new well information becomes available. It is worth mentioning that the proposed DNN models can be directly integrated into existing hydraulic fracturing design routines.",35,37,5
Fracture,Horizontal Wells,"Wang, Bo; Zhou, Fujian; Zou, Yushi; Liang, Tianbo; Wang, Daobing; Xue, Yanpeng; Gao, Liyang",Quantitative investigation of fracture interaction by evaluating fracture curvature during temporarily plugging staged fracturing,Temporarily plugging staged fracturing; XFEM-Based CZM; Plugging efficiency; Propagation path,HYDRAULIC-FRACTURE; NUMERICAL-SIMULATION; HORIZONTAL WELL; FINITE-ELEMENT; NATURAL FRACTURES; SHALE FORMATIONS; PROPAGATION; STIMULATION; MODEL,"Temporarily plugging staged fracturing (TPSF) technique has been successfully applied in unconventional reservoirs. This paper quantificationally investigates fracture interaction between previous and subsequent fractures during TPSF through numerical experiments. Using XFEM-based CZM (the cohesive zone model based on the extended finite element method), a 2D fully fluid-solid coupling model is established to perform the investigation. Typically, the concept of ""turning angle"" is proposed to quantify the degree of fracture interaction under different conditions. Moreover, the opening of the previously created fracture is simulated by truss model, which indicates truss elements distributed on the fracture surfaces; the effects of formation heterogeneity are investigated by changing rock mechanical properties surrounding the subsequent fractures. Simulation results reveal that the previously created and propped fracture will generate induced stresses, which cause the subsequent fracture to propagate with curvature. Factors influencing the subsequent fracture propagation curvature during TPSF, are sorted by sensitivity (strong to weak): plugging efficiency, Young's modulus, percent of initial aperture propped, fracture spacing, horizontal stress contrast, rock tensile strength, and formation permeability. The investigations provide a deep understanding of fracture interaction between previous and subsequent fractures during TPSF.",28,31,4
Fracture,Horizontal Wells,"Li, Tianjiao; Li, Lianchong; Tang, Chun'an; Zhang, Zilin; Li, Ming; Zhang, Liaoyuan; Li, Aishan",A coupled hydraulic-mechanical-damage geotechnical model for simulation of fracture propagation in geological media during hydraulic fracturing,HMD; Numerical simulation; Unsteady flow; Hydraulic fracturing; Stress shadow effect,FINITE-ELEMENT-METHOD; NUMERICAL MANIFOLD METHOD; FLUID-FLOW; CUBIC LAW; POROUS-MEDIA; ROCK; STRESS; DISCONTINUITY; COALESCENCE; CONTINUUM,"This paper proposed a coupled hydraulic-mechanical-damage (HMD) geotechnical model for simulating the entire failure process in geological media. In this model, elastic damage mechanics describes the damage process of elements. Darcy's Law and unsteady seepage flow equation describe fluid flow in elements, where compression of fluid and rock are considered. The coupled process is fulfilled by Biot's consolidation theory describing how pore-pressure affects the stress field and the stress/aperture/mesh-dependent permeability that represents the influence of stress on seepage field. The HMD model is implemented in the calculation module of Rock-Failure-Process-Analysis on Petroleum-problems (RFPA-Petrol) codes. The RFPA suite of software codes is based on the idea that the heterogeneity leads to non-linearity and causes progressive failure behavior observed in brittle rock. The capability of RFPA-Petrol simulator is demonstrated by a typical coupled problem related to double fractures propagation during hydraulic fracturing. This simulation successfully reproduces the asynchronous initiation, asymmetric growth and non-equal deflection of fractures in the numerical model. Then this simulator was used to investigate how fracture spacing and horizontal stress ratio influence propagation and reorientation of three hydraulic fractures from a horizontal well. At last, a horizontal well drilled by SHENGLI oilfield is simulated to certificate RFPA-Petrol's ability on field-scale models. It is found that larger fracture spacing and higher initial fracture height will form longer and wider fractured zones. HMD-based RFPA-Petrol is suitable for simulation of laboratory scale and field scale fracture propagation problems.",26,27,5
Fracture,Horizontal Wells,"Jiang, Changbao; Niu, Binwei; Yin, Guangzhi; Zhang, Dongming; Yu, Tang; Wang, Pei",CT-based 3D reconstruction of the geometry and propagation of hydraulic fracturing in shale,Shale; True triaxial testing; Hydraulic fracturing; CT scanning; 3D reconstruction; Fracture distribution,TIGHT,"Hydraulic fracturing is one of the primary techniques which has been widely implemented in order to allow for the stimulation of shale gas reservoirs. To accurately distinguish the extension characteristics and the spatial distribution of fractures during the hydraulic fracturing of the Longmaxi shale reservoirs in Changning, a self-developed, multifunctional, true triaxial experimental process (utilizing a fluid-solid coupling testing system) was used to simulate the horizontal well hydraulic fracturing. The CT technique was used to scan the samples prior to and following the conduction of the experiments; the CT scanning images of internal fractures were reconstructed and visualized via 3D reconstruction. The influence of in-situ stress, the displacement of the fracturing fluid upon the fracture morphology and the resultant fractural extensions caused by hydraulic fracturing were discussed. The study shows that the reconstructed 3D model based on the different CT values corresponding to the shale matrix, minerals and fractures can accurately characterize the internal structure and fracture distribution of shale. Shale hydraulic fracturing fractures can be divided into 3 categories: single transverse fractures, main arc fractures and complex fractures. The ""fluctuation phenomenon"" of a water pressure curve is related to the formation and extension of reservoir fractures, and is a discernible characteristic of complex fractures formed by the volume fracturing of shale. Stress differences and the stress difference coefficient are the governing factors in terms of the complexity of shale hydraulic fracturing networks. Displacement has a particular range of influence on the manifestation of fracture complexity; a low displacement may not result in a complete fracture, but too high a displacement tends to culminate a single fracture in the formation, which to a certain extent reduces fractural complexity.",26,27,4
Fracture,Horizontal Wells,"Vishkai, Mahta; Gates, Ian","On multistage hydraulic fracturing in tight gas reservoirs: Montney Formation, Alberta, Canada",Geomechanical model; Multistage hydraulic fracturing; Tight rock reservoirs; Montney formation,MODEL,"The combination of horizontal drilling and multistage hydraulic fracturing technology has unlocked production of petroleum from tight/shale rock. Prediction of single or multistage hydraulic fracturing treatments along horizontal wells in tight formations remains a challenge and thus optimization of these stimulation treatments is difficult. Currently, there are few effective approaches to characterize multistage hydraulic fracturing in tight rock reservoirs. In this paper, we use a three-dimensional tight rock simulator based on the Unconventional Fracture Model (UFM) to understand multistage hydraulic fracturing in the Montney Formation in Alberta, Canada. We use geological and geomechanical properties, stress magnitude and orientation, completion and production data to history match and characterize fracture volume and conductivity in the Montney Formation. Predictions of fractures from the history-matched reservoir model reveal the strong connection between the fracture conductivity and reservoir permeability, elastic rock properties as well as stresses distributions. The field example demonstrates how stress maps and rock properties calculated from density and gamma logs are integrated to yield predictive hydraulic fracturing capability. This study illustrates the critical role of reservoir permeability on fracture extent and conductivity. This workflow can be used to develop strategies for (1) refracturing of existing wells, (2) design and number of perforations, and (3) prediction of fracture propagation in later stages.",26,29,3
Fracture,Horizontal Wells,"Zhang, Ruxin; Hou, Bing; Han, Huifen; Fan, Meng; Chen, Mian",Experimental investigation on fracture morphology in laminated shale formation by hydraulic fracturing,Shale; Fracture propagation; Discontinuities; Fracturing energy; Horizontal stress difference,PROPAGATION BEHAVIOR; INITIATION; CRITERION,"A complex fracture network, which is the precondition of stimulated reservoir volume for shale formation, depends on the interaction between hydraulic fractures and discontinuities, such as bedding planes and natural fractures. However, the fracture propagation behavior in laminated shale formation still maintains ambiguous and the formation mechanism of complex fracture network has not been well understood. Therefore, hydraulic fracturing simulated experiments were conducted on shale outcrops to clarify above issues under the effects of multiple factors, such as horizontal stress difference, pump rate, and fluid viscosity. The results reveal that dilation and crossing are two main hydraulic fracture propagation behaviors because of discontinuities influencing, resulting in three categories of the ultimate fracture morphologies. Simple fracture is a single induced fracture. Complex fracture is consisted of two or more induced fractures which do not link up with each other. However, network fracture includes induced fractures which interweave with each other like a network. All the fracture geometries are generated under the mutual interaction of natural factors and engineering factors. A large horizontal stress difference and a high fracturing energy reduce the complexity of fracture geometry, whereas, a small horizontal stress difference and a low fracturing energy enhance the activated probability of discontinuities, resulting in a complex fracture network. Furthermore, weak cementing strength and large opening degree of discontinuities increase the complexity of the fracture. In addition, the fracturing curve reflects fracture morphology indirectly. Simple fracturing curve and steady extensive pressure indicate the simple fracture. The rising extensive pressure implies the complex fracture, whereas, the fluctuation of fracturing curve suggests the network fracture. In the meantime, each fracture morphology has its own dimensionless net pressure features, which could be applied to judge fracture morphology in shale formation.",24,26,8
Fracture,Horizontal Wells,"Cui, Ronghao; Feng, Qihong; Chen, Hongwei; Zhang, Wei; Wang, Sen",Multiscale random pore network modeling of oil-water two-phase slip flow in shale matrix,Pore network model; Shale oil; Two-phase flow; Slip effect; Computational fluid dynamics,FRACTURED HORIZONTAL WELL; FAST MASS-TRANSPORT; POROUS-MEDIA; RELATIVE PERMEABILITY; DYNAMIC PROPERTIES; CO2 SEQUESTRATION; ORGANIC-MATTER; GAS-FLOW; NANOPORES; RESERVOIR,"The large-scale hydraulic fracturing technology is commonly employed to significantly improve oil recovery in shale. An exceptional phenomenon from many field tests is worthy of attention that the majority of fracturing fluid (mainly water) does not return to the surface during hydraulic fracturing, but flows into shale matrix. As a consequence of this phenomenon, oil-water two-phase flow would happen. However, the fluid transportation in nano-pores is different from that of the conventional sandstone reservoirs. To understand oil-water two-phase flow in shale, an integrated pore network model (PNM) framework including network construction and flow simulation is developed. In the network construction, combined with a pore-size distribution (PSD) curve of shale system, a shale multiscale random pore network model is proposed, where organic pores and inorganic pores can be distinguished appropriately. In the flow simulation, considering that the traditional Hagen-Poiseuille equation may not be applicable in shale system, new bulk fluid and corner film flow models with slip length in various geometric pores (circular, square, equilateral triangle) are developed using the computational fluid dynamic (CFD) method. Through the quasi-static simulation technique, we estimate the flow properties in shale including capillary pressure and relative permeability. Simulation results confirm the slip effect would significantly affect oil-water two-phase flow in shale. And then, influences of shale pore structure on two-phase flow are further investigated. Through coupling network construction and two-phase flow simulation, we believe our work could shed light on the further research for multi-phase transportation in shale.",23,24,9
Fracture,Horizontal Wells,"Tang, Hewei; Sun, Zhuang; He, Youwei; Chai, Zhi; Hasan, A. Rashid; Killough, John",Investigating the pressure characteristics and production performance of liquid-loaded horizontal wells in unconventional gas reservoirs,Liquid loading; Horizontal well; Unconventional gas reservoir; Coupled wellbore-reservoir simulation; Natural cyclical production,WELLBORE-FLOW MODEL; 2-PHASE FLOW; TRANSIENT ANALYSIS; FRACTURE,"The increasing exploiting activities in unconventional gas reservoirs renew the interests of investigating liquid loading phenomenon, a common production issue for gas wells. Most previous studies focused on predicting the onset of liquid loading. The reservoir pressure characteristics and wellbore production performance after the onset of liquid loading have not been systematically investigated. This work introduces a newly developed fully implicitly coupled wellbore reservoir model to investigate the liquid loading effects on horizontal wells in low permeability gas reservoirs. The model honors the mass and momentum balances in both reservoir and wellbore systems, and thus allows us to analyze both wellbore and reservoir dynamics after the onset of liquid loading. The simulation results reveal that horizontal gas wells in low permeability reservoirs might experience natural cyclical production after the onset of liquid loading, which coincides with field observations. Both uniform stimulation and hydraulic fracturing help mitigate the cyclical production phenomenon. The near-wellbore reservoir pressure buildup and wellbore fluid reinjection are also evaluated. This work demonstrates the successful application of the coupled wellbore reservoir model in predicting the rich production phenomena of stimulated horizontal wells after the onset of liquid loading.",22,22,4
Fracture,Horizontal Wells,"Qin, Jiazheng; Cheng, Shiqing; Li, Peng; He, Youwei; Lu, Xin; Yu, Haiyang",Interference well-test model for vertical well with double-segment fracture in a multi-well system,Interference well-test analysis; Double-segment fracture; Fracture closure; Vertically fractured well; Multi-well system; Type curves,PRESSURE-TRANSIENT ANALYSIS; TIGHT OIL-RESERVOIRS; HORIZONTAL WELL; CONDUCTIVITY; PERMEABILITY; BEHAVIOR; FLOW,"Single well pressure transient analysis ignores the impact from adjacent wells, while well interference has obvious effect on the pressure response. Additionally, fracture conductivity and half-length may decrease severely, leading to non-uniform closure along fractures. The interpreted fracture half-length could be much shorter than designed half-length if this phenomenon is ignored. Besides, well interference caused by adjacent wells in multi-well system could be mistaken as boundary effect in single-well model since type curves of these two circumstances are quite similar to each other, which could bring about unrealistic results compared with geologic characteristics. Therefore, distinguishing interference effect from boundary effect while considering non-uniform fracture closure becomes a major challenge. This work proposes a new interference well-test model of vertical well with double-segment fractures (VWDSF). Each double-segment fracture (DSF) contains two fracture segments (FS) with individual length, rate and conductivity, etc. The new model allows the observation well and adjacent wells to produce at the same time, which does not influence production. Analytical solution is verified by comparing with numerical solution from Saphir, and model comparison is proposed to elaborate the significance of the novel model. New flow regimes including fracture interference flow, multi-well interference flow, interference-radial flow regime (IRFR) and system-radial flow can be observed on type curves. Furthermore, the influence of the observation well and adjacent wells on type curves are analyzed. Case study highlights the ability of the developed model in distinguishing the interference effect and boundary effect using the novel model. The proposed model provides a useful tool for addressing erroneous interpretation of pressure transient data due to non-uniform fracture closure and/or well interference.",21,23,2
Fracture,Horizontal Wells,"Guo, Xueli; Li, Jun; Liu, Gonghui; Xi, Yan; Zeng, Yijin; He, Miao; Yan, Hui",Numerical simulation of casing deformation during volume fracturing of horizontal shale gas wells,Casing deformation; Stage finite element model procedure; Volume fracturing; Fault slip; Transient temperature; Cement property,UNCONVENTIONAL RESOURCE EXPLOITATION; INTEGRITY IMPLICATIONS; FINITE-ELEMENT; OIL; EARTHQUAKES; MECHANICS; MODEL; LAW,"Casing deformation problems occur frequently during volume fracturing of shale gas wells. It is crucial to assess the casing deformation near heel (the beginning of the horizontal wellbore trajectory) where natural faults exist among 84.6% of the deformation positions in some shale plays. Based on the source mechanism, the fault slip distance was derived from microseismic inversion. Then, three-dimensional physical and finite element models were established using a stage finite element model procedure to investigate the influences of fault slippage on casing stress and displacement. Other factors such as pump rate, fracturing pressure, formation anisotropy, formation elastic modulus, cement sheath elastic modulus, casing size, and cement sheath thickness were taken into consideration. The results show that (1) fault slippage is an important mechanism of casing deformation near heel. The casing has a higher risk of deformation under the conditions of fault slippage combined with high external stress and internal pressure. (2) Under different slip distances, the casing Mises stress dramatically increases with an increase in the cement sheath and formation elastic moduli and the ratio of the casing diameter to the thickness D-out/t. (3) The high pump rate, high inner casing pressure, large formation anisotropy, and small cement sheath thickness can aggrandize casing stress. The calculated casing displacements using this model obtained good agreement when compared to the deformations of the actual wells. Countermeasures such as avoiding natural fault areas, using cement with an elastic modulus smaller than 10 GPa, using a higher grade and smaller diameter casing with a value of D-out/t smaller than 12.7 can be effective to prevent casing deformation during multi-fracturing operation.",21,21,2
Fracture,Horizontal Wells,"Ren, Long; Su, Yuliang; Zhan, Shiyuan; Meng, Fankun; Zhao, Guangyuan",Fully coupled fluid-solid numerical simulation of stimulated reservoir volume (SRV)-fractured horizontal well with multi-porosity media in tight oil reservoirs,Tight oil reservoir; SRV-fractured horizontal well; Multi-porosity media; Fully coupled fluid-solid; Numerical simulation,HYDROMECHANICAL PROCESSES; HYDRAULIC FRACTURE; MODEL; SYSTEM; FLOW,"A mutual coupling effect exists between the flow and stress fields in tight oil reservoir development. In terms of the characteristics of multi-porosity media (the matrix, natural fractures and network fractures) for stimulated reservoir volume (SRV)-fractured horizontal wells in tight oil reservoirs, considering the dual porosities of matrix and natural fractures, and based on the flowing feature of a discrete-fracture mode (DFM) fracture network stimulated system, a numerical simulation method based on fully coupled fluid-solid is introduced. According to the effective stress principle and regional flow characteristics, the fully coupled fluid-solid mathematical model considering the multi-porosity media characteristics of complex fracture networks is presented. The fully coupling numerical solution for the stress and flow fields is solved by the finite element method. The accuracy of this model is verified by comparing the finite differential model, non-coupled model and actual production data, respectively. And analyzing the computational time needed to solve the model under different solution methods and complexity levels. The variation of stress-strain and reservoir physical property parameters is revealed. For the non-coupled and fully coupled model, the productivity and formation pressure differences are compared and analysed. The results show that when considering the stress field, the initial production rate of an SRV-fractured horizontal well is large but declines quickly, and it has fundamentally different characteristics from the traditional flow model. Our research provides theoretical and technical guidance for the efficient development of unconventional resources.",20,23,1
Fracture,Horizontal Wells,"Zhao, Jinzhou; Wang, Qiang; Hu, Yongquan; Ren, Lan; Zhao, Chaoneng",Numerical investigation of shut-in time on stress evolution and tight oil production,Energy accumulation; Shut-in; Stress evolution; Optimum shut-in time; Geomechanics/fluid flow,SHALE-GAS-PRODUCTION; RESERVOIR; FLOW; GEOMECHANICS; SIMULATION; PRESSURE; FRACTURE; LEAKOFF; BASIN,"Among investigations on the mechanics of energy accumulation via well shut-in to increase oil production, reservoir imbibition is deemed effective. However, another element, i.e., the coupling effect of fluid flow and geomechanics has always been underrated in production. Hence, this is discussed herein based on seepage mechanics, elastic mechanics, and Biot pore elastic theory. Further, an integral mechanical coupling numerical model is established from staged fracturing on a horizontal well to analyze well shut-in and production, to simulate stress variation during the shut-in period and the impact of shut-in time on oil production. The model considers the coupling effect of oil and water flow, and geomechanics on the stress distribution of reservoir adjacent to hydraulic cracks during fracturing, well shut-in, and production. From the study of reservoir stress and physical parameters in different shut-down times, it is found that reservoir stress and physical parameters demonstrate some regular changes. The pore pressure and saturation demonstrate pressure diffusion and oil phase saturation recovery with increasing well shut-in time. Owing to pressure diffusion, horizontal maximum principal stress, and horizontal minimum principal stress, the shear stress and stress difference demonstrate high complexity. Meanwhile, permeability and porosity exhibit a complex distribution subject to effective stress; the characteristic parameters of reservoir rock based on construction parameters (total injection volume, injection rate, and shut-in time) affect the subsequent production considerably. The correlation curves drawn upon a simulated experiment that reflect the construction parameters against cumulative oil production indicate that cumulative oil production is in direct proportion to shut-in time and in reverse proportion to injection rate. The optimum shut-in time is correlated positively with both the total injection volume and injection rate.",19,19,5
Fracture,Horizontal Wells,"Wu, Yonghui; Cheng, Linsong; Huang, Shijun; Fang, Sidong; Jia, Pin; Rao, Xiang",An analytical model for analyzing the impact of fracturing fluid-induced formation damage on rate transient behavior in tight formations,Water blockage; Rate transient behavior; Tight formation; Analytical model; Multi-fractured horizontal well,HORIZONTAL WELLS; SHALE GAS; SEMIANALYTICAL MODEL; RESERVOIRS; FLOW; PERFORMANCE; SIMULATION; MECHANISMS; DENSITY; CLEANUP,"An enormous amount of fracturing fluid is irreducible in the tight formation after hydraulic fracturing stimulation. This will cause serious damage to the fracture face as well as the matrix close to the hydraulic fractures by invading into the matrix. Modeling the effect of water blockage on rate transient behavior is significant in reservoir engineering. This paper presents a modified trilinear model to analyze the rate transient behavior after flowback period. Single-phase flow is assumed in this stage because most injected water is hard to be reduced. For damage to the matrix caused by rock-fluid interaction, clay swelling, and polymer adsorption, a fracturing fluid invasion layer is added to the model between hydraulic fractures and the inner stimulated reservoir volume to capture this kind of damage. A skin factor is used to capture the damage to the matrix-fracture face caused by gel filter cake formation and polymer adsorption. The analytical model is benchmarked using the commercial numerical simulator Eclipse. Several synthetic cases and a field case are studied, the results show that water blockage has a great impact on the productivity of the well and decline curves. The effect of choking effect, convergence flow, and gel filter cake could be incorporated using a skin factor in the model. In addition, two more flow regimes could be observed on the theoretical type curve if the well is affected by water blockage, and the two flow regimes would happen before linear flow dominated by the inner stimulated zone. Besides, the duration of the inner zone linear flow regime could be shortened if the permeability of the fracturing fluid invasion layer is lower and invasion depth is larger. These phenomena can be used in matching the field production data from water blockage affected wells, which exhibit a transition flow regime before the formation linear flow regime. This transition flow regime could be matched quite better using the proposed model than the classical trilinear flow model. The reason is that the linear flow regime could be much longer if the water blockage effect is not considered in the model. On the other hand, the skin factor has a different impact on the flow regimes, so the water blockage effect could be characterized properly only by adding a skin factor to the model. The main contribution of this paper is the provision of an analytical model for evaluating the formation damage caused by irreducible fracturing fluid, analyzing production data and making forecasts.",18,19,6
Fracture,Horizontal Wells,"Wang, Deqiang; Cheng, Linsong; Cao, Renyi; Jia, Pin; Fang, Sidong; Rao, Xiang; Wu, Yonghui; Dai, Dan",The effects of the boundary layer and fracture networks on the water huff-n-puff process of tight oil reservoirs,Tight reservoir; Water huff-n-puff; Volume fracture; Boundary layer; Embedded discrete fracture model,PERMEABILITY STRESS SENSITIVITY; HORIZONTAL WELLS; RELATIVE PERMEABILITY; SEMIANALYTICAL MODEL; FLOW BEHAVIOR; SHALE; PERFORMANCE; SIMULATION; SCALE,"Application of multi-fractured horizontal wells has led to significant progress in the development of tight oil reservoirs. However, oil production rapidly decreases and the estimated ultimate recovery is still low when the well is in production and approaching depletion. Water huff-n-puff is regarded as a useful measure to improve oil recovery due to oil-water imbibition and drainage. Additionally, complex fracture networks consisting of natural fractures (NF) and hydraulic fractures can significantly enhance oil recovery in the process of water huff-n-puff after multi-stage hydraulic fracturing. However, there is a non-flowing thin film on the solid-liquid wall surface in the pore-throats of the matrix, and the so-called boundary layer effect (BLE) is quite significant at the nanoscale. This effect reduces the effective flow space and effective permeability of the reservoir, leading to production damage. To date, few numerical simulation studies have considered the impact of the BLE and complex fracture networks in water huff-n-puff process simulation studies. In this study, the process of water huff-n-puff is evaluated considering complex fracture networks and formation damage in a matrix. The embedded discrete fracture model (EDMF), validated by local grid refinement (LGR), is applied to describe the distribution of hydraulic fractures and NF. The well performance considering the BLE is analyzed by a vectorization programming. The results show that the BLE reduces production and accelerates the production decline, so the BLE should be considered in reservoir simulations and productivity evaluations of water huff-n-puff processes. A certain degree of natural fracture development is conducive to improving the sweep efficiency of the water huff-n-puff, which could significantly improve oil recovery compared to depletion. By considering the impact of the BLE in water huff-n-puff simulations in tight oil reservoirs, it is possible to accurately evaluate the well performance and provide a theoretical basis for the optimization of water huff-n-puff.",17,16,5
Fracture,Horizontal Wells,"Wei, Shiming; Xia, Yang; Jin, Yan; Chen, Mian; Chen, Kangping",Quantitative study in shale gas behaviors using a coupled triple-continuum and discrete fracture model,Shale gas; Hydraulic fracture network; Non-equilibrium desorption/adsorption mechanism; Gas behavior,HORIZONTAL WELLS; PRACTICAL METHOD; TIGHT OIL; FLOW; RESERVOIR; SIMULATION; FLUID; DIFFUSION; TRANSPORT; FRAMEWORK,"The shale has ultra-low permeability wherein multi-scale natural fractures are well-developed. The success of providing high diversion channels makes multi-stage fractured horizontal wells (MFHWs) become the powerful technique for economically producing gas from shale. This study presents a triple-continuum and discrete fracture model to describe a fractured shale reservoir embedded with a MFHW. The model incorporates non-equilibrium desorption/adsorption mechanism (NEDAM), viscous flow, Knudsen diffusion, and surface diffusion. The discrete fracture networks (DFNs) is quantitatively constructed according to the fracture density and stimulated reservoir area (SRA). This model is used to analyze the temporal/spatial evolution of the gas pressure and the net desorption rate. NEDAM is compared with the conventional equilibrium desorption mechanism (EDM) and its found that NEDAM uncovers the delayed phenomenon during gas desorption, and the use of EDM overestimates the production contributed from the adsorbed gas. The maximum net desorption rate of adsorbed gas gradually spread from the SRA region to the nonSRA region. The complete flow stages are clearly interpreted in a semi-logarithmic curve of well testing, and the flow stage controlled by the hydraulic fractures is clearly presented. Finally, the instructions on hydraulic fracturing treatment are given based on the production analysis.",17,18,2
Fracture,Horizontal Wells,"Lyu, Shuaifeng; Wang, Shengwei; Chen, Xiaojun; Shah, S. M.; Li, Rui; Xiao, Yuhang; Dong, Qingxiang; Gu, Yuanyuan",Experimental study of a degradable polymer drilling fluid system for coalbed methane well,Degradable polymer drilling fluid; Bio-enzymes; Permeability recovery; Polymer removal; Coal cuttings carrying; South Qinshui Basin,WATER; NANOPARTICLES; PERFORMANCE; PRESSURE; BENTONITE; SEAM,"Drilling along the coal seam is an effective way to improve gas recovery. Due to complex coal body structure and natural fractures, there are many difficulties, including a low abilities of cutting carrying, leakage while crossing the fracture zone and reservoir damage. In this work, a low density degradable polymer drilling fluid system is developed to solve these difficulties to enhance coalbed methane (CBM) production. In the laboratory, the properties of the polymer drilling fluid were evaluated using the coal cuttings suspension experiment, borehole stability simulation test, viscosity attenuation method, laser particle size analysis, polymer removal and core permeability recovery method. The experimental result indicates that the developed drilling fluid has good rheology and filtration, a high yield point and a strong inhibition, thereby meeting conventional drilling requirements and carrying coal cuttings effectively. Under the bio-enzymes, the viscosity of degradable drilling fluid can be initially reduced to 16%. The optimum temperature and pH for the enzyme activity is obtained, and enzymes with small weight fraction of 0.01% can dramatically alter rheological properties of drilling fluid and thereby the high biological activity. After degradation, the particle size in drilling fluid decreases greatly. During immersion test, the polymer film on the surface of the lump coal and thin sections is almost removed by enzyme solution. The reservoir's permeability damage rate may be reduced from 50% to 25% via the functionality of the enzymes, and it is noticeable that the relationships between effective stress and gas permeability treated by the drilling fluid and enzyme still obey the exponential function. Field applications show that the drilling fluid has a good coal fines resistance and compatibility with conventional plugging materials, which ensures the long horizontal footage of 901 m with the short construction period. The later decreased viscosity of the drilling fluid by the enzymes is conducive to reduce the damage to the coal reservoirs.",16,16,7
Fracture,Horizontal Wells,Liu Lijun; Yao Jun; Sun Hai; Huang Zhaoqin; Yan Xia; Li Longlong,Compositional modeling of shale condensate gas flow with multiple transport mechanisms,Shale; Condensate gas; Compositional model; Transport mechanism; Phase behavior,HYDROCARBONS RECOVERY; SCALE SIMULATION; RESERVOIRS; PERMEABILITY; FLUID; MICRO,"Shale condensate gas has gained great attention in recent years due to the production of profitable liquid hydrocarbons. The fluid flow in shale matrix is complex and influenced by multiple transport mechanisms, such as stress sensitivity, Knudsen diffusion, adsorption, molecular diffusion, and confined phase behavior. In addition, the coexistence of multiscale pore space, including hydraulic fractures, micro-fractures in simulated reservoir volume (SRV) and nanopores in matrix further increases the fluid flow complexity. Conventional models cannot commonly consider all the factors. In this work, we develop a hybrid model for condensate gas reservoir, where fluid flow is described by compositional model coupled with transport mechanisms, micro-fractures and hydraulic fractures are handled by multiple interacting continua (MINC) model and embedded discretized fracture model (EDFM). Then based on the proposed model, the effects of gas transport mechanisms on a multi-stage fractured horizontal well production are analyzed, where simulations are conducted with and without SRV to investigate the importance of SRV. Furthermore, some important reservoir parameters, such as SRV properties, hydraulic fracture length and bottom-hole pressure are also investigated with the proposed model.",16,17,4
Fracture,Horizontal Wells,"Yan, Xiaopeng; Kang, Yili; You, Lijun; Xu, Chengyuan; Lin, Chong; Zhang, Jingyi","Drill-in fluid loss mechanisms in brittle gas shale: A case study in the Longmaxi Formation, Sichuan Basin, China",Brittle gas shale; Drill-in fluid loss; Plugging zone stability; Dynamic fracture width; Case study,CIRCULATION; DAMAGE; COEFFICIENT; STABILITY; IMPACT; WELLS,"Brittle gas shale consists of a high content of brittle mineral and developed natural fractures and has become the focus of petroleum industry in recent years. Lost circulation may easily occur due to the long soaking time and an overbalanced pressure difference during the drill-in process of the horizontal long section. The dynamic fracture width simulation induced by drill-in fluid invasion, plugging zone pressure containment test, friction coefficient test between lost circulation materials and shale surface, oil based drill-in fluid filtrate immersion test were conducted to investigate the drill-in fluid loss mechanisms in the brittle Longmaxi Shale in the Sichuan Basin of China. Results show that the fracture width at the fracture mouth increased from 2 mu m to 239 mu m for the two mutually perpendicular fractures connecting to the wellbore due to drill-in fluid invasion. Effective plugging for dynamic fractures was failed to be achieved for the original drill-in fluid. Fracture width increase induced by drill-in fluid invasion is the major cause of plugging failure of brittle gas shale. Instability of the brittle shale induced by oil phase lubrication and high pH drill-in fluid erosion further exacerbates lost circulation problems. Optimized LCMs considering the dynamic apertures of fractures should be selected and added into drill-in fluid to rapidly seal pre-exiting fractures and induced fractures for lost circulation control in brittle shale. The results serve as a guide for the drill-in fluid design of shale gas in brittle gas shale formation.",16,19,3
Fracture,Horizontal Wells,"Jia, Pin; Cheng, Linsong; Huang, Shijun; Xue, Yongchao; Clarkson, Christopher R.; Williams-Kovacs, Jesse D.; Wang, Suran; Wang, Deqiang",Dynamic coupling of analytical linear flow solution and numerical fracture model for simulating early-time flowback of fractured tight oil wells (planar fracture and complex fracture network),Linear flow; Flowback; Flow regimes; Tight oil reservoir,MULTIFRACTURED HORIZONTAL WELLS; 2-PHASE FLOWBACK; SEMIANALYTICAL MODEL; SECONDARY FRACTURES; HYDRAULIC FRACTURE; TRANSIENT-BEHAVIOR; GAS; SYSTEM,"Quantitative analysis of flowback data provides an early opportunity to interpret hydraulic fracture properties of fractured wells in unconventional reservoirs. In recent years, a number of studies have been dedicated to the analysis of single-phase flow data prior to hydrocarbon breakthrough and multi-phase flow data after hydrocarbon breakthrough during flowback. This study provides a new model to simulate flowback of fractured tight oil wells with planar fractures or a complex fracture network. In the model, fractures are discretized into a number of segments and the fully numerical method is used to model fracture flow. It is assumed that the pressure interference in the matrix caused by these fracture segments can be accounted using a no-flow boundary condition and that the drainage volumes of fracture segments form isolated regions to allow for linear flow from the matrix to each segment. To model this behavior, matrix flow is simulated using the analytical transient linear flow solution which is dynamically coupled with the fracture flow model by imposing continuity of pressure and flux on the fracture surfaces. The model is simple, but rigorous enough to take into account the important physics of the fracture system, including arbitrary fracture geometries and fracture conductivity distributions. The pressure and saturation gradients of each phase in fractures are accounted for. The ease of model setup and improved computational performance makes it convenient for practical application. The new model is verified with a commercial reservoir simulator. Investigation of the assumption of no-flow boundary condition for the pressure interference in the matrix caused by the fracture segments reveals that the assumption becomes poorer with increasing matrix permeability and decreasing fracture permeability. Flow regime analysis demonstrates that, for planar fractures, water exhibits an early transient linear flow period (first linear flow in the fracture) followed by boundary-dominated flow (first boundary-dominated flow in the fracture) prior to hydrocarbon breakthrough, after which a second transient linear flow in the fracture develops. The final flow period is boundary-dominated flow (second boundary-dominated flow in the fracture), indicating the end time of the flowback period. At this stage, oil will be the dominant phase in the fracture, and will exhibit transient linear flow in the matrix, which is the first flow-regime typically observed during the long-term production period. The case of a complex fracture network exhibits a similar sequence of flow regimes. The second transient linear flow for this case has not been discussed in the literature. The development of this flow period may be caused by the maintenance of fracture pressure, and decrease of water relative permeability due to hydrocarbon contribution from the matrix. A field example from western Canada exhibits the flow regimes noted above and is history-matched successfully using the new model. The results demonstrate the practical application of the new model for deriving reservoir/fracture properties from flowback data and for forecasting.",15,15,3
Fracture,Horizontal Wells,"Wu, Yonghui; Cheng, Linsong; Huang, Shijun; Bai, Yuhu; Jia, Pin; Wang, Suran; Xu, Bingxiang; Chen, Ling",An approximate semianalytical method for two-phase flow analysis of liquid-rich shale gas and tight light-oil wells,Two-phase; Multistage fractured horizontal well; Liquid-rich shale gas; Tight oil; Semianalytical method,FRACTURED HORIZONTAL WELLS; INTEGRATED WORKFLOW; CURVES,"Two-phase flow of oil and gas is quite common in the reservoir during the depletion of liquid-rich shale gas and tight light-oil. Many analytical models proposed for multistage fractured horizontal wells completed in unconventional reservoirs are restricted to single phase flow problem. In this paper, an approximate semianalytical method is proposed to handle the complexities of phase change, pressure dependent PVT properties, two-phase flow behavior and complex fracture networks. The black oil model is used to model phase change and two-phase flow of oil and gas. The secondary fractures in the stimulated reservoir volume and the reservoir beyond the main fractures are considered in the physical model to make long-term production forecasts. The forecasted producing GOR is used to decrease the equations of the two-phase flow model, so only the flow equations of primary phase are used to develop the mathematic model. Then an approximate method is used to linearize the model and the analytical solution is obtained in Laplace space for constant pressure inner boundary problem. The Duhamel's principle is applied to correct the production rate under variable flowing pressure inner boundary, and a procedure is proposed for history matching of field production data and making forecasts. Finally, the semianalytical model is validated with two simulation examples, the average relative error is shown to be less than 10%. After that, two field examples are used to show its utility.",15,16,0
Fracture,Horizontal Wells,"Tian, Jian; Kang, Yili; Luo, Pingya; You, Lijun; Zhang, Dujie",A new method of water phase trapping damage evaluation on tight oil reservoirs,Tight oil reservoirs; Water saturation; Water phase trapping; Back pressure; New method; Experimental evaluation,PERMEABILITY GAS-RESERVOIRS; FRACTURED HORIZONTAL WELLS; FINES-MIGRATION; BLOCKING; MODEL; IMBIBITION; RESOURCES; PRESSURE; FLOW,"Displacement pressure difference and initial water saturation are two key factors of evaluating water phase trapping (WPT) damage under a given reservoir situation. Requiring a high displacement pressure to drive liquid through a tight rock, the conventional method has difficulty in measuring very small liquid flow rates. Besides, it exists a strongly advantageous flow path selectivity phenomenon, causing a situation that the water existing in those thinner pores cannot be moved effectively. As a result, the irreducible water saturation is high after oil displacing water, thus leading to an overestimated oil permeability damage from WPT. This paper would have presented a high back pressure displacement method (HBPD) for the establishment of initial water saturation and measurement of liquid permeability of core samples from tight oil reservoirs. Then the damage of WPT using this new method was compared with the results obtained by the conventional method. According to the reservoir fluid flow situation, pore pressure and downstream pressure were simulated by the operation of back pressure. Results showed that an average initial water saturation (S-wi) of 46.2% was established by the conventional method. However, the S-wi established with the use of this new method was only 29.9%, which was consistent with the results from sealed core data of the reservoir. The oil permeability damage derived from water phase trapping was estimated as an average of 37.0% with the conventional method while that of 21.8% by the new method respectively. The conventional method overestimated the damage of water phase trapping at 41.4%. Our research appears to have an insight into analyzing oil-water flow behaviors and investigating the reservoir forming process of tight oil reservoirs.",14,15,0
Fracture,Horizontal Wells,"Wang, Fei; Li, Baoman; Chen, Qiaoyun; Zhang, Shicheng",Simulation of proppant distribution in hydraulically fractured shale network during shut-in periods,Shale; Fracture network; Proppant transport; Well shut-in; Proppant-carrying fluid flow,NUMERICAL-SIMULATION; TRANSPORT,"Proppant distribution is an important topic, because it is closely related to the success or failure of hydraulic fracturing treatment. Although, many proppant transport models have been published, there is still relatively limited research on proppant distribution between the created fracture network in shale especially during the post-treatment shut-in periods. In this paper, based on the intercoupling of particle hydrodynamics, fluid hydrodynamics, and poro-elastic rock mechanics, a mathematical model regarding the transport of liquid-solid phases has been established to simulate the behavior of the proppant transport and the carrying fluid migration in the fractured shale network during the well shut-in. The coupled model takes main hydraulic fractures, secondary induced fractures and matrix into account, namely a three-dimensional triple-porosity medium. All the important processes in fractured shale network can be explained by the liquid-solid transport simulation with the coupled model, including (1) liquid transport driven by viscous and gravity forces, (2)proppant particle transport driven by the horizontal forces of drag, inertia and collision, and the vertical gravity and buoyancy, and (3) hydraulic-fracture closure, which is considered as a poro-elastic rock deformation during the shut-in periods. Based on the conservation of mass and momentum, the liquid-solid transport coupled with rock deformation, are described by a set of partial differential equations, which are solved by the semi-implicit finite-difference method. The evolution of the proppant concentration and fluid pressure profiles is calculated. The fluxes of the proppant and proppant-carrying fluids between the main fracture and secondary fracture during the post-stimulation well shut-in are also calculated. The influences of proppant properties (concentration, density and size) and proppant-carrying fluid properties (viscosity and density) on the proppant distribution are investigated. The results of this study are expected to provide a better understanding of the proppant and proppant-carrying fluid distribution for different physical properties of proppant and carrying fluids, and explain which is the predominant factor influencing the proppant distribution during the shut-in periods.",13,13,7
Fracture,Shale Gas,"Li, Hu; Tang, Hongming; Qin, Qirong; Zhou, Jiling; Qin, Zhangjin; Fan, Cunhui; Su, Peidong; Wang, Qin; Zhong, Cheng","Characteristics, formation periods and genetic mechanisms of tectonic fractures in the tight gas sandstones reservoir: A case study of Xujiahe Formation in YB area, Sichuan Basin, China",Tight gas sandstone; Tectonic fractures; Characteristics; Formation periods; Xujiahe formation; YB area Sichuan; Basin,PERMIAN LUCAOGOU FORMATION; SLIP-FAULT ZONE; QUANTITATIVE PREDICTION; STRESS-FIELD; ORDOS BASIN; ACOUSTIC-EMISSION; JUNGGAR BASIN; ZHENJING AREA; SHALE; ROCK,"The main target for hydrocarbon exploration of terrestrial strata in Sichuan Basin is the tight gas sandstone reservoir of the Upper Triassic Xujiahe Formation. Xujiahe Formation in YB area is a major discovery of hydrocarbon exploration in recent years, which is characterized as tight with ultralow porosity, ultralow permeability, and intensive heterogeneity. The tectonic fractures have important influence on accumulation and productivity of gas in the area. In the paper, analysis data of outcrop, core, imaging logging and other experiments were used to determine the characteristics, formation periods and genetic mechanisms of tectonic fractures. There are mainly high-angle and low-angle shear fractures in the area, which caused by tectonic stress. The length of the fractures is mainly 0-4 m from the outcrop and 10-20 cm from the cores and fracture frequencies (number per meter) is mostly 2-7 m(-1), 2-4 m(-1) respectively. The fracture fillings are mainly calcite, argillaceous and carbonaceous, about 60% of the fractures is unfilled or incompletely filled. Without considering the diagenetic fractures, there are three periods of the fractures: the middle-late Yanshanian tectonic movement, the early-middle Himalaya tectonic movement and the late Himalaya tectonic movement. The first period of the fractures are mainly filled with fine calcite, homogenization temperature of inclusion is 75-85 degrees C and the maximum effective principal stress of paleostress is 71.64 Mpa. The second period of the fractures are half-filled (or unfilled) with coarse calcite, homogenization temperature of inclusion is 150-175 degrees C and the maximum effective principal stress of paleostress is 74.91 Mpa. The third period of the fractures are low filling degree and cuts formed fractures clearly, the maximum effective principal stress of paleostress is 86.52 Mpa. For these tectonic movement, there are four sets of the plane ""X"" shear fractures in the area: NE strike fractures, NW strike fractures, NEE strike fractures, S-N strike fractures. There are one set of the profile shear fractures of NWW strike. Finally, the complex fault system of nearly N-S, NW and NE strike are formed in YB area.",31,32,8
Fracture,Shale Gas,"Zhang, Yixiang; He, Jianming; Li, Xiao; Lin, Chong",Experimental study on the supercritical CO2 fracturing of shale considering anisotropic effects,Hydraulic fracturing; Shale; Supercritical CO2; Anisotropic characteristic,FLUID VISCOSITY; CARBON-DIOXIDE; GAS; OIL; WATER; INJECTION,"Hydraulic fracturing using freshwater as fracturing fluid is regularly employed in commercial shale gas or oil production. Many problems are brought by the fracturing fluid of water, such as water shortages, swelling of clay mineral, and the pollution of flow-back water. Replacement of water by supercritical CO2 (SC-CO2) in the hydraulic fracturing treatment of shale reservoir has meaningful potential for the improvement of gas production. Hydraulic fracturing experiments, under different injection rate and stress state, were carried out for studying the SC-CO2 fracturing of shale considering anisotropy effects. Anisotropy of shale has a significant impact on the mechanical behavior and fracture propagation of shale in the experiment. There shows a downward tendency for breakdown pressure with the increase of bedding plane angle in general. Higher injection rate can lead to the higher breakdown pressure, while higher deviator stress can lead to the lower breakdown pressure instead. In addition, three patterns of fracture propagation can be observed in the experiment, relative to the bedding structures of shale specimen, including propagating along, propagating across and arresting. The maximum values of fracture width during experiment in shale with different bedding plane angle ranges from 0.29 mm to 1.05 mm, while the final fracture width after the fracturing experiment is kept within the range of 0.01 mm-0.04 mm under the injection rate of 0.3 ml/s.",28,28,6
Fracture,Shale Gas,"Jiang, Changbao; Niu, Binwei; Yin, Guangzhi; Zhang, Dongming; Yu, Tang; Wang, Pei",CT-based 3D reconstruction of the geometry and propagation of hydraulic fracturing in shale,Shale; True triaxial testing; Hydraulic fracturing; CT scanning; 3D reconstruction; Fracture distribution,TIGHT,"Hydraulic fracturing is one of the primary techniques which has been widely implemented in order to allow for the stimulation of shale gas reservoirs. To accurately distinguish the extension characteristics and the spatial distribution of fractures during the hydraulic fracturing of the Longmaxi shale reservoirs in Changning, a self-developed, multifunctional, true triaxial experimental process (utilizing a fluid-solid coupling testing system) was used to simulate the horizontal well hydraulic fracturing. The CT technique was used to scan the samples prior to and following the conduction of the experiments; the CT scanning images of internal fractures were reconstructed and visualized via 3D reconstruction. The influence of in-situ stress, the displacement of the fracturing fluid upon the fracture morphology and the resultant fractural extensions caused by hydraulic fracturing were discussed. The study shows that the reconstructed 3D model based on the different CT values corresponding to the shale matrix, minerals and fractures can accurately characterize the internal structure and fracture distribution of shale. Shale hydraulic fracturing fractures can be divided into 3 categories: single transverse fractures, main arc fractures and complex fractures. The ""fluctuation phenomenon"" of a water pressure curve is related to the formation and extension of reservoir fractures, and is a discernible characteristic of complex fractures formed by the volume fracturing of shale. Stress differences and the stress difference coefficient are the governing factors in terms of the complexity of shale hydraulic fracturing networks. Displacement has a particular range of influence on the manifestation of fracture complexity; a low displacement may not result in a complete fracture, but too high a displacement tends to culminate a single fracture in the formation, which to a certain extent reduces fractural complexity.",26,27,4
Fracture,Shale Gas,"Heng, Shuai; Liu, Xiao; Li, Xianzhong; Zhang, Xiaodong; Yang, Chunhe",Experimental and numerical study on the non-planar propagation of hydraulic fractures in shale,Shale; Bedding plane; Hydraulic fracturing; Non-planar propagation; Fracture network,ROCK FAILURE; BEHAVIOR; STRESS; GROWTH; DISCONTINUITIES; INITIATION; INTERFACE,"To better understand the non-planar propagation and geometry of fracture networks, hydraulic fracturing simulation tests on shale specimens were conducted using an established true triaxial hydraulic fracturing simulation test system. A two-dimensional numerical model of hydraulic fracturing was developed to clarify the evolution of hydraulic fractures and their non-planar behaviour at bedding planes. The numerical model with the alternating rock matrix and bedding planes considered the coupling effect of stress, fluid flow, and damage. The mechanisms by which hydraulic fractures penetrate or become arrested/deflected at bedding planes were then revealed as per the physical and numerical simulation results. The results revealed that the typical severe fluctuation of the injection pressure, which is closely related to the growth of sub-fractures along bedding planes or natural fractures, is a clear characteristic of the non-planar propagation of hydraulic fractures. The mechanical properties of the bedding primarily determine whether a hydraulic fracture penetrates or is deflected at the bedding. Strong beddings favour hydraulic fracture penetration; whereas, weak beddings favour hydraulic fracture deflection along the beddings. The hydraulic fractures typically extend along the path of least resistance, and therefore, induce the non-planar propagation behaviour at bedding planes. Tensile failure is a major fracture mechanism of the hydraulic fractures that penetrate or deviate at bedding planes. The experimental and numerical findings provide a basis for the optimum design of hydraulic fracturing and control of the fracture growth geometry in shale gas reservoirs.",25,25,13
Fracture,Shale Gas,"Chen, Hao; Hu, Yi; Kang, Yong; Cai, Can; Liu, Jiawei; Liu, Yiwei",Fracture initiation and propagation under different perforation orientation angles in supercritical CO2 fracturing,SC-CO2 fracturing; Perforation angle; Breakdown pressure; Fracture initiation and propagation; Fracture geometry,KRISHNA-GODAVARI BASIN; IN-SITU STRESS; CARBON-DIOXIDE; ACOUSTIC-EMISSION; PORE PRESSURE; SHALE GAS; WATER; RESERVOIR; FLUIDS; JET,"Supercritical carbon dioxide (SC-CO2) fracturing has attracted considerable attention on exploiting shale gas and tight gas. This study investigated the influence of the perforation orientation on fracture initiation and propagation induced by SC-CO2 fracturing through a series of laboratory fracturing experiments under tri-axial stress states and water was also used as a fracturing fluid to compare with SC-CO2. It was found that breakdown pressure increases with the increase of perforation angle according to the pressure curves in SC-CO2 fracturing and hydraulic fracturing. AE energy characteristic has shown that AE energy release rate of SC-CO2 fracturing is larger than that of hydraulic fracturing, indicating that fractures induced by SC-CO2 fracturing are more complex. Fracture geometry and energy surges verified that there were more fractures induced by SC-CO2 fracturing with increase of the perforation orientation angle. It was observed that hydraulic fracturing mainly induced a biwing fracture while SC-CO2 fracturing induced bi-wing and tri-wing fracture. At low perforation angle (alpha <= 45 degrees), perforation orientation has little influence on fracture propagation direction and fracture extends along the direction of the maximum principle direction in SC-CO2 fracturing. At high perforation angle (alpha <= 60 degrees), fracture propagation shows an independence of loading stress, fractures may extend in three directions. The findings are beneficial for further understanding the mechanism of SC-CO2 fracturing and optimizing perforation parameters in SC-CO2 field fracturing.",21,22,8
Fracture,Shale Gas,"Guo, Xueli; Li, Jun; Liu, Gonghui; Xi, Yan; Zeng, Yijin; He, Miao; Yan, Hui",Numerical simulation of casing deformation during volume fracturing of horizontal shale gas wells,Casing deformation; Stage finite element model procedure; Volume fracturing; Fault slip; Transient temperature; Cement property,UNCONVENTIONAL RESOURCE EXPLOITATION; INTEGRITY IMPLICATIONS; FINITE-ELEMENT; OIL; EARTHQUAKES; MECHANICS; MODEL; LAW,"Casing deformation problems occur frequently during volume fracturing of shale gas wells. It is crucial to assess the casing deformation near heel (the beginning of the horizontal wellbore trajectory) where natural faults exist among 84.6% of the deformation positions in some shale plays. Based on the source mechanism, the fault slip distance was derived from microseismic inversion. Then, three-dimensional physical and finite element models were established using a stage finite element model procedure to investigate the influences of fault slippage on casing stress and displacement. Other factors such as pump rate, fracturing pressure, formation anisotropy, formation elastic modulus, cement sheath elastic modulus, casing size, and cement sheath thickness were taken into consideration. The results show that (1) fault slippage is an important mechanism of casing deformation near heel. The casing has a higher risk of deformation under the conditions of fault slippage combined with high external stress and internal pressure. (2) Under different slip distances, the casing Mises stress dramatically increases with an increase in the cement sheath and formation elastic moduli and the ratio of the casing diameter to the thickness D-out/t. (3) The high pump rate, high inner casing pressure, large formation anisotropy, and small cement sheath thickness can aggrandize casing stress. The calculated casing displacements using this model obtained good agreement when compared to the deformations of the actual wells. Countermeasures such as avoiding natural fault areas, using cement with an elastic modulus smaller than 10 GPa, using a higher grade and smaller diameter casing with a value of D-out/t smaller than 12.7 can be effective to prevent casing deformation during multi-fracturing operation.",21,21,2
Fracture,Shale Gas,"Zhang, Kun; Song, Yan; Jia, Chengzao; Jiang, Zhenxue; Jiang, Shu; Huang, Yizhou; Wen, Ming; Liu, Xiaoxue; Liu, Weiwei; Chen, Zhiyuan; Xie, Xuelian; Liu, Tianlin; Wang, Xin; Wang, Pengfei; Li, Xin; Shan, Chang'an","Vertical sealing mechanism of shale and its roof and floor and effect on shale gas accumulation, a case study of marine shale in Sichuan basin, the Upper Yangtze area",Physical sealing; Burial depth; Adsorption; Permeability; Evaluation method,SILURIAN LONGMAXI FORMATION; SOUTH CHINA EVIDENCE; ADSORPTION CAPACITY; ORGANIC-MATTER; PORE STRUCTURE; ENRICHMENT; PLATFORM; CHALLENGES; MATURITY; RODINIA,"Shale and its roof and floor are very important for shale gas preservation. How to clarify the mechanism of its vertical sealing and its effect on shale gas enrichment is a significant problem to be solved. In this paper, the objective layers are the Upper Ordovician Wufeng Formation, the first member of the Lower Silurian Longmaxi Formation and the Lower Cambrian Qiongzhusi Formation, which are all in the representative shale gas blocks in the Sichuan basin of the Yangtze region. Studied by statistical drilling data, the focus is on the detailed analyses of the JiaoYe-1, Ning-201 and Wei-201 well, and experiments were carried out such as the porosity test, the TOC content analysis and the experiment of overburden permeability, permeability experiments before and after adsorption of methane under different osmotic pressure, and isothermal adsorption experiments. The experiments results are applied on studying the effect of shale and its roof and floor on shale gas enrichment, combined with formula deduction. The results show that the roof and floor have a vertical sealing effect on the organic-rich shale by the difference of physical properties. In eastern Sichuan, the roof of the organic-rich shale of the Wufeng Formation and the first member of Longmaxi Formation is assemblage of argillaceous siltstone and siliceous shale, while in southern Sichuan it is assemblage of gray shale and siliceous shale. The floor is nodular limestone and limestone in both areas. The combination of roof and floor, with low porosity, can form a quality roof and floor sealing ability in the absence of fracture development. Its sealing ability is stronger than that in the upper part of the Qiongzhusi Formation, considering its roof and floor composed of argillaceous siltstone and siliceous shale. The floor of the organic-rich shale at the bottom of the Qiongzhusi Formation is a dolomite reservoir with good storage capacity, between which there is an unconformable contact causing the worst sealing ability among the three intervals. With the increase of burial depth, the overlying pressure of shale increases. With the increase of TOC content and thickness, the amount of adsorption gas of shale increases. These two aspects of factors can lead to the permeability decline and self-sealing enhancement of the organic-rich shale. In this study, focusing on the Upper Ordovician-Lower Silurian and the Lower Cambrian in the Sichuan basin, four patterns of organic-rich shale and its roof and floor were summed up, and the rapid evaluation method of sealing of shale and its roof and floor under the limited geological data was established.",20,21,2
Fracture,Shale Gas,"Lai, Fengpeng; Li, Zhiping; Zhang, Tiantian; Zhou, Anqi; Gong, Bao","Characteristics of microscopic pore structure and its influence on spontaneous imbibition of tight gas reservoir in the Ordos Basin, China",Tight gas reservoir; Microscopic pore structure; Spontaneous imbibition; Experiments; Grey relational analysis,SANDSTONE RESERVOIRS; FLOW; PERMEABILITY; SHALE; MODEL,"Spontaneous imbibition is an important mechanism governing the tight reservoir production performance, especially in the early stage of production after hydraulic fracturing. The microscopic pore structure of reservoirs is an important factor affecting imbibition. In this study, high-pressure mercury injection (HPMI), rate-controlled mercury injection, and low-temperature nitrogen adsorption (LP-N(2)GA) were preformed to study pore structure characteristics and fluid distribution in samples from the Ordos Basin, China. Nuclear magnetic resonance (NMR) and imbibition experiments were used to investigate the fluid distribution in porous media during imbibition. The porosity of samples ranges from 11.378% to 12.356%, with an average of 12.034%. The permeability of samples ranges from 0.034 mD to 0.056 mD, with an average of 0.048 mD. Results show that the recovery ranges from 68% to 94.81%, with an average of 81.09%. The reservoir is dominated by open flat slit micropores and mesopores. Sample pore volume ranges from 0.0155 ml/g to 0.0193 ml/g, with an average of 0.01687 ml/g. Micropores and mesopores less than 50 nm provide most of the pore volume. Pore radius and pore-throat ratio were obtained from experiments. Imbibition occurs primarily in pores ranging from 0.1 mu m to 1 mu m in radius, followed by pores ranging from 1 mu m to 10 mu m. The effects of porosity, permeability, average pore radius, average throat radius, average pore-throat ratio, specific surface area, and pore volume on imbibition recovery were statistically analyzed. Grey relational analysis was applied to sequence the imbibition influencing factors and determine the most influential factor. Results demonstrate that imbibition recovery is the most affected by average pore radius, followed by permeability, porosity, average pore-throat ratio, median radius, average throat radius, and specific surface area.",19,18,4
Fracture,Shale Gas,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Liu, Wenyuan",Simulation of real gas mixture transport through aqueous nanopores during the depressurization process considering stress sensitivity,Shale gas; Nanoscale pores; Transport modeling; Gas mixture system; Stress sensitivity; Analytic model,GEOTHERMAL-ENERGY EXTRACTION; SHALE; FLOW; CO2; INJECTION; MODEL; WELL; PERMEABILITY; PERFORMANCE; SANDSTONE,"The study on shale gas transport mechanisms plays an important role in shale gas production simulation. The majority of previous works neglected the body gas diffusion mechanism, and the multiple effects of stress sensitivity and multi-component of gas mixture system. In this paper, first, a model is built considering the multiple transport mechanisms of continuum flow, slippage flow, body gas diffusion and Knudsen diffusion. Then, the multiple effects of stress sensitivity and multi-component of gas mixture system are coupled into the model. Results show that (a). For the body gas flow, both of the two weighted coefficients for items of body gas diffusion and slippage flow should be equal to one. And the ratio of one to Knudsen number is belong to the equation of body gas diffusion. (b). For a nanoscale pore of shale, the contribution of body gas diffusion on total mass flux cannot be neglected. The conductivities of continuum flow, slippage flow, modified slippage flow, Knudsen diffusion and weighted average flow decrease with decreasing of pressure due to shrinkage of nanopore radii and decrease in molecular concentration. (c). The decreasing of effective radii leads to the increase of the value of Knudsen number. The dominant transport mechanism is converting from modified slippage flow to Knudsen diffusion when the increase of stress sensitivity. (d). For methane confined in nanopores with extremely small effective transport radii, the injection of CO2 can increase the mobility of methane. After a period of CO2 injection, the methane molecules stored in nanopores can be flooded to fractures and then produced to the ground.",19,19,1
Fracture,Shale Gas,"Huang, Jingwei; Jin, Tianying; Chai, Zhi; Barrufet, Maria; Killough, John",Compositional simulation of fractured shale reservoir with distribution of nanopores using coupled multi-porosity and EDFM method,Pore size distribution; Multi-porosity coupled EDFM; Fractured shale reservoir; Phase behavior under confinement,CAPILLARY-PRESSURE; PHASE-BEHAVIOR; TIGHT-OIL; GAS; MODEL,"Shale reservoir contains highly heterogenous pore systems due to the wide-range distributions of nanopores in shale matrix and hydraulic/natural fractures. To explicitly include pore size distribution in simulation of shale reservoir, a multi-porosity model is applied to subdivide the matrix into multiple continua based on experimental pore size data. Each continuum has its own pore size, porosity and permeability, as well as other petrophysical properties. Besides, the embedded discrete fracture model (EDFM) is coupled with multi-porosity model to describe the complex fractures networks with any angles and intersections. To evaluate effects of pore size distribution on production, compositional simulation is conducted in a fractured shale reservoir using different number of continua in shale matrix. Simulation results show that the use of multiple continua results in lower oil and gas production. Different pressures, oil and gas saturations and compositions are observed in different continua. To further investigate the effects of distribution of nanopores, oil-gas capillary pressure is rigorously calculated in every continuum. The existence of large capillary pressure leads to different fluid properties in different size of nanopores. Moreover, capillary pressure reduces oil and gas recovery and alters compositions of residuals. The effects of capillary pressure are more significant in the low permeable continua due to smaller pore sizes.",19,19,0
Fracture,Shale Gas,"Wu, Yonghui; Cheng, Linsong; Huang, Shijun; Fang, Sidong; Jia, Pin; Rao, Xiang",An analytical model for analyzing the impact of fracturing fluid-induced formation damage on rate transient behavior in tight formations,Water blockage; Rate transient behavior; Tight formation; Analytical model; Multi-fractured horizontal well,HORIZONTAL WELLS; SHALE GAS; SEMIANALYTICAL MODEL; RESERVOIRS; FLOW; PERFORMANCE; SIMULATION; MECHANISMS; DENSITY; CLEANUP,"An enormous amount of fracturing fluid is irreducible in the tight formation after hydraulic fracturing stimulation. This will cause serious damage to the fracture face as well as the matrix close to the hydraulic fractures by invading into the matrix. Modeling the effect of water blockage on rate transient behavior is significant in reservoir engineering. This paper presents a modified trilinear model to analyze the rate transient behavior after flowback period. Single-phase flow is assumed in this stage because most injected water is hard to be reduced. For damage to the matrix caused by rock-fluid interaction, clay swelling, and polymer adsorption, a fracturing fluid invasion layer is added to the model between hydraulic fractures and the inner stimulated reservoir volume to capture this kind of damage. A skin factor is used to capture the damage to the matrix-fracture face caused by gel filter cake formation and polymer adsorption. The analytical model is benchmarked using the commercial numerical simulator Eclipse. Several synthetic cases and a field case are studied, the results show that water blockage has a great impact on the productivity of the well and decline curves. The effect of choking effect, convergence flow, and gel filter cake could be incorporated using a skin factor in the model. In addition, two more flow regimes could be observed on the theoretical type curve if the well is affected by water blockage, and the two flow regimes would happen before linear flow dominated by the inner stimulated zone. Besides, the duration of the inner zone linear flow regime could be shortened if the permeability of the fracturing fluid invasion layer is lower and invasion depth is larger. These phenomena can be used in matching the field production data from water blockage affected wells, which exhibit a transition flow regime before the formation linear flow regime. This transition flow regime could be matched quite better using the proposed model than the classical trilinear flow model. The reason is that the linear flow regime could be much longer if the water blockage effect is not considered in the model. On the other hand, the skin factor has a different impact on the flow regimes, so the water blockage effect could be characterized properly only by adding a skin factor to the model. The main contribution of this paper is the provision of an analytical model for evaluating the formation damage caused by irreducible fracturing fluid, analyzing production data and making forecasts.",18,19,6
Fracture,Shale Gas,"Li, Ziyan; Elsworth, Derek",Controls of CO2-N-2 gas flood ratios on enhanced shale gas recovery and ultimate CO2 sequestration,CO2-Enhanced shale gas recovery; N-2- enhanced shale gas recovery; Adsorption and desorption; CO2 sequestration; Permeability evolution,STORAGE,"Primary production of less than 25% of original gas in place (OGIP) may be elevated by enhanced shale gas recovery (ESGR) using either pure CO2 or N-2 as injected stimulants. Alternatively, injecting mixtures of CO2 and N-2 may potentially optimize recovery of natural gas and beneficially sequester CO2. We develop a dual-porosity, dual-permeability finite element (FEM) model coupled with multi-component gas flow and sorption behavior to 1) explore the evolution of sorption-induced strain resulting from competitive adsorption and its influence on the matrix and fracture permeability; 2) define cumulative production of CH4 and 3) evaluate the amount of CO2 sequestered in the reservoir; Results show that pure-CO2 injection can increase shale gas recovery by similar to 20%. Conversely, pure-N-2 injection can increase shale gas recovery by similar to 80%. Injecting mixtures of CO2 and N-2 can increase shale gas recovery between these end-member magnitudes of similar to 20%-similar to 80% depending on the gas composition. We show that a higher proportion of CO2 in the injected CO2-N-2 mixture will result in the decreased recovery of shale gas. However, at the same injection pressure, injecting CO2-N-2 mixtures with a higher proportion of CO2 does not always result in more CO2 sequestered in the reservoir. Indeed, when the CO2 injection ratio is > 70%, as explored in this study, increasing the CO2 injection ratio will result in less CO2 sequestered. This is because, as the CO2-N-2 gas ratio increases, shale gas recovery decreases and results in more CH4 left in the reservoir to compete with CO2 for sorption sites and finally resulting in less CO2 sequestered.",18,18,3
Fracture,Shale Gas,"Chen, Yulong; Zhang, Yuning; Li, Xuelong",Experimental study on influence of bedding angle on gas permeability in coal,Bedding plane orientation; Coal; Gas; Permeability,MECHANICAL-BEHAVIOR; HYDRAULIC-GRADIENT; FRACTURE NETWORKS; WAVE VELOCITY; FLUID-FLOW; MODEL; SHALE; STRESS; ANISOTROPIES,"The gas permeability of coalbeds is of critical significance to gas exploitation and recovery in coal seams. These properties are affected by bedding plane orientation. In this paper, the influence of different bedding angles in coal on mechanical properties, and gas permeability behavior in a complete stress-strain process is investigated. Experimental results reveal that with an increase in the bedding angle, the number of channels was found to increase along with the initial permeability. The increased bedding angle also caused the compression strengths of the coal sample to decrease initially and then increase. The corresponding compression strength was highest at a bedding angle of 0 degrees followed by a bedding angle of 90 degrees. Under these two conditions, the failure surface of coal was usually due to tensile splitting. The coal strength was lowest at a bedding angle of 60 degrees, where the coal mass experienced shear failure during the bedding plane. The coal sample at a bedding angle of 30 degrees exhibited compound split-shear failure.",17,17,10
Fracture,Shale Gas,"Zeng, Yijin; Liu, Rengguang; Li, Xiaojiang; Zhou, Shiming; Tao, Qian; Lu, Peiqing",Cement sheath sealing integrity evaluation under cyclic loading using large-scale sealing evaluation equipment for complex subsurface settings,Cement sheath; Sealing evaluation equipment; Failure mechanism; Cyclic loading; Hydraulic fracturing,,"Cement sheaths should provide zonal isolation and structural support through the entire service lifetime of wells. However, even if high-quality primary cementing was achieved, variations in pressure, for example, those due to staged fracturing in shale gas wells, are likely to lead to sealing integrity failure of the cement sheath. This work presents large-scale sealing evaluation equipment to assess the failure mechanisms of cement sheaths under cyclic loading. The equipment includes a borehole system, pressure system, and control and data acquisition system for automatic loading and unloading, gas channeling monitoring and pressure change and gas output recording. The pressure limit of the equipment is 120 MPa. A finite element model of the borehole system and sealing equipment was built to study the stress and strain under internal pressure. The failure mechanisms of the sealing integrity of the cement sheath were obtained by combining the test results with the finite element calculations. At a high internal pressure, plastic deformation was produced during loading due to the residual strain that arose after unloading of the cement sheath. Therefore, incompatible deformation occurred, and the tensile stress increased at the interfaces of the cement sheath. Under repeated loading and unloading, the plastic deformation increased, and the residual strain and interface tensile stress also increased. When the interface tensile stress exceeded the bonding strength, a microannulus formed between the cement sheath and casing. Based on these results, guidelines for the assessment of the long-term sealing integrity of a shale gas well cement sheath and for the selection of mechanical properties of the cement systems are given to mitigate the risk of zonal isolation failure.",17,23,2
Fracture,Shale Gas,"Wei, Shiming; Xia, Yang; Jin, Yan; Chen, Mian; Chen, Kangping",Quantitative study in shale gas behaviors using a coupled triple-continuum and discrete fracture model,Shale gas; Hydraulic fracture network; Non-equilibrium desorption/adsorption mechanism; Gas behavior,HORIZONTAL WELLS; PRACTICAL METHOD; TIGHT OIL; FLOW; RESERVOIR; SIMULATION; FLUID; DIFFUSION; TRANSPORT; FRAMEWORK,"The shale has ultra-low permeability wherein multi-scale natural fractures are well-developed. The success of providing high diversion channels makes multi-stage fractured horizontal wells (MFHWs) become the powerful technique for economically producing gas from shale. This study presents a triple-continuum and discrete fracture model to describe a fractured shale reservoir embedded with a MFHW. The model incorporates non-equilibrium desorption/adsorption mechanism (NEDAM), viscous flow, Knudsen diffusion, and surface diffusion. The discrete fracture networks (DFNs) is quantitatively constructed according to the fracture density and stimulated reservoir area (SRA). This model is used to analyze the temporal/spatial evolution of the gas pressure and the net desorption rate. NEDAM is compared with the conventional equilibrium desorption mechanism (EDM) and its found that NEDAM uncovers the delayed phenomenon during gas desorption, and the use of EDM overestimates the production contributed from the adsorbed gas. The maximum net desorption rate of adsorbed gas gradually spread from the SRA region to the nonSRA region. The complete flow stages are clearly interpreted in a semi-logarithmic curve of well testing, and the flow stage controlled by the hydraulic fractures is clearly presented. Finally, the instructions on hydraulic fracturing treatment are given based on the production analysis.",17,18,2
Fracture,Shale Gas,"Cai, Can; Kang, Yong; Wang, Xiaochuan; Hu, Yi; Huang, Man; Liu, Yiwei; Liu, Jiawei; Chen, Hao; Li, Xiaohong",Experimental study on shale fracturing enhancement by using multi-times pulse supercritical carbon dioxide (SC-CO2) jet,Supercritical carbon dioxide; Shale gas; Pulse jet fracturing; Fracture morphology; Fracturing enhancement,ADSORPTION CHARACTERISTICS; CO2 INJECTION; FLOW-FIELD; GAS; PRESSURE; LIQUID; COAL; TEMPERATURE; PROPAGATION; SIMULATION,"Supercritical Carbon Dioxide (SC-CO2) fracturing can increase shale gas production and reduce carbon dioxide (CO2) emission. In order to enhance shale fracturing, a new method of multi-times pulse SC-CO2 jet fracturing is proposed and comprehensively studied. The results demonstrate there are more initiation positions and more complex fracture network after pulse SC-CO2 jet fracturing due to strong impingement and pressurization. Furthermore, three types of main fracture and four types of fracture branch are observed. The main fractures mostly initiate from perforation and propagate with irregular path to the specimen edge. CO2 absorption and fracture volume increase 77.72% and 2283%, respectively, more than that of single-pulse SC-CO2 jet fracturing. The comparison indicates that SC-CO2 creates more complex fracture morphology, larger fracture volume and CO2 absorption than that of water. Moreover, the effect of influential factors, including pulse jet frequency, pulse jet pressure and pulse jet distance, are discussed thoroughly. Thus, this study provides a method of jet fracturing enhancement, and is instructive for understanding and tackling pulse jet fracturing issue related to CO2 utilization and fracturing of shale reservoir.",16,16,11
Fracture,Shale Gas,Liu Lijun; Yao Jun; Sun Hai; Huang Zhaoqin; Yan Xia; Li Longlong,Compositional modeling of shale condensate gas flow with multiple transport mechanisms,Shale; Condensate gas; Compositional model; Transport mechanism; Phase behavior,HYDROCARBONS RECOVERY; SCALE SIMULATION; RESERVOIRS; PERMEABILITY; FLUID; MICRO,"Shale condensate gas has gained great attention in recent years due to the production of profitable liquid hydrocarbons. The fluid flow in shale matrix is complex and influenced by multiple transport mechanisms, such as stress sensitivity, Knudsen diffusion, adsorption, molecular diffusion, and confined phase behavior. In addition, the coexistence of multiscale pore space, including hydraulic fractures, micro-fractures in simulated reservoir volume (SRV) and nanopores in matrix further increases the fluid flow complexity. Conventional models cannot commonly consider all the factors. In this work, we develop a hybrid model for condensate gas reservoir, where fluid flow is described by compositional model coupled with transport mechanisms, micro-fractures and hydraulic fractures are handled by multiple interacting continua (MINC) model and embedded discretized fracture model (EDFM). Then based on the proposed model, the effects of gas transport mechanisms on a multi-stage fractured horizontal well production are analyzed, where simulations are conducted with and without SRV to investigate the importance of SRV. Furthermore, some important reservoir parameters, such as SRV properties, hydraulic fracture length and bottom-hole pressure are also investigated with the proposed model.",16,17,4
Fracture,Shale Gas,"Yan, Xiaopeng; Kang, Yili; You, Lijun; Xu, Chengyuan; Lin, Chong; Zhang, Jingyi","Drill-in fluid loss mechanisms in brittle gas shale: A case study in the Longmaxi Formation, Sichuan Basin, China",Brittle gas shale; Drill-in fluid loss; Plugging zone stability; Dynamic fracture width; Case study,CIRCULATION; DAMAGE; COEFFICIENT; STABILITY; IMPACT; WELLS,"Brittle gas shale consists of a high content of brittle mineral and developed natural fractures and has become the focus of petroleum industry in recent years. Lost circulation may easily occur due to the long soaking time and an overbalanced pressure difference during the drill-in process of the horizontal long section. The dynamic fracture width simulation induced by drill-in fluid invasion, plugging zone pressure containment test, friction coefficient test between lost circulation materials and shale surface, oil based drill-in fluid filtrate immersion test were conducted to investigate the drill-in fluid loss mechanisms in the brittle Longmaxi Shale in the Sichuan Basin of China. Results show that the fracture width at the fracture mouth increased from 2 mu m to 239 mu m for the two mutually perpendicular fractures connecting to the wellbore due to drill-in fluid invasion. Effective plugging for dynamic fractures was failed to be achieved for the original drill-in fluid. Fracture width increase induced by drill-in fluid invasion is the major cause of plugging failure of brittle gas shale. Instability of the brittle shale induced by oil phase lubrication and high pH drill-in fluid erosion further exacerbates lost circulation problems. Optimized LCMs considering the dynamic apertures of fractures should be selected and added into drill-in fluid to rapidly seal pre-exiting fractures and induced fractures for lost circulation control in brittle shale. The results serve as a guide for the drill-in fluid design of shale gas in brittle gas shale formation.",16,19,3
Fracture,Shale Gas,"Zhao, Shuai; Sun, Youhong; Wang, Haoran; Li, Qiang; Guo, Wei",Modeling and field-testing of fracturing fluid back-flow after acid fracturing in unconventional reservoirs,Oil shale; Acid fracturing; Fracturing fluid back-flow; Numerical simulation; Diversion capacity,OIL-SHALE; GAS,"When the oil shale reservoir completes acid fracturing, the back-flow of fracturing fluid program is needed. In this paper, a three-dimensional model is established and the finite element analysis software is used to simulate the feasibility of gas lift back fracturing fluid in Fuyu oil shale formation after acid fracturing. The results show that when the injection pressure of FK-1 well is 8.5 MPa, the fracturing fluid can be effectively displaced. Fracturing fluid is discharged along the fracture into FK-2 well, and a few fracturing fluids overflow the pyrolysis zone along the direction of oil shale bedding. Then the experiment is carried out to verify the accuracy of numerical simulation. What's more, it is also verified that the connectivity of oil shale reservoir meets the needs of oil shale in-situ pyrolysis process.",15,15,7
Fracture,Shale Gas,"Wu, Yonghui; Cheng, Linsong; Huang, Shijun; Bai, Yuhu; Jia, Pin; Wang, Suran; Xu, Bingxiang; Chen, Ling",An approximate semianalytical method for two-phase flow analysis of liquid-rich shale gas and tight light-oil wells,Two-phase; Multistage fractured horizontal well; Liquid-rich shale gas; Tight oil; Semianalytical method,FRACTURED HORIZONTAL WELLS; INTEGRATED WORKFLOW; CURVES,"Two-phase flow of oil and gas is quite common in the reservoir during the depletion of liquid-rich shale gas and tight light-oil. Many analytical models proposed for multistage fractured horizontal wells completed in unconventional reservoirs are restricted to single phase flow problem. In this paper, an approximate semianalytical method is proposed to handle the complexities of phase change, pressure dependent PVT properties, two-phase flow behavior and complex fracture networks. The black oil model is used to model phase change and two-phase flow of oil and gas. The secondary fractures in the stimulated reservoir volume and the reservoir beyond the main fractures are considered in the physical model to make long-term production forecasts. The forecasted producing GOR is used to decrease the equations of the two-phase flow model, so only the flow equations of primary phase are used to develop the mathematic model. Then an approximate method is used to linearize the model and the analytical solution is obtained in Laplace space for constant pressure inner boundary problem. The Duhamel's principle is applied to correct the production rate under variable flowing pressure inner boundary, and a procedure is proposed for history matching of field production data and making forecasts. Finally, the semianalytical model is validated with two simulation examples, the average relative error is shown to be less than 10%. After that, two field examples are used to show its utility.",15,16,0
Fracture,Shale Gas,"Hussien, Osman SalahEldin; Elraies, Khaled Abdalla; Almansour, Abdullah; Husin, Hazlina; Belhaj, Ahmed; Ern, Lim",Experimental study on the use of surfactant as a fracking fluid additive for improving shale gas productivity,Hydraulic fracturing; Surfactant; Surface tension; Shale gas; Shale wettability,AQUEOUS-SOLUTIONS; TEMPERATURE; TENSION; PRESSURE; WATER,"A substantial quantity (60-80%) of water utilized through hydraulic fracturing in shale formations stays trapped within the formation primarily because of capillary forces. The retained water could obstruct the flow path of gas therefore trapping it and decreasing its productivity. Surfactants are utilized as additives to lower the surface tension between gas and water, which includes a reduction in the capillary pressure and therefore easier flow of gas to be produced as well as water to be retrieved. Within this paper, the effects of BIO-TERGE (R) AS-40 surfactant on improving the performance of the fracturing fluid had been researched in the existence and lack of additional chemical additives at several fracking water salinities. The efficiency of the included surfactants was analyzed by measuring the surface tension between methane gas and surfactant mixtures utilizing the pendant drop technique at various temperatures and pressures. As results, BIO-TERGE (R) AS-40 has lowered the surface tension between methane gas and water from about 69 mN/m to 32.49 mN/m at critical micelle concentration (CMC) of 0.75 wt% and 10,000 ppm salinity. The addition of the nonionic Betain C60 has decreased the surface tension to a low value of 30.79 mN/m. The surfactant had a significant effect on reducing the contact angle, causing the shale rock to become more water wet. Reduction of surface tension as well as the change in the wetting phase aids in enhancing the desorption of gas from the shale. Furthermore, it was obvious that increasing the temperature and pressure would likely reduce the surface tension. The obtained information from this study can be utilized to optimize the performance of fracture fluid and then improve the shale gas production and overall sweep efficiency in addition to water flowback.",14,14,3
Fracture,Proppant,"Wang, Shuhua; Chen, Shengnan",Insights to fracture stimulation design in unconventional reservoirs based on machine learning modeling,Fracture stimulation design; Data mining; Feature selection; Machine learning; Montney tight reservoirs,ARTIFICIAL NEURAL-NETWORKS; GAS-PRODUCTION; NATURAL-GAS; TIGHT OIL; SHALE; OPTIMIZATION,"With rapid development of unconventional tight and shale reservoirs, considerable amounts of data sets are increasing rapidly. Data mining techniques are becoming attractive alternatives for well performance evaluation and optimization. This paper develops a comprehensive data mining process to evaluate well production performance in Montney Formations in western Canadian sedimentary basin. The general data visualization and statistical data evaluation are used to qualitatively and quantitatively evaluate the relationships between the stimulation parameters and first-year oil production. Then, the recursive feature elimination with cross validation (RFECV) is used to identify the most important factors on the first-year oil production in unconventional reservoirs. In addition, four commonly used supervised learning approaches including random forest (RF), adaptive boosting (AdaBoost), support vector machine (SVM), and neural network (NN) are compared to estimate the first-year well production. The results show that 6 features are the most important variables for constructing an accurate prediction model: well latitude, longitude, well true vertical depth (TVD), proppant pumped per well, well lateral length, and fluid injected per well. Compared to other algorithms, RF has the best prediction performance for the first-year oil production. Furthermore, such data-driven models are found to be very useful for reservoir engineers when designing hydraulic fracture treatments in Montney tight reservoirs.",45,46,5
Fracture,Proppant,"Zhu, Haiyan; Shen, Jiadong; Zhang, Fengshou",A fracture conductivity model for channel fracturing and its implementation with Discrete Element Method,Channel fracturing; Proppant pillar; Fracture conductivity; Optimization; Discrete element method,MECHANICAL STABILITY; PROPPANT EMBEDMENT; SIMULATION,"This paper introduces a new method to predict conductivity in channel fracturing by implementing analytical solution in Discrete Element Method (DEM). First, an analytical model for channel fracturing conductivity is proposed. Then, a DEM model calibrated by using experimental results is set up to investigate the deformation of proppant pillar. Finally, the analytical model of fracture conductivity is implemented in the DEM model to predict conductivity during fracture closing. Parametric analyses are carried out to understand the effects of four factors: proppant size combination, concentration, time ratio tau and elastic modulus to stress ratio lambda. Conductivity generally decreases during fracture closing and increases with the increasing proppant size and proppant concentration. The ratio of the pulsing time of proppant laden fluid to the pulsing time of the clean fluid is the key parameter for the field operation. A large time ratio could enhance the pillar stability though it may lead to the damage of fracture conductivity. For given rock modulus, closing stress and proppant size, the optimal range of time ratio can be given as a guidance for field operation. The field application of channel fracturing in the Shengli Oilfield proves that the optimized range of time ratio tau based on the proposed theoretical model is valid. The porosity of proppant pillar first decreases due to compression and then increases during fracture closing period because of the breakdown of the proppant pillar and the resulted particle movement outward. This paper gives insights for understanding the channel fracture conductivity and provides a practical tool for the optimization of channel fracturing design in the field.",40,40,6
Fracture,Proppant,"Wang, Shuhua; Chen, Zan; Chen, Shengnan",Applicability of deep neural networks on production forecasting in Bakken shale reservoirs,Production forecasting; Bakken formation; Deep neural networks; Hyperparameter optimization; Global sensitivity analysis,NEWTON OPTIMIZATION METHOD; TIGHT-OIL; GAS-PRODUCTION; MODEL; PREDICTION; DESIGN; STEAM,"The unconventional shale and tight formations, such as the Bakken in Williston Basin, are becoming an important hydrocarbon sources since the development of advanced horizontal drilling and multi-stage stimulation techniques. The appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery. Although reservoir simulations are commonly used for production analysis, the modeling of hydraulic fractures and intrinsic complexity of shale have restricted an understanding of the fluid flow behavior. Owing to the available of a large amount of data in unconventional tight and shale reservoirs, data-driven approaches, such as deep neural networks (DNNs), provide an alternative approach for production analysis in these formations. In this study, a total of 2919 wells including 2780 multi-stage hydraulic fractured horizontal wells and 139 vertical wells in Bakken Formation were collected and analyzed using a deep learning method and Sobol's global sensitivity analysis. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, and batch normalization were evaluated to develop a reliable deep neural network model. Moreover, k -fold cross validation was used to evaluate the prediction ability and robustness of models. Prior to the performance evaluation of DNN algorithms, an optimum DNN model was achieved by optimizing the dropout layer, activation function, and hyperparameters of DNN models. It is found that the number of hidden layers and neurons in each layer have significant effects on the performance of models. The optimized DNN model has 3 hidden layers and 200 neurons for each layer. The prediction performance of DNN models is acceptable with the low mean squared errors for both 6- and 18-months cumulative oil productions. Furthermore, the importance of each parameter was studied using the Sobol's analysis. Results show that the average proppant placed per stage is the most important parameter, which accounts for more than 35% of variability in both 6- and 18-months cumulative oil productions. These data-driven models can be readily updated when the new well information becomes available. It is worth mentioning that the proposed DNN models can be directly integrated into existing hydraulic fracturing design routines.",35,37,5
Fracture,Proppant,"Wang, Xiaoyu; Yao, Jun; Gong, Liang; Sun, Hai; Yang, Yongfei; Zhang, Lei; Li, Yang; Liu, Wenchao",Numerical simulations of proppant deposition and transport characteristics in hydraulic fractures and fracture networks,Proppants; Fractures and fracture networks; CFD-DEM coupling,PARTICLE-TRANSPORT; SHEAR DISPERSION; PRESSURE-DRIVEN; VERTICAL WELL; FLUID-FLOWS; MODEL; PLACEMENT; CHANNEL; GAS,"Proppants are used to resist fracture closure during hydraulic fracking treatments. Understand the proppant transport and distribution characteristics in fracture and fracture network become a meaningful topic for its effects on the conductivities of fractures. Since experiments are expensive, and it is also difficult to consider various conditions and detect the movement of particles during experiments, numerical simulation methods are often applied. In this work, the coupled Computational Fluid Dynamics-Discrete Element Method (CFD-DEM) was implemented to investigate the factors affecting proppant distribution in fracture and fracture networks. First, the CFD-DEM model was built for proppant flow and settlement. We validated the model by comparing with the published numerical simulation result. After that, we designed a series of cases to investigate the effects of fracture closure, injection velocity and no-uniform opening of the inlet on proppant distribution in a single fracture. Then, the effects of proppant diameter, density and perforation height differences on proppant sorting were studied. Next, we computed the proppant transport in fracture networks considering the aperture difference, the orientation of branch fractures and leak-off in fracture tips. The simulation results in this paper can help engineers to understand the transport and distribution of proppants visually in the fracture and fracture networks in unconventional reservoirs.",28,28,8
Fracture,Proppant,"Xing, Yuekun; Zhang, Guangqing; Luo, Tianyu; Jiang, Yongwang; Ning, Shiwen",Hydraulic fracturing in high-temperature granite characterized by acoustic emission,High-temperature; Hydraulic fracturing; Granite; Fracturing characteristics; Laboratory simulation; Acoustic emission,CRACK-GROWTH; ROCK; PRESSURE; ENERGY; MECHANICS,"Given the limited successes of hydraulic fracturing in enhanced geothermal systems (EGS), understanding of the hydraulic fracturing characteristics in high-temperature granites remains challenging and crucial. In this study, four groups of cube granite specimens (dimensions: 300/300/300 mm) were tested to investigate the characteristics of the hydraulic fracture, for two confining pressures (0.1/0.1/0.1 MPa and 10/25/30 MPa) and temperatures (20 degrees C and 120 degrees C). Acoustic emission (AE) was employed to characterize the hydraulic fracturing processes. The experimental results show that for different temperatures the fracture geometry is almost unchanged, whereas the injection pressure curves, spatial distribution of AE energy, and AE-based source mechanisms are significantly changed. (1) At 120 degrees C, The fracture pressures are increased by 3.6 similar to 4.9 MPa and two remarkable pressure peaks appear at the injection pressure curves, implying the hydraulic fracture propagates intermittently with increasing resistances. (2) The spatial distributions of AE energy delineate a microcrack-band distributing along the hydraulic fracture. At the high temperature (120 degrees C), the effective width of the microcrack-band is reduced by 40 similar to 56.4%, and the fracture energy is reduced by about 75% adjacent to the wellbore (about 40% of the fracture length) in the microcrack-band. (3) Based on the AE source analysis, the fracture mechanisms in the microcrack-band indicate the high-temperature (120 degrees C) reduces the proportion of shear microcracks by 6 similar to 12%. The characteristics of high-temperature reducing the effectiveness of EGS hydraulic fracturing are due to the change in granite microstructures from temperature induction and the transient temperature differential (Delta T) between granite and fracturing fluid. In the EGS hydraulic fracturing, the net pressure should be enhanced in real-time with hydraulic fracture propagation to avoid fracturing arrest, Delta T between high-temperature granite and fracturing fluid should be lowered to enlarge the stimulated reservoir volume, and the proppant is suggested to be appropriately placed to prevent the further reduction of the fracturing effectiveness from fracture closures.",27,28,12
Fracture,Proppant,"Zheng, Shuang; Manchanda, Ripudaman; Sharma, Mukul M.",Development of a fully implicit 3-D geomechanical fracture simulator,Hydraulic fracturing simulation; Simultaneous multi-fracture propagation; Slurry distribution; Finite volume and finite area method; Contact problem,PROPAGATION; ELASTICITY; MODEL; XFEM; FLOW,"Hydraulic fracturing modelling is a multi-physics problem which must be solved in the reservoir domain, fracture domain, and wellbore domain. The physical phenomena that need to be quantitatively modelled include solid deformation and fluid flow in the poroelastic reservoir, fluid flow in the fractures, and fluid and proppant transport in the wellbore. These problems which are tightly coupled with each other in a highly non-linear manner are solved together implicitly for the first time. This fully implicit, parallelized 3D hydraulic fracturing simulator is capable of simulating simultaneous propagation of multiple fractures in multi-well pads. In this new simulator, four sets of governing equations are coupled implicitly and solved simultaneously. The solid deformation equations and reservoir pressure equations are discretized using the finite volume method while the fracture pressure equation is discretized using the finite area method. Fluid flow in the wellbore is modelled considering wellbore compressibility, perforation pressure drop, and wellbore friction pressure drop. A Barton-Bandis contact model is applied to model fracture closure due to stress shadow effects as well as production. The simulator is parallelized using the distributed memory approach with domain decomposition to improve the computation efficiency. We first validated our simulator with two well-known model problems and the numerical results show good agreement with the existing analytical solutions. We compare the performance of the new simulator with the past explicit methods and show that the new simulator offers significant improvement in numerical stability and computation speed. Finally, the simulator is applied to simulate and analyze one stage of a fracturing treatment with five fractures propagating simultaneously to show the unique capabilities of our simulator.",21,21,0
Fracture,Proppant,"Zhu, Jingyi; Yang, Zhaozhong; Li, Xiaogang; Song, Zhichao; Liu, Ziwei; Xie, Shiyi",Settling behavior of the proppants in viscoelastic foams on the bubble scale,Proppant; Settling behavior; Viscoelastic foam; Drag force; Bubble structure,FRACTURING FLUID; HIGH-TEMPERATURE; PARTICLES; SHEAR; SURFACTANT; STABILITY; SOLIDS; MODEL; SEDIMENTATION; TRANSPORT,"Liquid foam is an alternative to water-based fracturing fluid due to its great proppant suspension ability. In this work, theoretical and experimental investigations on the settling behavior of the proppants in viscoelastic foams were analyzed on bubble scale. Settling trajectory was captured over time by optical microscope to calculate proppant settling velocity. At room temperature, proppants kept suspended well, but noticeable changes in proppant position could be observed at 70 degrees C. We concluded that the sedimentation of the proppants at high temperature was divided into three stages, that were drainage-dominated, structure-dominated and fluid-dominated regimes. For the large proppants, quick settling velocity was seen at first due to fast drainage rate. Then bubble pressure force and network force served as drag force exerting on the proppants when the proppants stretched or squeezed the liquid films. During this regime, bubble distribution, the existence of nodes, the length and the orientation of Plateau border leaded to the fluctuation in settling velocity. Lastly, the proppants would also flow freely along Plateau border over time, and the properties of the foam fluid such as viscosity and elasticity provided the drag force to prevent the proppants from settling. It's more likely for small proppants to change to this stage called fluid-dominated regime, but elasticity also guaranteed their low settling velocity. Moreover, in the existence of proppants, the analysis into drainage rate and bubble structure demonstrated the high stability of viscoelastic foams. These results helped understand the sedimentation of proppants in wet foams and broadened the application of viscoelastic foams in hydraulic fracturing.",20,21,3
Fracture,Proppant,"Zheng, Wenbo; Tannant, Dwayne D.",Influence of proppant fragmentation on fracture conductivity - Insights from three-dimensional discrete element modeling,Proppant crushing; Discrete element modeling; Particle breakage model; Permeability; Fracture conductivity,CRUSHING CHARACTERISTICS; BREAKAGE CRITERIA; NUMERICAL-MODEL; PERMEABILITY; EMBEDMENT; COMPACTION; PACKS; SOILS,"Proppant crushing under high closure stress is widely observed in the laboratory and the field but has rarely been simulated numerically. This paper presents 3D discrete element modeling of proppant fragmentation and its influence on the fracture conductivity. A particle breakage model was implemented to simulate proppant fragmentation. A practical procedure was developed to calibrate the parameters in the breakage model using stress-strain responses and grain size distributions from laboratory crush tests. The breakage model, along with the calibrated parameters for Jordan sand, Genoa sand, and a ceramic proppant, was used in a parametric analysis for multilayer proppant packs. The influence of proppant type, particle size, and proppant mixture on proppant fragmentation and fracture conductivity was examined. The results indicate that the proppant size needed to achieve optimal fracture conductivity is greatly affected by particle fragmentation, which in turn is sensitive to closure stress and size-dependent particle strength. A Hardin breakage ratio larger than 0.05 represents the onset of excessive proppant fragmentation that can greatly decrease fracture conductivity.",19,19,3
Fracture,Proppant,"Tong, Songyang; Gu, Ming; Singh, Robin; Mohanty, Kishore K.",Proppant transport in foam fracturing fluid during hydraulic fracturing,Proppant transport; Proppant settling correlation; Foam drainage; Hydraulic fracturing,DRAINAGE; FLOW; BEHAVIOR,"During hydraulic fracturing treatments, proppants often settle at the fracture bottom in low viscosity fracturing fluid (e.g., slickwater) and leave a large fraction of the fractured surface unpropped. Severe proppant settling leads to under performance of the well productivity. Polymer-free foams can be used as fracturing fluids for improved transport of proppants after a low viscosity pad. In this paper, proppant transport in foam is studied during hydraulic fracturing. A proppant settling velocity correlation in foam-based fracturing fluid is developed based on laboratory-scale experiments. Foam quality and the foam velocity gradient are found to control proppant settling. Additionally, foam liquid drainage is found to be an important process affecting proppant transport, and a foam drainage model is proposed based on literature studies. The new settling velocity correlation and the foam drainage model are incorporated into an in-house fracturing simulator, and proppant placement in foam fracturing fluid is evaluated at the field-scale. Foams place proppants more uniformly than slickwater. For dry foams, drainage has little effect on the final proppant placement. For wet foams, drainage affects the final proppant distribution. The faster the foam drains, the less uniform is the final proppant placement. The liquid from the foam collects at the bottom where the proppants settle fast and form a small proppant bed.",14,14,10
Fracture,Proppant,"Chauhan, Geetanjali; Verma, Amit; Doley, Amolina; Ojha, Keka",Rheological and breaking characteristics of Zr-crosslinked gum karaya gels for high-temperature hydraulic fracturing application,Gum karaya; Metal-crosslinked; Rheology; Gel breaking; Regained permeability,GUAR GUM; POLYMER; GELATION; FLUIDS; POLYACRYLAMIDE; NANOCOMPOSITE; PERMEABILITY; SPECTROSCOPY; MECHANISM,"The metal-crosslinked polymer gels play a vital role in stimulating oil and gas wells since many years, but the presence of large insoluble residues and incomplete breaking of the conventional guar-based fracturing fluids reduces the permeability of the proppant pack necessary for oil and gas flow. In the present study, a novel crosslinked gel has been synthesized using the low molecular weight acidic polymer gum karaya and zirconium crosslinker as an alternative to guar-based fracturing fluids to increase the proppant pack conductivity with competitive rheological performances. The polymer and crosslinker concentrations were optimized and the synthesized gel was studied for structure, morphology, time-independent and time-dependent rheological tests under simulated conditions of pressure and high temperature. The smaller amount of residues left by the fluid after breaking with oxidative breakers and higher regained permeability of the sand pack system compared to Guar confirm its ability to reduce the proppant pack damage.",14,15,5
Fracture,Proppant,"Huang, Hai; Babadagli, Tayfun; Li, Huazhou Andy; Develi, Kayhan; Wei, Gongjue",Effect of injection parameters on proppant transport in rough vertical fractures: An experimental analysis on visual models,Roughness effect; Proppant transport; Hydraulic fracturing; Rough fracture; Visual study,PHASE FLOW-THROUGH; FLUID-FLOW; SHEAR DISPLACEMENT; SINGLE FRACTURE; PERMEABILITY; APERTURE; CONDUCTIVITY; JOINTS,"The understanding of proppant flow through fractures is critical in evaluating the performance of hydraulic fracturing operations. As a continuation of our experimental efforts devoted to understanding how proppant flows in rough vertical fractures, in this paper, we examine the effect of injection parameters on the proppant transport in rough vertical fractures. The effects of polymer concentration, injection rate, proppant concentration, and type of proppant were investigated in detail. Experimental results show that, in general, two types of settling patterns can be observed in the proppant transport in a rough fracture: sand-dune settling pattern and tree-like settling pattern. The following conditions tend to suppress the tree-like settling behavior of proppants in the rough fracture: a higher density of the proppants, a lower viscosity of the polymer solution, and a lower injection rate. This is attributed to a higher settling velocity of the proppants in the fracture under these conditions. A sufficiently high polymer concentration is needed to enable effective proppant flow in rough fractures. In general, the relative coverage of proppants increased dramatically as the polymer concentration increased, implying that the higher viscosity of fracturing fluid could enhance the slurry's ability to place more proppant vertically into the fracture and help to maintain a better conductivity after fracturing treatment. A sufficiently high injection rate of the slurry is also needed to enable effective proppant flow in rough fractures. At certain low injection rates, the proppants carried by a low polymer solution might not exhibit a tree-like settling pattern, diminishing the effect of roughness on the proppant transport. This means that even in rough fractures, the treelike settling pattern of the proppants did not necessarily occur for sure; the injection rate should be properly selected to enable such phenomenon. With other conditions being kept constant, a higher proppant loading led to a higher final relative coverage of the proppants in the rough fractures. But if the injection rate used for delivering the proppants is not sufficiently high, we may encounter injectivity issues; in our lab experiments, this caused the choking of the pump. The heavier proppant (ceramic proppants) in the rough fracture models tended to suppress the tree-like settling pattern that was experienced by the lighter proppant (silica sands). This is attributed to the larger density of the ceramic proppants, leading to a larger settling velocity. In order to maximize the spreading of a given proppant over a rough fracture model, we should determine the proper values of all the essential injection parameters (including polymer solution, injection rate, proppant concentration) by striking a good balance among them. The conclusions obtained in this study shed light on how to optimize slurry injection parameters to achieve an optimal proppant-filling ratio during hydraulic fracturing.",14,14,4
Fracture,Proppant,"Fernandez, Macias E.; Sanchez, Martin; Pugnaloni, Luis A.",Proppant transport in a scaled vertical planar fracture: Vorticity and dune placement,Proppant transport; Hydraulic stimulation; Multiphase flow,POWER-LAW CORRELATIONS; SEDIMENT TRANSPORT; MECHANICS,"We report experimental results on the transport of proppant in a scaled planar cell. As a complement to many previous studies, we consider, apart from a proper scaling of the experimental cell and flow rate, a scaling of the perforations through which the fracturing slurry is injected. We also consider a fracture height relatively larger than usual, compatible with thick formations such as Vaca Muerta, Neuquen basin (Argentina). Under these conditions, we find that the flow pattern in the fracture presents large vortexes. The effect on the proppant transport is significant, yielding a much deeper placement of the dune than previously observed in similar experiments. We discuss the implications for the design of hydraulic fracturing operations.",14,14,3
Fracture,Proppant,"Wang, Fei; Li, Baoman; Chen, Qiaoyun; Zhang, Shicheng",Simulation of proppant distribution in hydraulically fractured shale network during shut-in periods,Shale; Fracture network; Proppant transport; Well shut-in; Proppant-carrying fluid flow,NUMERICAL-SIMULATION; TRANSPORT,"Proppant distribution is an important topic, because it is closely related to the success or failure of hydraulic fracturing treatment. Although, many proppant transport models have been published, there is still relatively limited research on proppant distribution between the created fracture network in shale especially during the post-treatment shut-in periods. In this paper, based on the intercoupling of particle hydrodynamics, fluid hydrodynamics, and poro-elastic rock mechanics, a mathematical model regarding the transport of liquid-solid phases has been established to simulate the behavior of the proppant transport and the carrying fluid migration in the fractured shale network during the well shut-in. The coupled model takes main hydraulic fractures, secondary induced fractures and matrix into account, namely a three-dimensional triple-porosity medium. All the important processes in fractured shale network can be explained by the liquid-solid transport simulation with the coupled model, including (1) liquid transport driven by viscous and gravity forces, (2)proppant particle transport driven by the horizontal forces of drag, inertia and collision, and the vertical gravity and buoyancy, and (3) hydraulic-fracture closure, which is considered as a poro-elastic rock deformation during the shut-in periods. Based on the conservation of mass and momentum, the liquid-solid transport coupled with rock deformation, are described by a set of partial differential equations, which are solved by the semi-implicit finite-difference method. The evolution of the proppant concentration and fluid pressure profiles is calculated. The fluxes of the proppant and proppant-carrying fluids between the main fracture and secondary fracture during the post-stimulation well shut-in are also calculated. The influences of proppant properties (concentration, density and size) and proppant-carrying fluid properties (viscosity and density) on the proppant distribution are investigated. The results of this study are expected to provide a better understanding of the proppant and proppant-carrying fluid distribution for different physical properties of proppant and carrying fluids, and explain which is the predominant factor influencing the proppant distribution during the shut-in periods.",13,13,7
Fracture,Proppant,"Zhou, Lei; Shen, Zhonghui; Wang, Jiandong; Li, Honglian; Lu, Yiyu",Numerical investigating the effect of nonuniform proppant distribution and unpropped fractures on well performance in a tight reservoir,,THEORETICAL CONDUCTIVITY ANALYSIS; LIGHT-WEIGHT PROPPANTS; LONG-TERM CONDUCTIVITY; NATURAL FRACTURES; PERMEABILITY; SIMULATION; EMBEDMENT; TRANSPORT; CLOSURE,"Distribution of the propped and unpropped fracture is an important factor affecting well performance that is necessary to study. This paper presents new numerical proppant and rock fracture conductivity models. The models are based on the results of physical experiments conducted for this study and the models consider proppant deformation, embedding, and loading paths. The models were implemented in a 3D hydromechanical coupled numerical simulator to model well production. A 3D hydraulic fracturing simulator was used to generate an artificial fracture with nonuniform proppant distribution using reservoir and operational parameters from a tight oil reservoir in northwestern China. The fracture generated by the model was further used to investigate the influence of the nonuniform propped fracture on well performance. According to the study, proppant distribution can significantly affect well performance, a decreased aperture distribution from the well to the fracture front is preferred when using certain amounts of proppant. A parameter sensitivity study was carried out during which the influence of proppant deformation, proppant embedment, proppant permeability, proppant volume, reservoir damage, in-situ stress, and the loading path effect were investigated. Based on the results, suggestions were given to improve the well performance.",13,14,5
Fracture,Proppant,"Zhao, Haifeng; Wang, Xiaohua; Liu, Zhiyuan","Experimental investigation of hydraulic sand fracturing on fracture propagation under the influence of coal macrolithotypes in Hancheng block, China",Coalbed methane; Hydraulic fracturing; Fracturing experiment; Coal macrolithotypes; Perforation location,EASTERN MARGIN; ORDOS BASIN; NUMERICAL-SIMULATION; NETWORK PROPAGATION; RESERVOIR; METHANE; SHALE; ROCK; MODEL; GEOMECHANICS,"The mechanical properties, brittleness and micro-fracture development of different coal macrolithotypes (bright coal, semi-bright coal, semi-dull coal and dull coal) are different, and these differences have an impact on the propagation of hydraulic fractures. To understand the influence of coal macrolithotypes on fractures propagation, several hydraulic sand fracturing experiments considering the classification of coal macrolithotypes were carried out by taking No. 11 coal seam of the Taiyuan formation in Hancheng block, China. We mainly investigated the influence of coal macrolithotypes and perforation location on the propagation of hydraulic fractures. Combined with observation results of mining excavation, the experimental results are verified. The research finds that fractures morphology and proppants distribution in bright-type coal is better than dull-type coal. Thus, bright-type coal is the fracturing sweet-spot section in coal seam. We also find that hydraulic fractures are prone to propagate along the stratigraphic interfaces or lithologic interfaces to form horizontal major-fractures, and the overall stimulation effect of coal seam is dependent on the fractures morphology and proppants placement of these horizontal major-fractures. The stimulation effect of horizontal major-fractures for coal seam is better when perforation location is selected near the weak planes instead of the middle of coal seam. The research results provide theoretical guidance for efficient fracturing of coal seam.",13,15,4
Fracture,Proppant,"Sun, Xin; Gao, Zhibin; Zhao, Mingwei; Gao, Mingwei; Du, Mingyong; Dai, Caili",Development and evaluation of a novel seawater-based viscoelastic fracturing fluid system,Viscoelastic fracturing fluid; Seawater; Performance evaluation; Microstructure,DISPERSED PARTICLE GEL; WORMLIKE MICELLES; RHEOLOGICAL PROPERTIES,"Based on the situation of the freshwater shortage during the large scale hydraulic fracturing on offshore-platform, a novel seawater-based viscoelastic fracturing fluid system was developed. The system was composed with a commercial anionic - nonionic viscoelastic surfactant named Fatty Methyl Ester Sulfonates (FMES) with the concentration of 60 mmol/L, the South China Sea simulated seawater with the TDS of 32500 mg/L and Na+ with the concentration of 1320 mmol/L. On the basis of this fracturing fluid system, a series of performances have been evaluated through extensive experiments. Analysis of laboratory tests indicated that the new fluid has good viscosity stability, low fluid loss and high proppant suspending ability under 75 degrees C. This fluid always appeared as a pseudoplastic fluid at various shearing speeds. After high speed shearing, the viscosity recovered quickly which means the fluid has remarkable self-repairability. This fluid breaks rapidly once oil injected. The observed permeability return rate achieved through core flooding experiment was over 70%, which indicated low formation damage after fracturing. Furthermore, the vermicular micelle and microstructure of fluid system has been discovered through Cryogenic Transmission Electron Microscope (cryo-TEM), which well explained the mechanism of excellent performances of fluid system.",13,13,4
Fracture,Stress Sensitivity,"Wu, Zhongwei; Cui, Chuanzhi; Lv, Guangzhong; Bing, Shaoxian; Cao, Gang",A multi-linear transient pressure model for multistage fractured horizontal well in tight oil reservoirs with considering threshold pressure gradient and stress sensitivity,Multi-linear transient pressure model; Multistage fractured horizontal well; Stress sensitivity; Threshold pressure gradient; Pedrosa's transformation; Perturbation theory,NON-DARCY FLOW; SHALE; PERMEABILITY; PERFORMANCE,"In general, tight oil reservoirs has a numerous tiny and complicated throats, and ultra-low permeability, which leads to a low-velocity non-Darcy flow when the fluid flows in tight reservoirs. The permeability of tight oil reservoirs is no longer a constant, but a variable, which is dependent on reservoir pressure. In other word, the tight oil reservoir is stress sensitive media. The low-velocity non-Darcy flow and stress sensitivity will greatly affect the bottom hole pressure response. So, the low-velocity non-Darcy flow and stress sensitivity should be taken into consideration when researching the transient pressure behaviors of multistage fractured horizontal wells. Currently, there are many researches on transient pressure behaviors of the multistage fractured horizontal well, but none of these researches has taken the low-velocity non-Darcy flow and stress sensitivity into consideration simultaneously. In this paper, threshold pressure gradient and permeability modulus are used to characterize the low-velocity non-Darcy flow and stress sensitivity, respectively. And, a multi-linear transient pressure model of multistage fractured horizontal well with considering low-velocity non-Darcy flow and stress sensitivity is established. The Pedrosa's transformation, perturbation theory, Laplace transformation and stehfest numerical inverse are used to solve this transient pressure model. The novel model is verified by comparing the result of proposed model with that of Ekaterina Stalagorova's model. According to the dimensionless pressure derivative curve, the flow process can be identified as six regimes: (1)the main fracture linear flow stage, (2)the first transition flow stage, (3)dual-linear flow stage,(4)the second transition flow stage, (5)the formation linear flow stage, (6)the boundary flow stage. Finally, the effects of threshold pressure gradient, permeability modulus and fracture density of stimulated reservoir on dimensionless pressure derivative are analyzed. This research provides theoretical support for correctly understanding the flow law of multistage fractured horizontal well.",42,44,6
Fracture,Stress Sensitivity,"Li, Xin; Fu, Xuehai; Ranjith, P. G.; Xu, Jiang",Stress sensitivity of medium- and high volatile bituminous coal: An experimental study based on nuclear magnetic resonance and permeability-porosity tests,Stress sensitivity; Coalbed methane; Medium volatile bituminous coal; High volatile bituminous coal; Low-field nuclear magnetic resonance,SOUTHERN JUNGGAR BASIN; TURPAN-HAMI BASIN; WATER EFFECTIVE PERMEABILITY; DYNAMIC PREDICTION MODEL; NMR RELAXATION METHOD; HIGH-RANK COALS; LOW-FIELD NMR; NW CHINA; MERCURY INTRUSION; PORE STRUCTURE,"Coalbed methane (CBM) development is in progress in northwestern China, where there are deposits of medium volatile bituminous coal (MVBC) and high volatile bituminous coal (HVBC). Stress sensitivity can lead to low gas-production during CBM development. In this study, three groups of HVBC samples and one group of MVBC samples are applied for low-field nuclear magnetic resonance (LF-NMR) and permeability-porosity tests (P-PT) under confining pressure. Each group contained two cores with similar physical properties, and one is used for LF-NMR and the other for P-PT under confining pressure. The key apertures dominating the reduction of permeability are revealed by comparative analysis of the results of LF-NMR and PP-T under confining pressure. Influences of multiscale pores and structure of macro-pores and fractures (MP-F) on stress sensitivity are discussed. In addition, this paper discusses the methods for determination of compressibility coefficients. The results shows that MP-F are the key apertures influencing stress sensitivity. Compressibility of macro-pore is the greatest, followed by mesopores (MEP), and that of micro-pores and transition pores (MP-TP) is the lowest. Stress sensitive stages are influenced by structure of MP-F. Method A (based on P-PT) is suitable for calculating compressibility coefficient of coal with a high proportion of MP-F and method B (based on LF-NMR) has advantages for calculating compressibility coefficients of MP-TP, MEP, and MP-F, respectively. An improved model, considering matrix deformation of low rank coal and compressibility coefficient of key apertures, is proposed to calculate permeability under increased effective stress.",28,29,5
Fracture,Stress Sensitivity,"Wang, Bo; Zhou, Fujian; Zou, Yushi; Liang, Tianbo; Wang, Daobing; Xue, Yanpeng; Gao, Liyang",Quantitative investigation of fracture interaction by evaluating fracture curvature during temporarily plugging staged fracturing,Temporarily plugging staged fracturing; XFEM-Based CZM; Plugging efficiency; Propagation path,HYDRAULIC-FRACTURE; NUMERICAL-SIMULATION; HORIZONTAL WELL; FINITE-ELEMENT; NATURAL FRACTURES; SHALE FORMATIONS; PROPAGATION; STIMULATION; MODEL,"Temporarily plugging staged fracturing (TPSF) technique has been successfully applied in unconventional reservoirs. This paper quantificationally investigates fracture interaction between previous and subsequent fractures during TPSF through numerical experiments. Using XFEM-based CZM (the cohesive zone model based on the extended finite element method), a 2D fully fluid-solid coupling model is established to perform the investigation. Typically, the concept of ""turning angle"" is proposed to quantify the degree of fracture interaction under different conditions. Moreover, the opening of the previously created fracture is simulated by truss model, which indicates truss elements distributed on the fracture surfaces; the effects of formation heterogeneity are investigated by changing rock mechanical properties surrounding the subsequent fractures. Simulation results reveal that the previously created and propped fracture will generate induced stresses, which cause the subsequent fracture to propagate with curvature. Factors influencing the subsequent fracture propagation curvature during TPSF, are sorted by sensitivity (strong to weak): plugging efficiency, Young's modulus, percent of initial aperture propped, fracture spacing, horizontal stress contrast, rock tensile strength, and formation permeability. The investigations provide a deep understanding of fracture interaction between previous and subsequent fractures during TPSF.",28,31,4
Fracture,Stress Sensitivity,"Chen, Shida; Tang, Dazhen; Tao, Shu; Ji, Xinyuan; Xu, Hao",Fractal analysis of the dynamic variation in pore-fracture systems under the action of stress using a low-field NMR relaxation method: An experimental study of coals from western Guizhou in China,Coal; Stress sensitivity; Cleat compressibility; Fractal; NMR,IN-SITU STRESS; CH4 ADSORPTION CAPACITY; DIFFERENT RANK COALS; SURFACE-AREA; MOLECULAR SIMULATION; MODEL MATCH; SAN-JUAN; PERMEABILITY; METHANE; GAS,"To quantitatively analyze the dynamic variation in pore-fracture systems under the action of stress, a low-field nuclear magnetic resonance (NMR) method was used to determine the stress sensitivity of six coal samples from western Guizhou in China. The NMR T-2 distributions show that the coals become considerably more compact due to the reduction of porosity with increasing coal rank and that the adsorption space (<= 100 nm) with short relaxation times (<= 2.5 ms) gradually become dominant With increasing confining pressures from 0 to 12 MPa, a significant decrease in peak areas with long relaxation times (> 2.5 ms) can be observed. Additionally, the lower rank coals have a higher stress sensitivity, and an increase in the adsorption space occurs due to the compression and closure of the seepage space (> 100 nm). When the pressure unloads (12 MPa -> 0 MPa), the destruction of the pore and fracture structures cannot be completely reversed. Moreover, the adsorption space fractal D-1 (T-2 <= 2.5 ms), seepage space fractal D-2 (T-2 > 2.5 ms) and the total pore space fractal D-NMR (0 < T-2 <= 10000 ms) were calculated with NMR fractal theory. The D-1 is generally less than 2, which does not conform to fractal geometry theory. The D-2 and D-NMR have positive linear correlations with the coal rank, the specific surface area of adsorption space and the Langmuir volume, while both of them decrease with increasing porosity and permeability. The higher D-2 and D-NMR indicate stronger adsorption capacity. With increasing confining pressure, D-2 increases gradually because of the closure of the seepage space. Furthermore, the cleat compressibility (C-f) calculated with the NMR results showed that C-f is not a constant factor but exhibits a decreasing trend as the pressure increases. The permeability at different pressures was also calculated with the C-f and initial permeability, which decrease exponentially with the increase of pressure. The negative linear relationship between the dynamic permeability and D-2 indicated that coals with high D-2 have low flow capability. The results of this study provide a visual method to quantify the stress sensitively of coal reservoirs within different pore sizes.",28,31,2
Fracture,Stress Sensitivity,"Li, Ning; Zou, Yushi; Zhang, Shicheng; Ma, Xinfang; Zhu, Xingwang; Li, Sihai; Cao, Tong",Rock brittleness evaluation based on energy dissipation under triaxial compression,Brittleness; Triaxial compression; Stress-strain curve; Energy dissipation; Failure behavior,ACOUSTIC-EMISSION RESPONSE; HYDRAULIC FRACTURE GROWTH; MECHANICAL-PROPERTIES; SHALE ROCKS; STRESS; MODEL; PROPAGATION; BEHAVIOR; CRITERIA; GRANITE,"Evaluating the brittleness of rock is significant for strategy determination of hydraulic fracturing, such as candidate selection and parameter optimization. A series of definitions and indices of brittleness have been proposed to characterize the mechanical behavior rock failure. However, these existing indices failed to consider the residual state and the confinement effect. Based on the analysis of energy evolution during the whole process of rock failure, the brittleness was redefined in this study as the comprehensive capability of dissipating little energy during the pre-peak stage and self-sustaining complete failure during the post-peak stage. Accordingly, a new energy-based brittleness index B was proposed in terms of the complete stress-strain curve to quantify this capability from following three aspects: the ratio of accumulated elastic strain energy and total absorbed energy during the pre-peak stage (B-1); the proportion of elastic strain energy in all energy source consumed for sustaining rock failure (B-2); and the dissipation extent of accumulated elastic strain energy during the post-peak stage (B-3). To verify the reliability of the new method, uniaxial and triaxial compression tests were performed on different types of rock samples. The application and comparison of various indices showed that the new brittleness index precisely characterized the stress-strain curves and failure behavior of rock samples under different confinement levels. The variation trends of brittleness with confining pressure were obviously distinct among different rock types. Three independent brittleness indices B-1, B-2, and B-3 were helpful for analyzing sensitivity difference of brittleness to confining pressure among different rock types. Accordingly, this new energy-based method can provide reliable evaluation of rock brittleness.",25,25,8
Fracture,Stress Sensitivity,"Zheng, Wenbo; Tannant, Dwayne D.",Influence of proppant fragmentation on fracture conductivity - Insights from three-dimensional discrete element modeling,Proppant crushing; Discrete element modeling; Particle breakage model; Permeability; Fracture conductivity,CRUSHING CHARACTERISTICS; BREAKAGE CRITERIA; NUMERICAL-MODEL; PERMEABILITY; EMBEDMENT; COMPACTION; PACKS; SOILS,"Proppant crushing under high closure stress is widely observed in the laboratory and the field but has rarely been simulated numerically. This paper presents 3D discrete element modeling of proppant fragmentation and its influence on the fracture conductivity. A particle breakage model was implemented to simulate proppant fragmentation. A practical procedure was developed to calibrate the parameters in the breakage model using stress-strain responses and grain size distributions from laboratory crush tests. The breakage model, along with the calibrated parameters for Jordan sand, Genoa sand, and a ceramic proppant, was used in a parametric analysis for multilayer proppant packs. The influence of proppant type, particle size, and proppant mixture on proppant fragmentation and fracture conductivity was examined. The results indicate that the proppant size needed to achieve optimal fracture conductivity is greatly affected by particle fragmentation, which in turn is sensitive to closure stress and size-dependent particle strength. A Hardin breakage ratio larger than 0.05 represents the onset of excessive proppant fragmentation that can greatly decrease fracture conductivity.",19,19,3
Fracture,Stress Sensitivity,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Liu, Wenyuan",Simulation of real gas mixture transport through aqueous nanopores during the depressurization process considering stress sensitivity,Shale gas; Nanoscale pores; Transport modeling; Gas mixture system; Stress sensitivity; Analytic model,GEOTHERMAL-ENERGY EXTRACTION; SHALE; FLOW; CO2; INJECTION; MODEL; WELL; PERMEABILITY; PERFORMANCE; SANDSTONE,"The study on shale gas transport mechanisms plays an important role in shale gas production simulation. The majority of previous works neglected the body gas diffusion mechanism, and the multiple effects of stress sensitivity and multi-component of gas mixture system. In this paper, first, a model is built considering the multiple transport mechanisms of continuum flow, slippage flow, body gas diffusion and Knudsen diffusion. Then, the multiple effects of stress sensitivity and multi-component of gas mixture system are coupled into the model. Results show that (a). For the body gas flow, both of the two weighted coefficients for items of body gas diffusion and slippage flow should be equal to one. And the ratio of one to Knudsen number is belong to the equation of body gas diffusion. (b). For a nanoscale pore of shale, the contribution of body gas diffusion on total mass flux cannot be neglected. The conductivities of continuum flow, slippage flow, modified slippage flow, Knudsen diffusion and weighted average flow decrease with decreasing of pressure due to shrinkage of nanopore radii and decrease in molecular concentration. (c). The decreasing of effective radii leads to the increase of the value of Knudsen number. The dominant transport mechanism is converting from modified slippage flow to Knudsen diffusion when the increase of stress sensitivity. (d). For methane confined in nanopores with extremely small effective transport radii, the injection of CO2 can increase the mobility of methane. After a period of CO2 injection, the methane molecules stored in nanopores can be flooded to fractures and then produced to the ground.",19,19,1
Fracture,Stress Sensitivity,"Wang, Boyang; Qin, Yong; Shen, Jian; Wang, Gang; Zhang, Qiusheng; Liu, Miao",Experimental study on water sensitivity and salt sensitivity of lignite reservoir under different pH,Lignite reservoirs; Water sensitivity; Salt sensitivity; pH,QUANTITATIVE-ANALYSIS; FUNCTIONAL-GROUPS; COAL FINES; FTIR; SPECTROSCOPY; TEMPERATURE; OXIDATION; MACERALS; FRACTURE; STRESS,"The water sensitivity and salt sensitivity of lignite reservoirs are important factors affecting the productivity of the coalbed methane (CBM) well. This paper took the lignite of Erlian Basin as the research object. The content and occurrence of mineral was analyzed by LTA + XRD combined with scanning electron microscopy (SEM), and distribution of each functional group of lignite was analyzed by infra-red spectrum. Based on the above analysis, standard salt water with different pH and salinity was used as the experimental injection fluid, and water sensitivity (salt sensitivity) experiments were performed under the condition of constant effective stress. The experimental results show that the sample contains a large number of water-sensitive minerals (kaolinite and illite/smectite mixed layer mineral), and the ratio of carbonyl, hydroxybenzene and carboxyl groups is 10:7:1. Hydrogen bonds are mainly OH center dot center dot center dot N hydrogen bonds. The lignite reservoirs with different pH have different degrees of water-sensitive damage, and the damage rates from high to low are partial alkalinity conditions (54.18%), partial acidity conditions (42.6%), and strong alkalinity conditions (23.67%). The dimensionless permeability changes with the decrease of salinity, which can be divided into three stages (no water sensitivity stage, particle migration water sensitivity stage, particle expansion water sensitivity stage) with 1250 mg/L and 10000 mg/L as the boundary. The displacement pressure and pH are the main controlling factors at different stages, and pH controls the wettability of pulverized coal and the hydration expansibility of clay minerals. The dimensionless permeability of lignite reservoir increases with the increase of salinity under the acidic condition. Under alkaline conditions, it is characterized by no-weak salt sensitivity. The greater the alkalinity, the stronger the salt sensitivity, which is mainly controlled by the change of the thickness of the water film under the influence of pH.",18,18,7
Fracture,Stress Sensitivity,"Zhao, Yan-long; Wang, Zhi-ming; Qin, Xing; Li, Jiang-tao; Yang, Hu",Stress-dependent permeability of coal fracture networks: A numerical study with Lattice Boltzmann method,Coal fracture networks; Lattice Boltzmann method; Fracture roughness; Effective stress; Stress sensitivity,GAS-FLOW; TRANSPORT-PROPERTIES; PREDICTION; SIMULATION; PRESSURE; MICROSTRUCTURE; MODEL,"Since coal permeability is sensitive to stress, fundamental understanding of gas flow in coal fracture networks and permeability change with varying effective stress are necessary in the processes of CBM production. Based on the rock elastic theory and finite difference method, the stress-strain model of reconstructed coal fracture networks is established. It has provided a more accurate geometry model under stress condition. For comparison purposes, gas permeability and porosity of coal sample with artificially generated fracture are measured under varying effective stress. Based on the experimental results and the Walsh model, fracture width and roughness are estimated. Lattice Boltzmann methods are implemented to model the flows in a single rough fracture under stress condition and the stress-dependent permeability is predicted. Compared with laboratory measurement, the maximum relative error is 25%. Furthermore, applications and case studies are performed for the flows in the 2D and 3D fracture networks. The effects of stress, fracture density, surface roughness and aperture on the associated permeability are discussed. The present study provides an alternative to investigate the microcosmic stress sensitivity mechanism of coal permeability.",18,18,3
Fracture,Stress Sensitivity,"Wang, Deqiang; Cheng, Linsong; Cao, Renyi; Jia, Pin; Fang, Sidong; Rao, Xiang; Wu, Yonghui; Dai, Dan",The effects of the boundary layer and fracture networks on the water huff-n-puff process of tight oil reservoirs,Tight reservoir; Water huff-n-puff; Volume fracture; Boundary layer; Embedded discrete fracture model,PERMEABILITY STRESS SENSITIVITY; HORIZONTAL WELLS; RELATIVE PERMEABILITY; SEMIANALYTICAL MODEL; FLOW BEHAVIOR; SHALE; PERFORMANCE; SIMULATION; SCALE,"Application of multi-fractured horizontal wells has led to significant progress in the development of tight oil reservoirs. However, oil production rapidly decreases and the estimated ultimate recovery is still low when the well is in production and approaching depletion. Water huff-n-puff is regarded as a useful measure to improve oil recovery due to oil-water imbibition and drainage. Additionally, complex fracture networks consisting of natural fractures (NF) and hydraulic fractures can significantly enhance oil recovery in the process of water huff-n-puff after multi-stage hydraulic fracturing. However, there is a non-flowing thin film on the solid-liquid wall surface in the pore-throats of the matrix, and the so-called boundary layer effect (BLE) is quite significant at the nanoscale. This effect reduces the effective flow space and effective permeability of the reservoir, leading to production damage. To date, few numerical simulation studies have considered the impact of the BLE and complex fracture networks in water huff-n-puff process simulation studies. In this study, the process of water huff-n-puff is evaluated considering complex fracture networks and formation damage in a matrix. The embedded discrete fracture model (EDMF), validated by local grid refinement (LGR), is applied to describe the distribution of hydraulic fractures and NF. The well performance considering the BLE is analyzed by a vectorization programming. The results show that the BLE reduces production and accelerates the production decline, so the BLE should be considered in reservoir simulations and productivity evaluations of water huff-n-puff processes. A certain degree of natural fracture development is conducive to improving the sweep efficiency of the water huff-n-puff, which could significantly improve oil recovery compared to depletion. By considering the impact of the BLE in water huff-n-puff simulations in tight oil reservoirs, it is possible to accurately evaluate the well performance and provide a theoretical basis for the optimization of water huff-n-puff.",17,16,5
Fracture,Stress Sensitivity,Liu Lijun; Yao Jun; Sun Hai; Huang Zhaoqin; Yan Xia; Li Longlong,Compositional modeling of shale condensate gas flow with multiple transport mechanisms,Shale; Condensate gas; Compositional model; Transport mechanism; Phase behavior,HYDROCARBONS RECOVERY; SCALE SIMULATION; RESERVOIRS; PERMEABILITY; FLUID; MICRO,"Shale condensate gas has gained great attention in recent years due to the production of profitable liquid hydrocarbons. The fluid flow in shale matrix is complex and influenced by multiple transport mechanisms, such as stress sensitivity, Knudsen diffusion, adsorption, molecular diffusion, and confined phase behavior. In addition, the coexistence of multiscale pore space, including hydraulic fractures, micro-fractures in simulated reservoir volume (SRV) and nanopores in matrix further increases the fluid flow complexity. Conventional models cannot commonly consider all the factors. In this work, we develop a hybrid model for condensate gas reservoir, where fluid flow is described by compositional model coupled with transport mechanisms, micro-fractures and hydraulic fractures are handled by multiple interacting continua (MINC) model and embedded discretized fracture model (EDFM). Then based on the proposed model, the effects of gas transport mechanisms on a multi-stage fractured horizontal well production are analyzed, where simulations are conducted with and without SRV to investigate the importance of SRV. Furthermore, some important reservoir parameters, such as SRV properties, hydraulic fracture length and bottom-hole pressure are also investigated with the proposed model.",16,17,4
Fracture,Stress Sensitivity,"Zhou, Lei; Shen, Zhonghui; Wang, Jiandong; Li, Honglian; Lu, Yiyu",Numerical investigating the effect of nonuniform proppant distribution and unpropped fractures on well performance in a tight reservoir,,THEORETICAL CONDUCTIVITY ANALYSIS; LIGHT-WEIGHT PROPPANTS; LONG-TERM CONDUCTIVITY; NATURAL FRACTURES; PERMEABILITY; SIMULATION; EMBEDMENT; TRANSPORT; CLOSURE,"Distribution of the propped and unpropped fracture is an important factor affecting well performance that is necessary to study. This paper presents new numerical proppant and rock fracture conductivity models. The models are based on the results of physical experiments conducted for this study and the models consider proppant deformation, embedding, and loading paths. The models were implemented in a 3D hydromechanical coupled numerical simulator to model well production. A 3D hydraulic fracturing simulator was used to generate an artificial fracture with nonuniform proppant distribution using reservoir and operational parameters from a tight oil reservoir in northwestern China. The fracture generated by the model was further used to investigate the influence of the nonuniform propped fracture on well performance. According to the study, proppant distribution can significantly affect well performance, a decreased aperture distribution from the well to the fracture front is preferred when using certain amounts of proppant. A parameter sensitivity study was carried out during which the influence of proppant deformation, proppant embedment, proppant permeability, proppant volume, reservoir damage, in-situ stress, and the loading path effect were investigated. Based on the results, suggestions were given to improve the well performance.",13,14,5
Fracture,Nuclear Magnetic Resonance,"Qin, Lei; Zhai, Cheng; Xu, Jizhao; Liu, Shimin; Zhong, Chao; Yu, Guoqing",Evolution of the pore structure in coal subjected to freeze - thaw using liquid nitrogen to enhance coalbed methane extraction,Cryogenic freezing; Fracturing; Coalbed methane; Nuclear magnetic resonance; Porosity,PERMEABILITY; DAMAGE; WATER; STRESS; TEMPERATURE; DURABILITY; CONCRETE,"The permeability of coalbed methane (CBM) reservoirs is typically very low and it is challenging and essential to effectively increase coal permeability to maximize CBM recovery. An exploratory study on enhancing coal porosity/permeability using freeze-thaw cycling with liquid nitrogen (LN2) was conducted. The changes of fracture and porosity in coal with the freeze - thaw treatment using LN2 were evaluated using nuclear magnetic resonance (NMR). After freeze - thaw treatment, the coal pore size tended to increase and new pores/fissures were generated. The growth rate of the pore size was positively correlated with the LN2 freezing duration. The effective porosity had a positive correlation with the freezing duration, but the correlation for residual porosity was negative. This means that the volume of irreducible fluid in the coal decreased while the amount of free fluid increased. Scanning electron micrograph studies indicated that the maximum fracture width in the coal samples grew from 5.56 mu m at a T-freezing = 1 min to 100 mu m for T-freezing = 60 min, matching the NMR findings. This study provides a scientific basis and guidance for engineering application of freeze-thaw using liquid nitrogen to enhance coalbed methane extraction.",54,53,18
Fracture,Nuclear Magnetic Resonance,Zhang Lufeng; Zhou Fujian; Zhang Shicheng; Li Zhu; Wang Ji; Wang Yuechun,Evaluation of permeability damage caused by drilling and fracturing fluids in tight low permeability sandstone reservoirs,Permeability damage; Pressure transmission test; Fracturing fluids; Drilling fluids; Tight sandstone reservoir,PULSE-DECAY METHOD; TRANSIENT LABORATORY METHOD; HYDRAULIC-PROPERTIES; GAS-PERMEABILITY; MECHANISM; METHODOLOGY; PERFORMANCE; RELAXATION; ROCKS; FLOW,"Tight sandstone reservoirs with low porosity and permeability are always vulnerable to damage due to drilling and fracturing fluids, which significantly impedes hydrocarbon production. Therefore, exploring damage evaluation methods has been an undeniable demand of formation protection and efficient development. However, the common steady-state core flow method is time-consuming and inaccurate for evaluating permeability damage in tight low permeability reservoirs. Aiming at this problem, this paper introduced pressure transmission test (PIT), a time-saving and accurate method, to quantitatively evaluate the core permeability damage degree from macroscopic perspective. Furthermore, nuclear magnetic resonance (NMR) was also used to analyze the damage mechanisms of fracturing fluids from microscopic perspective. In the fracturing fluids damage experiments, the results of PTT show that the ultimate damage degree of fracturing fluids is approximately 40%, of which water-sensitivity, water-block, and solid-phase are approximately 10%, 12% and 16%, respectively. With the technique of NMR, the damage mechanisms due to fracturing fluids are also investigated. In the drilling and fracturing fluids damage experiments, the results of PIT show that the drilling fluids cause the major damage. In the experiments of acidizing treatment, the chelating acid shows excellent properties in reliving core permeability damage caused by drilling and fracturing fluids. This study provides a new idea for evaluating permeability damage in low permeability reservoirs, such as shale, tight sandstone reservoirs, bedrock reservoirs, and so on.",37,38,12
Fracture,Nuclear Magnetic Resonance,"Guo, Xiaobo; Huang, Zhilong; Zhao, Libin; Han, Wei; Ding, Chao; Sun, Xiongwei; Yan, Ruitao; Zhang, Tonghui; Yang, Xuejun; Wang, Ruomei","Pore structure and multi-fractal analysis of tight sandstone using MIP, NMR and NMRC methods: A case study from the Kuqa depression, China",Tight sandstone; Fractal dimension; Pore structure; Kuqa depression,ORDOS BASIN; TARIM BASIN; SIZE DISTRIBUTION; GAS SANDSTONE; OIL; POROSIMETRY; PARAMETERS; RESERVOIRS; DYNAMICS; ROCKS,"The pore structure and fractal characteristic of tight gas sandstone from Cretaceous Bashijiqike Formation in Kuqa depression were investigated, using thin section, scanning electronic microscope (SEM), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR) and NMR cryoporometry (NMRC) measurements. The pores of tight sandstone samples mainly contain residual primary intergranular pores, intergranular and intragranular dissolved pores, micropores related to clay aggregates and microfractures. The MIP, NMR and NMRC analyses show that the pore structure of tight sandstone is complex and heterogeneous at different pore scales, displaying as a multi-fractal feature. Fractal dimension Dg-s (with respect to small pore throats) from MIP and Dn-1 (long T-2 relaxation time, representing large pores and fractures or movable-fluid pores) are negatively correlated with porosity, permeability, median pore throat radius and skewness, and have inverse relationships with bound water saturation (S-bnd). Fractal dimension Dg-b ( > 3.0, with respect to larger pore throats) and Dn-s ( < 2.0, short T-2 relaxation time, representing small pores or bound-water pores) from NMR don't present clear relationships with most of pore structure parameters. Fractal dimension Dc-(1) and Dc-(2) from NMRC show more complex or inconspicuous relationships with pore structure parameters, in the pore diameter size < 500 nm. Hence, Dg-s from MIP and Dn-1 from NMR can be considered as effective parameters for pore structure and fluid properties characterization of tight sandstone. Fractal dimension Dg-b ( > 3.0) and Dn-s ( < 2.0) have no practical significance to characterize the pore structure of tight sandstone. The formation of residual primary intergranular pores and intergranular dissolution pores can reduce the fractal dimension which could be an important sign of effective reservoirs in the study area.",37,39,10
Fracture,Nuclear Magnetic Resonance,"Cheng, Zhilin; Ning, Zhengfu; Ye, Xiongfei; Wang, Qing; Zhang, Wentong",New insights into spontaneous imbibition in tight oil sandstones with NMR,Spontaneous imbibition; Tight oil sandstones; Gravity effect; Anisotropic pore structure; Viscosity effect,PORE STRUCTURE; UNDERSTANDING WETTABILITY; BOUNDARY-CONDITIONS; SHAPE FACTOR; RECOVERY; SHALE; WATER; RESERVOIRS; PRESSURE; FLUID,"Previous research has confirmed that substantial yield has been recovered in the soaking period after hydraulic fracturing. Spontaneous imbibition (SI) is the primary mechanism responsible for the enhanced oil production and has become an effective oil recovery method with regards to unconventional reservoirs. Despite the importance of SI, an in-depth understanding of the features of SI in tight reservoirs is still inadequate. In this article, nuclear magnetic resonance (NMR) T-2 was employed to study the dynamic behavior of imbibition in tight sandstone samples from Yanchang formation, Ordos Basin. Additionally, high-pressure mercury intrusion (HPMI) and the initial T-2 of a core sample were combined to characterize pore structures of tight rocks and oil distributions in various pores at different imbibition stages. Then, the effects of gravity, anisotropic pore structure, and non-wetting phase (NWP) viscosity on imbibition recovery were determined via the variations in T-2 spectra for each sample. The results show that the tight cores feature a multiscale pore structure. Sub-micropores is the dominant type providing the major contribution to oil recovery, while nanopores have largest imbibition efficiency due to the larger capillary force. Gravity of fluids has a non-trivial effect on SI and cannot be neglected in tight samples under two-ends-open (TEO) or one-end-open (OEO) conditions; this seemingly counterintuitive finding is because the capillary force is weakened by the resistance force caused by the intricate flow paths and other possible surface forces at the nanoscale. Imbibition performance in a tight medium is strongly related to its pore structure. The variations in directional permeabilities, relative permeabilities and capillary pressure functions resulting from highly anisotropic samples greatly affect both the ultimate oil recovery and imbibition rate for tight samples under TEO condition, but only impact imbibition rate under allfaces-open (AFO) condition. Furthermore, because tight oil has a narrow range of viscosity, the imbibition behavior in tight samples may not be sensitive to the oil viscosity. It would be hoped that the insights gained from this study can help to improve our understanding of imbibition characteristics in tight reservoirs and develop new scaling models for the predication of oil recovery.",32,34,10
Fracture,Nuclear Magnetic Resonance,"Li, Xin; Fu, Xuehai; Ranjith, P. G.; Xu, Jiang",Stress sensitivity of medium- and high volatile bituminous coal: An experimental study based on nuclear magnetic resonance and permeability-porosity tests,Stress sensitivity; Coalbed methane; Medium volatile bituminous coal; High volatile bituminous coal; Low-field nuclear magnetic resonance,SOUTHERN JUNGGAR BASIN; TURPAN-HAMI BASIN; WATER EFFECTIVE PERMEABILITY; DYNAMIC PREDICTION MODEL; NMR RELAXATION METHOD; HIGH-RANK COALS; LOW-FIELD NMR; NW CHINA; MERCURY INTRUSION; PORE STRUCTURE,"Coalbed methane (CBM) development is in progress in northwestern China, where there are deposits of medium volatile bituminous coal (MVBC) and high volatile bituminous coal (HVBC). Stress sensitivity can lead to low gas-production during CBM development. In this study, three groups of HVBC samples and one group of MVBC samples are applied for low-field nuclear magnetic resonance (LF-NMR) and permeability-porosity tests (P-PT) under confining pressure. Each group contained two cores with similar physical properties, and one is used for LF-NMR and the other for P-PT under confining pressure. The key apertures dominating the reduction of permeability are revealed by comparative analysis of the results of LF-NMR and PP-T under confining pressure. Influences of multiscale pores and structure of macro-pores and fractures (MP-F) on stress sensitivity are discussed. In addition, this paper discusses the methods for determination of compressibility coefficients. The results shows that MP-F are the key apertures influencing stress sensitivity. Compressibility of macro-pore is the greatest, followed by mesopores (MEP), and that of micro-pores and transition pores (MP-TP) is the lowest. Stress sensitive stages are influenced by structure of MP-F. Method A (based on P-PT) is suitable for calculating compressibility coefficient of coal with a high proportion of MP-F and method B (based on LF-NMR) has advantages for calculating compressibility coefficients of MP-TP, MEP, and MP-F, respectively. An improved model, considering matrix deformation of low rank coal and compressibility coefficient of key apertures, is proposed to calculate permeability under increased effective stress.",28,29,5
Fracture,Nuclear Magnetic Resonance,"Chen, Shida; Tang, Dazhen; Tao, Shu; Ji, Xinyuan; Xu, Hao",Fractal analysis of the dynamic variation in pore-fracture systems under the action of stress using a low-field NMR relaxation method: An experimental study of coals from western Guizhou in China,Coal; Stress sensitivity; Cleat compressibility; Fractal; NMR,IN-SITU STRESS; CH4 ADSORPTION CAPACITY; DIFFERENT RANK COALS; SURFACE-AREA; MOLECULAR SIMULATION; MODEL MATCH; SAN-JUAN; PERMEABILITY; METHANE; GAS,"To quantitatively analyze the dynamic variation in pore-fracture systems under the action of stress, a low-field nuclear magnetic resonance (NMR) method was used to determine the stress sensitivity of six coal samples from western Guizhou in China. The NMR T-2 distributions show that the coals become considerably more compact due to the reduction of porosity with increasing coal rank and that the adsorption space (<= 100 nm) with short relaxation times (<= 2.5 ms) gradually become dominant With increasing confining pressures from 0 to 12 MPa, a significant decrease in peak areas with long relaxation times (> 2.5 ms) can be observed. Additionally, the lower rank coals have a higher stress sensitivity, and an increase in the adsorption space occurs due to the compression and closure of the seepage space (> 100 nm). When the pressure unloads (12 MPa -> 0 MPa), the destruction of the pore and fracture structures cannot be completely reversed. Moreover, the adsorption space fractal D-1 (T-2 <= 2.5 ms), seepage space fractal D-2 (T-2 > 2.5 ms) and the total pore space fractal D-NMR (0 < T-2 <= 10000 ms) were calculated with NMR fractal theory. The D-1 is generally less than 2, which does not conform to fractal geometry theory. The D-2 and D-NMR have positive linear correlations with the coal rank, the specific surface area of adsorption space and the Langmuir volume, while both of them decrease with increasing porosity and permeability. The higher D-2 and D-NMR indicate stronger adsorption capacity. With increasing confining pressure, D-2 increases gradually because of the closure of the seepage space. Furthermore, the cleat compressibility (C-f) calculated with the NMR results showed that C-f is not a constant factor but exhibits a decreasing trend as the pressure increases. The permeability at different pressures was also calculated with the C-f and initial permeability, which decrease exponentially with the increase of pressure. The negative linear relationship between the dynamic permeability and D-2 indicated that coals with high D-2 have low flow capability. The results of this study provide a visual method to quantify the stress sensitively of coal reservoirs within different pore sizes.",28,31,2
Fracture,Nuclear Magnetic Resonance,"Zhao, Peiqiang; Wang, Xixin; Cai, Jianchao; Luo, Miao; Zhang, Jin; Liu, Yuming; Rabiei, Minou; Li, Chuncheng",Multifractal analysis of pore structure of Middle Bakken formation using low temperature N-2 adsorption and NMR measurements,Middle Bakken; Multifractal analysis; N-2 adsorption; Nuclear magnetic resonance (NMR),NUCLEAR-MAGNETIC-RESONANCE; RATE-CONTROLLED POROSIMETRY; FORD SHALE SAMPLES; SICHUAN BASIN; GAS-RESERVOIR; FRACTAL CHARACTERIZATION; ORGANIC-MATTER; OIL; SANDSTONE; DIMENSION,"Understanding the complexity and heterogeneity of pore structure can improve the comprehensive characterization for complex unconventional reservoirs and better exploit those resources. In this paper, multifractal analysis was conducted on low temperature N-2 adsorption and NMR T-2 distribution for the pore structure investigation in Middle Bakken formation in Williston Basin, USA. Results show that the averages of specific surface area, total pore volume, the average pore size of five N-2 adsorption samples are 3.31 m(2)/g, 0.008 cm(3)/g, and 19.57 nm, respectively. Six NMR T(2 )distributions are bimodal and the signals of left dominant peaks are mainly distributed between 0.3 ms and 10 ms. The T-2 logarithmic mean value ranges from 2.18 ms to 2.95 ms with an average value of 2.57 ms. Both N-2 adsorption isotherms and T-2 distribution demonstrated the multifractal nature of different pore sizes. The key multifractal parameter, singularity strength range (Aa) calculated from N-2 adsorption and T-2 distribution are respectively distributed in scopes of 0.72-1.54 and 1.63-2.89, indicating that the heterogeneity of pore space from T-2 distribution is stronger than that from N-2 adsorption. It was observed that the specific surface, micro pore volume, and average pore size are correlated well with Delta alpha. There are no any correlations between Delta alpha and porosity and T-21m, but the cumulative porosity and width of right secondary peaks have an impact on the Delta alpha, which means that the heterogeneity difference between the two methods is attributed by larger pore and micro fractures.",27,27,7
Fracture,Nuclear Magnetic Resonance,"Lai, Fengpeng; Li, Zhiping; Zhang, Tiantian; Zhou, Anqi; Gong, Bao","Characteristics of microscopic pore structure and its influence on spontaneous imbibition of tight gas reservoir in the Ordos Basin, China",Tight gas reservoir; Microscopic pore structure; Spontaneous imbibition; Experiments; Grey relational analysis,SANDSTONE RESERVOIRS; FLOW; PERMEABILITY; SHALE; MODEL,"Spontaneous imbibition is an important mechanism governing the tight reservoir production performance, especially in the early stage of production after hydraulic fracturing. The microscopic pore structure of reservoirs is an important factor affecting imbibition. In this study, high-pressure mercury injection (HPMI), rate-controlled mercury injection, and low-temperature nitrogen adsorption (LP-N(2)GA) were preformed to study pore structure characteristics and fluid distribution in samples from the Ordos Basin, China. Nuclear magnetic resonance (NMR) and imbibition experiments were used to investigate the fluid distribution in porous media during imbibition. The porosity of samples ranges from 11.378% to 12.356%, with an average of 12.034%. The permeability of samples ranges from 0.034 mD to 0.056 mD, with an average of 0.048 mD. Results show that the recovery ranges from 68% to 94.81%, with an average of 81.09%. The reservoir is dominated by open flat slit micropores and mesopores. Sample pore volume ranges from 0.0155 ml/g to 0.0193 ml/g, with an average of 0.01687 ml/g. Micropores and mesopores less than 50 nm provide most of the pore volume. Pore radius and pore-throat ratio were obtained from experiments. Imbibition occurs primarily in pores ranging from 0.1 mu m to 1 mu m in radius, followed by pores ranging from 1 mu m to 10 mu m. The effects of porosity, permeability, average pore radius, average throat radius, average pore-throat ratio, specific surface area, and pore volume on imbibition recovery were statistically analyzed. Grey relational analysis was applied to sequence the imbibition influencing factors and determine the most influential factor. Results demonstrate that imbibition recovery is the most affected by average pore radius, followed by permeability, porosity, average pore-throat ratio, median radius, average throat radius, and specific surface area.",19,18,4
Fracture,Cement,"Zhang, Ruxin; Hou, Bing; Han, Huifen; Fan, Meng; Chen, Mian",Experimental investigation on fracture morphology in laminated shale formation by hydraulic fracturing,Shale; Fracture propagation; Discontinuities; Fracturing energy; Horizontal stress difference,PROPAGATION BEHAVIOR; INITIATION; CRITERION,"A complex fracture network, which is the precondition of stimulated reservoir volume for shale formation, depends on the interaction between hydraulic fractures and discontinuities, such as bedding planes and natural fractures. However, the fracture propagation behavior in laminated shale formation still maintains ambiguous and the formation mechanism of complex fracture network has not been well understood. Therefore, hydraulic fracturing simulated experiments were conducted on shale outcrops to clarify above issues under the effects of multiple factors, such as horizontal stress difference, pump rate, and fluid viscosity. The results reveal that dilation and crossing are two main hydraulic fracture propagation behaviors because of discontinuities influencing, resulting in three categories of the ultimate fracture morphologies. Simple fracture is a single induced fracture. Complex fracture is consisted of two or more induced fractures which do not link up with each other. However, network fracture includes induced fractures which interweave with each other like a network. All the fracture geometries are generated under the mutual interaction of natural factors and engineering factors. A large horizontal stress difference and a high fracturing energy reduce the complexity of fracture geometry, whereas, a small horizontal stress difference and a low fracturing energy enhance the activated probability of discontinuities, resulting in a complex fracture network. Furthermore, weak cementing strength and large opening degree of discontinuities increase the complexity of the fracture. In addition, the fracturing curve reflects fracture morphology indirectly. Simple fracturing curve and steady extensive pressure indicate the simple fracture. The rising extensive pressure implies the complex fracture, whereas, the fluctuation of fracturing curve suggests the network fracture. In the meantime, each fracture morphology has its own dimensionless net pressure features, which could be applied to judge fracture morphology in shale formation.",24,26,8
Fracture,Cement,"He, Wenhao; Chen, Keyong; Hayatdavoudi, Asadollah; Sawant, Kaustubh; Lomas, Matthew","Effects of clay content, cement and mineral composition characteristics on sandstone rock strength and deformability behaviors",Clay content; Rock strength; Deformability; Cement; Mineral composition; Scanning electron microscope (SEM),,"To keep the stability and integrity of wellbore, it is required to figure out the interaction between clays, water and rock strength in the drilling process. As revealed in available literatures, a high content of clays usually leads to a low value of rock strength and can easily result in the deformation of rocks. However, few studies can succeed in taking the mineral composition and the cement type of clays into consideration. By combining scanning electron microscope (SEM), X-ray diffraction (XRD) analysis with the Brazilian tests, this research can explain the overall effects of clays on the rock strength and deformability behaviors in three kinds of sandstones. The results indicate that the content contrast cannot be a determinant factor in specifying the rock strength. When compared with a lower value, a higher clay content can also exhibit high tensile strength due to a difference in the cement and mineral composition characteristics of clays. Moreover, chlorites were found to contribute more to the strength loss when encountered with water than montmorillonite and illite. This is most likely due to its undulatory surface which can trap much water and thus locally cause massive expansion of clays. According to the cement types, the fracture patterns can be classified into three groups: (1) Grain sliding occurs when abundant clays cement the matrix. The fracture goes through the soft clay cement and the contact surface between clays and grains. (2) Grain fracturing occurs when the clays cannot prohibit the quartz overgrowth, and the fracture can run across the silica-cemented grains. (3) Grain shearing occurs when the rock matrix is un-consolidated and is filled with few clays between grains. The fracture tends to break the rock grains apart in an irregular behavior. Meanwhile, the strengthening mechanism of lost circulation materials was also studied by tracking their migrations through porous media using energy-dispersive system (EDS).",23,23,11
Fracture,Cement,"Guo, Xueli; Li, Jun; Liu, Gonghui; Xi, Yan; Zeng, Yijin; He, Miao; Yan, Hui",Numerical simulation of casing deformation during volume fracturing of horizontal shale gas wells,Casing deformation; Stage finite element model procedure; Volume fracturing; Fault slip; Transient temperature; Cement property,UNCONVENTIONAL RESOURCE EXPLOITATION; INTEGRITY IMPLICATIONS; FINITE-ELEMENT; OIL; EARTHQUAKES; MECHANICS; MODEL; LAW,"Casing deformation problems occur frequently during volume fracturing of shale gas wells. It is crucial to assess the casing deformation near heel (the beginning of the horizontal wellbore trajectory) where natural faults exist among 84.6% of the deformation positions in some shale plays. Based on the source mechanism, the fault slip distance was derived from microseismic inversion. Then, three-dimensional physical and finite element models were established using a stage finite element model procedure to investigate the influences of fault slippage on casing stress and displacement. Other factors such as pump rate, fracturing pressure, formation anisotropy, formation elastic modulus, cement sheath elastic modulus, casing size, and cement sheath thickness were taken into consideration. The results show that (1) fault slippage is an important mechanism of casing deformation near heel. The casing has a higher risk of deformation under the conditions of fault slippage combined with high external stress and internal pressure. (2) Under different slip distances, the casing Mises stress dramatically increases with an increase in the cement sheath and formation elastic moduli and the ratio of the casing diameter to the thickness D-out/t. (3) The high pump rate, high inner casing pressure, large formation anisotropy, and small cement sheath thickness can aggrandize casing stress. The calculated casing displacements using this model obtained good agreement when compared to the deformations of the actual wells. Countermeasures such as avoiding natural fault areas, using cement with an elastic modulus smaller than 10 GPa, using a higher grade and smaller diameter casing with a value of D-out/t smaller than 12.7 can be effective to prevent casing deformation during multi-fracturing operation.",21,21,2
Fracture,Cement,"Zeng, Yijin; Liu, Rengguang; Li, Xiaojiang; Zhou, Shiming; Tao, Qian; Lu, Peiqing",Cement sheath sealing integrity evaluation under cyclic loading using large-scale sealing evaluation equipment for complex subsurface settings,Cement sheath; Sealing evaluation equipment; Failure mechanism; Cyclic loading; Hydraulic fracturing,,"Cement sheaths should provide zonal isolation and structural support through the entire service lifetime of wells. However, even if high-quality primary cementing was achieved, variations in pressure, for example, those due to staged fracturing in shale gas wells, are likely to lead to sealing integrity failure of the cement sheath. This work presents large-scale sealing evaluation equipment to assess the failure mechanisms of cement sheaths under cyclic loading. The equipment includes a borehole system, pressure system, and control and data acquisition system for automatic loading and unloading, gas channeling monitoring and pressure change and gas output recording. The pressure limit of the equipment is 120 MPa. A finite element model of the borehole system and sealing equipment was built to study the stress and strain under internal pressure. The failure mechanisms of the sealing integrity of the cement sheath were obtained by combining the test results with the finite element calculations. At a high internal pressure, plastic deformation was produced during loading due to the residual strain that arose after unloading of the cement sheath. Therefore, incompatible deformation occurred, and the tensile stress increased at the interfaces of the cement sheath. Under repeated loading and unloading, the plastic deformation increased, and the residual strain and interface tensile stress also increased. When the interface tensile stress exceeded the bonding strength, a microannulus formed between the cement sheath and casing. Based on these results, guidelines for the assessment of the long-term sealing integrity of a shale gas well cement sheath and for the selection of mechanical properties of the cement systems are given to mitigate the risk of zonal isolation failure.",17,23,2
Fracture,Cement,"Yan, Yan; Guan, Zhichuan; Xu, Yuqiang; Yan, Weijun; Wang, Hongtu",Numerical investigation of perforation to cementing interface damage area,Perforation fluid channeling cementing; interface damage area numerical simulation,PENETRATION DEPTH; SHEATH INTEGRITY; TARGET STRENGTH; CRACK-GROWTH; PROPAGATION; SIMULATION; IMPACT; FORMULATION; INITIATION,"Perforation will cause local damage to the cement and cementing interface, increasing the possibility of fluid channeling during hydraulic fracturing. Perforation experiment of ring target is extremely dangerous and cementing interface damage is difficult to observe, so the numerical model based on LS-DYNA software is set up in this paper. Cylindrical target penetration test is used to verify the interface damage area caused by perforation. Then, the effects of confining pressure, shear modulus of cement and diameter of shaped charge on interface damage area are analyzed. The results reveal that the damage area of casing/cement interface and the confining pressure shows a quadratic function relationship. The interface damage area has a logarithm function relationship with cement shear modulus and a strongly linear relationship with diameter of the shaped charge. In order to reduce interface damage caused by perforation, cement with lower shear modulus should be selected.",16,16,0
Fracture,Cement,Zhao Zhongxiang; Dong Chunmei; Zhang Xianguo; Lin Chengyan; Huang Xin; Duan Dongping; Lin Jianli; Zeng Fang; Li Dan,"Reservoir controlling factors of the Paleogene Oligocene Huagang Formation in the north central part of the Xihu Depression, East China Sea Basin, China",East China Sea Basin; Xihu depression; Huagang formation; Reservoir controlling factors; Low permeability - tight reservoir,DEPOSITIONAL FACIES; SANDSTONES; POROSITY; COMPACTION; DIAGENESIS; FIELD; CEMENTATION; PROPAGATION; PREDICTION; KAOLINITE,"Huagang Formation is a typical offshore, deep, low-permeability, tight sandstone reservoir with a low level of exploration and development and unclear control factors in the North Central area of the Xihu Depression in the East China Sea Basin. In this paper, we begin with the analysis of basic data, such as cores, casting thin sections, cathode luminescence, scanning electron microscopy, physical property statistics, grain size analysis, mercury penetration and magnetic resonance imaging, combined with field logging data from conventional logging, imaging logging and three-dimensional seismic imagery. The reservoir's physical properties were comprehensively discussed in terms of provenance, deposition, diagenesis and fractures. The results showed that the reservoir physical properties of the Huagang Formation were mainly affected by compaction, and the porosity and permeability decreased with the depth of burial. When the depth exceeds 4000 m, the porosity is basically < 10% and the permeability is nearly < 1 mD. The compaction above 4000 m was mainly controlled by provenance and depositional microfacies. The reservoir physical properties in the northern provenance is better than that of the east provenance. A high-energy braided channel is the best physical depositional microfacies. The reservoir formed by event sedimentation, such as from storms and floods, due to poor sorting, often containing mud and so on, with poor physical properties. Carbonate cementation only had a great influence on the local reservoir. Illite, illite/smectite and pore-filling chlorite were important factors affecting physical property deterioration. Pore-lining chlorite can promote the retention of primary pores. Below 4000 m, favorable reservoirs were mainly controlled by dissolution, resulting in dissolution pores being the main reservoir space. Microfractures played an important role in the properties of low-permeability and tight reservoirs. Microfractures themselves were easily dissolved into dissolution pores while being an important seepage channel for low-permeability and tight reservoirs. The denser the reservoir is, the more important the microfracture seepage is.",13,14,4
Fracture,Spontaneous Imbibition,"Liu, Junrong; Shen, James J.; Wang, Xiukun; Ge, Hongkui; Yao, Erdong",Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants,Shale oil; Spontaneous imbibition; Wettability alteration; Surfactant; IFT,CARBONATE RESERVOIRS; LOW-PERMEABILITY; RECOVERY; WATER; WET,"Wettability alteration exhibits a significant potential to improve the oil recovery of shale reservoirs by means of spontaneous imbibition through shifting the rock wetness from oil-wet to water-wet. The wettability of the oil-wet shale can be modified by adding surfactants in hydraulic fracturing fluids in the field practice. However, the mechanisms of wettability alteration in shale rocks are still unclear and there are reported discrepancies in different types of surfactants solutions. This work attempts to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of the Sichuan Basin in China, and to analyze their effects of wettability alteration and interfacial-tension (IFT) reduction on the spontaneous imbibition process of the oil-wet shale samples. By measuring the contact-angle, zeta-potential, and IFT, the efficiencies of different surfactants in terms of wettability alteration and IFT reduction are evaluated. The contact-angle experiments show that the water contact angle in rock/oil/water systems decreases when we add more surfactants, which indicates the hydrophilicity of shales is increased by surfactants. Specifically, for the anionic surfactant solutions, the contact angle doesn't immediately change, and it decreases with time, which is different from the sudden change of nonionic surfactants. Moreover, for different surfactants, the IFT decreases in a similar trend with the increase of surfactant concentration. Finally, spontaneous imbibition experiments are conducted and the results show that anionic surfactants are more favorable to recover shale oil than the nonionic surfactants. From the results obtained, it can be concluded that the anion surfactants and nonionic surfactant have different mechanisms for wettability alteration on the shale surface; anionic surfactants have better effect on wettability alteration than nonionic surfactants, however, the mechanism of wettability alteration in anionic surfactants have time delay. The wettability alteration dominates the oil recovery in the way of spontaneous imbibition. More water-wetness tends to yield a higher recovery. In addition, for anionic surfactant solutions, the reduction of IFT increases the final oil recovery and leads to a decrease of the imbibition rate. For nonionic surfactant solutions, the reduction of IFT increases both the imbibition rate and the final recovery, but the enhancement is not significant.",52,52,9
Fracture,Spontaneous Imbibition,"Cheng, Zhilin; Ning, Zhengfu; Ye, Xiongfei; Wang, Qing; Zhang, Wentong",New insights into spontaneous imbibition in tight oil sandstones with NMR,Spontaneous imbibition; Tight oil sandstones; Gravity effect; Anisotropic pore structure; Viscosity effect,PORE STRUCTURE; UNDERSTANDING WETTABILITY; BOUNDARY-CONDITIONS; SHAPE FACTOR; RECOVERY; SHALE; WATER; RESERVOIRS; PRESSURE; FLUID,"Previous research has confirmed that substantial yield has been recovered in the soaking period after hydraulic fracturing. Spontaneous imbibition (SI) is the primary mechanism responsible for the enhanced oil production and has become an effective oil recovery method with regards to unconventional reservoirs. Despite the importance of SI, an in-depth understanding of the features of SI in tight reservoirs is still inadequate. In this article, nuclear magnetic resonance (NMR) T-2 was employed to study the dynamic behavior of imbibition in tight sandstone samples from Yanchang formation, Ordos Basin. Additionally, high-pressure mercury intrusion (HPMI) and the initial T-2 of a core sample were combined to characterize pore structures of tight rocks and oil distributions in various pores at different imbibition stages. Then, the effects of gravity, anisotropic pore structure, and non-wetting phase (NWP) viscosity on imbibition recovery were determined via the variations in T-2 spectra for each sample. The results show that the tight cores feature a multiscale pore structure. Sub-micropores is the dominant type providing the major contribution to oil recovery, while nanopores have largest imbibition efficiency due to the larger capillary force. Gravity of fluids has a non-trivial effect on SI and cannot be neglected in tight samples under two-ends-open (TEO) or one-end-open (OEO) conditions; this seemingly counterintuitive finding is because the capillary force is weakened by the resistance force caused by the intricate flow paths and other possible surface forces at the nanoscale. Imbibition performance in a tight medium is strongly related to its pore structure. The variations in directional permeabilities, relative permeabilities and capillary pressure functions resulting from highly anisotropic samples greatly affect both the ultimate oil recovery and imbibition rate for tight samples under TEO condition, but only impact imbibition rate under allfaces-open (AFO) condition. Furthermore, because tight oil has a narrow range of viscosity, the imbibition behavior in tight samples may not be sensitive to the oil viscosity. It would be hoped that the insights gained from this study can help to improve our understanding of imbibition characteristics in tight reservoirs and develop new scaling models for the predication of oil recovery.",32,34,10
Fracture,Spontaneous Imbibition,"Nowrouzi, Iman; Manshad, Abbas Khaksar; Mohammadi, Amir H.",Effects of concentration and size of TiO2 nano-particles on the performance of smart water in wettability alteration and oil production under spontaneous imbibition,Smart water; TiO2; Wettability; Contact angle; Nano-fluids; Chemical enhanced oil recovery,INTERFACIAL-TENSION IFT; DISSOLVED CARBON-DIOXIDE; LOW-SALINITY; CRUDE-OIL; THERMAL-CONDUCTIVITY; PHYSICAL-PROPERTIES; INJECTION PROCESSES; CONTACT-ANGLE; POROUS-MEDIA; RECOVERY EOR,"Using smart nano-fluids with respect to enhanced oil recovery (EOR) is an emerging technology, which is normally studied in combination with other methods. Nano-fluid performance depends on type, size and concentration of the dispersed nano-particles in it. In the current work, effects of size and concentration of seawater-based nano-fluid of TiO2 in different salinities (resulted from dilution) on enhanced oil recovery parameters including contact angle, wettability and interfacial tension (IFT) have been investigated using the pendant drop method. Eventually, effect of TiO2 nano-particles in nano-fluids on recovered quantity has been investigated using imbibition experiment mechanism, which is one of the most important mechanisms in oil production from fractured reservoirs. Results of the experiments show that using higher concentration and smaller particle sizes of TiO2 would decrease the IFT and contact angle. Higher concentration and larger particle sizes of TiO2 in nano-fluid would increase the viscosity. Imbibition experiments show that the nanofluids containing smaller TiO2 nanoparticles are more efficient.",30,30,9
Fracture,Spontaneous Imbibition,"Lai, Fengpeng; Li, Zhiping; Zhang, Tiantian; Zhou, Anqi; Gong, Bao","Characteristics of microscopic pore structure and its influence on spontaneous imbibition of tight gas reservoir in the Ordos Basin, China",Tight gas reservoir; Microscopic pore structure; Spontaneous imbibition; Experiments; Grey relational analysis,SANDSTONE RESERVOIRS; FLOW; PERMEABILITY; SHALE; MODEL,"Spontaneous imbibition is an important mechanism governing the tight reservoir production performance, especially in the early stage of production after hydraulic fracturing. The microscopic pore structure of reservoirs is an important factor affecting imbibition. In this study, high-pressure mercury injection (HPMI), rate-controlled mercury injection, and low-temperature nitrogen adsorption (LP-N(2)GA) were preformed to study pore structure characteristics and fluid distribution in samples from the Ordos Basin, China. Nuclear magnetic resonance (NMR) and imbibition experiments were used to investigate the fluid distribution in porous media during imbibition. The porosity of samples ranges from 11.378% to 12.356%, with an average of 12.034%. The permeability of samples ranges from 0.034 mD to 0.056 mD, with an average of 0.048 mD. Results show that the recovery ranges from 68% to 94.81%, with an average of 81.09%. The reservoir is dominated by open flat slit micropores and mesopores. Sample pore volume ranges from 0.0155 ml/g to 0.0193 ml/g, with an average of 0.01687 ml/g. Micropores and mesopores less than 50 nm provide most of the pore volume. Pore radius and pore-throat ratio were obtained from experiments. Imbibition occurs primarily in pores ranging from 0.1 mu m to 1 mu m in radius, followed by pores ranging from 1 mu m to 10 mu m. The effects of porosity, permeability, average pore radius, average throat radius, average pore-throat ratio, specific surface area, and pore volume on imbibition recovery were statistically analyzed. Grey relational analysis was applied to sequence the imbibition influencing factors and determine the most influential factor. Results demonstrate that imbibition recovery is the most affected by average pore radius, followed by permeability, porosity, average pore-throat ratio, median radius, average throat radius, and specific surface area.",19,18,4
Fracture,Spontaneous Imbibition,"Harimi, Behrouz; Masihi, Mohsen; Mirzaei-Paiaman, Abouzar; Hamidpour, Esmaeil",Experimental study of dynamic imbibition during water flooding of naturally fractured reservoirs,Spontaneous imbibition; Dynamic imbibition; Fractured reservoirs; Water flooding,COCURRENT SPONTANEOUS IMBIBITION; OIL-RECOVERY; POROUS-MEDIA; PETROPHYSICAL PROPERTIES; ANALYTICAL-MODEL; WET; INJECTION; SATURATION; GLYCEROL; GRAVITY,"Capillary imbibition is an important recovery mechanism in naturally fractured reservoirs when water-filled fractures surround water-wet matrix blocks. A large amount of studies of imbibition process is simply total or partial immersion of nonwetting phase saturated rock in aqueous wetting phase. However, water advance in fractures during water flooding or water encroachment from an active aquifer introduces time dependent boundary conditions where invariant exposure of rock surface to water is not representative. In this work, a laboratory simulated matrix-fracture system was used to investigate different aspects of imbibition in the presence of fracture fluid flow (namely dynamic imbibition). A limestone and a sandstone core plug samples were selected as porous media. A total number of 11 dynamic imbibition and one static imbibition experiments were performed. Core plugs were strongly water-wet to maximize the role of capillary forces. Kerosene and air were the nonwetting fluids in experiments. The impact of water injection rate in the fracture was examined and the results revealed that as the injection rate increases above a critical rate, breakthrough recovery declines, however when injection rate is less than the critical rate increasing injection rate enhances recovery rate without any loss in recovery. Increasing wetting phase viscosity by means of glycerol solution was examined, as well. This reduced the imbibition rate and breakthrough recovery in both water-oil and water-air systems. Furthermore, comparing dynamic imbibition recovery data with a conventional immersion static experiment showed clear discrepancy which is due to different counter- and co-current flow modes. This emphasizes that static imbibition results should not be used for prediction of fractured reservoir performance under water flooding.",19,19,2
Fracture,Water Blockage,"Wu, Yonghui; Cheng, Linsong; Huang, Shijun; Fang, Sidong; Jia, Pin; Rao, Xiang",An analytical model for analyzing the impact of fracturing fluid-induced formation damage on rate transient behavior in tight formations,Water blockage; Rate transient behavior; Tight formation; Analytical model; Multi-fractured horizontal well,HORIZONTAL WELLS; SHALE GAS; SEMIANALYTICAL MODEL; RESERVOIRS; FLOW; PERFORMANCE; SIMULATION; MECHANISMS; DENSITY; CLEANUP,"An enormous amount of fracturing fluid is irreducible in the tight formation after hydraulic fracturing stimulation. This will cause serious damage to the fracture face as well as the matrix close to the hydraulic fractures by invading into the matrix. Modeling the effect of water blockage on rate transient behavior is significant in reservoir engineering. This paper presents a modified trilinear model to analyze the rate transient behavior after flowback period. Single-phase flow is assumed in this stage because most injected water is hard to be reduced. For damage to the matrix caused by rock-fluid interaction, clay swelling, and polymer adsorption, a fracturing fluid invasion layer is added to the model between hydraulic fractures and the inner stimulated reservoir volume to capture this kind of damage. A skin factor is used to capture the damage to the matrix-fracture face caused by gel filter cake formation and polymer adsorption. The analytical model is benchmarked using the commercial numerical simulator Eclipse. Several synthetic cases and a field case are studied, the results show that water blockage has a great impact on the productivity of the well and decline curves. The effect of choking effect, convergence flow, and gel filter cake could be incorporated using a skin factor in the model. In addition, two more flow regimes could be observed on the theoretical type curve if the well is affected by water blockage, and the two flow regimes would happen before linear flow dominated by the inner stimulated zone. Besides, the duration of the inner zone linear flow regime could be shortened if the permeability of the fracturing fluid invasion layer is lower and invasion depth is larger. These phenomena can be used in matching the field production data from water blockage affected wells, which exhibit a transition flow regime before the formation linear flow regime. This transition flow regime could be matched quite better using the proposed model than the classical trilinear flow model. The reason is that the linear flow regime could be much longer if the water blockage effect is not considered in the model. On the other hand, the skin factor has a different impact on the flow regimes, so the water blockage effect could be characterized properly only by adding a skin factor to the model. The main contribution of this paper is the provision of an analytical model for evaluating the formation damage caused by irreducible fracturing fluid, analyzing production data and making forecasts.",18,19,6
Fracture,Water Blockage,"Hassan, Amjed M.; Mahmoud, Mohamed A.; Al-Majed, Abdulaziz A.; Al-Nakhli, Ayman R.; Bataweel, Mohammed A.",Water blockage removal and productivity index enhancement by injecting thermochemical fluids in tight sandstone formations,Water blockage; Thermochemical fluids; Tight sandstone; Micro fractures; Capillary forces,FORMATION DAMAGE; LOW PERMEABILITY; GAS-RESERVOIRS; BLOCKING; PREVENTION; BASIN; FLOW; OIL,"Several challenges are associated with hydrocarbon production from tight reservoirs. Tight reservoirs are characterized with low permeability which reduces the hydrocarbon flow into the wellbore. Water blockage is considered one of the main damaging mechanisms in tight reservoirs due to the increase of water saturation around the wellbore region and eventually decrease in the relative permeability of hydrocarbons. Acid fracturing or hydraulic fracturing are required to remove the damage and enhance the formation conductivity. This paper presents a new technique to remove the water blockage from tight formations and improve the formation productivity using thermochemical treatment. Chemicals that generate pressure and heat at reservoir conditions are used to remove the water bank from tight core samples to enhance the flow conditions. Coreflooding experiments, capillary pressure, and NMR measurements were conducted as well as routine core analysis. The impact of thermochemical treatment on improving the formation productivity was quantified. The productivity index for core samples were determined before and after the thermochemical flooding. The effect of thermochemical injection on reducing the capillary forces was analyzed by measuring the capillary pressure before and after the chemical treatment. The alteration in pore geometry due to the thermochemical flooding was evaluated using NMR measurements. The results of this study show that water blockage is a potential damage in tight gas reservoirs. Injecting thermochemical fluids into tight samples reduced the capillary forces and removed the water banking. Flooding tight core samples with thermochemical resulted in generating tiny fractures in the treated samples, which reduces the capillary forces by 55.6% after the chemical treatment. The in-situ generated heat and nitrogen gas during thermochemical treatment can result in removing the water blockage from tight formations utilizing the desiccation effect. Also, thermochemical treatment showed a significant improvement in the core conductivity. The productivity index of core samples increased by 94.3% due to the chemical flooding. This study introduces a new chemical treatment for removing the water blockage from tight formations using environmentally friendly fluids. Thermochemical treatment improved the productivity index by a factor of 1.94 and decreased the drawdown pressure by more than 80%. Consequently, the trapped water was removed, and the total hydrocarbon production significantly improved.",16,16,4
Fracture,Water Blockage,"Fu, Lipei; Liao, Kaili; Ge, Jijiang; Zhang, Guicai; He, Yanfeng; Wang, Xiang; Zhang, Shifeng; Deng, Song",Study of ethylenediammonium dichloride as a clay stabilizer used in the fracturing fluid,Clay stabilizer; Ethylenediammonium dichloride; Inhibition mechanism; Clay hydration; Fracturing fluid,OIL-RECOVERY; SHALE; NANOTECHNOLOGY; NANOPARTICLES; POLYMER,"Clay stabilizer is the topic of a great number of studies, particularly in petroleum engineering. The organic cationic polymer is a kind of clay stabilizer with excellent anti-swelling effect. However, for tight reservoirs, the organic cationic polymer type clay stabilizers tend to increase the permeability damage caused by retention and blockage of stabilizers. Therefore, stabilizers with low molecular weight are necessary for tight reservoirs. The inhibition properties and the mechanisms of ethylenediammonium dichloride (EDD) were studied in this paper. The clay inhibition properties were studied from three aspects: swelling inhibition, clay sedimentation, and particle size distribution. Results showed that the anti-swelling rate reaches 91.98%. Control experiments showed that EDD had better inhibition property than KCl, NH4Cl, and poly dimethyldiallyl ammonium chloride (PDMDAAC). The inhibition mechanisms, studied from the aspect of surface hydrophobicity, surface charge, interlayer water content, and crystal spacing, can be concluded as that EDD reduces clay electronegativity and enhances the hydrophobicity of the clay surface, thereby keeping clay in a stable state. Compatibility tests showed that EDD can be used in guar based fracturing fluid. This study provides an alternative clay stabilizer for hydraulic fracturing.",14,16,9
Fracture,Water Blockage,"Rao, Xiang; Cheng, Linsong; Cao, Renyi; Jia, Pin; Wu, Yonghui; Liu, Hao; Zhao, Yuying; Chen, Ying",A modified embedded discrete fracture model to study the water blockage effect on water huff-n-puff process of tight oil reservoirs,Water blockage effect; Water huff-n-puff process; Embedded discrete fracture model; Tight oil reservoirs,INDUCED FORMATION DAMAGE; WELL PERFORMANCE; POROUS-MEDIA; SIMULATION; FLOW; IMPACT; EDFM; NETWORKS; BLOCKING; BASIN,"This paper constructs a numerical model to study the water blockage effect on water huff-n-puff process of tight oil reservoirs, by borrowing the conception of ""fracturing fluid layer"" and modifying embedded discrete fracture model (EDFM). Based on the proposed model, the effects of the permeability, initial water saturation and width of the fracturing fluid layer on water huff-n-puff process are detailly studied. It is found that, (i) initial water saturation of FFL makes little effect on water huff-n-puff process, because the water injection can refresh the water saturation distribution near fractures, and this 'refreshment effect' significantly reduce the effect of the initial water saturation of FFL. Moreover, the longer water injection time is, the stronger ` refreshment effect' will be, then the smaller effect the initial water saturation of FFL will make. (ii) both of width and permeability of FFL make a significant negative effect on the oil production rate of water huff-n-puff process, and permeability is more influencing than width. These results may give theoretical instructions to optimize the water huff-n-puff process while considering the water blockage effect.",14,13,5
Fracture,Ultra-low Permeability,"Wu, Zhongwei; Cui, Chuanzhi; Lv, Guangzhong; Bing, Shaoxian; Cao, Gang",A multi-linear transient pressure model for multistage fractured horizontal well in tight oil reservoirs with considering threshold pressure gradient and stress sensitivity,Multi-linear transient pressure model; Multistage fractured horizontal well; Stress sensitivity; Threshold pressure gradient; Pedrosa's transformation; Perturbation theory,NON-DARCY FLOW; SHALE; PERMEABILITY; PERFORMANCE,"In general, tight oil reservoirs has a numerous tiny and complicated throats, and ultra-low permeability, which leads to a low-velocity non-Darcy flow when the fluid flows in tight reservoirs. The permeability of tight oil reservoirs is no longer a constant, but a variable, which is dependent on reservoir pressure. In other word, the tight oil reservoir is stress sensitive media. The low-velocity non-Darcy flow and stress sensitivity will greatly affect the bottom hole pressure response. So, the low-velocity non-Darcy flow and stress sensitivity should be taken into consideration when researching the transient pressure behaviors of multistage fractured horizontal wells. Currently, there are many researches on transient pressure behaviors of the multistage fractured horizontal well, but none of these researches has taken the low-velocity non-Darcy flow and stress sensitivity into consideration simultaneously. In this paper, threshold pressure gradient and permeability modulus are used to characterize the low-velocity non-Darcy flow and stress sensitivity, respectively. And, a multi-linear transient pressure model of multistage fractured horizontal well with considering low-velocity non-Darcy flow and stress sensitivity is established. The Pedrosa's transformation, perturbation theory, Laplace transformation and stehfest numerical inverse are used to solve this transient pressure model. The novel model is verified by comparing the result of proposed model with that of Ekaterina Stalagorova's model. According to the dimensionless pressure derivative curve, the flow process can be identified as six regimes: (1)the main fracture linear flow stage, (2)the first transition flow stage, (3)dual-linear flow stage,(4)the second transition flow stage, (5)the formation linear flow stage, (6)the boundary flow stage. Finally, the effects of threshold pressure gradient, permeability modulus and fracture density of stimulated reservoir on dimensionless pressure derivative are analyzed. This research provides theoretical support for correctly understanding the flow law of multistage fractured horizontal well.",42,44,6
Fracture,Ultra-low Permeability,"Wei, Shiming; Xia, Yang; Jin, Yan; Chen, Mian; Chen, Kangping",Quantitative study in shale gas behaviors using a coupled triple-continuum and discrete fracture model,Shale gas; Hydraulic fracture network; Non-equilibrium desorption/adsorption mechanism; Gas behavior,HORIZONTAL WELLS; PRACTICAL METHOD; TIGHT OIL; FLOW; RESERVOIR; SIMULATION; FLUID; DIFFUSION; TRANSPORT; FRAMEWORK,"The shale has ultra-low permeability wherein multi-scale natural fractures are well-developed. The success of providing high diversion channels makes multi-stage fractured horizontal wells (MFHWs) become the powerful technique for economically producing gas from shale. This study presents a triple-continuum and discrete fracture model to describe a fractured shale reservoir embedded with a MFHW. The model incorporates non-equilibrium desorption/adsorption mechanism (NEDAM), viscous flow, Knudsen diffusion, and surface diffusion. The discrete fracture networks (DFNs) is quantitatively constructed according to the fracture density and stimulated reservoir area (SRA). This model is used to analyze the temporal/spatial evolution of the gas pressure and the net desorption rate. NEDAM is compared with the conventional equilibrium desorption mechanism (EDM) and its found that NEDAM uncovers the delayed phenomenon during gas desorption, and the use of EDM overestimates the production contributed from the adsorbed gas. The maximum net desorption rate of adsorbed gas gradually spread from the SRA region to the nonSRA region. The complete flow stages are clearly interpreted in a semi-logarithmic curve of well testing, and the flow stage controlled by the hydraulic fractures is clearly presented. Finally, the instructions on hydraulic fracturing treatment are given based on the production analysis.",17,18,2
Fracture,Ultra-low Permeability,"Weijermars, Ruud; Nandlal, Kiran; Khanal, Aadi; Tugan, Murat Fatih",Comparison of pressure front with tracer front advance and principal flow regimes in hydraulically fractured wells in unconventional reservoirs,Shale reservoirs; Pressure front; Tracer front; Depth of investigation; Drained rock volume; Flow regimes,VERTICAL WELL; INTERFERENCE,"Pressure depletion patterns near hydraulically fractured wells in ultra-low permeability reservoirs occupy a much larger region than outlined by fluid withdrawal contours. When used for reservoirs with moderate or high permeability (say k>1 mD), industry never needed to caution using pressure depletion plots as a proxy for fluid removal or drained rock volume (DRV). For such conventional reservoirs, pressure depletion plots are good proxies for fluid removal or drained rock volume (DRV). The fluid that moves from the margins of a pressure front, indicative of the so-called diffusive depth of investigation (DOI), will reach the well on the time-scale of economic life of the well. However, a whole new way of thinking is required when studying ultra-low permeability shales (nanoDarcy range), where the distinction between pressure depletion zones and the DRV regions (where fluid is recovered from) becomes crucial to understand which factors control the hydrocarbon recovery process. Our detailed analysis compares the diffusive DOI, of the leading edge of the pressure depletion front, and that of the convective DRV given by a tracer front. Results show that the pressure depletion front between the fractures quickly approaches the adjoining fracture pressure, and most of the production originates from the fracture tips after 12 months. The pressure depletion pattern vastly overestimates the DRV, whereas the tracer front shows the actual produced rock volume. A final section evaluates the specific flow regimes that correspond to certain diffusive DOI and convective DRV growth stages in the life of the well. The discussion section explains how production diagnostic plots can be used to identify the moment in the well life when enhanced oil recovery methods should be applied. This study can facilitate a better understanding of the fluid flow in fractured porous media and can be used to optimize fracture and well spacing to maximize the DRV.",16,16,0
Fracture,Ultra-low Permeability,Wang Dongqi; Yin Daiyin; Zhou Yazhou,Fine classification of ultra-low permeability reservoirs around the Placanticline of Daqing oilfield (PR of China),Ultra-low permeability reservoirs; Fine classification; Grey correlation analysis; Multi-parameter cluster analysis; Dynamic-static consistency check; Comprehensive evaluation,EMULSION,"Under SY/T 6285-2011 classification standard in China, reservoirs of which permeability ranging from 1 x 10(-3)mu m(2) to 10 x 10(-3)mu m(2) are divided into ultra-low permeability reservoir. While development practice of ultra-low permeability reservoirs around the Placanticline of Daqing shows that, water-breakthrough time and development effect of different reservoir types are greatly different. Besides the permeability values, reservoir fracture development is another important factor affecting development effect of ultra-low permeability reservoirs. Therefore, based on geologic characteristics of 63 blocks in ultra-low permeability reservoirs around the Placanticline of Daqing oilfield, using fracture parameters as primary classification index, matrix permeability, average throat radius, pore-throat ratio, movable fluid saturation and fluid mobility as main classification indexes, the method combined with grey correlation analysis, multi-parameter cluster analysis, dynamic-static consistency check and comprehensive evaluation is established. The classification evaluation criteria for two groups and four sub-groups has been determined, and the classification results of each block are verified. The results show that this method solves the problem of classification difficulty caused by classification parameters of individual blocks falling in different classification areas and realizes the goal of rational classification of 63 developed ultra-low permeability blocks. At the same time, it has the characteristics of simple calculation and high accuracy, which provides a powerful basis for the efficient and fine classification of ultra-low permeability blocks with similar geological characteristics.",13,15,5
Fracture,Wettability Alteration,"Liu, Junrong; Shen, James J.; Wang, Xiukun; Ge, Hongkui; Yao, Erdong",Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants,Shale oil; Spontaneous imbibition; Wettability alteration; Surfactant; IFT,CARBONATE RESERVOIRS; LOW-PERMEABILITY; RECOVERY; WATER; WET,"Wettability alteration exhibits a significant potential to improve the oil recovery of shale reservoirs by means of spontaneous imbibition through shifting the rock wetness from oil-wet to water-wet. The wettability of the oil-wet shale can be modified by adding surfactants in hydraulic fracturing fluids in the field practice. However, the mechanisms of wettability alteration in shale rocks are still unclear and there are reported discrepancies in different types of surfactants solutions. This work attempts to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of the Sichuan Basin in China, and to analyze their effects of wettability alteration and interfacial-tension (IFT) reduction on the spontaneous imbibition process of the oil-wet shale samples. By measuring the contact-angle, zeta-potential, and IFT, the efficiencies of different surfactants in terms of wettability alteration and IFT reduction are evaluated. The contact-angle experiments show that the water contact angle in rock/oil/water systems decreases when we add more surfactants, which indicates the hydrophilicity of shales is increased by surfactants. Specifically, for the anionic surfactant solutions, the contact angle doesn't immediately change, and it decreases with time, which is different from the sudden change of nonionic surfactants. Moreover, for different surfactants, the IFT decreases in a similar trend with the increase of surfactant concentration. Finally, spontaneous imbibition experiments are conducted and the results show that anionic surfactants are more favorable to recover shale oil than the nonionic surfactants. From the results obtained, it can be concluded that the anion surfactants and nonionic surfactant have different mechanisms for wettability alteration on the shale surface; anionic surfactants have better effect on wettability alteration than nonionic surfactants, however, the mechanism of wettability alteration in anionic surfactants have time delay. The wettability alteration dominates the oil recovery in the way of spontaneous imbibition. More water-wetness tends to yield a higher recovery. In addition, for anionic surfactant solutions, the reduction of IFT increases the final oil recovery and leads to a decrease of the imbibition rate. For nonionic surfactant solutions, the reduction of IFT increases both the imbibition rate and the final recovery, but the enhancement is not significant.",52,52,9
Fracture,Wettability Alteration,"Nowrouzi, Iman; Manshad, Abbas Khaksar; Mohammadi, Amir H.",Effects of concentration and size of TiO2 nano-particles on the performance of smart water in wettability alteration and oil production under spontaneous imbibition,Smart water; TiO2; Wettability; Contact angle; Nano-fluids; Chemical enhanced oil recovery,INTERFACIAL-TENSION IFT; DISSOLVED CARBON-DIOXIDE; LOW-SALINITY; CRUDE-OIL; THERMAL-CONDUCTIVITY; PHYSICAL-PROPERTIES; INJECTION PROCESSES; CONTACT-ANGLE; POROUS-MEDIA; RECOVERY EOR,"Using smart nano-fluids with respect to enhanced oil recovery (EOR) is an emerging technology, which is normally studied in combination with other methods. Nano-fluid performance depends on type, size and concentration of the dispersed nano-particles in it. In the current work, effects of size and concentration of seawater-based nano-fluid of TiO2 in different salinities (resulted from dilution) on enhanced oil recovery parameters including contact angle, wettability and interfacial tension (IFT) have been investigated using the pendant drop method. Eventually, effect of TiO2 nano-particles in nano-fluids on recovered quantity has been investigated using imbibition experiment mechanism, which is one of the most important mechanisms in oil production from fractured reservoirs. Results of the experiments show that using higher concentration and smaller particle sizes of TiO2 would decrease the IFT and contact angle. Higher concentration and larger particle sizes of TiO2 in nano-fluid would increase the viscosity. Imbibition experiments show that the nanofluids containing smaller TiO2 nanoparticles are more efficient.",30,30,9
Fracture,Wettability Alteration,"Al-Busaidi, Intisar K.; Al-Maamari, Rashid S.; Karimi, Mahvash; Naser, Jamil",Effect of different polar organic compounds on wettability of calcite surfaces,Wettability; Calcite; Double bond; Benzene ring; Carboxylic acids; Asphaltene,FATTY-ACIDS; CRUDE-OIL; WATER; ADSORPTION; CHALK; ASPHALTENES; SOLUBILITY; PETROLEUM,"The average oil recovery by conventional water flooding from oil-wet and naturally fractured carbonate reservoirs is often less than 30%. Removal of adsorbed acidic components and/or asphaltene from the carbonate surface results in wettability alteration towards water-wet which is an effective approach to enhance oil recovery. Long chain fatty acids, long chain naphthenic acids and asphaltene are major components in crude oil which are responsible for wettability alteration in carbonate reservoirs while unsaturated acids have minor effect. In this study, a more accurate quantification of the effects of different types and structures of polar components that contribute to the initial oil-wetting extent of the reservoir rocks were used (aliphatic saturated acids, aliphatic unsaturated acids, naphthenic acids, aromatic acids and asphaltene). Different analytical tools (contact angle, zeta potential, Fourier transform infrared spectroscopy and thermal analysis) were utilized for all acids in order to study surface characteristics. The results indicated that polar organic compounds act in different ways according to their structure and properties. Presence of double bond could make the acid molecule more polar, reactive and less hydrophobic. In addition, it can affect the spatial arrangement of the molecule and hence its orientation on the surface. Presence of benzene ring increases the reactivity and polarity of carboxylic group. Moreover, it enhances hydrophilic properties of the acid due to electrons of pi double bonds that can resonate over aromatic carbon atoms. The results revealed that, in the presence of water film, combination of acid dissociation in water, surface activity of acid and water solubility controls the acid adsorption and hence wettability alteration of the surface during aging process. Chemisorption of carboxylic acids/asphaltene changes the wettability of calcite surface. In addition to chemical adsorption, some acids adsorb physically on the surface. Physical adsorption of polar compounds may happen via hydrogen bonding between carboxylic groups and carbonate ions on the surface. Although physical adsorption is reversible and forms weak bonds between adsorbate and adsorbent, it may partially contribute to wettability alteration.",14,14,2
Fracture,Pressure Depletion,"Khanal, Aadi; Weijermars, Ruud",Pressure depletion and drained rock volume near hydraulically fractured parent and child wells,Depth of investigation; Drained rock volume; Well interference; Eagle ford; Complex analysis methods; Velocity plots,FLOOD DISPLACEMENT FRONTS; EAGLE FORD SHALE; INTERFERENCE; RESERVOIRS; HISTORY; MULTIWELL; TEXAS; OIL,"Field development of unconventional reservoirs tends to downsize well spacing when commercial success of a shale play is proven. The earlier, so-called parent wells are joined by infill wells, commonly called child wells. Tighter well spacing improves the recovery factor but the risk of well interference increases. The flow interference and pressure communication of adjoining wells via the matrix and their hydraulic fractures was investigated using the depth of investigation and associated pressure depletion plots. A sensitivity analysis shows how the depth of investigation in an unconventional reservoir is impacted by matrix permeability, other fluid properties, and time lapse between drilling of parent and child wells. In all cases, the extent of the drained region of a reservoir with hydraulic fractures is controlled by the fluid particle paths guided by the depth of investigation and time-of-flight contours. Time-of-flight contours visualize the reservoir drainage by parent and child wells using complex analysis methods (CAM) in a case study of the Eagle Ford shale. Even after 30 years of production, the actual drained rock volume (DRV) remains small and lags the depth of investigation. A commercial numerical reservoir simulator provides history matched inputs for the CAM tool which then can model the flow near the discrete fractures in the reservoir at high resolution. The developed procedure provides a computationally efficient method to quantify and visualize the DRV for parent and child wells in hydraulically fractured reservoirs. Fluid particle tracking provides a practical method to determine fracture and well-interference in combination with depth of investigation and pressure depletion studies.",18,18,0
Fracture,Pressure Depletion,"Weijermars, Ruud; Nandlal, Kiran; Khanal, Aadi; Tugan, Murat Fatih",Comparison of pressure front with tracer front advance and principal flow regimes in hydraulically fractured wells in unconventional reservoirs,Shale reservoirs; Pressure front; Tracer front; Depth of investigation; Drained rock volume; Flow regimes,VERTICAL WELL; INTERFERENCE,"Pressure depletion patterns near hydraulically fractured wells in ultra-low permeability reservoirs occupy a much larger region than outlined by fluid withdrawal contours. When used for reservoirs with moderate or high permeability (say k>1 mD), industry never needed to caution using pressure depletion plots as a proxy for fluid removal or drained rock volume (DRV). For such conventional reservoirs, pressure depletion plots are good proxies for fluid removal or drained rock volume (DRV). The fluid that moves from the margins of a pressure front, indicative of the so-called diffusive depth of investigation (DOI), will reach the well on the time-scale of economic life of the well. However, a whole new way of thinking is required when studying ultra-low permeability shales (nanoDarcy range), where the distinction between pressure depletion zones and the DRV regions (where fluid is recovered from) becomes crucial to understand which factors control the hydrocarbon recovery process. Our detailed analysis compares the diffusive DOI, of the leading edge of the pressure depletion front, and that of the convective DRV given by a tracer front. Results show that the pressure depletion front between the fractures quickly approaches the adjoining fracture pressure, and most of the production originates from the fracture tips after 12 months. The pressure depletion pattern vastly overestimates the DRV, whereas the tracer front shows the actual produced rock volume. A final section evaluates the specific flow regimes that correspond to certain diffusive DOI and convective DRV growth stages in the life of the well. The discussion section explains how production diagnostic plots can be used to identify the moment in the well life when enhanced oil recovery methods should be applied. This study can facilitate a better understanding of the fluid flow in fractured porous media and can be used to optimize fracture and well spacing to maximize the DRV.",16,16,0
Fracture,Pressure Depletion,"Wu, Yonghui; Cheng, Linsong; Huang, Shijun; Bai, Yuhu; Jia, Pin; Wang, Suran; Xu, Bingxiang; Chen, Ling",An approximate semianalytical method for two-phase flow analysis of liquid-rich shale gas and tight light-oil wells,Two-phase; Multistage fractured horizontal well; Liquid-rich shale gas; Tight oil; Semianalytical method,FRACTURED HORIZONTAL WELLS; INTEGRATED WORKFLOW; CURVES,"Two-phase flow of oil and gas is quite common in the reservoir during the depletion of liquid-rich shale gas and tight light-oil. Many analytical models proposed for multistage fractured horizontal wells completed in unconventional reservoirs are restricted to single phase flow problem. In this paper, an approximate semianalytical method is proposed to handle the complexities of phase change, pressure dependent PVT properties, two-phase flow behavior and complex fracture networks. The black oil model is used to model phase change and two-phase flow of oil and gas. The secondary fractures in the stimulated reservoir volume and the reservoir beyond the main fractures are considered in the physical model to make long-term production forecasts. The forecasted producing GOR is used to decrease the equations of the two-phase flow model, so only the flow equations of primary phase are used to develop the mathematic model. Then an approximate method is used to linearize the model and the analytical solution is obtained in Laplace space for constant pressure inner boundary problem. The Duhamel's principle is applied to correct the production rate under variable flowing pressure inner boundary, and a procedure is proposed for history matching of field production data and making forecasts. Finally, the semianalytical model is validated with two simulation examples, the average relative error is shown to be less than 10%. After that, two field examples are used to show its utility.",15,16,0
Fracture,non-Darcy Flow,"Wu, Zhongwei; Cui, Chuanzhi; Lv, Guangzhong; Bing, Shaoxian; Cao, Gang",A multi-linear transient pressure model for multistage fractured horizontal well in tight oil reservoirs with considering threshold pressure gradient and stress sensitivity,Multi-linear transient pressure model; Multistage fractured horizontal well; Stress sensitivity; Threshold pressure gradient; Pedrosa's transformation; Perturbation theory,NON-DARCY FLOW; SHALE; PERMEABILITY; PERFORMANCE,"In general, tight oil reservoirs has a numerous tiny and complicated throats, and ultra-low permeability, which leads to a low-velocity non-Darcy flow when the fluid flows in tight reservoirs. The permeability of tight oil reservoirs is no longer a constant, but a variable, which is dependent on reservoir pressure. In other word, the tight oil reservoir is stress sensitive media. The low-velocity non-Darcy flow and stress sensitivity will greatly affect the bottom hole pressure response. So, the low-velocity non-Darcy flow and stress sensitivity should be taken into consideration when researching the transient pressure behaviors of multistage fractured horizontal wells. Currently, there are many researches on transient pressure behaviors of the multistage fractured horizontal well, but none of these researches has taken the low-velocity non-Darcy flow and stress sensitivity into consideration simultaneously. In this paper, threshold pressure gradient and permeability modulus are used to characterize the low-velocity non-Darcy flow and stress sensitivity, respectively. And, a multi-linear transient pressure model of multistage fractured horizontal well with considering low-velocity non-Darcy flow and stress sensitivity is established. The Pedrosa's transformation, perturbation theory, Laplace transformation and stehfest numerical inverse are used to solve this transient pressure model. The novel model is verified by comparing the result of proposed model with that of Ekaterina Stalagorova's model. According to the dimensionless pressure derivative curve, the flow process can be identified as six regimes: (1)the main fracture linear flow stage, (2)the first transition flow stage, (3)dual-linear flow stage,(4)the second transition flow stage, (5)the formation linear flow stage, (6)the boundary flow stage. Finally, the effects of threshold pressure gradient, permeability modulus and fracture density of stimulated reservoir on dimensionless pressure derivative are analyzed. This research provides theoretical support for correctly understanding the flow law of multistage fractured horizontal well.",42,44,6
Fracture,non-Darcy Flow,"Cheng, Zhilin; Ning, Zhengfu; Wang, Qing; Zeng, Yan; Qi, Rongrong; Huang, Liang; Zhang, Wentong",The effect of pore structure on non-Darcy flow in porous media using the lattice Boltzmann method,Porous media; Pore structure; Darcy flow; Non-Darcy flow; Lattice Boltzmann method,RANDOM ARRAYS; RELATIVE PERMEABILITY; FLUID-FLOW; SIMULATION; INERTIA; NUMBER; COEFFICIENTS; PREDICTION; CYLINDERS; TRANSPORT,"Non-Darcy flows associated with high Reynolds numbers often occur in the near-wellbore regions of gas reservoirs or hydraulic fractures and thus should not be ignored. However, investigating non-Darcy flow in these porous rocks through laboratory experiments is always expensive and time-consuming. As such, this article sought an alternative method, and a lattice Boltzmann study of non-Darcy flow in various porous models was performed. The applicability of two non-Darcy correlations in porous media and the effect of pore structure on non-Darcy flow were examined. In addition, the reasons for the deviation from the linear Darcy flow and different flow patterns related to inertial effects of the fluid were also studied. The results showed that the characterization of non-Darcy flow in porous media with the cubic law can only be valid in a narrow range of Reynolds number beyond the Darcy regime, outside of which the strong inertia-dominated flow yields to the quadratic correction. On the whole, representing the non-Darcy flows using the quadratic correction is acceptable, especially for porous media with a higher complexity. The features of non-Darcy flow greatly depend on the pore structure of a porous medium, and more heterogeneous pore models always have a faster cessation for Darcy flow and a higher beta factor. Furthermore, for simple porous media a small amount of parameters may be adequate for the prediction of the beta factor; while the correlations involving more parameters would be needed to determine the beta factor for more intricate porous models, although such correlations may not be widely used in various industries. Besides, the non-Darcy flow that occurs in porous media is collectively controlled by different mechanisms. At elevated velocities, the inertial core effect in a large channel will lead the flow to be more homogeneous and less tortuous, while in porous models with complicated pore space, the steady eddy and reversal flow resulting from drag force will make the flow paths more tortuous. As such, it is the hope of this study to provide some new insights into the non-Darcy flow in porous media.",22,23,10
Oil Recovery,Wettability Alteration,"Saxena, Neha; Kumar, Amit; Mandal, Ajay","Adsorption analysis of natural anionic surfactant for enhanced oil recovery: The role of mineralogy, salinity, alkalinity and nanoparticles",Anionic surfactant; Reservoir rock; Adsorption; Isotherm models; Nanoparticles,WETTABILITY ALTERATION; NONIONIC SURFACTANTS; SILICA NANOPARTICLES; STABILITY; MECHANISM; ROCK; ISOTHERMS; WET; PH,"Anionic surfactants are widely used as an effective chemical for enhanced oil recovery because of their unique characteristics of reducing interfacial tension (IFT) between the trapped crude oil and water, and alteration of wettability of reservoir rock from oil-wet to water-wet. However, the loss of surfactant by adsorption onto the solid rock surface is a major concern that reduces the efficiency of the surfactant flooding process and must be considered while designing the process. Present study highlights the equilibrium adsorption and kinetics of an anionic surfactant synthesized from soap-nut fruit on sandstone, carbonate and bentonite clay as representative of reservoir rocks. The mineralogy and morphology of the rocks were investigated by FE-SEM, XRD and BET surface area analysis. UV-Visible spectroscopy was used to measure the amount of surfactant adsorbed on solid rock/clay surface in batch experiments. The experimental equilibrium adsorption data were analyzed by using Langmuir, Freundlich, Temkin and Redlich-Peterson isotherm models and adsorption parameters were calculated. Adsorption kinetics of the surfactant system were studied and pseudo second order kinetic model was best fitted for the surfactant/rock/clay systems. Presence of salt was found to increase surfactant adsorption on rock/clay marginally. However, presence of alkali and nanoparticles was found to reduce the loss of surfactant by adsorption and shows synergistic effects on IFT reduction, which is beneficial for application of the surfactant in oil recovery. The findings of the study are quite helpful in proper designing of the surfactant flooding for enhanced oil recovery.",75,76,17
Oil Recovery,Wettability Alteration,"Liu, Junrong; Shen, James J.; Wang, Xiukun; Ge, Hongkui; Yao, Erdong",Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants,Shale oil; Spontaneous imbibition; Wettability alteration; Surfactant; IFT,CARBONATE RESERVOIRS; LOW-PERMEABILITY; RECOVERY; WATER; WET,"Wettability alteration exhibits a significant potential to improve the oil recovery of shale reservoirs by means of spontaneous imbibition through shifting the rock wetness from oil-wet to water-wet. The wettability of the oil-wet shale can be modified by adding surfactants in hydraulic fracturing fluids in the field practice. However, the mechanisms of wettability alteration in shale rocks are still unclear and there are reported discrepancies in different types of surfactants solutions. This work attempts to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of the Sichuan Basin in China, and to analyze their effects of wettability alteration and interfacial-tension (IFT) reduction on the spontaneous imbibition process of the oil-wet shale samples. By measuring the contact-angle, zeta-potential, and IFT, the efficiencies of different surfactants in terms of wettability alteration and IFT reduction are evaluated. The contact-angle experiments show that the water contact angle in rock/oil/water systems decreases when we add more surfactants, which indicates the hydrophilicity of shales is increased by surfactants. Specifically, for the anionic surfactant solutions, the contact angle doesn't immediately change, and it decreases with time, which is different from the sudden change of nonionic surfactants. Moreover, for different surfactants, the IFT decreases in a similar trend with the increase of surfactant concentration. Finally, spontaneous imbibition experiments are conducted and the results show that anionic surfactants are more favorable to recover shale oil than the nonionic surfactants. From the results obtained, it can be concluded that the anion surfactants and nonionic surfactant have different mechanisms for wettability alteration on the shale surface; anionic surfactants have better effect on wettability alteration than nonionic surfactants, however, the mechanism of wettability alteration in anionic surfactants have time delay. The wettability alteration dominates the oil recovery in the way of spontaneous imbibition. More water-wetness tends to yield a higher recovery. In addition, for anionic surfactant solutions, the reduction of IFT increases the final oil recovery and leads to a decrease of the imbibition rate. For nonionic surfactant solutions, the reduction of IFT increases both the imbibition rate and the final recovery, but the enhancement is not significant.",52,52,9
Oil Recovery,Wettability Alteration,"Yekeen, Nurudeen; Padmanabhan, Eswaran; Idris, Ahmad Kamal",Synergistic effects of nanoparticles and surfactants on n-decane-water interfacial tension and bulk foam stability at high temperature,Nanoparticles; Surfactants; Interfacial tension; Foam stability; Electrostatic interaction,SODIUM DODECYL-SULFATE; SILICA NANOPARTICLES; AQUEOUS FOAMS; CO2 FOAM; NONIONIC SURFACTANTS; WETTABILITY ALTERATION; OXIDE NANOPARTICLES; OIL; ADSORPTION; STABILIZATION,"The synergistic effects of nanoparticles and surfactants on decane-water interfacial tension, and bulk foam stability at high temperature was investigated in this study. The interfacial properties were determined using a spinning drop interfacial tensiometer while the foam stability was evaluated from the normalized foam height. The extent of interaction between nanoparticles and surfactants was estimated from the hydrodynamic nano-aggregate sizes and zeta potential values. The foam microscopic images and the bubble morphology were examined to elucidate the mechanisms of foam stabilization by nanoparticles. Results clearly showed that nano-particles-Triton X-100 mixed system demonstrated the smallest aggregate sizes in bulk solution and considerable reduction in water/n-decane interfacial tension. Significant reduction in interfacial tension and increased foam stability occurred due to electrostatic interaction between the charged surfaces of the nanoparticles and surfactant head-groups. However, influence of electrostatic attraction was found to be dominant over the influence of electrostatic repulsion in promoting foam stability and reducing interfacial tension. The most stable foam was generated by titanium dioxide (TiO2) nanoparticles and cetyltrimethylammonium, bromide (CTAB), while the least stable foam was generated in presence of multi-walled carbon nanotubes and triton X-100. Possible reasons and mechanisms for these observations were suggested. The destabilizing influence of high temperature on foam stability was significant, however, CTAB-foam stability increased by 160% and 440% in presence of silicon dioxide (SiO2) and TiO(2 )nanoparticles at 80 degrees C. This phenomenon can be attributed to the moderate adsorption and aggregation of surface-active complex at the gas-liquid interface of the foam and Plateau borders.",44,45,9
Oil Recovery,Wettability Alteration,"Saxena, Neha; Goswami, Abhishek; Dhodapkar, P. K.; Nihalani, M. C.; Mandal, Ajay","Bio-based surfactant for enhanced oil recovery: Interfacial properties, emulsification and rock-fluid interactions",Natural surfactant; Interfacial tension; Wettability alteration; Emulsion; Adsorption; Enhanced oil recovery,LIPASE-CATALYZED SYNTHESIS; ACIDIC CRUDE-OIL; WETTABILITY ALTERATION; ANIONIC SURFACTANT; POROUS-MEDIA; ADSORPTION; TENSION; WATER; SULFONATE; BIODEGRADABILITY,"Anionic surfactants are very effective for application in enhanced oil recovery (EOR) in sandstone reservoirs because of their promising surface-active properties. Considering the non-biodegradability of some of the commercial surfactants, the present study deals with an anionic surfactant synthesized from naturally occurring soap-nut oil with excellent interfacial properties for application in EOR. The soap-nut surfactant showed the promising properties of interfacial tension (IFT) reduction, emulsification, rock wettability alteration, which are desirable for its application in EOR. An ultra-low IFT value of 2.123 x 10( -2) mN/m between crude oil and surfactant solution was obtained at critical micelle concentration (CMC), which was further reduced to 2.037 x 10( -3) mN/m at optimum salinity. Phase behaviour studies showed the formation of Winsor III emulsion phase which is beneficial for recovery of the trapped oil from the fine pores of the reservoir by miscibility mechanism. The surfactant exhibited favourable rock-wetting ability from oil-wet rock to water-wet condition. The loss of surfactant by adsorption on the rock surface was studied, and the adsorption data were analysed by Langmuir and Freundlich models. Injection of a small pore volume of surfactant-slug augmented with polymer slug as mobility buffer recovered more than 30% of original oil in place (OOIP) after the conventional water-flooding.",39,39,4
Oil Recovery,Wettability Alteration,"Pal, Nilanjan; Kumar, Narendra; Saw, Rohit Kumar; Mandal, Ajay",Gemini surfactant/polymer/silica stabilized oil-in-water nanoemulsions: Design and physicochemical characterization for enhanced oil recovery,Nanoemulsions; Surfactant-polymer-nanoparticle systems; Dynamic light scattering; Viscosity; Wettability alteration; Chemical flooding,SURFACTANT-POLYMER; EMULSIONS; EOR; PERFORMANCE; MICROEMULSIONS; BEHAVIOR,"The present study deals with the synthesis and characterization of oil-in-water nanoemulsion systems for application in enhanced oil recovery (EOR). Nanoemulsions stabilized by N,N'-bis((dimethyltetradecyl)-1,6-hexanediammonium bromide) gemini surfactant (14-6-14 GS), partially hydrolyzed poly-acrylamide (PHPA) polymer and/or silica (SiO2) nanoparticle were synthesized by ultrasonication technique. Nanoparticles strengthen the mechanical barrier (electrostatic repulsion + steric hindrance) at oil-aqueous interfaces, resulting in increased ionic strength and droplet stability. Dynamic light scattering (DLS) results confirmed the formation of nano-sized (< 500 nm) oil droplets within bulk emulsion phase. Kinetic stabilities of nanoemulsions were investigated by zeta potential and phase behavior analyses. Surface tension of surfactant-stabilized nanoemulsions increased with PHPA addition. However, silica particles improved adsorption ability of surfactant-polymer-nanoparticle (SPN) systems, causing decrease in surface tension. Rheological experiments were conducted as screening experiment at different temperatures to identify pseudoplastic character, and flow parameters were fitted using the Power law model. Contact angle studies showed that nanoemulsions alter the wetting characteristics of rock from intermediate-wet to favorable water-wet condition. Core-flooding studies revealed tertiary oil recovery percentage of 26.25% of original oil in place (OOIP) by chemical injections of {14-6-14 GS + PHPA + SiO2} nanoemulsions, after conventional water-flooding.",36,37,8
Oil Recovery,Wettability Alteration,"Mokhtari, Rasoul; Ayatollahi, Shahab; Fatemi, Mobeen",Experimental investigation of the influence of fluid-fluid interactions on oil recovery during low salinity water flooding,Enhanced oil recovery; Low salinity water flooding; Fluid-fluid interactions; Core flooding; Interfacial tension,DETERMINING IONS CA2+; CRUDE-OIL; WETTABILITY ALTERATION; INTERFACIAL-TENSION; SMART WATER; SPONTANEOUS IMBIBITION; BRINE COMPOSITION; IMPACT; CARBONATES; TIME,"This study aims to investigate the role of fluid-fluid interactions during low salinity water flooding, using crude oil from an Iranian oil reservoir. To minimize the effects of mineral heterogeneity and wettability alteration, a synthetic sintered glass core was utilized and all coreflooding experiments were performed at low temperatures without any aging process. The effect of fluid-fluid interactions were investigated in both secondary and tertiary injection modes. pH measurements as well as UV-Vis spectroscopy and interfacial tension (IFT) analysis were performed on the effluent brine samples. Results: show that fluid-fluid interactions, mainly the dissolution of crude oil polar components into the brine, significantly affect brine physical and interfacial properties. In secondary injection scenario, two times diluted seawater (2SW), which has the lowest IFT value, exhibits the highest (81%) oil recovery factor. While the lowest recovery factor (60.75%) was observed for the case of formation water (FW) injection. To explore the effect of contacting time, after 48 h soaking, brine injection was resumed. The effluent pH measurement at this stage showed a reduction, where the UV-Vis spectroscopy and IFT measurements confirmed dissolution of the crude oil polar components into the brine. The results showed that as brine salinity decreases, the amount of dissociated polar components increases. pH value of ten times diluted sea water (10SW) was reduced from its initial value of 7.45 to 4.22, while FW exhibits minor pH variation. Consequently, 10SW, which dissolved highest amount of polar components, depicts the highest recovery factor (6%) after soaking. Contrary to this, in tertiary injection mode, the high amount of saline brine in the core (because of FW injection at secondary stage) hinders the potential for more production for SW, 2SW and 10SW injection as all resulted to lower recovery factor compared to their secondary counterparts.",31,32,3
Oil Recovery,Wettability Alteration,"Nowrouzi, Iman; Manshad, Abbas Khaksar; Mohammadi, Amir H.",Effects of concentration and size of TiO2 nano-particles on the performance of smart water in wettability alteration and oil production under spontaneous imbibition,Smart water; TiO2; Wettability; Contact angle; Nano-fluids; Chemical enhanced oil recovery,INTERFACIAL-TENSION IFT; DISSOLVED CARBON-DIOXIDE; LOW-SALINITY; CRUDE-OIL; THERMAL-CONDUCTIVITY; PHYSICAL-PROPERTIES; INJECTION PROCESSES; CONTACT-ANGLE; POROUS-MEDIA; RECOVERY EOR,"Using smart nano-fluids with respect to enhanced oil recovery (EOR) is an emerging technology, which is normally studied in combination with other methods. Nano-fluid performance depends on type, size and concentration of the dispersed nano-particles in it. In the current work, effects of size and concentration of seawater-based nano-fluid of TiO2 in different salinities (resulted from dilution) on enhanced oil recovery parameters including contact angle, wettability and interfacial tension (IFT) have been investigated using the pendant drop method. Eventually, effect of TiO2 nano-particles in nano-fluids on recovered quantity has been investigated using imbibition experiment mechanism, which is one of the most important mechanisms in oil production from fractured reservoirs. Results of the experiments show that using higher concentration and smaller particle sizes of TiO2 would decrease the IFT and contact angle. Higher concentration and larger particle sizes of TiO2 in nano-fluid would increase the viscosity. Imbibition experiments show that the nanofluids containing smaller TiO2 nanoparticles are more efficient.",30,30,9
Oil Recovery,Wettability Alteration,"Gbadamosi, Afeez O.; Junin, Radzuan; Manan, Muhammad A.; Agi, Augustine; Oseh, Jeffrey O.; Usman, Jamilu",Synergistic application of aluminium oxide nanoparticles and oilfield polyacrylamide for enhanced oil recovery,Enhanced oil recovery; Polymers; Nanoparticles; Polymeric nanofluid; Aluminium oxide; Nanotechnology,PARTIALLY HYDROLYZED POLYACRYLAMIDE; ACRYLAMIDE-BASED POLYMER; HEAVY-OIL; WETTABILITY ALTERATION; SILICA NANOPARTICLES; RHEOLOGICAL PROPERTIES; ADSORPTION MECHANISM; SIO2 NANOPARTICLES; THERMAL-STABILITY; NANOFLUIDS,"Due to the inherent limitation of oilfield polyacrylamide in reservoir temperature and salinity, nanoparticles (NPs) have been extensively studied for their application in enhanced oil recovery (EOR) because of their unique properties and availability in large quantities. Recent trend in nanotechnology involves incorporating NPs as additive with polymer to form novel materials termed polymeric nanofluids (PNF's) for EOR. However, previous studies have investigated and focussed more on the suitability of silica (SiO2) polymeric nanofluids. In this work, the potential application of metal oxide polymeric nanofluid for EOR was explored and evaluated. Aqueous HPAM-based Al2O3 PNF's were formulated and characterised using Transmission Electron Microscopy (TEM) and Fourier-transform infrared (FTIR) spectroscopy. The performance of aluminium oxide (Al2O3) NP on the rheological properties of HPAM in the presence of different electrolyte concentrations representative of field brine and typical reservoir temperatures were investigated. Wettability alteration study of Al2O3 PNF was carried out using DataPhysics optical contact angle (OCA) instrument. Results obtained for Al2O3 PNF were compared to the widely reported SiO2 PNF and base polymer without nanomaterial. Experimental results show that the rheological properties improved while degradation of HPAM macromolecule was inhibited due to the addition of NPs. At 2,000 ppm HPAM solution (25 mol. % degree of hydrolysis), 0.1 wt% NP concentration was found to be the optimal choice for Al2O3 NP which gives rise to the highest viscosity on the rheological characterization. Al2O3 PNF exhibited better steady shear viscosity performance under the different electrolyte concentrations and temperatures studied. Al2O3 PNF altered the wettability of the porous media from oil-wet to water-wetting condition. Finally, oil displacement test in sandstone cores at typical reservoir temperature and salinity showed that Al2O3 PNF had 11.3% incremental oil recovery over conventional HPAM. This study is beneficial for extending the frontier of knowledge in nanotechnology application for EOR.",28,28,9
Oil Recovery,Wettability Alteration,"Ghasemian, Javad; Riahi, Siavash; Ayatollahi, Shahab; Mokhtari, Rasoul",Effect of salinity and ion type on formation damage due to inorganic scale deposition and introducing optimum salinity,Water flooding; Smart water; Potential determining ions; Scale; Optimum composition; Enhanced oil recovery,CALCIUM-SULFATE SCALE; IMPROVED OIL-RECOVERY; WETTABILITY ALTERATION; BRINE COMPOSITION; CRUDE-OIL; INJECTION; SEAWATER; CHALK; TEMPERATURE; DISSOLUTION,"Smart water injection is recognized as an effective EOR process to alter the wettability and interfacial tension to obtain higher micro/macro sweep efficiencies. This water contains reactive ions such as Mg2+, Ca2+ and SO42- which can act as potential-determining ions and change the surface charge of calcite rocks. One of the major concerns in the execution of an effective water-flood process, especially in tight carbonate reservoirs, is the chemical incompatibility between the formation brine and the injecting water. In the present study, laboratory fluid compatibility tests were carried out and software simulation was done to investigate the most important challenges of the water-flooding process in one of the West Iranian oil fields with the possibility of developing formation damage. The chemical incompatibility between injected smart water and formation water leads to inorganic scale deposition. For this purpose, sea water as the basis of smart water was prepared to examine the impact of determining ions such as Mg2+, Ca2+ and SO42- and, to examine the effect of the salinity of the injected brine on the total amount of CaSO4 scale precipitation. According to the obtained results, as the concentration of SO42- in the injecting sea water increases from 1/4 to 1 times its concentration in ordinary sea water, the CaSO4 precipitation increases smoothly, and then it is accelerated as the concentration increases beyond that. Therefore, even though the increasing of the sulfate concentration improved the wettability alteration ability of the smart water, calcium sulfate deposition was noticed, resulting in permanent formation damage. The test results also showed that CaSO4 deposition increases as the concentration of Ca2+ in the sea water increases. On the other hand, the presence of Mg(2+ )ion in sea water increases the solubility of CaSO4 and subsequently, lower scale formation was noticed by increasing the concentration of magnesium. This study also showed that there is an optimum salinity in which the minimum amount of mineral scale is deposited, and 5 times dilution of sea water is determined as the optimum salinity. The findings would enable us to optimize the ion contents of smart water for both, better oil sweep efficiency and lower risk of formation damage. In the end, this paper discusses the laboratory fluid compatibility results and scale prediction analysis for different smart water injection utilizations.",27,29,2
Oil Recovery,Wettability Alteration,"Yu, M.; Zeinijahromi, A.; Bedrikovetsky, P.; Genolet, L.; Behr, A.; Kowollik, P.; Hussain, F.",Effects of fines migration on oil displacement by low-salinity water,Fines migration; Low-salinity waterflooding; Oil recovery; Water relative permeability; SEM-EDS analysis,BRINE COMPOSITION; ANALYTICAL-MODEL; 2-PHASE FLOW; RECOVERY; INJECTION; PERMEABILITY; SANDSTONE; RESERVOIR,"Enhanced oil recovery by low-salinity waterflooding (LSW) has been shown to result from the combined effect of various physical mechanisms. In this study, laboratory experiments were designed in such a way that only fines migration mechanism remains active. Then, experimental observations and detailed characterizations of core plugs and produced fluids (water and oil) were used to analyze the effect of fines migration-induced formation damage on displacement efficiency. In the first set of experiments, core plugs of Berea and Obernkirchener sandstones were subjected to single-phase injections of water at salinities 40, 30, 20, 10, 5, 2.5, 0.5 and 0 g/L NaCl. An order-of-magnitude decrease in permeability was observed for both core plugs and was associated with an increase in fines concentration in the produced water. SEM-EDS images of the produced fines showed that kaolinite is mobilized as the salinity is reduced. SEM images of the pores before and after injection also showed fines retention and blockage. In the second set of experiments, two-phase LSW was performed on a pair of core plugs comparable to those in the first set of experiments. Kaolinite migration results were consistent with those of single-phase LSW. The two-phase LSW experiments showed 50% reduction in water relative permeability and 3% increase in oil recovery. Because no wettability alteration mechanism was active, the increase in oil recovery is attributed solely to enhanced displacement due to fines migration.",27,27,1
Oil Recovery,Wettability Alteration,"Moradi, Siyamak; Isari, Ali Akbar; Bachari, Zahra; Mahmoodi, Hossien",Combination of a new natural surfactant and smart water injection for enhanced oil recovery in carbonate rock: Synergic impacts of active ions and natural surfactant concentration,Enhanced oil recovery; Tribulus terrestris surfactant; Smart water; Interfacial tension; Wettability alteration; Carbonate rock,LOW-SALINITY BRINE; WETTABILITY ALTERATION; INTERFACIAL-TENSION; NONIONIC SURFACTANT; CRUDE-OIL; SPONTANEOUS IMBIBITION; TRIBULUS-TERRESTRIS; WASTE-WATER; ADSORPTION; CHALK,"By increasing oil demand in carbonate reservoirs, enhanced oil recovery techniques play key role in improving oil production. Surfactant flooding and smart water injection are already well known as effective enhanced oil recovery techniques that increase oil recovery by reduction of oil-water interfacial tension and the alteration of rock wettability. In this work, a new plant-base natural surfactant, named Tribulus Terrestris is introduced and combined with smart water samples (i.e. synthetic seawater with different concentrations of active Ca2+, Mg(2+ )and SO42- ions) to determine their individual and integrated effects on reduction in interfacial tension, wettability alteration and oil recovery in carbonate rock samples. It was observed that increasing concentrations of SO42- up to 2.5 times resulted in maximum wettability restoration among active ions (by changing contact angle from 145.9 degrees to 54.4 degrees). Experimental results also showed that the effect of the concentration of active ions on wettability alteration was more significant compared to their effect on decreasing oil-water interfacial tension. In addition, the Tribulus Terrestris surfactant reduced oil-water interfacial tension considerably (from 45.3 mN/m to 13.5 mN/m at Critical Micelle Concentration of 0.3 wt %); hence, it was used as smart water modifier to integrate effects of wettability alteration (by smart water) and reduction in interfacial tension (by new natural surfactant). Core flooding experiments demonstrated increased oil recovery from 45.2% for distilled water injection up to 64% and 72% for smart water and combined smart water-surfactant respectively.",25,25,0
Oil Recovery,Wettability Alteration,"Divandari, Hassan; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin; Ranjbar, Mohammad",Integrating synthesized citric acid-coated magnetite nanoparticles with magnetic fields for enhanced oil recovery: Experimental study and mechanistic understanding,Enhanced oil recovery; Nanofluid; Citric acid-coated Fe3O4 nanoparticles; Magnetic field; Wettability alteration; IFT; Micromodel,HEAVY OIL; ALPHA-FE2O3 NANOPARTICLES; MAGNETORHEOLOGICAL FLUID; WETTABILITY ALTERATION; SANDSTONE CORES; NANO-PARTICLES; CRUDE-OIL; WATER; WET; NANOFLUID,"Nanofluid injection has emerged as an attractive enhanced oil recovery (EOR) process in the past decade. These fluids improve oil recovery by reducing interfacial tension (IFT), modifying wettability, and reducing mobility ratio. In this communication, magnetite citric acid-coated nanoparticles (NPs) were synthesized by an affordable, facile and one step method and then characterized using Field emission scanning electron microscopy (FESEM), X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR), and Dynamic light scattering (DLS). Afterward, the microscopic and macroscopic efficiencies of oil recovery in heterogeneous and homogeneous 2D micromodels were investigated in the presence of magnetic field. Citric acid-coated magnetite NPs started to respond to the magnetic field around the intensity of 800 Gauss and also showed the maximum ultimate recovery factor at the intensity of 2750 Gauss. In addition, citric acid coated magnetite NPs provided more enhanced oil recovery factor compared to hematite NPs, because of reducing interfacial tension (IFT) between the oil and injection fluid, altering surface wettability from oil-wet to water-wet, promoting the NPs distribution in porous media, and generating column-like structure in the presence of magnetic field. In fact, magnetite NPs act as piston toward the magnetic field by creating a column which sweeps the oil and increases production. Furthermore, citric acid-coated magnetite NPs flooding increased ultimate recovery factor more than polymer and hematite NPs flooding.",24,25,10
Oil Recovery,Wettability Alteration,"Giraldo, Lady J.; Gallego, Jaime; Villegas, Juan P.; Franco, Camilo A.; Cortes, Farid B.",Enhanced waterflooding with NiO/SiO2 0-D Janus nanoparticles at low concentration,Janus nanoparticles; Nanofluid flooding; Capillary number (N-C); Enhanced oil recovery (EOR),HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SILICA NANOPARTICLES; POROUS-MEDIA; SIO2 NANOPARTICLES; ADSORPTION ENERGY; RECOVERY; WATER; ASPHALTENES; BEHAVIOR,"The nanofluid (nanoparticles dispersed in determined carrier fluid) flooding has been studied for reducing the interfacial tension (IFT), increasing the viscosity of the displacement phase and to alter the rock wettability, which impact the capillary number and hence increase the crude oil recovery. However, this technique requires commonly large concentration of nanoparticles for being efficient in enhanced oil recovery (EOR) processes. Hence, the primary objective of this manuscript is to develop NiO-containing Janus nanoparticles based on zero-dimension (0-D) SiO2 nanoparticles which can be effective at low concentrations. The synthesized nanoparticles were characterized by transmission electron microscopy (TEM), surface area (S-BET), zeta potential, interfacial tension (IFT), rheology, contact angle measurements and coreflooding tests. The results showed a sharply increase of the capillary number (Nc) at a very low concentration of 100 mg/L of Janus nanoparticles, mainly attributed to the decrease in the interfacial tension, which can lead to the increase of the oil recovery. Displacement tests using a SiO2 nanoparticles-based nanofluid at a concentration of 100 mg/L did not show an increase in oil recovery regarding the one obtained in the waterflooding step. Meanwhile, the nanofluid based on NiO/SiO2 Janus nanoparticles at the same concentration of 100 mg/L showed an increase in oil recovery up to 50%.",21,22,6
Oil Recovery,Wettability Alteration,"Aghajanzadeh, Mohammad Reza; Ahmadi, Pouyan; Sharifi, Mohammad; Riazi, Masoud",Wettability modification of oil-wet carbonate reservoirs using silica-based nanofluid: An experimental approach,Wettability alteration (WA); Nanoparticles; Spontaneous imbibition; Oil recovery; Carbonate rocks; Relative permeability,RECOVERY; NANOPARTICLES; IMBIBITION; CALCITE,"Wettability is an important factor which controls oil recovery and fluids displacement efficiency in the porous media. Wettability alteration (WA) from strongly oil-wet towards water wet or neutral states is one of the most effective methods of oil recovery increment. Many studies have shown that nanofluid can change the wettability of rock surface towards a desirable state and base on literature structural disjoining pressure is the main mechanism of wettability alteration via nano-treatment. However, there is a lack of information regarding the impact of salinity on nanofluid performance in porous media. Therefore, in this work, the effects of salinity, nanofluid concentration and rock type (i.e. limestone and dolomite surfaces) on wettability alteration of oil wet carbonate substrates under ambient condition were investigated. For this purpose, various static and dynamic experiments including contact angle, imbibition and core flood tests have been performed. The results on contact angle measurements showed that by increasing nanoparticles and electrolyte concentration the wettability alteration from oil wet to water wet was significantly enhanced. Moreover, the wettability alteration of dolomite substrate is much more than that of limestone substrate. In the following, the impact of nanofluid on the spontaneous imbibition for strongly oil-wet carbonate cores was closely examined. Finding results showed an increase as much as 15% of oil recovery for nanofluid imbibition in comparison to that of formation brine. Final evaluation of the nanofluid treatment in terms of its effectiveness was measured by core flood experimental runs. Comparison of relative permeability curves before and after treating have outlined that after the treatment process, the relative permeability curve has shifted to the right and the water relative permeability has reduced from 0.43 mD to 0.23 mD at the residual oil saturation due to wettability alteration of rock surface from strongly oil wet to water wet state.",21,21,6
Oil Recovery,Wettability Alteration,"Tabar, Mohammad Azadi; Ghazanfari, Mohammad Hossein; Monfared, Abolfazl Dehghan",On the size-dependent behavior of drop contact angle in wettability alteration of reservoir rocks to preferentially gas wetting using nanofluid,Gas condensate reservoir; Wettability alteration; Size dependent wettability; Pseudo-line tension; Surface roughness,LINE-TENSION; YOUNGS EQUATION; SURFACE-TENSION; NANO-SILICA; WIDE-RANGE; EVAPORATION; WATER; ENERGY; ENHANCEMENT; HYSTERESIS,"Wettability alteration of rock surfaces toward gas wetting have been recognized as a practical approach for maximizing the production from the gas condensate reservoirs. Most of the reported work in this area applied the so called sessile drop contact angle measurement technique to examine the change in wetting state of a surface. However, the size-dependent wetting behavior of drop which could affect the exact determination of wettability and wettability changes was not well discussed in the previous studies. Therefore, in this work, the size dependency of contact angle for four different liquid-solid-gas systems; i.e., water-calcite-air, water-treated calciteair (nanofluid treated calcite), oil-calcite-air, and oil-treated calcite-air, were investigated. To provide a better understanding of the displacement of reservoir gas and liquid following the wettability alteration process, a dynamic contact angle measurement approach was designed. The effect of drop size and surface roughness on the wetting state of calcite rock samples at the initial and altered condition of wettability was then investigated through experimental and modeling approaches. The surface roughness of calcite samples and drop contact angles were determined using Atomic Force Microscopy and Low bond axisymmetric drop shape analysis method, respectively. Analysis of results demonstrated that size dependency of contact angle imposed an error as high as 22.2 degrees on the measurement of achieved wettability alteration in the case of water-calcite/treated calciteair system. On the basis of calculated pseudo-line tension from the modeling schemes, it was also revealed that the surface roughness had a significant impact on wettability measurements. Both low and high pseudo-line tension values of order 10(-9) and 10(-6) N, respectively, could dictate some level of errors in contact angle measurements. However, high values were supposed to have a considerable degree of importance in gas condensate applications. The results of this study could provide a better understanding of the contact angle measurement experiments for petroleum engineers to evaluate the wettability alteration schemes.",21,21,1
Oil Recovery,Wettability Alteration,"Gharibshahi, Reza; Jafari, Arezou; Ahmadi, Hamid",CFD investigation of enhanced extra-heavy oil recovery using metallic nanoparticles/steam injection in a micromodel with random pore distribution,Oil recovery factor; Steam; Nanoparticles; CFD; Design experiment; Taguchi method; Optimization; Micromodel,MULTIPHASE MIXTURE MODEL; CAPILLARY-POROUS MEDIA; MULTICOMPONENT TRANSPORT; WETTABILITY ALTERATION; STEAM INJECTION; SANDSTONE CORES; SIMULATION; NANOFLUID; CATALYST,"The present study simulated thermal enhanced oil recovery (steam and nanoparticles) for the first time using computational fluid dynamics. To better visualize fluid flow in the reservoir, a 2D micromodel generated by commercial grid generation tools was used as the porous medium. Four parameters that have a great impaction on the process were studied to determine the best combination of factors to attain maximum oil recovery. Type of nanoparticle, volume fraction of nanoparticles, diameter of nanoparticles and temperature of injected fluid were examined using the Taguchi method. All governing equations were solved in Fluent software based on finite volume. The numerical results were in a good agreement with the experimental results and the data shows that Al2O3 nanoparticles have the greatest potential for enhanced oil recovery in comparison with CuO and Fe3O4 nanoparticles. Decreasing the diameter of the nanoparticles and increasing their volume fraction in the base fluid and the temperature of the injected fluid improved oil recovery and a large amount of oil was produced from the porous medium. Injecting the nanofluid at an optimal level decreased the viscosity of the extra heavy oil from 35 to 25 Pas.",18,20,6
Oil Recovery,Wettability Alteration,"Al-Saedi, Hasan N.; Brady, Patrick V.; Flori, Ralph E.; Heidari, Peyman",Insights into the role of clays in low salinity water flooding in sand columns,Geochemistry; Low salinity Water Flooding; Mechanisms of the Low Salinity Water; Enhanced Oil Recovery,OIL-RECOVERY; WETTABILITY ALTERATION; MAGNESITE DISSOLUTION; SPATIAL-DISTRIBUTION; HETEROGENEITY; FLOW; SORPTION; AQUIFER; IMPACT; BRINE,"Clays in sandstone are thought to be a key factor in low salinity (LS) water flooding. This study investigates the effects of quartz, kaolinite and illite in LS water flooding in synthetic sand columns as a function of temperature. Four chromatography columns containing different amounts of pure quartz sand, illite, and kaolinite (100% quartz sand; 95/5% sand/illite; 95/5 sand/kaolinite; and 95/2.5/2.5% sand/illite/kaolinite). The use of these synthetic columns gives full control over mineralogy. These columns were saturated with high salinity (HS) formation water with 0.01 M (M) sodium acetate and aged for a week at 70 degrees C. They were then flooded with waters (yes, the use of water to displace water) with various salinities at four different temperatures (25, 70, 90 and 120 degrees C). Effluent concentrations of Ca2+ and acetate (CH3COO-) and pH were measured. This is a novel experimental design, where formation water containing sodium acetate is flooded with waters of varying salinity to gain insight into LS flood performance and possible recovery mechanisms. The hypothesis pursued here is that the behavior of the acetate ion (attached to matrix minerals during the aging process and then released due to ionic exchange) in an LS flood would provide a valuable analog that would simulate the bonding of carboxylic acids in crude oils with reservoir matrix minerals (and subsequent desorption during LS flooding). Key results include the following: (a) Our hypothesis was correct-the use of Na acetate behaved analogously to carboxylic acid, giving useful insights; (b) The quartz-only column showed strong evidence (elevated pH, presence of Ca2+ and acetate in effluent) of ionic exchange due to LS flooding, showing that pure quartz is responsive to LS flooding and that clays are not absolutely needed; (c) Quartz plus kaolinite plus illite gave a slightly higher response than pure quartz so clays can play a role. Oil displacement results were also done for a pure quartz sand column, and this showed a strong response to the LS flood, confirming that clays are not absolutely needed.",18,19,3
Oil Recovery,Wettability Alteration,"Dahkaee, Kaveh Padasht; Sadeghi, Mohammad Taghi; Fakhroueian, Zahra; Esmaeilzadeh, Pouriya",Effect of NiO/SiO2 nanofluids on the ultra interfacial tension reduction between heavy oil and aqueous solution and their use for wettability alteration of carbonate rocks,NiO/SiO2 nanocomposites; EOR; IFT reduction; Smart surface modification; Wettability alteration; Heavy oil,ZRO2 NANOPARTICLES; SILICA; SURFACTANT; RECOVERY; BEHAVIOR; SIO2; NANOCOMPOSITES; PERFORMANCE; WATER,"One of the important factors in enhanced oil recovery (EOR), which leads to better oil flow in reservoirs and increases the recovery efficiency of the reservoirs, is the reduction of surface tension (S.T) and interfacial tension (IFT). The effect of NiO and SiO2 nanoparticles and their nanocomposites as NiO/SiO2 on the reduction of oil/water interfacial tension was investigated for the heavy oil of Soroush field located in Iran with a density of 0.965 g/cm(3) and viscosity of 1310 cP at 22 degrees C. NiO and SiO2 nanoparticles were produced by sol-gel-hydrothermal process and NiO/SiO2 nanocomposites were synthesized by co-precipitation-hydrothermal method. The interfacial tension of water/Soroush oil was measured to be 29.02 mN/m, as the reference, in the absence of nanoparticles. Water-based nanofluid of 30 wt% NiO/SiO2 and 28 wt% Fe@ NiO/SiO2 nanocomposites that benefits the synergism of the Fe promotor, decreased the IFT to 1.28 mN/m and less than 1 mN/m, respectively. In addition, the key factors such as concentration, aging time and salinity affect were studied in variation of S.T and IFT. It was found that 8 v/v% of the 30 wt% NiO/SiO2 diluted in water had the best efficiency in reducing the S.T and IFT, while preheating time of nanofluids and salinity of water that the nanofluid dissolved in had negligible impacts on surface and interfacial tension. Moreover, as the 30 wt% NiO/SiO2 nanocomposites were essentially hydrophobic, novel hydrophilic and eco-friendly nanocomposites of 30 wt% NiO/SiO2 were also synthesized through smart surface modifications by polyethylene glycol (PEG 6000) and polydimethylsiloxane. It was shown that the surface-modified nanocomposites could reduce the S.T and IFT significantly and alter the wettability of a strong oil-wet carbonate rock to water-wet condition.",18,20,3
Oil Recovery,Wettability Alteration,"Chen, Yongqiang; Xie, Quan; Saeedi, Ali","Role of ion exchange, surface complexation, and albite dissolution in low salinity water flooding in sandstone",Low salinity water flooding; Reactive transport; Ion exchange; Surface complexation; Albite dissolution,OIL-RECOVERY; MECHANISM,"Wettability alteration appears to be an important mechanism for low salinity water flooding, but two major challenges in predicting the low salinity effect are (1) to understand the contribution of ion exchange, surface complexation, and albite dissolution mechanisms, and (2) to quantify how the three mechanisms contribute to pH increase during low salinity water flooding. We thus modelled one-dimensional (1D) reactive transport, examining the ion exchange, surface complexation, and albite dissolution using PHREEQC, and compared with RezaeiDoust et al.'s [Energy and Fuels. 2011; 25(5):2151-62.] experimental pH profiles during low salinity water injection. We reasonably matched RezaeiDoust et al.'s experimental pH profiles. We found that ion exchange, and albite dissolution significantly contribute to pH increase, and surface complexation mechanism plays a minor role in pH increase. Our results suggest that basal charged clays (e.g., illite, smectite, chlorite) and albite are minerals to trigger pH increase which decreases the bridging number ( > -NH + > -COOCa) for basal charge clays, and also decrease the bonds ([ > AlOH2 (+)] [-COO-] + [ > Al:SiO-][-NH+] + [ > Al:SiO-][-COOCa+] + [ > Al:SiOCa+][ > [-COO-]) for edge charged clays (e.g., kaolinite). Our results provide insights to characterize the geochemical features of oil/brine/sandstone and shed light on constraining the intrinsic uncertainties of low salinity water FOR in sandstone reservoirs.",16,16,2
Oil Recovery,Wettability Alteration,"Lee, Yeonkyeong; Lee, Wonsuk; Jang, Youngho; Sung, Wonmo",Oil recovery by low-salinity polymer flooding in carbonate oil reservoirs,Polymer adsorption; Wettability alteration; PDI; Low-salinity polymer flooding; Carbonate reservoir,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; WATER; INJECTION; IMPACT; CHALK; EOR; MECHANISMS; EFFICIENCY; RETENTION,"Low-salinity polymer flooding (LSPF) is a promising enhanced oil recovery (EOR) method with a synergetic effect of combining the polymer injection and low-salinity water injection methods. To maximize EOR efficiency, it is essential to design the compositions of low-salinity water appropriately while considering polymer properties. The goal of this study was to investigate the effects of pH and potential determining ions (PDI; SO42- and Ca2+) in low-salinity polymer solution used as injection water on oil production when applying LSPF to a carbonate oil reservoir. From the experimental results, the SO42- ions interfered with polymer adsorption in the neutral SO42--containing polymer solution, while the adsorption was greatly promoted in the acidic conditions, reducing the permeability. In the Ca2+-containing polymer solution, the adsorption trend was different from the SO42- case. In examining the wettability alteration, the change in residual oil saturation between after-LSWF and after-LSPF (Delta S-or) was greater with higher SO42- concentration under the neutral state. This means that the end-point of the relative permeability-saturation curves shifted to the right, indicating that wettability was altered to a more water-wet state. Under acidic conditions, Delta S-or was smaller compared to the neutral state due to greater polymer adsorption. A small Delta S-or was observed when Ca2+ ions were contained in the neutral polymer solution, causing less wettability alteration. This is because Ca2+ ions are involved in precipitation as well as adsorption, thus reducing the permeability more than SO42--containing case. We confirmed these changes also in the contact angle analysis. In conclusion, since SO42- ions interfered with adsorption of polymer molecules and adsorption occurred less in the neutral state, a neutral polymer solution with high SO42- ion concentration as an injection water provided the highest enhancement in the EOR efficiency.",16,16,1
Oil Recovery,Wettability Alteration,"Ali, Nour El Cheikh; Zoghbi, Bilal; Fahes, Mashhad; Nasrabadi, Hadi; Retnanto, Albertus",The impact of near-wellbore wettability on the production of gas and condensate: Insights from experiments and simulations,Gas condensate; Wettability; Carbonate; Condensate banking; Well stimulation,POROUS-MEDIA; SANDSTONE; WELLS,"Condensate banking commonly occurs in gas-condensate reservoirs resulting in a reduction in well productivity. This phenomenon is linked to the phase behavior of the reservoir fluid, the drawdown management technique, as well as the trapping of liquid hydrocarbons due to strong rock-fluid interactions. Wettability alteration to neutral-wetting near the wellbore has been identified as a possible solution to alleviate the problem. In this work, we investigate optimizing wettability conditions towards maximizing productivity. A range of wetting conditions is examined, experimentally, and using numerical simulation techniques. The results show that it is possible to target an optimum wettability state that maximizes gas well deliverability. A signature of these optimum conditions is identified in the trend of spontaneous imbibition tests. Complete reversal of wetting conditions can result in better well productivity than the original wetting state, but in some cases it can reduce the amount of condensate recovered. This puts into question the common perception that an increase in the recovery of heavy components should be expected when liquid-wetting is reduced.",15,16,1
Oil Recovery,Wettability Alteration,"Cui, Jiangfeng",Oil transport in shale nanopores and micro-fractures: Modeling and analysis,Shale oil; Asphaltenes; Mixed wettability; Adsorption; Mathematical model,MOLECULAR-DYNAMICS SIMULATION; ASPHALTENE PRECIPITATION; APPARENT PERMEABILITY; LIQUID PERMEABILITY; ORGANIC NANOPORES; FLOW; ENHANCEMENT; DIFFUSION; WATER; SLIP,"The mathematical modeling and analysis for the apparent permeability of shale oil with complicated compositions in dual-wettability shales (superior to existing single-component or single-wettability analysis), which is the core of this work, will help understand the detailed contributions of the considered mechanisms. Based on a previously established flow enhancement model, the effects of the mixed wettability and those triggered by asphaltenes, namely, the wettability alteration, the pore radius reduction, and the viscosity increment, are taken into account by respective corrections of the variables in the model. The effect of the mixed wettability is quantified by the water-wet area ratio, while the surface coverage, the adsorption thickness, and the volume fraction in the free phase are utilized to quantify the effects of asphaltenes. The volume fraction of asphaltenes in the free phase is related to that in both phases by the volume conservation equation. The full mathematical model and its several simplifications are achieved. Comprehensive sensitivity analysis and comparisons are carried out to demonstrate the effects of each variable (i.e., the pore radius, the initial water-wet surface ratio, the relative adsorption thickness, and the surface coverage) on: (1) the flow enhancement; (2) the relative importance of all mechanisms; (3) the differences among organic pores/inorganic pores/micro-fractures; and (4) the overall contribution of asphaltenes. The effect of different adsorption patterns (characterized by the relative adsorption thickness and the surface coverage) is also discussed.",14,14,3
Oil Recovery,Wettability Alteration,"Al-Busaidi, Intisar K.; Al-Maamari, Rashid S.; Karimi, Mahvash; Naser, Jamil",Effect of different polar organic compounds on wettability of calcite surfaces,Wettability; Calcite; Double bond; Benzene ring; Carboxylic acids; Asphaltene,FATTY-ACIDS; CRUDE-OIL; WATER; ADSORPTION; CHALK; ASPHALTENES; SOLUBILITY; PETROLEUM,"The average oil recovery by conventional water flooding from oil-wet and naturally fractured carbonate reservoirs is often less than 30%. Removal of adsorbed acidic components and/or asphaltene from the carbonate surface results in wettability alteration towards water-wet which is an effective approach to enhance oil recovery. Long chain fatty acids, long chain naphthenic acids and asphaltene are major components in crude oil which are responsible for wettability alteration in carbonate reservoirs while unsaturated acids have minor effect. In this study, a more accurate quantification of the effects of different types and structures of polar components that contribute to the initial oil-wetting extent of the reservoir rocks were used (aliphatic saturated acids, aliphatic unsaturated acids, naphthenic acids, aromatic acids and asphaltene). Different analytical tools (contact angle, zeta potential, Fourier transform infrared spectroscopy and thermal analysis) were utilized for all acids in order to study surface characteristics. The results indicated that polar organic compounds act in different ways according to their structure and properties. Presence of double bond could make the acid molecule more polar, reactive and less hydrophobic. In addition, it can affect the spatial arrangement of the molecule and hence its orientation on the surface. Presence of benzene ring increases the reactivity and polarity of carboxylic group. Moreover, it enhances hydrophilic properties of the acid due to electrons of pi double bonds that can resonate over aromatic carbon atoms. The results revealed that, in the presence of water film, combination of acid dissociation in water, surface activity of acid and water solubility controls the acid adsorption and hence wettability alteration of the surface during aging process. Chemisorption of carboxylic acids/asphaltene changes the wettability of calcite surface. In addition to chemical adsorption, some acids adsorb physically on the surface. Physical adsorption of polar compounds may happen via hydrogen bonding between carboxylic groups and carbonate ions on the surface. Although physical adsorption is reversible and forms weak bonds between adsorbate and adsorbent, it may partially contribute to wettability alteration.",14,14,2
Oil Recovery,Wettability Alteration,"Al-Ibadi, Hasan; Stephen, Karl D.; Mackay, Eric",Insights into the fractional flow of low salinity water flooding in the light of solute dispersion and effective salinity interactions,Low salinity waterflooding; Fractional flow; Chemical flooding and salinity dispersion,IMPROVED OIL-RECOVERY; CRUDE-OIL; WETTABILITY ALTERATION; BRINE COMPOSITION; INJECTION; FINES; PERMEABILITY; MIGRATION; FLUID,"The objective of Low Salinity Water Flooding (LSWF) is to improve oil recovery. While a significant number of laboratory tests have been carried out to investigate the impact of LSWF, field scale modelling is often reported in the form of sector models with relatively coarse cells. This paper assesses the impact of simulating flow at very fine scales and informs on the properties that should be captured at the coarse scale to avoid numerical errors. We have found that the weighting function that is used to control changes to fluid mobility combines with numerical and physical diffusion to induce a retardation/acceleration effect. This is a physical effect rather than part of a chemical reaction. In this study, numerous simulations of LSWF have been carried out at the reservoir scale to investigate flow behaviour for various salt concentration (salinity) weighting functions and dispersion coefficients. We have examined the effective salinity range over which the weighting function is applied as well as considering various shapes. Dispersion was varied to represent physical and numerical effects. These have been compared to analytical solutions from fractional flow theory. We also observed that the fractional flow of the oil bank will be same for both the secondary and tertiary flooding. We point out the relative importance of various parts of the relative permeability curves. An important finding of this work is that by spreading the salinity front through dispersion and setting a low value at which salinity impacts mobility, we saw the injected low salinity front advance more slowly while the high salinity front of formation water moves more quickly. This is an effective retardation effect. We related this to an effect equivalent to adsorption in the fractional flow theory and could measure it in a similar way. We were also able to develop a prediction of the effect using the analytical solution to the advection-diffusion equation. The outcome is that we can estimate a corrective term for the flow behaviour in situations where the dispersion is quite strong, particularly in numerical simulations. We consider that this enable corrections to be made for numerical dispersion effects in field scale models.",14,14,2
Oil Recovery,Wettability Alteration,"Liang, Can; Xiao, Lizhi; Zhou, Cancan; Wang, Hua; Hu, Falong; Liao, Guangzhi; Jia, Zijian; Liu, Huabing",Wettability characterization of low-permeability reservoirs using nuclear magnetic resonance: An experimental study,Wettability; NMR relaxation; Low-permeability reservoir; Aging; Reservoir type,DIFFUSION MEASUREMENTS; INDEX DETERMINATION; POROUS-MEDIA; RELAXATION; RECOVERY; TIME; IMBIBITION; ROCKS; PROBE; WATER,"Influence of wettability to petrophysical responses in low permeability reservoirs is increasingly evident, but research of nuclear magnetic resonance (NMR) technology on wettability calibration in such reservoirs is very limited even though it has been used promisingly. The challenge is that the empirical interpretation model only applies to simple pore structure. It is urgent to develop a relatively simple, quick, and practicable model for wettability evaluation in low permeable reservoirs. This paper presents an experimental NMR study, integrating with Amott tests, X-ray diffraction, and scanning electron microscope (SEM) measurements, on wettability characterization of five typical core samples from different low-permeability reservoirs. NMR relaxation mechanisms and the effect of the aging were analyzed in detail. The study showed that all the core samples had a shift of T-2( )(spin-spin relaxation time) spectra between before and after aging. According to the shift characteristics, the core samples were divided into two types. The first type is that the wettability alteration relied on the aging and it displaced crude oil into original water-wet movable pore spaces to restore reservoir wettability. This type of formation is generated in distant-source reservoirs, which mainly involves fluid transport through buoyancy. Another type is that the wettability alteration was attributed to the natural oil-wet property of the rock matrix. This formation is mainly found in inner-source or near-source reservoirs, which may generate abundant oil-wet materials. Thus, the wettability alteration is the result of hydrocarbon accumulation modes. Based on the observations, a potential method for obtaining the wettability index was proposed. The method uses both the ratio of oil-wetted to water-wetted pore surface areas and diffusion-relaxation diagrams. The estimated results corresponded reasonably to the independent Amott tests. This study demonstrates that NMR relaxation is an effective solution to analyze and quantify wettability in low permeability reservoirs.",14,14,1
Oil Recovery,Wettability Alteration,"Panahpoori, Donya; Rezvani, Hosein; Parsaei, Rafat; Riazi, Masoud",A pore-scale study on improving CTAB foam stability in heavy crude oil-water system using TiO2 nanoparticles,TiO2 nanoparticle; CTAB foam; Foam stability; EOR; Glass micromodel,IMMISCIBLE FOAM; POROUS-MEDIA; CO2 FOAM; SURFACTANT; ZRO2; DISPLACEMENT; ASPHALTENE; ADSORPTION; RECOVERY; BULK,"The main challenge of foam injection for enhanced oil recovery (EOR) is foam stability at harsh reservoir conditions. With regard to this matter, this research aims to investigate the effect of TiO2 nanoparticles (NPs) in improving the stability of foam bubbles in porous media. The conductivity of hexadecyltrimethylammonium bromide (CTAB) solutions was measured to determine critical micelle concentration (CMC). Thereafter, TiO2 NPs were added into the foam solution and pH, contact angle, and interfacial tension (IFT) in the presence and absence of CTAB were measured. The stability of foam bubbles was evaluated through bulk foam tests and absorbance measurements. Finally, different nanofluids (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.10 wt%), nano-CTAB solutions (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs at the CMC of CTAB) and foams (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs and at the CMC of CTAB) were injected into a heavy oil saturated heterogeneous porous medium. The results of the conductivity measurements showed that the highest adsorption of CTAB molecules onto the NPs surfaces occurs at 0.03 wt% NPs and 0.03 wt% CTAB. The results of micro- and macroscopic images from bulk foam tests revealed improved foam stability for this nano-CTAB foam. Moreover, contact angle and IFT results showed further improvement in interfacial properties for the mixture of NPs and CTAB solutions. Ultimately, in terms of oil recovery, the highest oil recovery factor (54%) was observed upon injection of foam with 0.03 wt% TiO2 NPs and 0.03 wt% CTAB, compared to the 22% recovery factor of DW injection. The visualization experiments showed that 32% enhancement in the recovery factor was mainly due to oil production from dead-end pores. This was because of different functions of NPs including stabilization of foam bubbles, wettability alteration, and improved foam generation mechanisms.",13,13,4
Oil Recovery,Porous Media,"Saxena, Neha; Goswami, Abhishek; Dhodapkar, P. K.; Nihalani, M. C.; Mandal, Ajay","Bio-based surfactant for enhanced oil recovery: Interfacial properties, emulsification and rock-fluid interactions",Natural surfactant; Interfacial tension; Wettability alteration; Emulsion; Adsorption; Enhanced oil recovery,LIPASE-CATALYZED SYNTHESIS; ACIDIC CRUDE-OIL; WETTABILITY ALTERATION; ANIONIC SURFACTANT; POROUS-MEDIA; ADSORPTION; TENSION; WATER; SULFONATE; BIODEGRADABILITY,"Anionic surfactants are very effective for application in enhanced oil recovery (EOR) in sandstone reservoirs because of their promising surface-active properties. Considering the non-biodegradability of some of the commercial surfactants, the present study deals with an anionic surfactant synthesized from naturally occurring soap-nut oil with excellent interfacial properties for application in EOR. The soap-nut surfactant showed the promising properties of interfacial tension (IFT) reduction, emulsification, rock wettability alteration, which are desirable for its application in EOR. An ultra-low IFT value of 2.123 x 10( -2) mN/m between crude oil and surfactant solution was obtained at critical micelle concentration (CMC), which was further reduced to 2.037 x 10( -3) mN/m at optimum salinity. Phase behaviour studies showed the formation of Winsor III emulsion phase which is beneficial for recovery of the trapped oil from the fine pores of the reservoir by miscibility mechanism. The surfactant exhibited favourable rock-wetting ability from oil-wet rock to water-wet condition. The loss of surfactant by adsorption on the rock surface was studied, and the adsorption data were analysed by Langmuir and Freundlich models. Injection of a small pore volume of surfactant-slug augmented with polymer slug as mobility buffer recovered more than 30% of original oil in place (OOIP) after the conventional water-flooding.",39,39,4
Oil Recovery,Porous Media,"Meng, Qingbang; Cai, Zhongxian; Cai, Jianchao; Yang, Feng",Oil recovery by spontaneous imbibition from partially water-covered matrix blocks with different boundary conditions,Spontaneous imbibition; Partially water-covered boundary condition; Scaling of imbibition data; Characteristic length,COUNTER-CURRENT IMBIBITION; POROUS-MEDIA; COCURRENT; VISCOSITY; RESERVOIRS; CARBONATE; SYSTEMS; TUBES; WORK; FLOW,"Oil production by spontaneous imbibition from matrix block can occur in both co- and counter-current modes when matrix block was partially covered by water. In this paper, oil recovery from partially water-covered matrix blocks with different boundary conditions was studied by numerical calculation. The boundary conditions were categorized and named according to the number of water-cover- and oil-covered-faces and relative position between water-covered- and oil-covered-faces. The numerical models with different boundary conditions were established. The water saturation distribution and direction of fluid flow in the matrix blocks were presented. In addition, the imbibition recovery curves of oil recovery versus imbibition time for different boundary conditions were presented and the effect of different factors on the rate of oil production was discussed. The calculated results showed that the area of water-covered-face has more significant effect on the rate of oil production than that of oil-covered-face. The distance travelled by fluids from water-covered-face to oil-covered-face is another important factor that affects the rate of oil production. The water imbibed from a certain water-covered-face preferentially displaces oil towards the closest oil-covered-face. Accordingly, three criteria for calculation of characteristic length for co-current imbibition is proposed and the close correlation of imbibition curves was obtained in the early stage of imbibition process by use of the proposed characteristic length to calculate the dimensionless time.",32,33,6
Oil Recovery,Porous Media,"Nowrouzi, Iman; Manshad, Abbas Khaksar; Mohammadi, Amir H.",Effects of concentration and size of TiO2 nano-particles on the performance of smart water in wettability alteration and oil production under spontaneous imbibition,Smart water; TiO2; Wettability; Contact angle; Nano-fluids; Chemical enhanced oil recovery,INTERFACIAL-TENSION IFT; DISSOLVED CARBON-DIOXIDE; LOW-SALINITY; CRUDE-OIL; THERMAL-CONDUCTIVITY; PHYSICAL-PROPERTIES; INJECTION PROCESSES; CONTACT-ANGLE; POROUS-MEDIA; RECOVERY EOR,"Using smart nano-fluids with respect to enhanced oil recovery (EOR) is an emerging technology, which is normally studied in combination with other methods. Nano-fluid performance depends on type, size and concentration of the dispersed nano-particles in it. In the current work, effects of size and concentration of seawater-based nano-fluid of TiO2 in different salinities (resulted from dilution) on enhanced oil recovery parameters including contact angle, wettability and interfacial tension (IFT) have been investigated using the pendant drop method. Eventually, effect of TiO2 nano-particles in nano-fluids on recovered quantity has been investigated using imbibition experiment mechanism, which is one of the most important mechanisms in oil production from fractured reservoirs. Results of the experiments show that using higher concentration and smaller particle sizes of TiO2 would decrease the IFT and contact angle. Higher concentration and larger particle sizes of TiO2 in nano-fluid would increase the viscosity. Imbibition experiments show that the nanofluids containing smaller TiO2 nanoparticles are more efficient.",30,30,9
Oil Recovery,Porous Media,"Xu, Jianchun; Sun, Baojiang; Chen, Bailian",A hybrid embedded discrete fracture model for simulating tight porous media with complex fracture systems,Numerical simulation; Discrete fracture model; Naturally fractured tight oil reservoir; Transient transfer; Stochastic permeability,SHALE-GAS-RESERVOIRS; SHAPE FACTORS; NUMERICAL-SIMULATION; FLOW; PRESSURE; TRANSPORT; FLUIDS; OIL; FRAMEWORK,"Numerical simulation considering complex fracture networks in tight oil reservoir becomes a hot issue during these years. Recently, embedded discrete fracture model (EDFM) shows great advantages over the DFM approaches in both calculation efficiency and simplicity of simulation workflow. EDFM has been widely used in tight oil/gas natural energy or enhanced oil recovery (EOR) development. If a large number of small-scale natural fractures exist in reservoir, the calculation efficiency of EDFM method may decrease. In this paper, a new hybrid simulation model combining the EDFM and dual porosity (DP) model is proposed. The large-scale fractures are dealt with EDFM method while small scale fractures are dealt with DP model. Considering the low permeability of matrix, transient transfer between matrix and natural fracture is considered. The proposed hybrid model is validated compared with the local grid refinement (LGR) model and EDFM-MINC model, and the difference between transient transfer and pseudo-steady-state transfer effect on production is presented. Finally, two test cases are presented, and the sensitivity of some key parameters are investigated. Result shows that the new simulation model has higher calculation efficiency than LGR and EDFM-MINC models. Meanwhile, it honors a good accuracy. The pseudo-steady-state transfer between matrix and natural fracture leads to big error in tight oil production performance analysis both in single phase and two phases flow. Low matrix permeability and big matrix size increase the production difference between pseudo-steady-state transfer and transient transfer models. The proposed model can simulate reservoirs considering stochastic permeability distribution.",29,30,6
Oil Recovery,Porous Media,"Gbadamosi, Afeez O.; Junin, Radzuan; Manan, Muhammad A.; Agi, Augustine; Oseh, Jeffrey O.; Usman, Jamilu",Synergistic application of aluminium oxide nanoparticles and oilfield polyacrylamide for enhanced oil recovery,Enhanced oil recovery; Polymers; Nanoparticles; Polymeric nanofluid; Aluminium oxide; Nanotechnology,PARTIALLY HYDROLYZED POLYACRYLAMIDE; ACRYLAMIDE-BASED POLYMER; HEAVY-OIL; WETTABILITY ALTERATION; SILICA NANOPARTICLES; RHEOLOGICAL PROPERTIES; ADSORPTION MECHANISM; SIO2 NANOPARTICLES; THERMAL-STABILITY; NANOFLUIDS,"Due to the inherent limitation of oilfield polyacrylamide in reservoir temperature and salinity, nanoparticles (NPs) have been extensively studied for their application in enhanced oil recovery (EOR) because of their unique properties and availability in large quantities. Recent trend in nanotechnology involves incorporating NPs as additive with polymer to form novel materials termed polymeric nanofluids (PNF's) for EOR. However, previous studies have investigated and focussed more on the suitability of silica (SiO2) polymeric nanofluids. In this work, the potential application of metal oxide polymeric nanofluid for EOR was explored and evaluated. Aqueous HPAM-based Al2O3 PNF's were formulated and characterised using Transmission Electron Microscopy (TEM) and Fourier-transform infrared (FTIR) spectroscopy. The performance of aluminium oxide (Al2O3) NP on the rheological properties of HPAM in the presence of different electrolyte concentrations representative of field brine and typical reservoir temperatures were investigated. Wettability alteration study of Al2O3 PNF was carried out using DataPhysics optical contact angle (OCA) instrument. Results obtained for Al2O3 PNF were compared to the widely reported SiO2 PNF and base polymer without nanomaterial. Experimental results show that the rheological properties improved while degradation of HPAM macromolecule was inhibited due to the addition of NPs. At 2,000 ppm HPAM solution (25 mol. % degree of hydrolysis), 0.1 wt% NP concentration was found to be the optimal choice for Al2O3 NP which gives rise to the highest viscosity on the rheological characterization. Al2O3 PNF exhibited better steady shear viscosity performance under the different electrolyte concentrations and temperatures studied. Al2O3 PNF altered the wettability of the porous media from oil-wet to water-wetting condition. Finally, oil displacement test in sandstone cores at typical reservoir temperature and salinity showed that Al2O3 PNF had 11.3% incremental oil recovery over conventional HPAM. This study is beneficial for extending the frontier of knowledge in nanotechnology application for EOR.",28,28,9
Oil Recovery,Porous Media,"Wang, Yanwei; Liu, Huiqing; Wang, Jing; Dong, Xiaohu; Chen, Fangxuan",Formulation development and visualized investigation of temperature-resistant and salt-tolerant surfactant-polymer flooding to enhance oil recovery,Surfactant-polymer flooding; Enhanced oil recovery; Anti-temperature; Salt-tolerance; Visualized experiment; Microscopic mechanisms analysis,INTERFACIAL-TENSION; ZWITTERIONIC SURFACTANT; OPTIMIZATION; PERFORMANCE; SYSTEM,"As a tertiary oil recovery technique with broad application prospects, surfactant-polymer flooding can significantly improve sweep efficiency and enhance oil recovery, while eliminate the negative effects of alkali thoroughly. However, for most oil reservoirs abroad, belonging to marine carbonate reservoirs with high temperature and high salt content, SP flooding is largely limited. In this paper, the surface (interface) chemical properties of different types of surfactants were evaluated to select a mixed surfactant system with better performance and synergistic effect. And experiments on the physicochemical properties evaluation of polymers were performed to select a more suitable polymer. On this basis, the formulation of the surfactant-polymer binary composite system was optimized and the performance was evaluated. A visualized model was adopted to study the process of SP flooding, which vividly reflected the interaction of chemical agents with crude oil and the migration of chemical agents in porous media, as well as macroscopic and microscopic EOR mechanisms of SP Flooding. The results showed that Hexadecyl dimethyl carboxybetaine (C16HSB), heavy alkyl the linear alkylated diphenylmethane sulfonate (C-14-DSDM) and the hydrophobically modified polyacrylamide-based novel functional polymer GT-1 were selected. The optimized formulation of the SP flooding system was selected for 2000 mg/L GT-1 + 3000 mg/L C-14-DSDM + 1000 mg/L C16HSB, which showed higher apparent viscosity and lower interfacial tension (7.2 x 10(-3) mN/m) under the condition of 70 degrees C and 9780.5 mg/L formation water salinity. The system showed a certain resistance to temperature and salt, and stability under the conditions of temperature below 80 degrees C and salinity below 40000 mg/L and an EOR value of 31.2% in the visualized displacement experiment. Surfactants in the SP flooding system can emulsify the residual oil into spherical and flocculent emulsions, which are then stripped, drawn into filaments, and easily motivated. The retention of more polymer molecules in the throat causes the intermolecular association of polymer molecules to form a denser network structure, which plays an important role in increasing flow resistance and changing the direction of liquid flow, and its viscoelasticity contributes to the discharge of residual oil. Under the synergistic effect of surfactants and polymer, hydrodynamic residual oil, membrane residual oil, and residual oil droplets can be mobilized, thus beneficial to enhance oil recovery.",26,29,4
Oil Recovery,Porous Media,"Divandari, Hassan; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin; Ranjbar, Mohammad",Integrating synthesized citric acid-coated magnetite nanoparticles with magnetic fields for enhanced oil recovery: Experimental study and mechanistic understanding,Enhanced oil recovery; Nanofluid; Citric acid-coated Fe3O4 nanoparticles; Magnetic field; Wettability alteration; IFT; Micromodel,HEAVY OIL; ALPHA-FE2O3 NANOPARTICLES; MAGNETORHEOLOGICAL FLUID; WETTABILITY ALTERATION; SANDSTONE CORES; NANO-PARTICLES; CRUDE-OIL; WATER; WET; NANOFLUID,"Nanofluid injection has emerged as an attractive enhanced oil recovery (EOR) process in the past decade. These fluids improve oil recovery by reducing interfacial tension (IFT), modifying wettability, and reducing mobility ratio. In this communication, magnetite citric acid-coated nanoparticles (NPs) were synthesized by an affordable, facile and one step method and then characterized using Field emission scanning electron microscopy (FESEM), X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR), and Dynamic light scattering (DLS). Afterward, the microscopic and macroscopic efficiencies of oil recovery in heterogeneous and homogeneous 2D micromodels were investigated in the presence of magnetic field. Citric acid-coated magnetite NPs started to respond to the magnetic field around the intensity of 800 Gauss and also showed the maximum ultimate recovery factor at the intensity of 2750 Gauss. In addition, citric acid coated magnetite NPs provided more enhanced oil recovery factor compared to hematite NPs, because of reducing interfacial tension (IFT) between the oil and injection fluid, altering surface wettability from oil-wet to water-wet, promoting the NPs distribution in porous media, and generating column-like structure in the presence of magnetic field. In fact, magnetite NPs act as piston toward the magnetic field by creating a column which sweeps the oil and increases production. Furthermore, citric acid-coated magnetite NPs flooding increased ultimate recovery factor more than polymer and hematite NPs flooding.",24,25,10
Oil Recovery,Porous Media,"Cui, Ronghao; Feng, Qihong; Chen, Hongwei; Zhang, Wei; Wang, Sen",Multiscale random pore network modeling of oil-water two-phase slip flow in shale matrix,Pore network model; Shale oil; Two-phase flow; Slip effect; Computational fluid dynamics,FRACTURED HORIZONTAL WELL; FAST MASS-TRANSPORT; POROUS-MEDIA; RELATIVE PERMEABILITY; DYNAMIC PROPERTIES; CO2 SEQUESTRATION; ORGANIC-MATTER; GAS-FLOW; NANOPORES; RESERVOIR,"The large-scale hydraulic fracturing technology is commonly employed to significantly improve oil recovery in shale. An exceptional phenomenon from many field tests is worthy of attention that the majority of fracturing fluid (mainly water) does not return to the surface during hydraulic fracturing, but flows into shale matrix. As a consequence of this phenomenon, oil-water two-phase flow would happen. However, the fluid transportation in nano-pores is different from that of the conventional sandstone reservoirs. To understand oil-water two-phase flow in shale, an integrated pore network model (PNM) framework including network construction and flow simulation is developed. In the network construction, combined with a pore-size distribution (PSD) curve of shale system, a shale multiscale random pore network model is proposed, where organic pores and inorganic pores can be distinguished appropriately. In the flow simulation, considering that the traditional Hagen-Poiseuille equation may not be applicable in shale system, new bulk fluid and corner film flow models with slip length in various geometric pores (circular, square, equilateral triangle) are developed using the computational fluid dynamic (CFD) method. Through the quasi-static simulation technique, we estimate the flow properties in shale including capillary pressure and relative permeability. Simulation results confirm the slip effect would significantly affect oil-water two-phase flow in shale. And then, influences of shale pore structure on two-phase flow are further investigated. Through coupling network construction and two-phase flow simulation, we believe our work could shed light on the further research for multi-phase transportation in shale.",23,24,9
Oil Recovery,Porous Media,"Giraldo, Lady J.; Gallego, Jaime; Villegas, Juan P.; Franco, Camilo A.; Cortes, Farid B.",Enhanced waterflooding with NiO/SiO2 0-D Janus nanoparticles at low concentration,Janus nanoparticles; Nanofluid flooding; Capillary number (N-C); Enhanced oil recovery (EOR),HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SILICA NANOPARTICLES; POROUS-MEDIA; SIO2 NANOPARTICLES; ADSORPTION ENERGY; RECOVERY; WATER; ASPHALTENES; BEHAVIOR,"The nanofluid (nanoparticles dispersed in determined carrier fluid) flooding has been studied for reducing the interfacial tension (IFT), increasing the viscosity of the displacement phase and to alter the rock wettability, which impact the capillary number and hence increase the crude oil recovery. However, this technique requires commonly large concentration of nanoparticles for being efficient in enhanced oil recovery (EOR) processes. Hence, the primary objective of this manuscript is to develop NiO-containing Janus nanoparticles based on zero-dimension (0-D) SiO2 nanoparticles which can be effective at low concentrations. The synthesized nanoparticles were characterized by transmission electron microscopy (TEM), surface area (S-BET), zeta potential, interfacial tension (IFT), rheology, contact angle measurements and coreflooding tests. The results showed a sharply increase of the capillary number (Nc) at a very low concentration of 100 mg/L of Janus nanoparticles, mainly attributed to the decrease in the interfacial tension, which can lead to the increase of the oil recovery. Displacement tests using a SiO2 nanoparticles-based nanofluid at a concentration of 100 mg/L did not show an increase in oil recovery regarding the one obtained in the waterflooding step. Meanwhile, the nanofluid based on NiO/SiO2 Janus nanoparticles at the same concentration of 100 mg/L showed an increase in oil recovery up to 50%.",21,22,6
Oil Recovery,Porous Media,"Aghajanzadeh, Mohammad Reza; Ahmadi, Pouyan; Sharifi, Mohammad; Riazi, Masoud",Wettability modification of oil-wet carbonate reservoirs using silica-based nanofluid: An experimental approach,Wettability alteration (WA); Nanoparticles; Spontaneous imbibition; Oil recovery; Carbonate rocks; Relative permeability,RECOVERY; NANOPARTICLES; IMBIBITION; CALCITE,"Wettability is an important factor which controls oil recovery and fluids displacement efficiency in the porous media. Wettability alteration (WA) from strongly oil-wet towards water wet or neutral states is one of the most effective methods of oil recovery increment. Many studies have shown that nanofluid can change the wettability of rock surface towards a desirable state and base on literature structural disjoining pressure is the main mechanism of wettability alteration via nano-treatment. However, there is a lack of information regarding the impact of salinity on nanofluid performance in porous media. Therefore, in this work, the effects of salinity, nanofluid concentration and rock type (i.e. limestone and dolomite surfaces) on wettability alteration of oil wet carbonate substrates under ambient condition were investigated. For this purpose, various static and dynamic experiments including contact angle, imbibition and core flood tests have been performed. The results on contact angle measurements showed that by increasing nanoparticles and electrolyte concentration the wettability alteration from oil wet to water wet was significantly enhanced. Moreover, the wettability alteration of dolomite substrate is much more than that of limestone substrate. In the following, the impact of nanofluid on the spontaneous imbibition for strongly oil-wet carbonate cores was closely examined. Finding results showed an increase as much as 15% of oil recovery for nanofluid imbibition in comparison to that of formation brine. Final evaluation of the nanofluid treatment in terms of its effectiveness was measured by core flood experimental runs. Comparison of relative permeability curves before and after treating have outlined that after the treatment process, the relative permeability curve has shifted to the right and the water relative permeability has reduced from 0.43 mD to 0.23 mD at the residual oil saturation due to wettability alteration of rock surface from strongly oil wet to water wet state.",21,21,6
Oil Recovery,Porous Media,"Jia, Bao; Tsau, Jyun-Syung; Barati, Reza",Measurement of CO2 diffusion coefficient in the oil-saturated porous media,Molecular diffusion; CO2; Single-porosity; Grid sensitivity,CARBON-DIOXIDE; GAS INJECTION; RECOVERY; PRESSURE; BITUMEN; STORAGE,"Molecular diffusion is an important EOR mechanism in naturally fractured reservoirs. However, the laboratory-measured diffusion coefficient in the fractured porous media is still limited; and grid sensitivity analysis is missing in the literature when the single-porosity system is applied to history match the pressure decline curve. We aimed to fill the gaps using Radial Constant Volume Diffusion (RCVD) method experimentally to investigate diffusion coefficients at different pressures in hydrocarbon saturated porous media. A special in-house cell is designed to hold the core sample in the center with the annulus around simulating the fracture. The core is initially saturated with oil while the annulus is filled with CO2 at the same pressure. During the measurements, the system pressure declines as gas diffuses into the oil phase until it reaches chemical equilibrium. The pressure decline curve is history matched to determine the diffusion coefficient. The initial pressure is 597 psi, and the diffusion coefficient is determined in numerical models accordingly. Molecular diffusion coefficients are estimated at different experiment periods to reveal the pressure-dependency. A workflow is proposed to obtain effective diffusion coefficients in dual-porosity models that could be extended to multi-component systems. Besides, flow characteristics in the RCVD system are characterized and capillary pressure effect is investigated in this study.",20,20,2
Oil Recovery,Porous Media,"Wang, Fuyong; Zhao, Jiuyu",A mathematical model for co-current spontaneous water imbibition into oil-saturated tight sandstone: Upscaling from pore-scale to core-scale with fractal approach,Spontaneous imbibition; Co-current; Tight oil; Fractal; Porous media; Capillary tube,2-PHASE FLOW; RECOVERY; WETTABILITY; DYNAMICS,Spontaneous Imbibition (SI) is an important mechanism of enhancing oil recovery in tight oil reservoirs. Predicting core-scale oil flow rate by water imbibition from the pore-scale SI modelling is challenging due to the wide distributions of nano- and micro-pores in tight sandstone and huge amount of calculation of upscaling pore-scale modelling results for core-scale prediction. A semi-analytical mathematical model of characterizing co-current SI of water into oil-saturated tight sandstone has been proposed in this paper based on the capillary tube model and fractal theory. The non-uniform of water imbibition front due to the different imbibition rate in different sizes of pores can be dynamically characterized. Connate water and residual oil are considered and treated as immovable boundary-layers and coupled into the tortuous capillary tube model. The proposed model has been validated with the experiments results of core imbibition tests from literature. The key parameters of pore structures and fluid properties influencing imbibition flow rate have been quantitatively analyzed and identified.,19,23,6
Oil Recovery,Porous Media,"Harimi, Behrouz; Masihi, Mohsen; Mirzaei-Paiaman, Abouzar; Hamidpour, Esmaeil",Experimental study of dynamic imbibition during water flooding of naturally fractured reservoirs,Spontaneous imbibition; Dynamic imbibition; Fractured reservoirs; Water flooding,COCURRENT SPONTANEOUS IMBIBITION; OIL-RECOVERY; POROUS-MEDIA; PETROPHYSICAL PROPERTIES; ANALYTICAL-MODEL; WET; INJECTION; SATURATION; GLYCEROL; GRAVITY,"Capillary imbibition is an important recovery mechanism in naturally fractured reservoirs when water-filled fractures surround water-wet matrix blocks. A large amount of studies of imbibition process is simply total or partial immersion of nonwetting phase saturated rock in aqueous wetting phase. However, water advance in fractures during water flooding or water encroachment from an active aquifer introduces time dependent boundary conditions where invariant exposure of rock surface to water is not representative. In this work, a laboratory simulated matrix-fracture system was used to investigate different aspects of imbibition in the presence of fracture fluid flow (namely dynamic imbibition). A limestone and a sandstone core plug samples were selected as porous media. A total number of 11 dynamic imbibition and one static imbibition experiments were performed. Core plugs were strongly water-wet to maximize the role of capillary forces. Kerosene and air were the nonwetting fluids in experiments. The impact of water injection rate in the fracture was examined and the results revealed that as the injection rate increases above a critical rate, breakthrough recovery declines, however when injection rate is less than the critical rate increasing injection rate enhances recovery rate without any loss in recovery. Increasing wetting phase viscosity by means of glycerol solution was examined, as well. This reduced the imbibition rate and breakthrough recovery in both water-oil and water-air systems. Furthermore, comparing dynamic imbibition recovery data with a conventional immersion static experiment showed clear discrepancy which is due to different counter- and co-current flow modes. This emphasizes that static imbibition results should not be used for prediction of fractured reservoir performance under water flooding.",19,19,2
Oil Recovery,Porous Media,"Gharibshahi, Reza; Jafari, Arezou; Ahmadi, Hamid",CFD investigation of enhanced extra-heavy oil recovery using metallic nanoparticles/steam injection in a micromodel with random pore distribution,Oil recovery factor; Steam; Nanoparticles; CFD; Design experiment; Taguchi method; Optimization; Micromodel,MULTIPHASE MIXTURE MODEL; CAPILLARY-POROUS MEDIA; MULTICOMPONENT TRANSPORT; WETTABILITY ALTERATION; STEAM INJECTION; SANDSTONE CORES; SIMULATION; NANOFLUID; CATALYST,"The present study simulated thermal enhanced oil recovery (steam and nanoparticles) for the first time using computational fluid dynamics. To better visualize fluid flow in the reservoir, a 2D micromodel generated by commercial grid generation tools was used as the porous medium. Four parameters that have a great impaction on the process were studied to determine the best combination of factors to attain maximum oil recovery. Type of nanoparticle, volume fraction of nanoparticles, diameter of nanoparticles and temperature of injected fluid were examined using the Taguchi method. All governing equations were solved in Fluent software based on finite volume. The numerical results were in a good agreement with the experimental results and the data shows that Al2O3 nanoparticles have the greatest potential for enhanced oil recovery in comparison with CuO and Fe3O4 nanoparticles. Decreasing the diameter of the nanoparticles and increasing their volume fraction in the base fluid and the temperature of the injected fluid improved oil recovery and a large amount of oil was produced from the porous medium. Injecting the nanofluid at an optimal level decreased the viscosity of the extra heavy oil from 35 to 25 Pas.",18,20,6
Oil Recovery,Porous Media,"Yang, Jun; Wang, Xiangzeng; Peng, Xiaolong; Du, Zhongwei; Zeng, Fanhua",Experimental studies on CO2 foam performance in the tight cores,Foam; Mobility control; Tight oil; EOR; Resistance factor; Relative mobility,IMPROVED OIL-RECOVERY; SURFACTANTS; INJECTION; RESERVOIR; BEHAVIOR; WELLS,"Enhanced oil recovery for tight reservoirs with extremely low permeability and porosity is becoming the new routine for reservoir engineering research. Foam flooding has already been proven as an effective approach to enhance the oil recovery in conventional reservoirs. However, limited research has been done on the phenomena and mechanism of foam performance in the tight porous media. In this study, a series of core flooding tests are performed to investigate the foam performance in the absence and presence of oil in tight core samples with different permeabilities from 0.1mD to 3.3 mD. The foam resistance factor, mobility reduction factor, and relative mobility of the displacing fluid are investigated by comparing the foam flooding processes with waterflooding and the co-injection processes of brine and gas. The effectiveness of applying foam flooding as a tertiary recovery method in the tight core samples is studied by comparing the production data, pressure drop data, and relative mobility of displacing fluid between foam flooding and waterflooding. Unlike conventional foam injection process, the increase of foam quality will not create more stable foam flow that gives significant higher foam resistance factor and much better mobility control as expected in the tight core samples. Also, the foam resistance factors even decrease with increasing injection rates at such a low permeability. These results suggest the foam with low foam quality and low injection rate may be the answer to tight reservoir EOR application. As for the oil production test, the experimental results support the effectiveness of foam flooding on reducing mobility compared with waterflooding and the co-injection of brine and gas. An additional 15-22% oil recovery factor is achieved by introducing foam flooding after waterflooding has done. Surprisingly, comparing with a long period of waterflooding without any oil production, the additional oil was successfully produced at a much lower pressure drop during the early stage of foam injection. Since extremely high pressure drop may not be a necessary constraint on foam flooding EOR process in tight reservoirs, it suggests the potential solution on questionable injectivity issue during foam flooding in the tight reservoirs by introducing an optimized discontinuous surfactant-alternating-gas gas process. Also, the relative mobility of displacing fluid is lowered by one order of magnitude compared with waterflooding in the presence of oil.",17,17,2
Oil Recovery,Porous Media,"Weijermars, Ruud; Nandlal, Kiran; Khanal, Aadi; Tugan, Murat Fatih",Comparison of pressure front with tracer front advance and principal flow regimes in hydraulically fractured wells in unconventional reservoirs,Shale reservoirs; Pressure front; Tracer front; Depth of investigation; Drained rock volume; Flow regimes,VERTICAL WELL; INTERFERENCE,"Pressure depletion patterns near hydraulically fractured wells in ultra-low permeability reservoirs occupy a much larger region than outlined by fluid withdrawal contours. When used for reservoirs with moderate or high permeability (say k>1 mD), industry never needed to caution using pressure depletion plots as a proxy for fluid removal or drained rock volume (DRV). For such conventional reservoirs, pressure depletion plots are good proxies for fluid removal or drained rock volume (DRV). The fluid that moves from the margins of a pressure front, indicative of the so-called diffusive depth of investigation (DOI), will reach the well on the time-scale of economic life of the well. However, a whole new way of thinking is required when studying ultra-low permeability shales (nanoDarcy range), where the distinction between pressure depletion zones and the DRV regions (where fluid is recovered from) becomes crucial to understand which factors control the hydrocarbon recovery process. Our detailed analysis compares the diffusive DOI, of the leading edge of the pressure depletion front, and that of the convective DRV given by a tracer front. Results show that the pressure depletion front between the fractures quickly approaches the adjoining fracture pressure, and most of the production originates from the fracture tips after 12 months. The pressure depletion pattern vastly overestimates the DRV, whereas the tracer front shows the actual produced rock volume. A final section evaluates the specific flow regimes that correspond to certain diffusive DOI and convective DRV growth stages in the life of the well. The discussion section explains how production diagnostic plots can be used to identify the moment in the well life when enhanced oil recovery methods should be applied. This study can facilitate a better understanding of the fluid flow in fractured porous media and can be used to optimize fracture and well spacing to maximize the DRV.",16,16,0
Oil Recovery,Porous Media,"Ameli, Forough; Moghbeli, Mohammad Reza; Alashkar, Ali",On the effect of salinity and nano-particles on polymer flooding in a heterogeneous porous media: Experimental and modeling approaches,Polymer flooding; Micro-model; Simulation; Recovery factor; Breakthrough time,ENHANCED OIL-RECOVERY; 2-PHASE FLOW; RELATIVE PERMEABILITY; RESIDUAL OIL; WETTABILITY; RESERVOIR; PHASE; FLUID; GAS,"In this study, polymer flooding process was simulated using COMSOL Multiphysics (R) modeling software. Navier-Stokes and phase field equations were solved simultaneously using finite element approach. Effects of salinity, viscosity, and nano-particles were studied on displacement efficiency of oil sample in the heterogeneous porous media. Modeling results for oil recovery factor and breakthrough time were obtained and compared to experimental outputs of another study. Results indicated that there exists a proper accommodation between the results. Errors ranged from 3% to 7% for oil recovery factor and 0.5%-0.9% for the breakthrough time in various injection scenarios. Using predefined structure of the under test micromodel, star-like meshes were developed in this software for the first time. This unstructured mesh is more likely to the pore structures of the sandstone reservoirs. To increase the validity of the results, a boundary layer was designated in the fluid flow path and mesh generation was performed manually in a complicated pore space instead of automatic mesh generation. Experimental and modeling results for the residual oil saturation as a function of dimensionless time were compared. Mesh dependency studies were performed to obtain the best number of mesh elements in which the most accurate results were obtained in the minimum required time. Finally, sensitivity analysis studies were performed as a function of injection rate, mobility ratio, and viscosity and the operating conditions were analyzed in terms of capillary number. All the polymer injection scenarios led to reasonable range for this parameter which verifies the accuracy of the selected operating parameters and the modeling approach.",15,15,5
Oil Recovery,Porous Media,"Yu, Fuwei; Jiang, Hanqiao; Xu, Fei; Zhen, Fan; Wang, Jitao; Cheng, Baoyang; Su, Hang; Li, Junjian",A multi-scale experimental study of hydrophobically-modified polyacrylamide flood and surfactant-polymer flood on enhanced heavy oil recovery,Heavy oil; Surfactant-polymer flood; Hydrophobically-modified polyacrylamide flood; Multi-scale experiments,IN-WATER EMULSIONS; INTERFACIAL-TENSION; CONFORMANCE CONTROL; POROUS-MEDIA; PORE-SCALE; INJECTION; SALINITY; RESERVOIR; METHODOLOGY; IMBIBITION,"A large amount of residual oil remained in heavy oil reservoirs after water flood due to its viscosity nature. And it has been validated that chemical flood, if applied appropriately, is an efficient and economical EOR method for deeply buried or thin heavy oil reservoirs. A multi-scale experimental evaluation workflow was designed to explore the mechanisms behind the production of residual oil in heavy oil reservoirs by chemical flood. And we conducted three multi-scale experiments to evaluate the performance of hydrophobically-modified polyacrylamide (HMHPAM) flood, surfactant-polymer (SP) flood and their combination. Based on the results of corefloods and medical CT scans, we demonstrated the EOR potential of HMHPAM flood (HPF) synergy with SP flood (SPF). After each coreflood, two samples were drilled from the heterogenous core used in the macro-scale experiment. And the micro-CT scan results of these samples visualized the distribution of oil phase and aqueous phase in each coreflood at the pore scale, and further quantified the decrease of continuous oil clusters caused by the HMHPAM solution and following injected fluids. Besides, we also observed the linear relationship between the volume of each oil cluster against its surface area and the logarithmic relationship between the volume of discontinuous oil cluster and its cumulative contribution to total oil volume. Moreover, a simple method to calculate the oil-water proportion in pores was developed to correlate the relationship between the displacement efficiency of each pore and its pore size. Results showed that the relationship between oil saturation in each pore and its pore size followed the power law correlation. Moreover, the pore-scale analysis also validated that the residual oil in most pores after water flood was effectively mobilized by the synergy of HPF and SPF.",15,18,5
Oil Recovery,Porous Media,"Ali, Nour El Cheikh; Zoghbi, Bilal; Fahes, Mashhad; Nasrabadi, Hadi; Retnanto, Albertus",The impact of near-wellbore wettability on the production of gas and condensate: Insights from experiments and simulations,Gas condensate; Wettability; Carbonate; Condensate banking; Well stimulation,POROUS-MEDIA; SANDSTONE; WELLS,"Condensate banking commonly occurs in gas-condensate reservoirs resulting in a reduction in well productivity. This phenomenon is linked to the phase behavior of the reservoir fluid, the drawdown management technique, as well as the trapping of liquid hydrocarbons due to strong rock-fluid interactions. Wettability alteration to neutral-wetting near the wellbore has been identified as a possible solution to alleviate the problem. In this work, we investigate optimizing wettability conditions towards maximizing productivity. A range of wetting conditions is examined, experimentally, and using numerical simulation techniques. The results show that it is possible to target an optimum wettability state that maximizes gas well deliverability. A signature of these optimum conditions is identified in the trend of spontaneous imbibition tests. Complete reversal of wetting conditions can result in better well productivity than the original wetting state, but in some cases it can reduce the amount of condensate recovered. This puts into question the common perception that an increase in the recovery of heavy components should be expected when liquid-wetting is reduced.",15,16,1
Oil Recovery,Porous Media,"Sharifipour, M.; Nakhaee, A.; Pourafshary, P.",Model development of permeability impairment due to clay swelling in porous media using micromodels,LSW flooding; Clay swelling; Permeability impairment; Micromodel; Image processing,OIL-RECOVERY FACTOR; CAPILLARY-PRESSURE; WATER; GAS; MONTMORILLONITE; WETTABILITY; SURFACE,"Swelling and displacement of clay minerals during drilling and production of oil and gas reservoirs are among the main mechanisms of formation damage. Most reservoirs contain clay minerals, either originally deposited during sedimentation phase, or precipitated from fluids flowing through matrix. Owing to the large specific surface area of clay particles, their swelling, detachment, and migrationmay lead to permeability impairment in porous media. Therefore, an accurate interpretation of the behaviour of clay particles in the porous media may enable us to prevent and possibly reverse the respective damage mechanisms. In this work, the pore-scale swelling behaviour of clays are studied using glass micro models as porous medium and Sodium bentonite as swelling clay. By image processing technique, effective porosity of model during low salinity water (LSW) flooding are estimated. The effect of different parameters such as porous medium aspect ratio and clay concentration on permeability impairment is studied. According to this study, besides higher clay concentrations, the permeability is also affected adversely by larger aspect ratio of pore bodies. Based on our experiments, a model is developed to estimate permeability impairment by clay swelling as a function of pore geometry and clay concentration.",14,14,2
Oil Recovery,Porous Media,"Liang, Can; Xiao, Lizhi; Zhou, Cancan; Wang, Hua; Hu, Falong; Liao, Guangzhi; Jia, Zijian; Liu, Huabing",Wettability characterization of low-permeability reservoirs using nuclear magnetic resonance: An experimental study,Wettability; NMR relaxation; Low-permeability reservoir; Aging; Reservoir type,DIFFUSION MEASUREMENTS; INDEX DETERMINATION; POROUS-MEDIA; RELAXATION; RECOVERY; TIME; IMBIBITION; ROCKS; PROBE; WATER,"Influence of wettability to petrophysical responses in low permeability reservoirs is increasingly evident, but research of nuclear magnetic resonance (NMR) technology on wettability calibration in such reservoirs is very limited even though it has been used promisingly. The challenge is that the empirical interpretation model only applies to simple pore structure. It is urgent to develop a relatively simple, quick, and practicable model for wettability evaluation in low permeable reservoirs. This paper presents an experimental NMR study, integrating with Amott tests, X-ray diffraction, and scanning electron microscope (SEM) measurements, on wettability characterization of five typical core samples from different low-permeability reservoirs. NMR relaxation mechanisms and the effect of the aging were analyzed in detail. The study showed that all the core samples had a shift of T-2( )(spin-spin relaxation time) spectra between before and after aging. According to the shift characteristics, the core samples were divided into two types. The first type is that the wettability alteration relied on the aging and it displaced crude oil into original water-wet movable pore spaces to restore reservoir wettability. This type of formation is generated in distant-source reservoirs, which mainly involves fluid transport through buoyancy. Another type is that the wettability alteration was attributed to the natural oil-wet property of the rock matrix. This formation is mainly found in inner-source or near-source reservoirs, which may generate abundant oil-wet materials. Thus, the wettability alteration is the result of hydrocarbon accumulation modes. Based on the observations, a potential method for obtaining the wettability index was proposed. The method uses both the ratio of oil-wetted to water-wetted pore surface areas and diffusion-relaxation diagrams. The estimated results corresponded reasonably to the independent Amott tests. This study demonstrates that NMR relaxation is an effective solution to analyze and quantify wettability in low permeability reservoirs.",14,14,1
Oil Recovery,Porous Media,"Panahpoori, Donya; Rezvani, Hosein; Parsaei, Rafat; Riazi, Masoud",A pore-scale study on improving CTAB foam stability in heavy crude oil-water system using TiO2 nanoparticles,TiO2 nanoparticle; CTAB foam; Foam stability; EOR; Glass micromodel,IMMISCIBLE FOAM; POROUS-MEDIA; CO2 FOAM; SURFACTANT; ZRO2; DISPLACEMENT; ASPHALTENE; ADSORPTION; RECOVERY; BULK,"The main challenge of foam injection for enhanced oil recovery (EOR) is foam stability at harsh reservoir conditions. With regard to this matter, this research aims to investigate the effect of TiO2 nanoparticles (NPs) in improving the stability of foam bubbles in porous media. The conductivity of hexadecyltrimethylammonium bromide (CTAB) solutions was measured to determine critical micelle concentration (CMC). Thereafter, TiO2 NPs were added into the foam solution and pH, contact angle, and interfacial tension (IFT) in the presence and absence of CTAB were measured. The stability of foam bubbles was evaluated through bulk foam tests and absorbance measurements. Finally, different nanofluids (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.10 wt%), nano-CTAB solutions (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs at the CMC of CTAB) and foams (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs and at the CMC of CTAB) were injected into a heavy oil saturated heterogeneous porous medium. The results of the conductivity measurements showed that the highest adsorption of CTAB molecules onto the NPs surfaces occurs at 0.03 wt% NPs and 0.03 wt% CTAB. The results of micro- and macroscopic images from bulk foam tests revealed improved foam stability for this nano-CTAB foam. Moreover, contact angle and IFT results showed further improvement in interfacial properties for the mixture of NPs and CTAB solutions. Ultimately, in terms of oil recovery, the highest oil recovery factor (54%) was observed upon injection of foam with 0.03 wt% TiO2 NPs and 0.03 wt% CTAB, compared to the 22% recovery factor of DW injection. The visualization experiments showed that 32% enhancement in the recovery factor was mainly due to oil production from dead-end pores. This was because of different functions of NPs including stabilization of foam bubbles, wettability alteration, and improved foam generation mechanisms.",13,13,4
Oil Recovery,Interfacial Tension,"Saxena, Neha; Kumar, Amit; Mandal, Ajay","Adsorption analysis of natural anionic surfactant for enhanced oil recovery: The role of mineralogy, salinity, alkalinity and nanoparticles",Anionic surfactant; Reservoir rock; Adsorption; Isotherm models; Nanoparticles,WETTABILITY ALTERATION; NONIONIC SURFACTANTS; SILICA NANOPARTICLES; STABILITY; MECHANISM; ROCK; ISOTHERMS; WET; PH,"Anionic surfactants are widely used as an effective chemical for enhanced oil recovery because of their unique characteristics of reducing interfacial tension (IFT) between the trapped crude oil and water, and alteration of wettability of reservoir rock from oil-wet to water-wet. However, the loss of surfactant by adsorption onto the solid rock surface is a major concern that reduces the efficiency of the surfactant flooding process and must be considered while designing the process. Present study highlights the equilibrium adsorption and kinetics of an anionic surfactant synthesized from soap-nut fruit on sandstone, carbonate and bentonite clay as representative of reservoir rocks. The mineralogy and morphology of the rocks were investigated by FE-SEM, XRD and BET surface area analysis. UV-Visible spectroscopy was used to measure the amount of surfactant adsorbed on solid rock/clay surface in batch experiments. The experimental equilibrium adsorption data were analyzed by using Langmuir, Freundlich, Temkin and Redlich-Peterson isotherm models and adsorption parameters were calculated. Adsorption kinetics of the surfactant system were studied and pseudo second order kinetic model was best fitted for the surfactant/rock/clay systems. Presence of salt was found to increase surfactant adsorption on rock/clay marginally. However, presence of alkali and nanoparticles was found to reduce the loss of surfactant by adsorption and shows synergistic effects on IFT reduction, which is beneficial for application of the surfactant in oil recovery. The findings of the study are quite helpful in proper designing of the surfactant flooding for enhanced oil recovery.",75,76,17
Oil Recovery,Interfacial Tension,"Liu, Junrong; Shen, James J.; Wang, Xiukun; Ge, Hongkui; Yao, Erdong",Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants,Shale oil; Spontaneous imbibition; Wettability alteration; Surfactant; IFT,CARBONATE RESERVOIRS; LOW-PERMEABILITY; RECOVERY; WATER; WET,"Wettability alteration exhibits a significant potential to improve the oil recovery of shale reservoirs by means of spontaneous imbibition through shifting the rock wetness from oil-wet to water-wet. The wettability of the oil-wet shale can be modified by adding surfactants in hydraulic fracturing fluids in the field practice. However, the mechanisms of wettability alteration in shale rocks are still unclear and there are reported discrepancies in different types of surfactants solutions. This work attempts to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of the Sichuan Basin in China, and to analyze their effects of wettability alteration and interfacial-tension (IFT) reduction on the spontaneous imbibition process of the oil-wet shale samples. By measuring the contact-angle, zeta-potential, and IFT, the efficiencies of different surfactants in terms of wettability alteration and IFT reduction are evaluated. The contact-angle experiments show that the water contact angle in rock/oil/water systems decreases when we add more surfactants, which indicates the hydrophilicity of shales is increased by surfactants. Specifically, for the anionic surfactant solutions, the contact angle doesn't immediately change, and it decreases with time, which is different from the sudden change of nonionic surfactants. Moreover, for different surfactants, the IFT decreases in a similar trend with the increase of surfactant concentration. Finally, spontaneous imbibition experiments are conducted and the results show that anionic surfactants are more favorable to recover shale oil than the nonionic surfactants. From the results obtained, it can be concluded that the anion surfactants and nonionic surfactant have different mechanisms for wettability alteration on the shale surface; anionic surfactants have better effect on wettability alteration than nonionic surfactants, however, the mechanism of wettability alteration in anionic surfactants have time delay. The wettability alteration dominates the oil recovery in the way of spontaneous imbibition. More water-wetness tends to yield a higher recovery. In addition, for anionic surfactant solutions, the reduction of IFT increases the final oil recovery and leads to a decrease of the imbibition rate. For nonionic surfactant solutions, the reduction of IFT increases both the imbibition rate and the final recovery, but the enhancement is not significant.",52,52,9
Oil Recovery,Interfacial Tension,"Yekeen, Nurudeen; Padmanabhan, Eswaran; Idris, Ahmad Kamal",Synergistic effects of nanoparticles and surfactants on n-decane-water interfacial tension and bulk foam stability at high temperature,Nanoparticles; Surfactants; Interfacial tension; Foam stability; Electrostatic interaction,SODIUM DODECYL-SULFATE; SILICA NANOPARTICLES; AQUEOUS FOAMS; CO2 FOAM; NONIONIC SURFACTANTS; WETTABILITY ALTERATION; OXIDE NANOPARTICLES; OIL; ADSORPTION; STABILIZATION,"The synergistic effects of nanoparticles and surfactants on decane-water interfacial tension, and bulk foam stability at high temperature was investigated in this study. The interfacial properties were determined using a spinning drop interfacial tensiometer while the foam stability was evaluated from the normalized foam height. The extent of interaction between nanoparticles and surfactants was estimated from the hydrodynamic nano-aggregate sizes and zeta potential values. The foam microscopic images and the bubble morphology were examined to elucidate the mechanisms of foam stabilization by nanoparticles. Results clearly showed that nano-particles-Triton X-100 mixed system demonstrated the smallest aggregate sizes in bulk solution and considerable reduction in water/n-decane interfacial tension. Significant reduction in interfacial tension and increased foam stability occurred due to electrostatic interaction between the charged surfaces of the nanoparticles and surfactant head-groups. However, influence of electrostatic attraction was found to be dominant over the influence of electrostatic repulsion in promoting foam stability and reducing interfacial tension. The most stable foam was generated by titanium dioxide (TiO2) nanoparticles and cetyltrimethylammonium, bromide (CTAB), while the least stable foam was generated in presence of multi-walled carbon nanotubes and triton X-100. Possible reasons and mechanisms for these observations were suggested. The destabilizing influence of high temperature on foam stability was significant, however, CTAB-foam stability increased by 160% and 440% in presence of silicon dioxide (SiO2) and TiO(2 )nanoparticles at 80 degrees C. This phenomenon can be attributed to the moderate adsorption and aggregation of surface-active complex at the gas-liquid interface of the foam and Plateau borders.",44,45,9
Oil Recovery,Interfacial Tension,"Saxena, Neha; Goswami, Abhishek; Dhodapkar, P. K.; Nihalani, M. C.; Mandal, Ajay","Bio-based surfactant for enhanced oil recovery: Interfacial properties, emulsification and rock-fluid interactions",Natural surfactant; Interfacial tension; Wettability alteration; Emulsion; Adsorption; Enhanced oil recovery,LIPASE-CATALYZED SYNTHESIS; ACIDIC CRUDE-OIL; WETTABILITY ALTERATION; ANIONIC SURFACTANT; POROUS-MEDIA; ADSORPTION; TENSION; WATER; SULFONATE; BIODEGRADABILITY,"Anionic surfactants are very effective for application in enhanced oil recovery (EOR) in sandstone reservoirs because of their promising surface-active properties. Considering the non-biodegradability of some of the commercial surfactants, the present study deals with an anionic surfactant synthesized from naturally occurring soap-nut oil with excellent interfacial properties for application in EOR. The soap-nut surfactant showed the promising properties of interfacial tension (IFT) reduction, emulsification, rock wettability alteration, which are desirable for its application in EOR. An ultra-low IFT value of 2.123 x 10( -2) mN/m between crude oil and surfactant solution was obtained at critical micelle concentration (CMC), which was further reduced to 2.037 x 10( -3) mN/m at optimum salinity. Phase behaviour studies showed the formation of Winsor III emulsion phase which is beneficial for recovery of the trapped oil from the fine pores of the reservoir by miscibility mechanism. The surfactant exhibited favourable rock-wetting ability from oil-wet rock to water-wet condition. The loss of surfactant by adsorption on the rock surface was studied, and the adsorption data were analysed by Langmuir and Freundlich models. Injection of a small pore volume of surfactant-slug augmented with polymer slug as mobility buffer recovered more than 30% of original oil in place (OOIP) after the conventional water-flooding.",39,39,4
Oil Recovery,Interfacial Tension,"Mokhtari, Rasoul; Ayatollahi, Shahab; Fatemi, Mobeen",Experimental investigation of the influence of fluid-fluid interactions on oil recovery during low salinity water flooding,Enhanced oil recovery; Low salinity water flooding; Fluid-fluid interactions; Core flooding; Interfacial tension,DETERMINING IONS CA2+; CRUDE-OIL; WETTABILITY ALTERATION; INTERFACIAL-TENSION; SMART WATER; SPONTANEOUS IMBIBITION; BRINE COMPOSITION; IMPACT; CARBONATES; TIME,"This study aims to investigate the role of fluid-fluid interactions during low salinity water flooding, using crude oil from an Iranian oil reservoir. To minimize the effects of mineral heterogeneity and wettability alteration, a synthetic sintered glass core was utilized and all coreflooding experiments were performed at low temperatures without any aging process. The effect of fluid-fluid interactions were investigated in both secondary and tertiary injection modes. pH measurements as well as UV-Vis spectroscopy and interfacial tension (IFT) analysis were performed on the effluent brine samples. Results: show that fluid-fluid interactions, mainly the dissolution of crude oil polar components into the brine, significantly affect brine physical and interfacial properties. In secondary injection scenario, two times diluted seawater (2SW), which has the lowest IFT value, exhibits the highest (81%) oil recovery factor. While the lowest recovery factor (60.75%) was observed for the case of formation water (FW) injection. To explore the effect of contacting time, after 48 h soaking, brine injection was resumed. The effluent pH measurement at this stage showed a reduction, where the UV-Vis spectroscopy and IFT measurements confirmed dissolution of the crude oil polar components into the brine. The results showed that as brine salinity decreases, the amount of dissociated polar components increases. pH value of ten times diluted sea water (10SW) was reduced from its initial value of 7.45 to 4.22, while FW exhibits minor pH variation. Consequently, 10SW, which dissolved highest amount of polar components, depicts the highest recovery factor (6%) after soaking. Contrary to this, in tertiary injection mode, the high amount of saline brine in the core (because of FW injection at secondary stage) hinders the potential for more production for SW, 2SW and 10SW injection as all resulted to lower recovery factor compared to their secondary counterparts.",31,32,3
Oil Recovery,Interfacial Tension,"Nowrouzi, Iman; Manshad, Abbas Khaksar; Mohammadi, Amir H.",Effects of concentration and size of TiO2 nano-particles on the performance of smart water in wettability alteration and oil production under spontaneous imbibition,Smart water; TiO2; Wettability; Contact angle; Nano-fluids; Chemical enhanced oil recovery,INTERFACIAL-TENSION IFT; DISSOLVED CARBON-DIOXIDE; LOW-SALINITY; CRUDE-OIL; THERMAL-CONDUCTIVITY; PHYSICAL-PROPERTIES; INJECTION PROCESSES; CONTACT-ANGLE; POROUS-MEDIA; RECOVERY EOR,"Using smart nano-fluids with respect to enhanced oil recovery (EOR) is an emerging technology, which is normally studied in combination with other methods. Nano-fluid performance depends on type, size and concentration of the dispersed nano-particles in it. In the current work, effects of size and concentration of seawater-based nano-fluid of TiO2 in different salinities (resulted from dilution) on enhanced oil recovery parameters including contact angle, wettability and interfacial tension (IFT) have been investigated using the pendant drop method. Eventually, effect of TiO2 nano-particles in nano-fluids on recovered quantity has been investigated using imbibition experiment mechanism, which is one of the most important mechanisms in oil production from fractured reservoirs. Results of the experiments show that using higher concentration and smaller particle sizes of TiO2 would decrease the IFT and contact angle. Higher concentration and larger particle sizes of TiO2 in nano-fluid would increase the viscosity. Imbibition experiments show that the nanofluids containing smaller TiO2 nanoparticles are more efficient.",30,30,9
Oil Recovery,Interfacial Tension,"Ghasemian, Javad; Riahi, Siavash; Ayatollahi, Shahab; Mokhtari, Rasoul",Effect of salinity and ion type on formation damage due to inorganic scale deposition and introducing optimum salinity,Water flooding; Smart water; Potential determining ions; Scale; Optimum composition; Enhanced oil recovery,CALCIUM-SULFATE SCALE; IMPROVED OIL-RECOVERY; WETTABILITY ALTERATION; BRINE COMPOSITION; CRUDE-OIL; INJECTION; SEAWATER; CHALK; TEMPERATURE; DISSOLUTION,"Smart water injection is recognized as an effective EOR process to alter the wettability and interfacial tension to obtain higher micro/macro sweep efficiencies. This water contains reactive ions such as Mg2+, Ca2+ and SO42- which can act as potential-determining ions and change the surface charge of calcite rocks. One of the major concerns in the execution of an effective water-flood process, especially in tight carbonate reservoirs, is the chemical incompatibility between the formation brine and the injecting water. In the present study, laboratory fluid compatibility tests were carried out and software simulation was done to investigate the most important challenges of the water-flooding process in one of the West Iranian oil fields with the possibility of developing formation damage. The chemical incompatibility between injected smart water and formation water leads to inorganic scale deposition. For this purpose, sea water as the basis of smart water was prepared to examine the impact of determining ions such as Mg2+, Ca2+ and SO42- and, to examine the effect of the salinity of the injected brine on the total amount of CaSO4 scale precipitation. According to the obtained results, as the concentration of SO42- in the injecting sea water increases from 1/4 to 1 times its concentration in ordinary sea water, the CaSO4 precipitation increases smoothly, and then it is accelerated as the concentration increases beyond that. Therefore, even though the increasing of the sulfate concentration improved the wettability alteration ability of the smart water, calcium sulfate deposition was noticed, resulting in permanent formation damage. The test results also showed that CaSO4 deposition increases as the concentration of Ca2+ in the sea water increases. On the other hand, the presence of Mg(2+ )ion in sea water increases the solubility of CaSO4 and subsequently, lower scale formation was noticed by increasing the concentration of magnesium. This study also showed that there is an optimum salinity in which the minimum amount of mineral scale is deposited, and 5 times dilution of sea water is determined as the optimum salinity. The findings would enable us to optimize the ion contents of smart water for both, better oil sweep efficiency and lower risk of formation damage. In the end, this paper discusses the laboratory fluid compatibility results and scale prediction analysis for different smart water injection utilizations.",27,29,2
Oil Recovery,Interfacial Tension,"Wang, Yanwei; Liu, Huiqing; Wang, Jing; Dong, Xiaohu; Chen, Fangxuan",Formulation development and visualized investigation of temperature-resistant and salt-tolerant surfactant-polymer flooding to enhance oil recovery,Surfactant-polymer flooding; Enhanced oil recovery; Anti-temperature; Salt-tolerance; Visualized experiment; Microscopic mechanisms analysis,INTERFACIAL-TENSION; ZWITTERIONIC SURFACTANT; OPTIMIZATION; PERFORMANCE; SYSTEM,"As a tertiary oil recovery technique with broad application prospects, surfactant-polymer flooding can significantly improve sweep efficiency and enhance oil recovery, while eliminate the negative effects of alkali thoroughly. However, for most oil reservoirs abroad, belonging to marine carbonate reservoirs with high temperature and high salt content, SP flooding is largely limited. In this paper, the surface (interface) chemical properties of different types of surfactants were evaluated to select a mixed surfactant system with better performance and synergistic effect. And experiments on the physicochemical properties evaluation of polymers were performed to select a more suitable polymer. On this basis, the formulation of the surfactant-polymer binary composite system was optimized and the performance was evaluated. A visualized model was adopted to study the process of SP flooding, which vividly reflected the interaction of chemical agents with crude oil and the migration of chemical agents in porous media, as well as macroscopic and microscopic EOR mechanisms of SP Flooding. The results showed that Hexadecyl dimethyl carboxybetaine (C16HSB), heavy alkyl the linear alkylated diphenylmethane sulfonate (C-14-DSDM) and the hydrophobically modified polyacrylamide-based novel functional polymer GT-1 were selected. The optimized formulation of the SP flooding system was selected for 2000 mg/L GT-1 + 3000 mg/L C-14-DSDM + 1000 mg/L C16HSB, which showed higher apparent viscosity and lower interfacial tension (7.2 x 10(-3) mN/m) under the condition of 70 degrees C and 9780.5 mg/L formation water salinity. The system showed a certain resistance to temperature and salt, and stability under the conditions of temperature below 80 degrees C and salinity below 40000 mg/L and an EOR value of 31.2% in the visualized displacement experiment. Surfactants in the SP flooding system can emulsify the residual oil into spherical and flocculent emulsions, which are then stripped, drawn into filaments, and easily motivated. The retention of more polymer molecules in the throat causes the intermolecular association of polymer molecules to form a denser network structure, which plays an important role in increasing flow resistance and changing the direction of liquid flow, and its viscoelasticity contributes to the discharge of residual oil. Under the synergistic effect of surfactants and polymer, hydrodynamic residual oil, membrane residual oil, and residual oil droplets can be mobilized, thus beneficial to enhance oil recovery.",26,29,4
Oil Recovery,Interfacial Tension,"Moradi, Siyamak; Isari, Ali Akbar; Bachari, Zahra; Mahmoodi, Hossien",Combination of a new natural surfactant and smart water injection for enhanced oil recovery in carbonate rock: Synergic impacts of active ions and natural surfactant concentration,Enhanced oil recovery; Tribulus terrestris surfactant; Smart water; Interfacial tension; Wettability alteration; Carbonate rock,LOW-SALINITY BRINE; WETTABILITY ALTERATION; INTERFACIAL-TENSION; NONIONIC SURFACTANT; CRUDE-OIL; SPONTANEOUS IMBIBITION; TRIBULUS-TERRESTRIS; WASTE-WATER; ADSORPTION; CHALK,"By increasing oil demand in carbonate reservoirs, enhanced oil recovery techniques play key role in improving oil production. Surfactant flooding and smart water injection are already well known as effective enhanced oil recovery techniques that increase oil recovery by reduction of oil-water interfacial tension and the alteration of rock wettability. In this work, a new plant-base natural surfactant, named Tribulus Terrestris is introduced and combined with smart water samples (i.e. synthetic seawater with different concentrations of active Ca2+, Mg(2+ )and SO42- ions) to determine their individual and integrated effects on reduction in interfacial tension, wettability alteration and oil recovery in carbonate rock samples. It was observed that increasing concentrations of SO42- up to 2.5 times resulted in maximum wettability restoration among active ions (by changing contact angle from 145.9 degrees to 54.4 degrees). Experimental results also showed that the effect of the concentration of active ions on wettability alteration was more significant compared to their effect on decreasing oil-water interfacial tension. In addition, the Tribulus Terrestris surfactant reduced oil-water interfacial tension considerably (from 45.3 mN/m to 13.5 mN/m at Critical Micelle Concentration of 0.3 wt %); hence, it was used as smart water modifier to integrate effects of wettability alteration (by smart water) and reduction in interfacial tension (by new natural surfactant). Core flooding experiments demonstrated increased oil recovery from 45.2% for distilled water injection up to 64% and 72% for smart water and combined smart water-surfactant respectively.",25,25,0
Oil Recovery,Interfacial Tension,"Divandari, Hassan; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin; Ranjbar, Mohammad",Integrating synthesized citric acid-coated magnetite nanoparticles with magnetic fields for enhanced oil recovery: Experimental study and mechanistic understanding,Enhanced oil recovery; Nanofluid; Citric acid-coated Fe3O4 nanoparticles; Magnetic field; Wettability alteration; IFT; Micromodel,HEAVY OIL; ALPHA-FE2O3 NANOPARTICLES; MAGNETORHEOLOGICAL FLUID; WETTABILITY ALTERATION; SANDSTONE CORES; NANO-PARTICLES; CRUDE-OIL; WATER; WET; NANOFLUID,"Nanofluid injection has emerged as an attractive enhanced oil recovery (EOR) process in the past decade. These fluids improve oil recovery by reducing interfacial tension (IFT), modifying wettability, and reducing mobility ratio. In this communication, magnetite citric acid-coated nanoparticles (NPs) were synthesized by an affordable, facile and one step method and then characterized using Field emission scanning electron microscopy (FESEM), X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR), and Dynamic light scattering (DLS). Afterward, the microscopic and macroscopic efficiencies of oil recovery in heterogeneous and homogeneous 2D micromodels were investigated in the presence of magnetic field. Citric acid-coated magnetite NPs started to respond to the magnetic field around the intensity of 800 Gauss and also showed the maximum ultimate recovery factor at the intensity of 2750 Gauss. In addition, citric acid coated magnetite NPs provided more enhanced oil recovery factor compared to hematite NPs, because of reducing interfacial tension (IFT) between the oil and injection fluid, altering surface wettability from oil-wet to water-wet, promoting the NPs distribution in porous media, and generating column-like structure in the presence of magnetic field. In fact, magnetite NPs act as piston toward the magnetic field by creating a column which sweeps the oil and increases production. Furthermore, citric acid-coated magnetite NPs flooding increased ultimate recovery factor more than polymer and hematite NPs flooding.",24,25,10
Oil Recovery,Interfacial Tension,"Li, Lei; Su, Yuliang; Hao, Yongmao; Zhan, Shiyuan; Lv, Yuting; Zhao, Qingmin; Wang, Haitao",A comparative study of CO2 and N-2 huff-n-puff EOR performance in shale oil production,Gas huff-n-puff; Shale oil; Oil component analysis; Vaporization effect; Injected gas mass,BAKKEN TIGHT OIL; INJECTION PRESSURE; RECOVERY; SIMULATION; RESERVOIRS; STORAGE; MECHANISMS; FIELD,"In this study, Huff-n-Puff (HnP) experiments were conducted to investigate the potential for producing hydrocarbons from the shale core samples using CO2 HnP and N-2 HnP, respectively. The compositions of crude oil, produced oil, and gas in the system were analyzed by Gas Chromatography/Mass Spectrometer (GC/MS). The results showed that at the end of six injection cycles, the cumulative oil recovery factors were 61.49% for CO2 injection and 34.85% for N2 injection. CO2 had better injectivity in the ultra-low permeability shale cores than N-2. The injected gas extracted and vaporized the light hydrocarbon components C3-8 into the gas phase. After six HnP cycles, the recovery factors of C3-4 were 91.6% for CO2 HnP and 75.1% for N-2 HnP. For the other components, the recovery factors were about 60% for CO2 HnP and 30% for N-2 HnP. After that, a core scale model was established to mimic the process of HnP and the mechanisms leading to the different performances of CO2 HnP and N-2 HnP were discussed. Different properties relating to the EOR mechanisms during HnP process were investigated. The results indicated that a significant amount of CO2 could dissolve into the crude oil and deposit as free gas phase existing in the core. During the CO2 HnP process, the oil and gas interfacial tension reduced to zero, and the oil viscosity was reduced by 40%-60%. The gas cap drive, dissolved gas drive, and miscible drive during CO2 HnP are more efficient than that during N-2 HnP. The change of the molecular diffusion rate resulted in an obvious change in oil recovery factor. Although simultaneous CO2 and N-2 is still improving the recovery, pure CO2 shows the best result. This study provides operators with valuable laboratory data about the produced hydrocarbon analysis on CO2 HnP and N-2 HnP in shale oil production and a better understanding of gas HnP mechanisms.",23,25,6
Oil Recovery,Interfacial Tension,"Giraldo, Lady J.; Gallego, Jaime; Villegas, Juan P.; Franco, Camilo A.; Cortes, Farid B.",Enhanced waterflooding with NiO/SiO2 0-D Janus nanoparticles at low concentration,Janus nanoparticles; Nanofluid flooding; Capillary number (N-C); Enhanced oil recovery (EOR),HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SILICA NANOPARTICLES; POROUS-MEDIA; SIO2 NANOPARTICLES; ADSORPTION ENERGY; RECOVERY; WATER; ASPHALTENES; BEHAVIOR,"The nanofluid (nanoparticles dispersed in determined carrier fluid) flooding has been studied for reducing the interfacial tension (IFT), increasing the viscosity of the displacement phase and to alter the rock wettability, which impact the capillary number and hence increase the crude oil recovery. However, this technique requires commonly large concentration of nanoparticles for being efficient in enhanced oil recovery (EOR) processes. Hence, the primary objective of this manuscript is to develop NiO-containing Janus nanoparticles based on zero-dimension (0-D) SiO2 nanoparticles which can be effective at low concentrations. The synthesized nanoparticles were characterized by transmission electron microscopy (TEM), surface area (S-BET), zeta potential, interfacial tension (IFT), rheology, contact angle measurements and coreflooding tests. The results showed a sharply increase of the capillary number (Nc) at a very low concentration of 100 mg/L of Janus nanoparticles, mainly attributed to the decrease in the interfacial tension, which can lead to the increase of the oil recovery. Displacement tests using a SiO2 nanoparticles-based nanofluid at a concentration of 100 mg/L did not show an increase in oil recovery regarding the one obtained in the waterflooding step. Meanwhile, the nanofluid based on NiO/SiO2 Janus nanoparticles at the same concentration of 100 mg/L showed an increase in oil recovery up to 50%.",21,22,6
Oil Recovery,Interfacial Tension,"Purwasena, Isty Adhitya; Astuti, Dea Indriani; Syukron, Muhamad; Amaniyah, Maghfirotul; Sugai, Yuichi",Stability test of biosurfactant produced by Bacillus licheniformis DS1 using experimental design and its application for MEOR,Bacillus licheniformis; Biosurfactant; Lipopeptide; MEOR; Stability,ENHANCED OIL-RECOVERY; PSEUDOMONAS-AERUGINOSA; OPTIMIZATION; SURFACE; LIPOPEPTIDES; WETTABILITY; BACTERIUM; STRAINS; IMPACT,"Microbial enhanced oil recovery (MEOR) is a proven tertiary recovery technique. Biosurfactant is a microbial bioproduct that plays an important role in MEOR applications. This study aimed to test biosurfactant stability using a design experiment based on response surface methodology. First, isolation and screening for potential biosurfactant-producing bacteria from crude oil samples was performed, followed by their characterization. A biosurfactant core flooding experiment was also conducted to examine bacterial activity on MEOR. Thirty-one sequential isolates of bacteria were screened based on qualitative and semi-qualitative parameters. One selected biosurfactant-producing bacterium was identified as Bacillus licheniformis DS1 based on phylogenetic analysis of the 16S rRNA gene. This bacterium had the highest emulsification activity (E-i24 = 65.19%) in light crude oil and could reduce the interfacial tension between oil and water with an effective critical-micelle concentration of 157.5 mg/L. The biosurfactant was observed as a growth-associated metabolite type and the Fourier transform infrared spectrum revealed that the biosurfactant produced belonged to a group of lipopeptides. The biosurfactant has good stability in maintaining emulsification activity at pH 4-10, high temperatures up to 120 degrees C, and with an NaCl concentration up to 10% (w/v). Based on response surface methodology using the Box-Behnken experimental design, the optimum condition for the most stable biosurfactant is pH 12, a 40 degrees C temperature and 10% salinity, with an E-i24 value of 94.28%. Core flooding experiments with biosurfactant resulted in 5.4% additional oil recovery. Therefore, this biosurfactant shows a high potential application for MEOR.",21,21,3
Oil Recovery,Interfacial Tension,"Pillai, Prathibha; Saw, Rohit Kumar; Singh, Ranvijay; Padmanabhan, Eswaran; Mandal, Ajay",Effect of synthesized lysine-grafted silica nanoparticle on surfactant stabilized O/W emulsion stability: Application in enhanced oil recovery,Enhanced oil recovery; LGSs; Jatropha surfactant; Micro-emulsion; IFT; Surface tension,ULTRAFILTRATION MEMBRANES; PHASE-BEHAVIOR; POLYSULFONE; MECHANISM; SALINITY; EOR,"In enhanced oil recovery processes surfactants and nanoparticles are being widely used mainly due to their properties to reduce the interfacial tension between crude oil and aqueous phase. This results in a stable film of emulsion between these two immiscible fluids in case of surfactants and nanoparticles can form a solid layer at the droplet's interface and stand as a resistant stabilizer under harsh reservoir conditions. This research manifests whether the combination of surfactants and Lysine grafted silica nanoparticle (LGS) can provide a more stable emulsion. Oil in water and water in oil emulsions that are stabilized with different surface coating nanoparticles of uniform size have been developed. LGS was synthesized and characterized with FTIR, FESEM, EDX and TGA for proper understanding. Phase behavior study has been done with respect to salinity and synthesized nanoparticle concentration at high temperature. Prepared emulsions were also characterized by IFT, Micro-emulsion images and rheology. Results showed that synthesized surfactant from jatropha oil with a water continuous phase could give a stable emulsion. More emulsion stability was achieved by adding LGS to surfactant synthesized from jatropha oil. Sandpack flooding results were also found to be in line with the results and showed a greater recovery in the presence of LGS with an additional recovery of 24.6% which was much better the surfactant itself. Results showed that lysine grafted silica Nano-particle in combination with surfactant can be a potential candidate for EOR recovery in comparison to conventional flooding applied in the reservoirs.",19,19,3
Oil Recovery,Interfacial Tension,"Riswati, Shabrina S.; Bae, Wisup; Park, Changhyup; Permadi, Asep K.; Efriza, Ivan; Min, Byungun",Experimental analysis to design optimum phase type and salinity gradient of Alkaline Surfactant Polymer flooding at low saline reservoir,Salinity gradient; ASP flooding; Low salinity; Phase behavior; Core flooding,ULTRALOW INTERFACIAL-TENSION; ENHANCED OIL-RECOVERY; SCREENING CRITERIA; 3-PHASE BEHAVIOR; SOLUBILIZATION; FORMULATION; ATTAIN,"This paper presents the experimental analysis to find the optimum alkaline-surfactant-polymer (ASP) formula and the effects of salinity gradient suitable for oil reservoirs with low salinity formation water. It has been challenging to obtain high oil recovery when the reservoir salinity is lower than the injection salinity of ASP formulation. This paper carried out phase behavior tests for 28 experiments with 22 kinds of surfactant and subsequent coreflooding for the optimum formula with pre-designed salinity gradient profiling for pre-flush, ASP slug, and polymer drive. The optimum ASP formula from the phase behavior study, i.e., 0.5 wt% Linear alkyl-benzene sulfonate (LAS), 2 wt% Diethylene glycol butyl ether (DGBE), and 1 wt% Na2CO3, results in the optimum salinity of 2.8 wt% NaCl with 10 cc/cc solubilization ratio, and the middle phase type III microemulsion occurs in the range of 2.5-3.4 wt% NaCl. The oil recovery implementing this formula and negative salinity gradient, i.e. Winsor type II-III-I for coreflooding experiments are about 75.8% which is better than the other salinity gradients such as Winsor type I-II-I and I-III-I Excluding high saline pre-flush, the salinity gradient consisted of Winsor type I-II-I and Winsor type I-III-I are able to recover the desirable amount of oil. The results could be applicable on designing the optimal ASP flooding at low salinity formation considering the formulation of surfactants and co-solvents, and the effects of salinity gradients.",19,19,0
Oil Recovery,Interfacial Tension,"Dahkaee, Kaveh Padasht; Sadeghi, Mohammad Taghi; Fakhroueian, Zahra; Esmaeilzadeh, Pouriya",Effect of NiO/SiO2 nanofluids on the ultra interfacial tension reduction between heavy oil and aqueous solution and their use for wettability alteration of carbonate rocks,NiO/SiO2 nanocomposites; EOR; IFT reduction; Smart surface modification; Wettability alteration; Heavy oil,ZRO2 NANOPARTICLES; SILICA; SURFACTANT; RECOVERY; BEHAVIOR; SIO2; NANOCOMPOSITES; PERFORMANCE; WATER,"One of the important factors in enhanced oil recovery (EOR), which leads to better oil flow in reservoirs and increases the recovery efficiency of the reservoirs, is the reduction of surface tension (S.T) and interfacial tension (IFT). The effect of NiO and SiO2 nanoparticles and their nanocomposites as NiO/SiO2 on the reduction of oil/water interfacial tension was investigated for the heavy oil of Soroush field located in Iran with a density of 0.965 g/cm(3) and viscosity of 1310 cP at 22 degrees C. NiO and SiO2 nanoparticles were produced by sol-gel-hydrothermal process and NiO/SiO2 nanocomposites were synthesized by co-precipitation-hydrothermal method. The interfacial tension of water/Soroush oil was measured to be 29.02 mN/m, as the reference, in the absence of nanoparticles. Water-based nanofluid of 30 wt% NiO/SiO2 and 28 wt% Fe@ NiO/SiO2 nanocomposites that benefits the synergism of the Fe promotor, decreased the IFT to 1.28 mN/m and less than 1 mN/m, respectively. In addition, the key factors such as concentration, aging time and salinity affect were studied in variation of S.T and IFT. It was found that 8 v/v% of the 30 wt% NiO/SiO2 diluted in water had the best efficiency in reducing the S.T and IFT, while preheating time of nanofluids and salinity of water that the nanofluid dissolved in had negligible impacts on surface and interfacial tension. Moreover, as the 30 wt% NiO/SiO2 nanocomposites were essentially hydrophobic, novel hydrophilic and eco-friendly nanocomposites of 30 wt% NiO/SiO2 were also synthesized through smart surface modifications by polyethylene glycol (PEG 6000) and polydimethylsiloxane. It was shown that the surface-modified nanocomposites could reduce the S.T and IFT significantly and alter the wettability of a strong oil-wet carbonate rock to water-wet condition.",18,20,3
Oil Recovery,Interfacial Tension,"Radnia, Hamideh; Nazar, Ali Reza Solaimany; Rashidi, Alimorad",Effect of asphaltene on the emulsions stabilized by graphene oxide: A potential application of graphene oxide in enhanced oil recovery,Asphaltene; Pickering emulsions; Enhanced oil recovery; Experimental design; Graphene oxide; Interfacial tension,CRUDE-OIL; PICKERING EMULSIONS; WATER; BEHAVIOR; DISPERSIONS; SALINITY; FLOOD,"In this research, graphene oxide (GO) is used to prepare stable Pickering emulsions in chemical flooding for enhanced oil recovery (EOR). The effects of GO concentration (0-7 mg/mL), salinity of aqueous phase (0-10 wt %), and asphaltene concentration in organic phase (0-2 wt%) on the stability and morphology of the emulsions are examined. Moreover, the influence of these independent variables on the interfacial tension (IFT) between organic and aqueous phase is assessed through response surface methodology. The results show that the concentrations of GO and asphaltene have the most significant effect on the IFT; indeed, the IFT reduces with increasing both GO and asphaltene concentrations. Defining two quantitative indexes make it possible to compare the efficiency of emulsions formation (ESVI) and the stability of formed emulsions during time (ESTI) against creaming at different conditions. The maximum reported values for the ESTI and ESVI are 100% and 70%, respectively. In all conditions, the type of emulsions is oil-in-water (O/W) which is more suitable in EOR. However, water-in-oil emulsions (W/O) are observed at asphaltene concentrations higher than 1.5 wt%. For dominating this phenomenon, the water/oil ratio should be increased. At the presence of asphaltene and salinities higher than 1 wt%, some water-in-oil-in-water (W/O/W) multiple emulsion droplets are observed. The minimum of the reported average droplet size is 0.69 mu m for GO concentration of 1 mg/mL and asphaltene concentration of 0.05 wt%. These results demonstrate the potential applications of graphene based functional materials for EOR.",17,18,9
Oil Recovery,Interfacial Tension,"Yu, Fuwei; Jiang, Hanqiao; Xu, Fei; Zhen, Fan; Wang, Jitao; Cheng, Baoyang; Su, Hang; Li, Junjian",A multi-scale experimental study of hydrophobically-modified polyacrylamide flood and surfactant-polymer flood on enhanced heavy oil recovery,Heavy oil; Surfactant-polymer flood; Hydrophobically-modified polyacrylamide flood; Multi-scale experiments,IN-WATER EMULSIONS; INTERFACIAL-TENSION; CONFORMANCE CONTROL; POROUS-MEDIA; PORE-SCALE; INJECTION; SALINITY; RESERVOIR; METHODOLOGY; IMBIBITION,"A large amount of residual oil remained in heavy oil reservoirs after water flood due to its viscosity nature. And it has been validated that chemical flood, if applied appropriately, is an efficient and economical EOR method for deeply buried or thin heavy oil reservoirs. A multi-scale experimental evaluation workflow was designed to explore the mechanisms behind the production of residual oil in heavy oil reservoirs by chemical flood. And we conducted three multi-scale experiments to evaluate the performance of hydrophobically-modified polyacrylamide (HMHPAM) flood, surfactant-polymer (SP) flood and their combination. Based on the results of corefloods and medical CT scans, we demonstrated the EOR potential of HMHPAM flood (HPF) synergy with SP flood (SPF). After each coreflood, two samples were drilled from the heterogenous core used in the macro-scale experiment. And the micro-CT scan results of these samples visualized the distribution of oil phase and aqueous phase in each coreflood at the pore scale, and further quantified the decrease of continuous oil clusters caused by the HMHPAM solution and following injected fluids. Besides, we also observed the linear relationship between the volume of each oil cluster against its surface area and the logarithmic relationship between the volume of discontinuous oil cluster and its cumulative contribution to total oil volume. Moreover, a simple method to calculate the oil-water proportion in pores was developed to correlate the relationship between the displacement efficiency of each pore and its pore size. Results showed that the relationship between oil saturation in each pore and its pore size followed the power law correlation. Moreover, the pore-scale analysis also validated that the residual oil in most pores after water flood was effectively mobilized by the synergy of HPF and SPF.",15,18,5
Oil Recovery,Interfacial Tension,"Panahpoori, Donya; Rezvani, Hosein; Parsaei, Rafat; Riazi, Masoud",A pore-scale study on improving CTAB foam stability in heavy crude oil-water system using TiO2 nanoparticles,TiO2 nanoparticle; CTAB foam; Foam stability; EOR; Glass micromodel,IMMISCIBLE FOAM; POROUS-MEDIA; CO2 FOAM; SURFACTANT; ZRO2; DISPLACEMENT; ASPHALTENE; ADSORPTION; RECOVERY; BULK,"The main challenge of foam injection for enhanced oil recovery (EOR) is foam stability at harsh reservoir conditions. With regard to this matter, this research aims to investigate the effect of TiO2 nanoparticles (NPs) in improving the stability of foam bubbles in porous media. The conductivity of hexadecyltrimethylammonium bromide (CTAB) solutions was measured to determine critical micelle concentration (CMC). Thereafter, TiO2 NPs were added into the foam solution and pH, contact angle, and interfacial tension (IFT) in the presence and absence of CTAB were measured. The stability of foam bubbles was evaluated through bulk foam tests and absorbance measurements. Finally, different nanofluids (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.10 wt%), nano-CTAB solutions (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs at the CMC of CTAB) and foams (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs and at the CMC of CTAB) were injected into a heavy oil saturated heterogeneous porous medium. The results of the conductivity measurements showed that the highest adsorption of CTAB molecules onto the NPs surfaces occurs at 0.03 wt% NPs and 0.03 wt% CTAB. The results of micro- and macroscopic images from bulk foam tests revealed improved foam stability for this nano-CTAB foam. Moreover, contact angle and IFT results showed further improvement in interfacial properties for the mixture of NPs and CTAB solutions. Ultimately, in terms of oil recovery, the highest oil recovery factor (54%) was observed upon injection of foam with 0.03 wt% TiO2 NPs and 0.03 wt% CTAB, compared to the 22% recovery factor of DW injection. The visualization experiments showed that 32% enhancement in the recovery factor was mainly due to oil production from dead-end pores. This was because of different functions of NPs including stabilization of foam bubbles, wettability alteration, and improved foam generation mechanisms.",13,13,4
Oil Recovery,Pressure,"You, Qing; Wen, Quanyi; Fang, Jichao; Guo, Min; Zhang, Qingsheng; Dai, Caili",Experimental study on lateral flooding for enhanced oil recovery in bottom-water reservoir with high water cut,Bottom-water reservoir; Lateral flooding; Crosslinked polymer; Enhanced oil recovery; Packer,FOAM; PERFORMANCE; WELLS,"The regular enhanced oil recovery (EOR) methods in bottom-water reservoir aim to increase the vertical sweep efficiency. After multicycle chemical injection, the injected slug cannot effectively control the bottom water coning in the presence of fully developed water channel, decreasing the sweep efficiency and lowering economic efficiency. To improve the development effect of bottom-water reservoir, lateral flooding is proposed as a more cost-effective EOR technique by displacing the oil formation horizontally. In this study, three lateral flooding tests were performed in a three-dimensional physical model based on the geometric similarity criterion. Bottom-water reservoirs were simulated by sandpacking oil and water formations according to the parameters of the target oil reservoir. The bottom-water energy was supplied by an ISCO constant pressure, and the lateral flooding was conducted by an ISCO constant rate pumps. The oil recovery, water cut, pressure drop, and saturation variation maps obtained from these tests were recorded and analyzed. A comparison of these results between different crosslinked polymer slug tests shows that the improved oil recovery by lateral waterflooding can be mainly attributed to a significant increase in horizontal sweep efficiency. After 0.3 PV crosslinked polymer injection, about two-thirds of that was used to shut off the main water channels; the chemical packer, formed by the surplus polymer spreading along the oil/water interface under the drive of lateral injection, can inhibit bottom water from coning into the oil formation and prevent the crossflow. The 0.2, 0.3, and 0.4 PV crosslinked polymer injection can increase oil recovery by as much as 11.35, 36.23, and 39.74% of the original oil-in-place (OOIP), respectively. This confirms that lateral flooding is an efficient EOR method in bottom-water reservoir.",61,60,6
Oil Recovery,Pressure,"Dong, Bingqiang; Meng, Meng; Qiu, Zhengsong; Lu, Zhaohui; Zhang, Ye; Zhong, Hanyi",Formation damage prevention using microemulsion in tight sandstone gas reservoir,Damage mechanism; Water blocking; Sensitivity damages; Protective drilling fluid,STRESS SENSITIVITY; LOW-PERMEABILITY; DRILLING-FLUID; OIL; REMOVAL; MODEL; SAND; FLOW,"Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production.",43,45,1
Oil Recovery,Pressure,"Gao, Hui; Wang, Chen; Cao, Jie; He, Mengqing; Dou, Liangbin",Quantitative study on the stress sensitivity of pores in tight sandstone reservoirs of Ordos basin using NMR technique,Stress sensitivity of pores; NMR; Pore volume; Quantitative evaluation; Tight sandstone,NUCLEAR-MAGNETIC-RESONANCE; RESIDUAL OIL DISTRIBUTION; PERMEABILITY; GAS; POROSITY; SHALE; FLUID; ROCKS,"For tight sandstone reservoirs, the pore structure is sensitive to the stress variations during the production process. The alternation of pore structure influences the petrophysical properties and therefore the dynamic flow of tight sandstone reservoirs. In this research, Nuclear Magnetic Resonance (NMR) technique is employed to quantitatively study the pore volume variation under different confining pressures. Not only during the compression process, this research also investigated the sandstone pore sensitivity to stress during the recovery process of rock samples, which is equally important and happens during the production process when the formation pressure is building up due to the temporary well shut-in or water injection. The core samples selected from Ordos basin are first tested routinely for basic parameters like porosity, permeability and detrital components, and then through both compression and recovery processes where the pressure decreases and increases, respectively. It is found that the core samples with high permeability show stronger stress sensitivity of pores than those with low permeability due to the higher content of large pores. Besides permeability, detrital components and interstitial material can also affect the stress sensitivity of pores. During the recovery process, the low recovery degree of pore volume is related to the recoverable pore size (mainly smaller size pores) and the narrow distribution range of recovered pores. Furthermore, the power function relationship and the exponential relationship are suggested to evaluate the variation of pore volume in compression and recovery process, respectively. The results demonstrated that the compressibility of larger pores is bigger than that of smaller pores. During the compression process, the higher permeability rocks, containing a higher content of larger pores, are easier to be compressed, and has a greater decrease in permeability. Besides, the recoverability of the total pore volume after compression is mainly controlled by smaller pores, which results in the lower recoverability of the total pore volume and the permeability for the higher permeability core samples.",41,42,9
Oil Recovery,Pressure,"Gbadamosi, Afeez O.; Junin, Radzuan; Abdalla, Yassir; Agi, Augustine; Oseh, Jeffrey O.",Experimental investigation of the effects of silica nanoparticle on hole cleaning efficiency of water-based drilling mud,Water-based mud; Drilling fluid; Cuttings transports; Nanotechnology; Cuttings sizes; Nanosilica,ENHANCED OIL-RECOVERY; FILTRATION PROPERTIES; OXIDE NANOPARTICLES; CUTTINGS TRANSPORT; FLUIDS; PERFORMANCE; NANOSILICA; BEADS,"Effective cuttings transports and hole cleaning is crucial for obtaining an efficient drilling operation. Recently, the use of nanotechnology have been exploited to improve rheological and filtration properties of water-based mud. Herein, water-based mud (WBM) was formulated with nanosilica to enhance cuttings and solid particles transports from the wellbore to the surface. Different weight percent concentrations of nanosilica (0.001-1.5 wt %) at three different flow rates in litres/seconds (0.4, 0.6 and 1.0) and cuttings sizes (small, medium and large) were used to investigate the formulated water-based mud lifting capacity of the drilled cuttings. Experimental results show that addition of the nanosilica concentrations to the WBM enhances the viscosity, thereby increasing the muds carrying and circulating capacity. Moreover, nanosilica water-based mud (n-WBM) displays improved mud stability with high propensity to prevent intrusion of formation fluids. The effect of cuttings size on the wellbore cleaning is minimal. The large cuttings size shows a lower degree of cuttings transportation compared with the small and medium cutting size. Accordingly, the small cuttings size has higher cuttings recovery to the surface. Finally, though increase in flow rate leads to more cuttings recovery, there is every tendency that much fluid flow rate will cause an increase in frictional pressure losses and equivalent circulating density, high pump pressure requirement and potential hole erosion.",33,33,1
Oil Recovery,Pressure,"Cheng, Zhilin; Ning, Zhengfu; Ye, Xiongfei; Wang, Qing; Zhang, Wentong",New insights into spontaneous imbibition in tight oil sandstones with NMR,Spontaneous imbibition; Tight oil sandstones; Gravity effect; Anisotropic pore structure; Viscosity effect,PORE STRUCTURE; UNDERSTANDING WETTABILITY; BOUNDARY-CONDITIONS; SHAPE FACTOR; RECOVERY; SHALE; WATER; RESERVOIRS; PRESSURE; FLUID,"Previous research has confirmed that substantial yield has been recovered in the soaking period after hydraulic fracturing. Spontaneous imbibition (SI) is the primary mechanism responsible for the enhanced oil production and has become an effective oil recovery method with regards to unconventional reservoirs. Despite the importance of SI, an in-depth understanding of the features of SI in tight reservoirs is still inadequate. In this article, nuclear magnetic resonance (NMR) T-2 was employed to study the dynamic behavior of imbibition in tight sandstone samples from Yanchang formation, Ordos Basin. Additionally, high-pressure mercury intrusion (HPMI) and the initial T-2 of a core sample were combined to characterize pore structures of tight rocks and oil distributions in various pores at different imbibition stages. Then, the effects of gravity, anisotropic pore structure, and non-wetting phase (NWP) viscosity on imbibition recovery were determined via the variations in T-2 spectra for each sample. The results show that the tight cores feature a multiscale pore structure. Sub-micropores is the dominant type providing the major contribution to oil recovery, while nanopores have largest imbibition efficiency due to the larger capillary force. Gravity of fluids has a non-trivial effect on SI and cannot be neglected in tight samples under two-ends-open (TEO) or one-end-open (OEO) conditions; this seemingly counterintuitive finding is because the capillary force is weakened by the resistance force caused by the intricate flow paths and other possible surface forces at the nanoscale. Imbibition performance in a tight medium is strongly related to its pore structure. The variations in directional permeabilities, relative permeabilities and capillary pressure functions resulting from highly anisotropic samples greatly affect both the ultimate oil recovery and imbibition rate for tight samples under TEO condition, but only impact imbibition rate under allfaces-open (AFO) condition. Furthermore, because tight oil has a narrow range of viscosity, the imbibition behavior in tight samples may not be sensitive to the oil viscosity. It would be hoped that the insights gained from this study can help to improve our understanding of imbibition characteristics in tight reservoirs and develop new scaling models for the predication of oil recovery.",32,34,10
Oil Recovery,Pressure,"Xu, Jianchun; Sun, Baojiang; Chen, Bailian",A hybrid embedded discrete fracture model for simulating tight porous media with complex fracture systems,Numerical simulation; Discrete fracture model; Naturally fractured tight oil reservoir; Transient transfer; Stochastic permeability,SHALE-GAS-RESERVOIRS; SHAPE FACTORS; NUMERICAL-SIMULATION; FLOW; PRESSURE; TRANSPORT; FLUIDS; OIL; FRAMEWORK,"Numerical simulation considering complex fracture networks in tight oil reservoir becomes a hot issue during these years. Recently, embedded discrete fracture model (EDFM) shows great advantages over the DFM approaches in both calculation efficiency and simplicity of simulation workflow. EDFM has been widely used in tight oil/gas natural energy or enhanced oil recovery (EOR) development. If a large number of small-scale natural fractures exist in reservoir, the calculation efficiency of EDFM method may decrease. In this paper, a new hybrid simulation model combining the EDFM and dual porosity (DP) model is proposed. The large-scale fractures are dealt with EDFM method while small scale fractures are dealt with DP model. Considering the low permeability of matrix, transient transfer between matrix and natural fracture is considered. The proposed hybrid model is validated compared with the local grid refinement (LGR) model and EDFM-MINC model, and the difference between transient transfer and pseudo-steady-state transfer effect on production is presented. Finally, two test cases are presented, and the sensitivity of some key parameters are investigated. Result shows that the new simulation model has higher calculation efficiency than LGR and EDFM-MINC models. Meanwhile, it honors a good accuracy. The pseudo-steady-state transfer between matrix and natural fracture leads to big error in tight oil production performance analysis both in single phase and two phases flow. Low matrix permeability and big matrix size increase the production difference between pseudo-steady-state transfer and transient transfer models. The proposed model can simulate reservoirs considering stochastic permeability distribution.",29,30,6
Oil Recovery,Pressure,"Zhong, Xiankang; Lu, Wenjun; Yang, Huaijun; Liu, Min; Zhang, Yang; Liu, Hongwei; Hu, Junying; Zhang, Zhi; Zeng, Dezhi",Oxygen corrosion of N80 steel under laboratory conditions simulating high pressure air injection: Analysis of corrosion products,High pressure air injection; Corrosion products; Oxygen corrosion; Iron oxides,HIGH-TEMPERATURE CORROSION; CARBON-STEEL; CO2 CORROSION; IRON SULFIDE; MILD-STEEL; BEHAVIOR; HEMATITE; TRANSFORMATION; ENVIRONMENT; AKAGANEITE,"High pressure air injection (HPAI) is an effective and economic improved oil recovery process, however, the corrosion of tubing and casing in the injection well is one of the serious safety concerns which have limited its widely application. Until now the structure and composition of corrosion products formed in HPAI condition are still not fully clear because of the difficulty in simulating such a harsh environment in laboratory. In this work, the corrosion rates of N80 steel under laboratory conditions with different oxygen content (21-5% vol%), total pressure (50-20 MPa) and temperature (120-70 degrees C) simulating HPAI in Dagang oil field in China were investigated using weight loss measurement. The corrosion products on N80 steel surface were analyzed using scanning electron microscopy coupled with energy dispersive spectroscopy (SEM + EDS), X-ray diffraction (XRD) and transmission electron microscopy (TEM). The results show that the corrosion rate decreased with the decreasing oxygen partial pressure and temperature. Furthermore, for all the conditions, the corrosion rate was incredibly high in the simulating HPAI environment, consequently, large amount of corrosion products were formed. The corrosion products showed a two-layer structure: outer layer and inner layer. The outer layer was porous, brittle and easily flaked off, while the inner layer was more compact than outer layer. However, both layers could not effectively lower the corrosion rate of N80 steel in HPAI environment. The corrosion products were composed of hematite (alpha-Fe2O3), goethite (alpha-FeOOH), magnetite (Fe3O4) and trace amounts of Ca(OH)(2) and CaO. In addition, the structure and composition of corrosion products did not change with the temperature and oxygen partial pressure in the simulating HPAI conditions.",29,32,5
Oil Recovery,Pressure,"Aldousary, Salem; Kovscek, Anthony R.",The diffusion of water through oil contributes to spontaneous emulsification during low salinity waterflooding,Waterflooding; Microfluidics; Low salinity; Emulsion; Spontaneous,BRINE COMPOSITION; CRUDE-OIL; RECOVERY; MECHANISMS; EOR,"Increases in oil recovery due to Low Salinity Waterfloods (LSW) have been widely investigated. Literature is abundant with studies attempting to pinpoint the relevant mechanisms involved in the LSW process. Recently, there was clear evidence of spontaneous formation of emulsions during LSW under certain conditions. This work examines the diffusion of water through oil as a contributing factor for spontaneous emulsification during LSW. Experimental observations are pore scale using etched-silicon micromodels. Observations are accompanied by pore-scale mass transfer calculations. Spontaneous emulsification is observed as a result of so-called ""low salinity water"" and crude oil phases contacting under non-equilibrium conditions. The experimental observations provide clear evidence that physical contact between oil and low salinity water phases is imperative for emulsification. In addition, it is concluded that a larger salinity gradient results in greater emulsion concentrations. In such cases, the crude oil is preequilibrated through exposure to a formation brine that has substantial salinity and divalent cations. Emulsification results as the oil phase comes into equilibrium with a brine of lower salinity and different composition. A key mechanism is the osmotic pressure imbalance between water and oil phases that drives water into the oil phase by diffusion. Water reaches a supersaturated state and spontaneous nucleation of the water phase results in emulsions, under appropriate conditions. The experimental and numerical modeling schemes presented here demonstrate and quantify time scales of water-in-oil emulsion formation.",25,25,2
Oil Recovery,Pressure,"Cui, Ronghao; Feng, Qihong; Chen, Hongwei; Zhang, Wei; Wang, Sen",Multiscale random pore network modeling of oil-water two-phase slip flow in shale matrix,Pore network model; Shale oil; Two-phase flow; Slip effect; Computational fluid dynamics,FRACTURED HORIZONTAL WELL; FAST MASS-TRANSPORT; POROUS-MEDIA; RELATIVE PERMEABILITY; DYNAMIC PROPERTIES; CO2 SEQUESTRATION; ORGANIC-MATTER; GAS-FLOW; NANOPORES; RESERVOIR,"The large-scale hydraulic fracturing technology is commonly employed to significantly improve oil recovery in shale. An exceptional phenomenon from many field tests is worthy of attention that the majority of fracturing fluid (mainly water) does not return to the surface during hydraulic fracturing, but flows into shale matrix. As a consequence of this phenomenon, oil-water two-phase flow would happen. However, the fluid transportation in nano-pores is different from that of the conventional sandstone reservoirs. To understand oil-water two-phase flow in shale, an integrated pore network model (PNM) framework including network construction and flow simulation is developed. In the network construction, combined with a pore-size distribution (PSD) curve of shale system, a shale multiscale random pore network model is proposed, where organic pores and inorganic pores can be distinguished appropriately. In the flow simulation, considering that the traditional Hagen-Poiseuille equation may not be applicable in shale system, new bulk fluid and corner film flow models with slip length in various geometric pores (circular, square, equilateral triangle) are developed using the computational fluid dynamic (CFD) method. Through the quasi-static simulation technique, we estimate the flow properties in shale including capillary pressure and relative permeability. Simulation results confirm the slip effect would significantly affect oil-water two-phase flow in shale. And then, influences of shale pore structure on two-phase flow are further investigated. Through coupling network construction and two-phase flow simulation, we believe our work could shed light on the further research for multi-phase transportation in shale.",23,24,9
Oil Recovery,Pressure,"Li, Lei; Su, Yuliang; Hao, Yongmao; Zhan, Shiyuan; Lv, Yuting; Zhao, Qingmin; Wang, Haitao",A comparative study of CO2 and N-2 huff-n-puff EOR performance in shale oil production,Gas huff-n-puff; Shale oil; Oil component analysis; Vaporization effect; Injected gas mass,BAKKEN TIGHT OIL; INJECTION PRESSURE; RECOVERY; SIMULATION; RESERVOIRS; STORAGE; MECHANISMS; FIELD,"In this study, Huff-n-Puff (HnP) experiments were conducted to investigate the potential for producing hydrocarbons from the shale core samples using CO2 HnP and N-2 HnP, respectively. The compositions of crude oil, produced oil, and gas in the system were analyzed by Gas Chromatography/Mass Spectrometer (GC/MS). The results showed that at the end of six injection cycles, the cumulative oil recovery factors were 61.49% for CO2 injection and 34.85% for N2 injection. CO2 had better injectivity in the ultra-low permeability shale cores than N-2. The injected gas extracted and vaporized the light hydrocarbon components C3-8 into the gas phase. After six HnP cycles, the recovery factors of C3-4 were 91.6% for CO2 HnP and 75.1% for N-2 HnP. For the other components, the recovery factors were about 60% for CO2 HnP and 30% for N-2 HnP. After that, a core scale model was established to mimic the process of HnP and the mechanisms leading to the different performances of CO2 HnP and N-2 HnP were discussed. Different properties relating to the EOR mechanisms during HnP process were investigated. The results indicated that a significant amount of CO2 could dissolve into the crude oil and deposit as free gas phase existing in the core. During the CO2 HnP process, the oil and gas interfacial tension reduced to zero, and the oil viscosity was reduced by 40%-60%. The gas cap drive, dissolved gas drive, and miscible drive during CO2 HnP are more efficient than that during N-2 HnP. The change of the molecular diffusion rate resulted in an obvious change in oil recovery factor. Although simultaneous CO2 and N-2 is still improving the recovery, pure CO2 shows the best result. This study provides operators with valuable laboratory data about the produced hydrocarbon analysis on CO2 HnP and N-2 HnP in shale oil production and a better understanding of gas HnP mechanisms.",23,25,6
Oil Recovery,Pressure,"Xie, Quan; Liu, Fanghui; Chen, Yongqiang; Yang, Hui; Saeedi, Ali; Hossain, Md Mofazzal",Effect of electrical double layer and ion exchange on low salinity FOR in a pH controlled system,Enhanced oil recovery; Low salinity water flooding; Wettability; Atomic force microscopy; Disjoining pressure; Surface complexation modelling,OIL-RECOVERY; CRUDE-OIL; WATER; WETTABILITY; SANDSTONE; FORCE; ADHESION; EOR; TEMPERATURE; RESERVOIR,"Wettability of an oil/brine/sandstone system is an important petro-physical parameter, governing subsurface multi-phase flow and residual oil saturations. While how edge-charged clays (e.g., kaolinite) contribute to low salinity effect has been extensively investigated, few work have been done on basal-charged clays (e.g., illite, smectite, and chlorite), and few have look beyond the application of the low salinity effect in reservoirs bearing basal-charged clays. We thus integrated atomic force microscopy (AFM) (at a given pH = 7), disjoining pressure calculations, together with surface complexation modelling to understand the importance of basal-charged clays during low salinity water flooding in sandstone reservoirs. We found that low salinity effect can take place without pH increase, confirming that electrical double layer is at least one of the mechanisms to yield low salinity effect, which can be interpreted using disjoining pressure isotherm, whereas ion exchange between oil and basal charged clays leads to an opposite effect at a given pH. However, ion exchange likely favors low salinity effect without controlling pH due to the chemical reaction: > Na + H+ = > H + Na+, which in return decreasing the electrostatic bridges between -NH+/clays, -COOCa+/clays. Knowing the contribution of EDL and ion exchange on oil/brine/basal-charged clays interaction, the potential of low salinity effect in sandstone reservoirs can be quantified.",23,23,3
Oil Recovery,Pressure,"Ma, Quanzheng; Yang, Shenglai; Lv, Daoping; Wang, Mibang; Chen, Jianxun; Kou, Gen; Yang, Long",Experimental investigation on the influence factors and oil production distribution in different pore sizes during CO2 huff-n-puff in an ultra-high-pressure tight oil reservoir,Tight oil reservoir; MMP; CO2 huff-n-puff; Producing gas-oil ratio; NMR,CARBON-DIOXIDE; RECOVERY; PERFORMANCE; SIMULATION; INJECTION,"The Xinjiang tight oil reservoir has a low depletion recovery rate and high remaining oil content. The target reservoir has ultra-low permeability and complex pore structure. Therefore, performing water injection is very difficult, resulting in ineffective waterflooding. In this study, a series of experiments were conducted to study the effects of cycle numbers, production pressure, and permeability in CO2 huff-n-puff. The remaining oil production distribution in different pore sizes was also analyzed by the nuclear magnetic resonance (NMR) technique. The results showed that the cumulative oil recovery logarithmically increases with an increase in number of cycles, whereas, the oil recovery cycle decreases. Low production pressure and high permeability result in a higher oil recovery factor (ORF) of CO2 huff-n-puff. In addition, the optimal production pressure is 22 MPa. After the eighth cycle, the cumulative oil recovery can increase by 16.5%-44.5%, approximately 4.7-7.6 times that of the depletion recovery rate, indicating that CO2 huff-n-puff is a feasible way to enhance the ORF of a tight oil reservoir. HPR Chinaowever, the oil production in the first five cycles accounts for 84%-91.7% of the total enhanced recovery. Therefore, CO2 huff-n-puff operations should not have more than five cycles. NMR T-2 spectrum analysis shows that in the first cycle, the oil in macro and medium pores ( > 50 ms) is produced first, followed by small pores (10-50 ms), accounting for 49.5%-79% and 8%-37% of the total ORF, respectively, whereas, oil from the micropores ( < 10 ms) is rarely produced. However, for the subsequent cycles, the oil production in macro pores and medium pores decreases while that in small pores and micropores increases. Thus, the small pores and micropores become the main oil producing areas.",22,25,1
Oil Recovery,Pressure,"Aghajanzadeh, Mohammad Reza; Ahmadi, Pouyan; Sharifi, Mohammad; Riazi, Masoud",Wettability modification of oil-wet carbonate reservoirs using silica-based nanofluid: An experimental approach,Wettability alteration (WA); Nanoparticles; Spontaneous imbibition; Oil recovery; Carbonate rocks; Relative permeability,RECOVERY; NANOPARTICLES; IMBIBITION; CALCITE,"Wettability is an important factor which controls oil recovery and fluids displacement efficiency in the porous media. Wettability alteration (WA) from strongly oil-wet towards water wet or neutral states is one of the most effective methods of oil recovery increment. Many studies have shown that nanofluid can change the wettability of rock surface towards a desirable state and base on literature structural disjoining pressure is the main mechanism of wettability alteration via nano-treatment. However, there is a lack of information regarding the impact of salinity on nanofluid performance in porous media. Therefore, in this work, the effects of salinity, nanofluid concentration and rock type (i.e. limestone and dolomite surfaces) on wettability alteration of oil wet carbonate substrates under ambient condition were investigated. For this purpose, various static and dynamic experiments including contact angle, imbibition and core flood tests have been performed. The results on contact angle measurements showed that by increasing nanoparticles and electrolyte concentration the wettability alteration from oil wet to water wet was significantly enhanced. Moreover, the wettability alteration of dolomite substrate is much more than that of limestone substrate. In the following, the impact of nanofluid on the spontaneous imbibition for strongly oil-wet carbonate cores was closely examined. Finding results showed an increase as much as 15% of oil recovery for nanofluid imbibition in comparison to that of formation brine. Final evaluation of the nanofluid treatment in terms of its effectiveness was measured by core flood experimental runs. Comparison of relative permeability curves before and after treating have outlined that after the treatment process, the relative permeability curve has shifted to the right and the water relative permeability has reduced from 0.43 mD to 0.23 mD at the residual oil saturation due to wettability alteration of rock surface from strongly oil wet to water wet state.",21,21,6
Oil Recovery,Pressure,"Jia, Bao; Tsau, Jyun-Syung; Barati, Reza",Measurement of CO2 diffusion coefficient in the oil-saturated porous media,Molecular diffusion; CO2; Single-porosity; Grid sensitivity,CARBON-DIOXIDE; GAS INJECTION; RECOVERY; PRESSURE; BITUMEN; STORAGE,"Molecular diffusion is an important EOR mechanism in naturally fractured reservoirs. However, the laboratory-measured diffusion coefficient in the fractured porous media is still limited; and grid sensitivity analysis is missing in the literature when the single-porosity system is applied to history match the pressure decline curve. We aimed to fill the gaps using Radial Constant Volume Diffusion (RCVD) method experimentally to investigate diffusion coefficients at different pressures in hydrocarbon saturated porous media. A special in-house cell is designed to hold the core sample in the center with the annulus around simulating the fracture. The core is initially saturated with oil while the annulus is filled with CO2 at the same pressure. During the measurements, the system pressure declines as gas diffuses into the oil phase until it reaches chemical equilibrium. The pressure decline curve is history matched to determine the diffusion coefficient. The initial pressure is 597 psi, and the diffusion coefficient is determined in numerical models accordingly. Molecular diffusion coefficients are estimated at different experiment periods to reveal the pressure-dependency. A workflow is proposed to obtain effective diffusion coefficients in dual-porosity models that could be extended to multi-component systems. Besides, flow characteristics in the RCVD system are characterized and capillary pressure effect is investigated in this study.",20,20,2
Oil Recovery,Pressure,"Zhao, Jinzhou; Wang, Qiang; Hu, Yongquan; Ren, Lan; Zhao, Chaoneng",Numerical investigation of shut-in time on stress evolution and tight oil production,Energy accumulation; Shut-in; Stress evolution; Optimum shut-in time; Geomechanics/fluid flow,SHALE-GAS-PRODUCTION; RESERVOIR; FLOW; GEOMECHANICS; SIMULATION; PRESSURE; FRACTURE; LEAKOFF; BASIN,"Among investigations on the mechanics of energy accumulation via well shut-in to increase oil production, reservoir imbibition is deemed effective. However, another element, i.e., the coupling effect of fluid flow and geomechanics has always been underrated in production. Hence, this is discussed herein based on seepage mechanics, elastic mechanics, and Biot pore elastic theory. Further, an integral mechanical coupling numerical model is established from staged fracturing on a horizontal well to analyze well shut-in and production, to simulate stress variation during the shut-in period and the impact of shut-in time on oil production. The model considers the coupling effect of oil and water flow, and geomechanics on the stress distribution of reservoir adjacent to hydraulic cracks during fracturing, well shut-in, and production. From the study of reservoir stress and physical parameters in different shut-down times, it is found that reservoir stress and physical parameters demonstrate some regular changes. The pore pressure and saturation demonstrate pressure diffusion and oil phase saturation recovery with increasing well shut-in time. Owing to pressure diffusion, horizontal maximum principal stress, and horizontal minimum principal stress, the shear stress and stress difference demonstrate high complexity. Meanwhile, permeability and porosity exhibit a complex distribution subject to effective stress; the characteristic parameters of reservoir rock based on construction parameters (total injection volume, injection rate, and shut-in time) affect the subsequent production considerably. The correlation curves drawn upon a simulated experiment that reflect the construction parameters against cumulative oil production indicate that cumulative oil production is in direct proportion to shut-in time and in reverse proportion to injection rate. The optimum shut-in time is correlated positively with both the total injection volume and injection rate.",19,19,5
Oil Recovery,Pressure,"Huang, Jingwei; Jin, Tianying; Chai, Zhi; Barrufet, Maria; Killough, John",Compositional simulation of fractured shale reservoir with distribution of nanopores using coupled multi-porosity and EDFM method,Pore size distribution; Multi-porosity coupled EDFM; Fractured shale reservoir; Phase behavior under confinement,CAPILLARY-PRESSURE; PHASE-BEHAVIOR; TIGHT-OIL; GAS; MODEL,"Shale reservoir contains highly heterogenous pore systems due to the wide-range distributions of nanopores in shale matrix and hydraulic/natural fractures. To explicitly include pore size distribution in simulation of shale reservoir, a multi-porosity model is applied to subdivide the matrix into multiple continua based on experimental pore size data. Each continuum has its own pore size, porosity and permeability, as well as other petrophysical properties. Besides, the embedded discrete fracture model (EDFM) is coupled with multi-porosity model to describe the complex fractures networks with any angles and intersections. To evaluate effects of pore size distribution on production, compositional simulation is conducted in a fractured shale reservoir using different number of continua in shale matrix. Simulation results show that the use of multiple continua results in lower oil and gas production. Different pressures, oil and gas saturations and compositions are observed in different continua. To further investigate the effects of distribution of nanopores, oil-gas capillary pressure is rigorously calculated in every continuum. The existence of large capillary pressure leads to different fluid properties in different size of nanopores. Moreover, capillary pressure reduces oil and gas recovery and alters compositions of residuals. The effects of capillary pressure are more significant in the low permeable continua due to smaller pore sizes.",19,19,0
Oil Recovery,Pressure,"Khanal, Aadi; Weijermars, Ruud",Pressure depletion and drained rock volume near hydraulically fractured parent and child wells,Depth of investigation; Drained rock volume; Well interference; Eagle ford; Complex analysis methods; Velocity plots,FLOOD DISPLACEMENT FRONTS; EAGLE FORD SHALE; INTERFERENCE; RESERVOIRS; HISTORY; MULTIWELL; TEXAS; OIL,"Field development of unconventional reservoirs tends to downsize well spacing when commercial success of a shale play is proven. The earlier, so-called parent wells are joined by infill wells, commonly called child wells. Tighter well spacing improves the recovery factor but the risk of well interference increases. The flow interference and pressure communication of adjoining wells via the matrix and their hydraulic fractures was investigated using the depth of investigation and associated pressure depletion plots. A sensitivity analysis shows how the depth of investigation in an unconventional reservoir is impacted by matrix permeability, other fluid properties, and time lapse between drilling of parent and child wells. In all cases, the extent of the drained region of a reservoir with hydraulic fractures is controlled by the fluid particle paths guided by the depth of investigation and time-of-flight contours. Time-of-flight contours visualize the reservoir drainage by parent and child wells using complex analysis methods (CAM) in a case study of the Eagle Ford shale. Even after 30 years of production, the actual drained rock volume (DRV) remains small and lags the depth of investigation. A commercial numerical reservoir simulator provides history matched inputs for the CAM tool which then can model the flow near the discrete fractures in the reservoir at high resolution. The developed procedure provides a computationally efficient method to quantify and visualize the DRV for parent and child wells in hydraulically fractured reservoirs. Fluid particle tracking provides a practical method to determine fracture and well-interference in combination with depth of investigation and pressure depletion studies.",18,18,0
Oil Recovery,Pressure,"Huang, Xianfu; Zhao, Ya-Pu; Wang, Xiaohe; Pan, Lisheng",Adsorption-induced pore blocking and its mechanisms in nanoporous shale due to interactions with supercritical CO2,Shale oil and gas; CO2 sequestration; Swelling; Chemical reaction; Nitrogen adsorption isotherm; XPS,GAS-ADSORPTION; STORAGE CAPACITY; MARCELLUS SHALE; SURFACE-AREA; NATURAL-GAS; METHANE; MODEL; TRANSPORT; PRESSURE; RECOVERY,"Supercritical carbon dioxide (sCO(2)) has recently been used to recover hydrocarbons from shale formations due to its advantages in boosting production, saving water, and minimizing environmental impacts. Meanwhile, CO2 is sealed up underground, which would cut down the greenhouse gas emissions and reduce global warming. However, current knowledge regarding how sCO(2) interacts with shale, especially its nanopores which are responsible for adsorption, migration and storage of oil and gas, has been lacking. Here we show that after sCO(2) adsorption, the total pore volume decreases by similar to 20% in nanoporous shale, majorly by up to 60% in the range of 0.85-2.0 nm. We analyze the morphology and composition changes in shale, and show that the nanopore is either closed up or newly opened, with more closed pores than new ones. We for the first time propose that this adsorption-induced pore blocking phenomenon is jointly voluminal and geochemical resulted from physisorpfion, associative chemisorption and dissociative chemisorption of sCO(2) in shale. Our results help to effectively assess the hydrocarbon production capacity in shale gas reservoirs using CO2-fracking technique, and the CO2 storage potential in shale formations.",17,18,5
Oil Recovery,Pressure,"Yang, Jun; Wang, Xiangzeng; Peng, Xiaolong; Du, Zhongwei; Zeng, Fanhua",Experimental studies on CO2 foam performance in the tight cores,Foam; Mobility control; Tight oil; EOR; Resistance factor; Relative mobility,IMPROVED OIL-RECOVERY; SURFACTANTS; INJECTION; RESERVOIR; BEHAVIOR; WELLS,"Enhanced oil recovery for tight reservoirs with extremely low permeability and porosity is becoming the new routine for reservoir engineering research. Foam flooding has already been proven as an effective approach to enhance the oil recovery in conventional reservoirs. However, limited research has been done on the phenomena and mechanism of foam performance in the tight porous media. In this study, a series of core flooding tests are performed to investigate the foam performance in the absence and presence of oil in tight core samples with different permeabilities from 0.1mD to 3.3 mD. The foam resistance factor, mobility reduction factor, and relative mobility of the displacing fluid are investigated by comparing the foam flooding processes with waterflooding and the co-injection processes of brine and gas. The effectiveness of applying foam flooding as a tertiary recovery method in the tight core samples is studied by comparing the production data, pressure drop data, and relative mobility of displacing fluid between foam flooding and waterflooding. Unlike conventional foam injection process, the increase of foam quality will not create more stable foam flow that gives significant higher foam resistance factor and much better mobility control as expected in the tight core samples. Also, the foam resistance factors even decrease with increasing injection rates at such a low permeability. These results suggest the foam with low foam quality and low injection rate may be the answer to tight reservoir EOR application. As for the oil production test, the experimental results support the effectiveness of foam flooding on reducing mobility compared with waterflooding and the co-injection of brine and gas. An additional 15-22% oil recovery factor is achieved by introducing foam flooding after waterflooding has done. Surprisingly, comparing with a long period of waterflooding without any oil production, the additional oil was successfully produced at a much lower pressure drop during the early stage of foam injection. Since extremely high pressure drop may not be a necessary constraint on foam flooding EOR process in tight reservoirs, it suggests the potential solution on questionable injectivity issue during foam flooding in the tight reservoirs by introducing an optimized discontinuous surfactant-alternating-gas gas process. Also, the relative mobility of displacing fluid is lowered by one order of magnitude compared with waterflooding in the presence of oil.",17,17,2
Oil Recovery,Pressure,"Mehana, Mohamed; Abraham, Jocin; Fahes, Mashhad",The impact of asphaltene deposition on fluid flow in sandstone,Asphaltene; Waterflooding; Wettability; Recovery; Relative pereability,PRECIPITATION; SOLUBILITY; RESINS; SIZE,"Asphaltene deposition in oil reservoirs is a contentious issue affecting both well and reservoir productivity. Though the phenomenon has been previously studied in several laboratory experiments, the uniformity aspects of the asphaltene deposit are usually overlooked. We have previously developed an experimental workflow to create a uniform deposit of asphaltene inside the core sample. In this study, the impact of this uniform deposit on fluid flow is quantified through imbibition, corefloods and relative permeability experiments. In addition, the lab results are used in a field scale simulation to investigate the impact of deposition on field performance. The results exhibit a shift in the wettability state where a reduction in both water imbibition rate and capacity are observed after deposition. Besides, up to 25% reduction in absolute permeability is detected. Results of pressure drop experiments across the core conducted on the exposed rocks indicate a change in the wetting characteristics, with the exposed rocks becoming more mixed/intermediate wet and varying with the change in the initial brine saturation in the rock. Subsequently, the relative permeability set is affected where a shift in the oil residual saturation, a downgrade in the oil curve and an upgrade in the water curve are observed. Upscaling this new data to field scale indicated a loss of more than half of the well productivity and an earlier breakthrough if waterflooding is implemented.",17,19,0
Oil Recovery,Pressure,"Weijermars, Ruud; Nandlal, Kiran; Khanal, Aadi; Tugan, Murat Fatih",Comparison of pressure front with tracer front advance and principal flow regimes in hydraulically fractured wells in unconventional reservoirs,Shale reservoirs; Pressure front; Tracer front; Depth of investigation; Drained rock volume; Flow regimes,VERTICAL WELL; INTERFERENCE,"Pressure depletion patterns near hydraulically fractured wells in ultra-low permeability reservoirs occupy a much larger region than outlined by fluid withdrawal contours. When used for reservoirs with moderate or high permeability (say k>1 mD), industry never needed to caution using pressure depletion plots as a proxy for fluid removal or drained rock volume (DRV). For such conventional reservoirs, pressure depletion plots are good proxies for fluid removal or drained rock volume (DRV). The fluid that moves from the margins of a pressure front, indicative of the so-called diffusive depth of investigation (DOI), will reach the well on the time-scale of economic life of the well. However, a whole new way of thinking is required when studying ultra-low permeability shales (nanoDarcy range), where the distinction between pressure depletion zones and the DRV regions (where fluid is recovered from) becomes crucial to understand which factors control the hydrocarbon recovery process. Our detailed analysis compares the diffusive DOI, of the leading edge of the pressure depletion front, and that of the convective DRV given by a tracer front. Results show that the pressure depletion front between the fractures quickly approaches the adjoining fracture pressure, and most of the production originates from the fracture tips after 12 months. The pressure depletion pattern vastly overestimates the DRV, whereas the tracer front shows the actual produced rock volume. A final section evaluates the specific flow regimes that correspond to certain diffusive DOI and convective DRV growth stages in the life of the well. The discussion section explains how production diagnostic plots can be used to identify the moment in the well life when enhanced oil recovery methods should be applied. This study can facilitate a better understanding of the fluid flow in fractured porous media and can be used to optimize fracture and well spacing to maximize the DRV.",16,16,0
Oil Recovery,Pressure,"Chen, Ya-fei; Pu, Wan-fen; Liu, Xue-li; Li, Yi-bo; Varfolomeev, Mikhail A.; Hui, Jian",A preliminary feasibility analysis of in situ combustion in a deep fractured-cave carbonate heavy oil reservoir,In-situ combustion; Heavy oil; Adiabatic oxidation; Deposited coke; Thermal analysis; FTIR,LOW-TEMPERATURE OXIDATION; PRESSURE AIR INJECTION; KINETIC-ANALYSIS; RECOVERY; MODELS; PYROLYSIS; SYSTEM; LIGHT,"As an effective thermal-enhanced oil recovery technique, in-situ combustion (ISC) can achieve large oil displacement efficiency and upgrade the heavy oil technically, but there are still various barriers for ISC application in naturally fractured carbonate heavy reservoirs. In addition, the potential risk of wellbore plugging and formation collapse, caused by the possibility of carbonate rock decomposition at high temperatures, furtherly hinders the application of ISC technique and focuses more attention on feasibility evaluation. Hence, this paper attempted to estimate the preliminary feasible application of ISC in Tahe oilfield, characterized with fractured-cave carbonate heavy reservoir. From macro and micro aspects, results indicated that owing to large microscopic surface area and high oxygen contact ability between the deposited coke and oxygen, the oxidized ultra-heavy oil, under adiabatic condition, in simulative fractured-cave carbonate oil reservoir was successfully ignited and maintained the combustion process with the combustion front temperature. Besides, a large amount of heat generation from the combustion front can activate the ultra-heavy oil with better mobility ability. Additionally, in this process, the decomposition process of Tahe carbonate rock was not triggered ( similar to 631.6 degrees C) where the decomposition risk of running in-situ combustion process in Tahe carbonate reservoir can be neglected. Preliminarily, it implied that ISC is a feasible technique to upgrade the ultra-heavy oil for Tahe oilfield.",15,15,1
Oil Recovery,Pressure,"Aitkulov, Almas; Mohanty, Kishore K.",Investigation of alkaline-surfactant-polymer flooding in a quarter five-spot sandpack for viscous oil recovery,Viscous oil recovery; Chemical flooding; Enhanced oil recovery; Alkaline-surfactant-polymer flooding; Optimum viscosity,,"The alkaline-surfactant-polymer (ASP) flood has been shown in the past to reduce residual oil saturation significantly after waterflood. ASP floods for light oils are designed to be stable where the mobility ratio of the oil bank to the ASP slug is kept close to one. For viscous oils, such stable recovery processes may be unreasonably slow due higher oil viscosity. The goal of this paper is to study unstable ASP flooding (i.e., oil to ASP slug mobility ratio < 1) in secondary and tertiary modes. A viscous oil of viscosity 100 cp was displaced by an ASP slug in a quarter 5-spot sandpack. The ASP formulation was developed by studying the phase behavior of the oil with several alkaline-surfactant formulations. The effectiveness of the ASP formulation was validated in a 1D sandpack by conducing a water flood followed by a stable tertiary ASP flood. A reservoir sand was used to create a sandpack inside a square steel cell similar to a quarter five-spot pattern. Several ASP floods were then conducted in this cell to study both the displacement efficiency and the sweep efficiency of ASP floods. The tertiary ASP flood recovered most of the oil (similar to 98% of OOIP) when the ASP slug viscosity exceeded the oil viscosity, but pressure gradients were high at similar to 1 ft/d injection. When the ASP slug viscosity was lowered to about 1/3 of the oil viscosity, the oil recovery dropped slightly to 90% OOIP, but the pressure gradient decreased significantly. As the extent of waterflood preceding the ASP flood became shorter, the oil was recovered faster for the same pore volumes injected. The ultimate recovery was independent of the extent of waterflood. The laboratory 5-spot floods were modeled by the simulator UTCHEM. The calibrated simulator can be used at the field scale to determine optimum viscosity ratio and ASP flood timing for viscous oil reservoirs.",14,14,2
Oil Recovery,Surfactant,"Saxena, Neha; Kumar, Amit; Mandal, Ajay","Adsorption analysis of natural anionic surfactant for enhanced oil recovery: The role of mineralogy, salinity, alkalinity and nanoparticles",Anionic surfactant; Reservoir rock; Adsorption; Isotherm models; Nanoparticles,WETTABILITY ALTERATION; NONIONIC SURFACTANTS; SILICA NANOPARTICLES; STABILITY; MECHANISM; ROCK; ISOTHERMS; WET; PH,"Anionic surfactants are widely used as an effective chemical for enhanced oil recovery because of their unique characteristics of reducing interfacial tension (IFT) between the trapped crude oil and water, and alteration of wettability of reservoir rock from oil-wet to water-wet. However, the loss of surfactant by adsorption onto the solid rock surface is a major concern that reduces the efficiency of the surfactant flooding process and must be considered while designing the process. Present study highlights the equilibrium adsorption and kinetics of an anionic surfactant synthesized from soap-nut fruit on sandstone, carbonate and bentonite clay as representative of reservoir rocks. The mineralogy and morphology of the rocks were investigated by FE-SEM, XRD and BET surface area analysis. UV-Visible spectroscopy was used to measure the amount of surfactant adsorbed on solid rock/clay surface in batch experiments. The experimental equilibrium adsorption data were analyzed by using Langmuir, Freundlich, Temkin and Redlich-Peterson isotherm models and adsorption parameters were calculated. Adsorption kinetics of the surfactant system were studied and pseudo second order kinetic model was best fitted for the surfactant/rock/clay systems. Presence of salt was found to increase surfactant adsorption on rock/clay marginally. However, presence of alkali and nanoparticles was found to reduce the loss of surfactant by adsorption and shows synergistic effects on IFT reduction, which is beneficial for application of the surfactant in oil recovery. The findings of the study are quite helpful in proper designing of the surfactant flooding for enhanced oil recovery.",75,76,17
Oil Recovery,Surfactant,"Liu, Junrong; Shen, James J.; Wang, Xiukun; Ge, Hongkui; Yao, Erdong",Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants,Shale oil; Spontaneous imbibition; Wettability alteration; Surfactant; IFT,CARBONATE RESERVOIRS; LOW-PERMEABILITY; RECOVERY; WATER; WET,"Wettability alteration exhibits a significant potential to improve the oil recovery of shale reservoirs by means of spontaneous imbibition through shifting the rock wetness from oil-wet to water-wet. The wettability of the oil-wet shale can be modified by adding surfactants in hydraulic fracturing fluids in the field practice. However, the mechanisms of wettability alteration in shale rocks are still unclear and there are reported discrepancies in different types of surfactants solutions. This work attempts to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of the Sichuan Basin in China, and to analyze their effects of wettability alteration and interfacial-tension (IFT) reduction on the spontaneous imbibition process of the oil-wet shale samples. By measuring the contact-angle, zeta-potential, and IFT, the efficiencies of different surfactants in terms of wettability alteration and IFT reduction are evaluated. The contact-angle experiments show that the water contact angle in rock/oil/water systems decreases when we add more surfactants, which indicates the hydrophilicity of shales is increased by surfactants. Specifically, for the anionic surfactant solutions, the contact angle doesn't immediately change, and it decreases with time, which is different from the sudden change of nonionic surfactants. Moreover, for different surfactants, the IFT decreases in a similar trend with the increase of surfactant concentration. Finally, spontaneous imbibition experiments are conducted and the results show that anionic surfactants are more favorable to recover shale oil than the nonionic surfactants. From the results obtained, it can be concluded that the anion surfactants and nonionic surfactant have different mechanisms for wettability alteration on the shale surface; anionic surfactants have better effect on wettability alteration than nonionic surfactants, however, the mechanism of wettability alteration in anionic surfactants have time delay. The wettability alteration dominates the oil recovery in the way of spontaneous imbibition. More water-wetness tends to yield a higher recovery. In addition, for anionic surfactant solutions, the reduction of IFT increases the final oil recovery and leads to a decrease of the imbibition rate. For nonionic surfactant solutions, the reduction of IFT increases both the imbibition rate and the final recovery, but the enhancement is not significant.",52,52,9
Oil Recovery,Surfactant,"Yekeen, Nurudeen; Padmanabhan, Eswaran; Idris, Ahmad Kamal",Synergistic effects of nanoparticles and surfactants on n-decane-water interfacial tension and bulk foam stability at high temperature,Nanoparticles; Surfactants; Interfacial tension; Foam stability; Electrostatic interaction,SODIUM DODECYL-SULFATE; SILICA NANOPARTICLES; AQUEOUS FOAMS; CO2 FOAM; NONIONIC SURFACTANTS; WETTABILITY ALTERATION; OXIDE NANOPARTICLES; OIL; ADSORPTION; STABILIZATION,"The synergistic effects of nanoparticles and surfactants on decane-water interfacial tension, and bulk foam stability at high temperature was investigated in this study. The interfacial properties were determined using a spinning drop interfacial tensiometer while the foam stability was evaluated from the normalized foam height. The extent of interaction between nanoparticles and surfactants was estimated from the hydrodynamic nano-aggregate sizes and zeta potential values. The foam microscopic images and the bubble morphology were examined to elucidate the mechanisms of foam stabilization by nanoparticles. Results clearly showed that nano-particles-Triton X-100 mixed system demonstrated the smallest aggregate sizes in bulk solution and considerable reduction in water/n-decane interfacial tension. Significant reduction in interfacial tension and increased foam stability occurred due to electrostatic interaction between the charged surfaces of the nanoparticles and surfactant head-groups. However, influence of electrostatic attraction was found to be dominant over the influence of electrostatic repulsion in promoting foam stability and reducing interfacial tension. The most stable foam was generated by titanium dioxide (TiO2) nanoparticles and cetyltrimethylammonium, bromide (CTAB), while the least stable foam was generated in presence of multi-walled carbon nanotubes and triton X-100. Possible reasons and mechanisms for these observations were suggested. The destabilizing influence of high temperature on foam stability was significant, however, CTAB-foam stability increased by 160% and 440% in presence of silicon dioxide (SiO2) and TiO(2 )nanoparticles at 80 degrees C. This phenomenon can be attributed to the moderate adsorption and aggregation of surface-active complex at the gas-liquid interface of the foam and Plateau borders.",44,45,9
Oil Recovery,Surfactant,"Yekeen, Nurudeen; Padmanabhan, Eswaran; Idris, Ahmad Kamal; Ibad, Syed Muhammad","Surfactant adsorption behaviors onto shale from Malaysian formations: Influence of silicon dioxide nanoparticles, surfactant type, temperature, salinity and shale lithology",Surfactants; adsorption; nanoparticles; temperature; shale,ENHANCED OIL-RECOVERY; NONIONIC SURFACTANTS; IONIC LIQUIDS; CO2 FOAM; WETTABILITY; MINERALOGY; STABILITY; ADDITIVES; SALT,"The application of surfactants has proven important in the field of hydrocarbon recovery from the conventional and unconventional reservoirs. An experimental investigation of influence of silicon dioxide nanoparticles, temperature, salinity, as well as surfactant type and shale lithology, on the adsorption behaviours of three types of commonly used surfactants onto two types of shale found in specific Malaysian formations was investigated in this study. Shale samples were characterized using electron microscopy and FITR spectroscopy. Critical micelle concentration and zeta potential studies were performed on surfactants. Nanoparticles were analyzed in terms of elemental composition and wettability. A series of adsorption experiments was conducted. The amount of surfactant adsorbed on shale was determined through the batch experiments using UV-Visible spectroscopy. Adsorption isotherms data were analyzed by fitting with Linear, Langmuir, Freundlich and Temkin isotherm models. Surfactant adsorption onto shale increases with increasing salinity and decreases with increasing temperature and presence of nanoparticles in the surfactant solutions. The adsorption behaviours of surfactants and nanoparticles-surfactant mixtures onto shale were suited by different equilibrium adsorption isotherm models depending on the surfactant type, adsorbent lithology, as well as, critical parameters such as salinity and temperature conditions. Presence of clay minerals contributed significantly to the adsorption capacity of shale. There is a threshold surfactant concentration, below which there is almost complete adsorption of surfactant monomers on the adsorbent surfaces. The maximum amount of surfactant adsorbed onto shale rock with 55 wt% quartz content was in the increasing order of CTAB > SDBS > Triton X-100 while it was in the order of CTAB > Triton X-100 > SDBS for shale sample with 74 wt% quartz content. Electrostatic interaction between the charged surfaces of the SiO2 nanoparticles and the surfactant head-groups resulted in almost 50% decrease in amount of surfactant adsorbed onto shale at high salinity (3 wt% NaCl) and by 81% at high temperature (353K) conditions. The findings of the study have wide applications in surfactant flooding designs, surfactant adsorption minimization and optimization in the field.",40,40,5
Oil Recovery,Surfactant,"Saxena, Neha; Goswami, Abhishek; Dhodapkar, P. K.; Nihalani, M. C.; Mandal, Ajay","Bio-based surfactant for enhanced oil recovery: Interfacial properties, emulsification and rock-fluid interactions",Natural surfactant; Interfacial tension; Wettability alteration; Emulsion; Adsorption; Enhanced oil recovery,LIPASE-CATALYZED SYNTHESIS; ACIDIC CRUDE-OIL; WETTABILITY ALTERATION; ANIONIC SURFACTANT; POROUS-MEDIA; ADSORPTION; TENSION; WATER; SULFONATE; BIODEGRADABILITY,"Anionic surfactants are very effective for application in enhanced oil recovery (EOR) in sandstone reservoirs because of their promising surface-active properties. Considering the non-biodegradability of some of the commercial surfactants, the present study deals with an anionic surfactant synthesized from naturally occurring soap-nut oil with excellent interfacial properties for application in EOR. The soap-nut surfactant showed the promising properties of interfacial tension (IFT) reduction, emulsification, rock wettability alteration, which are desirable for its application in EOR. An ultra-low IFT value of 2.123 x 10( -2) mN/m between crude oil and surfactant solution was obtained at critical micelle concentration (CMC), which was further reduced to 2.037 x 10( -3) mN/m at optimum salinity. Phase behaviour studies showed the formation of Winsor III emulsion phase which is beneficial for recovery of the trapped oil from the fine pores of the reservoir by miscibility mechanism. The surfactant exhibited favourable rock-wetting ability from oil-wet rock to water-wet condition. The loss of surfactant by adsorption on the rock surface was studied, and the adsorption data were analysed by Langmuir and Freundlich models. Injection of a small pore volume of surfactant-slug augmented with polymer slug as mobility buffer recovered more than 30% of original oil in place (OOIP) after the conventional water-flooding.",39,39,4
Oil Recovery,Surfactant,"Chen, Gang; Cheng, Chao; Zhang, Jie; Sun, Yan; Hu, Qi; Qu, Chengtun; Dong, Sanbao",Synergistic effect of surfactant and alkali on the treatment of oil sludge,Oily sludge; Surfactant; Alkali; Residual oil rate,RECOVERY; REMEDIATION; SOIL; BIOREMEDIATION; INCINERATION; ULTRASOUND; PYROLYSIS; COMMUNITY; DISPOSAL; WASTE,"The oil sludge is considered as a hazardous waste, the improper disposal or insufficient treatment can pose a major problem to the oil production, transportation and processing processes, and may result in serious environmental concerns and human health risks. In the present study, washing treatment with a cleaning solution containing surfactant and alkali was investigated to remove the residual oil from the oil sludge obtained from Tahe Oilfield. The effects of the dosage of surfactant, cleaning temperature, stirring rate, stirring time and liquid-solid ratio on the performance in residual oil removing were analyzed. Sodium nonylphenol polyoxyethylene ether sulfate (AEOS) and alkali were used as the cleaning agents. The results show that the content of the residual oil in the sludge could be lowered from 14.3 wt% to 0.9 wt% after being washed twice under the optimum operation conditions with a 0.6 wt% AEOS and 3 wt% KOH solution for 30 min at 80 degrees C, a stirring rate of 210 rpm and a liquid-solid ratio of 3:1. Thermogravimetric (TGA) and infrared analyses confirmed that the oil components in the oil sludge can be mostly removed.",37,39,17
Oil Recovery,Surfactant,"Pal, Nilanjan; Kumar, Narendra; Saw, Rohit Kumar; Mandal, Ajay",Gemini surfactant/polymer/silica stabilized oil-in-water nanoemulsions: Design and physicochemical characterization for enhanced oil recovery,Nanoemulsions; Surfactant-polymer-nanoparticle systems; Dynamic light scattering; Viscosity; Wettability alteration; Chemical flooding,SURFACTANT-POLYMER; EMULSIONS; EOR; PERFORMANCE; MICROEMULSIONS; BEHAVIOR,"The present study deals with the synthesis and characterization of oil-in-water nanoemulsion systems for application in enhanced oil recovery (EOR). Nanoemulsions stabilized by N,N'-bis((dimethyltetradecyl)-1,6-hexanediammonium bromide) gemini surfactant (14-6-14 GS), partially hydrolyzed poly-acrylamide (PHPA) polymer and/or silica (SiO2) nanoparticle were synthesized by ultrasonication technique. Nanoparticles strengthen the mechanical barrier (electrostatic repulsion + steric hindrance) at oil-aqueous interfaces, resulting in increased ionic strength and droplet stability. Dynamic light scattering (DLS) results confirmed the formation of nano-sized (< 500 nm) oil droplets within bulk emulsion phase. Kinetic stabilities of nanoemulsions were investigated by zeta potential and phase behavior analyses. Surface tension of surfactant-stabilized nanoemulsions increased with PHPA addition. However, silica particles improved adsorption ability of surfactant-polymer-nanoparticle (SPN) systems, causing decrease in surface tension. Rheological experiments were conducted as screening experiment at different temperatures to identify pseudoplastic character, and flow parameters were fitted using the Power law model. Contact angle studies showed that nanoemulsions alter the wetting characteristics of rock from intermediate-wet to favorable water-wet condition. Core-flooding studies revealed tertiary oil recovery percentage of 26.25% of original oil in place (OOIP) by chemical injections of {14-6-14 GS + PHPA + SiO2} nanoemulsions, after conventional water-flooding.",36,37,8
Oil Recovery,Surfactant,"Druetta, P.; Picchioni, F.",Polymer and nanoparticles flooding as a new method for Enhanced Oil Recovery,EOR; Polymer; Nanotechnology; Reservoir simulation,SILICA NANOPARTICLES; RHEOLOGICAL BEHAVIOR; CONFORMATIONAL PROPERTIES; POLYACRYLAMIDE SOLUTION; 2-PHASE FLOW; AGGREGATION; VISCOSITY; SEDIMENTATION; POLYSTYRENE; SUSPENSIONS,"A new Enhanced Oil Recovery (EOR) method is proposed by combining the effects of a traditional polymer flooding and exploiting the advantages that nanotechnology presents in the oil industry. Thus, a novel technique is introduced and applied to a 2D reservoir model with a two-phase, five-component system (aqueous, oil phases and water, hydrocarbon, polymer, nanoparticles and salt). For the polymer characterization, a novel approach is presented considering the polymer's architecture and its degradation in order to calculate the physical properties, which has never been reported in reservoir simulation. The presence of the nanoparticles affects mainly the rheological behavior and the wett ability of the rock, increasing the oil phase mobility. Moreover, negative effects such as particle aggregation and sedimentation are also modeled using a novel formulation in reservoir simulation. The combined action of polymers and nanoparticles allowed increasing the recovery factors beyond standard EOR processes, and it represents a suitable alternative to replace traditional combined methods, such as Surfactant-Polymer (SP) or Alkaline-Surfactant-Polymer (ASP). This is due to the fact that the nanoparticles act, to a greater or lesser extent, on the wettability, rheological and interfacial properties of fluids and rock formation, which is complemented with the polymer's viscosifying properties. Moreover, economical factors could also render this technique more attractive, since the nanoparticles' associated costs are substantially lower than those from surfactant flooding. This simulation proves the potential of nanotechnology as a mean to boost traditional EOR techniques in order to further increase the operative life of mature oil fields.",30,31,5
Oil Recovery,Surfactant,"Ghasemi, Mehdi; Moslemizadeh, Aghil; Shahbazi, Khalil; Mohammadzadeh, Omid; Zendehboudi, Sohrab; Jafari, Sina",Primary evaluation of a natural surfactant for inhibiting clay swelling,Ginsenosides; Biosurfactant; Clay swelling inhibitor; Wettability; Compatibility,WELLBORE STABILITY; SHALE HYDRATION; REDUCING ADSORPTION; ANIONIC SURFACTANT; MODIFIED BENTONITE; IONIC LIQUID; WATER; GINSENG; COPOLYMER; MONTMORILLONITE,"Water-based drilling muds, a more environment-friendly candidate than oil-based drilling muds, are wildly used for drilling oil and gas wells. When water-based drilling mud is used for drilling formations with shale containing active clay constituents, it is challenging to preserve stability of the borehole due to clay swelling unless proper inhibition mechanisms are foreseen. In the current study, the feasibility of using Korean red Ginseng root extract was assessed as a clay swelling inhibitor. This root extract is rich in non-ionic surfactants such as Ginsenosides Rg3, Rg5, and RK1, and is referred to as ""biosurfactant"" throughout this manuscript. After preparation of mud systems containing problematic clay particles, the clay-swelling inhibition performance of the biosurfactant was systematically investigated through a series of tests, including mud formation, filtration, immersion, sedimentation assisted with optical microscopy, wettability by sessile drop technique, use of thermal gravimetric analysis (TGA), scanning electron microscopy (SEM) and Fourier-transform infrared spectroscopy (FTIR), and shale cuttings recovery. The clay-swelling inhibition performance of the biosurfactant was then compared against two clay swelling inhibitors namely CTAB (Cetrimonium bromide, a known cationic surfactant) and potassium chloride. There are some properties associated with the mud systems prepared with biosurfactant solution which makes this product unique. These properties include: remarkable loading capacity of sodium montmorillonite (Mt) which in turn resulted in low rheological profile, poor fluid loss control, creation of stable Mt pellets, creation of larger size and aggregated Mt particles with less hydrophilicity, creation of fully unstable dispersed Mt particles that resulted in good sedimentation over time, less mass loss, and higher shale cuttings recovery, all compared to the baseline fluid made without the presence of biosurfactant. The results of this study indicate that the biosurfactant provides excellent clay swelling inhibition properties, comparable to known inhibitors. The biosurfactant's compatibility with other drilling mud components was also checked, and it was found that the fluid properties are independent of the biosurfactant. The wettability and FTIR analyses were also performed to investigate the mechanisms involved in clay swelling inhibition of the biosurfactant, which are believed to be as a result of coating the clay active surfaces with a hydrophobic layer, hence repelling the water phase. This hydrophobic layer is probably formed by interactions of the hydrophilic group of the Ginsenosides and the oxygen atoms available on the Mt surfaces, when the hydrophobic tail is oriented toward the aqueous phase.",30,30,0
Oil Recovery,Surfactant,"Wang, Yanwei; Liu, Huiqing; Wang, Jing; Dong, Xiaohu; Chen, Fangxuan",Formulation development and visualized investigation of temperature-resistant and salt-tolerant surfactant-polymer flooding to enhance oil recovery,Surfactant-polymer flooding; Enhanced oil recovery; Anti-temperature; Salt-tolerance; Visualized experiment; Microscopic mechanisms analysis,INTERFACIAL-TENSION; ZWITTERIONIC SURFACTANT; OPTIMIZATION; PERFORMANCE; SYSTEM,"As a tertiary oil recovery technique with broad application prospects, surfactant-polymer flooding can significantly improve sweep efficiency and enhance oil recovery, while eliminate the negative effects of alkali thoroughly. However, for most oil reservoirs abroad, belonging to marine carbonate reservoirs with high temperature and high salt content, SP flooding is largely limited. In this paper, the surface (interface) chemical properties of different types of surfactants were evaluated to select a mixed surfactant system with better performance and synergistic effect. And experiments on the physicochemical properties evaluation of polymers were performed to select a more suitable polymer. On this basis, the formulation of the surfactant-polymer binary composite system was optimized and the performance was evaluated. A visualized model was adopted to study the process of SP flooding, which vividly reflected the interaction of chemical agents with crude oil and the migration of chemical agents in porous media, as well as macroscopic and microscopic EOR mechanisms of SP Flooding. The results showed that Hexadecyl dimethyl carboxybetaine (C16HSB), heavy alkyl the linear alkylated diphenylmethane sulfonate (C-14-DSDM) and the hydrophobically modified polyacrylamide-based novel functional polymer GT-1 were selected. The optimized formulation of the SP flooding system was selected for 2000 mg/L GT-1 + 3000 mg/L C-14-DSDM + 1000 mg/L C16HSB, which showed higher apparent viscosity and lower interfacial tension (7.2 x 10(-3) mN/m) under the condition of 70 degrees C and 9780.5 mg/L formation water salinity. The system showed a certain resistance to temperature and salt, and stability under the conditions of temperature below 80 degrees C and salinity below 40000 mg/L and an EOR value of 31.2% in the visualized displacement experiment. Surfactants in the SP flooding system can emulsify the residual oil into spherical and flocculent emulsions, which are then stripped, drawn into filaments, and easily motivated. The retention of more polymer molecules in the throat causes the intermolecular association of polymer molecules to form a denser network structure, which plays an important role in increasing flow resistance and changing the direction of liquid flow, and its viscoelasticity contributes to the discharge of residual oil. Under the synergistic effect of surfactants and polymer, hydrodynamic residual oil, membrane residual oil, and residual oil droplets can be mobilized, thus beneficial to enhance oil recovery.",26,29,4
Oil Recovery,Surfactant,"Moradi, Siyamak; Isari, Ali Akbar; Bachari, Zahra; Mahmoodi, Hossien",Combination of a new natural surfactant and smart water injection for enhanced oil recovery in carbonate rock: Synergic impacts of active ions and natural surfactant concentration,Enhanced oil recovery; Tribulus terrestris surfactant; Smart water; Interfacial tension; Wettability alteration; Carbonate rock,LOW-SALINITY BRINE; WETTABILITY ALTERATION; INTERFACIAL-TENSION; NONIONIC SURFACTANT; CRUDE-OIL; SPONTANEOUS IMBIBITION; TRIBULUS-TERRESTRIS; WASTE-WATER; ADSORPTION; CHALK,"By increasing oil demand in carbonate reservoirs, enhanced oil recovery techniques play key role in improving oil production. Surfactant flooding and smart water injection are already well known as effective enhanced oil recovery techniques that increase oil recovery by reduction of oil-water interfacial tension and the alteration of rock wettability. In this work, a new plant-base natural surfactant, named Tribulus Terrestris is introduced and combined with smart water samples (i.e. synthetic seawater with different concentrations of active Ca2+, Mg(2+ )and SO42- ions) to determine their individual and integrated effects on reduction in interfacial tension, wettability alteration and oil recovery in carbonate rock samples. It was observed that increasing concentrations of SO42- up to 2.5 times resulted in maximum wettability restoration among active ions (by changing contact angle from 145.9 degrees to 54.4 degrees). Experimental results also showed that the effect of the concentration of active ions on wettability alteration was more significant compared to their effect on decreasing oil-water interfacial tension. In addition, the Tribulus Terrestris surfactant reduced oil-water interfacial tension considerably (from 45.3 mN/m to 13.5 mN/m at Critical Micelle Concentration of 0.3 wt %); hence, it was used as smart water modifier to integrate effects of wettability alteration (by smart water) and reduction in interfacial tension (by new natural surfactant). Core flooding experiments demonstrated increased oil recovery from 45.2% for distilled water injection up to 64% and 72% for smart water and combined smart water-surfactant respectively.",25,25,0
Oil Recovery,Surfactant,"Pillai, Prathibha; Saw, Rohit Kumar; Singh, Ranvijay; Padmanabhan, Eswaran; Mandal, Ajay",Effect of synthesized lysine-grafted silica nanoparticle on surfactant stabilized O/W emulsion stability: Application in enhanced oil recovery,Enhanced oil recovery; LGSs; Jatropha surfactant; Micro-emulsion; IFT; Surface tension,ULTRAFILTRATION MEMBRANES; PHASE-BEHAVIOR; POLYSULFONE; MECHANISM; SALINITY; EOR,"In enhanced oil recovery processes surfactants and nanoparticles are being widely used mainly due to their properties to reduce the interfacial tension between crude oil and aqueous phase. This results in a stable film of emulsion between these two immiscible fluids in case of surfactants and nanoparticles can form a solid layer at the droplet's interface and stand as a resistant stabilizer under harsh reservoir conditions. This research manifests whether the combination of surfactants and Lysine grafted silica nanoparticle (LGS) can provide a more stable emulsion. Oil in water and water in oil emulsions that are stabilized with different surface coating nanoparticles of uniform size have been developed. LGS was synthesized and characterized with FTIR, FESEM, EDX and TGA for proper understanding. Phase behavior study has been done with respect to salinity and synthesized nanoparticle concentration at high temperature. Prepared emulsions were also characterized by IFT, Micro-emulsion images and rheology. Results showed that synthesized surfactant from jatropha oil with a water continuous phase could give a stable emulsion. More emulsion stability was achieved by adding LGS to surfactant synthesized from jatropha oil. Sandpack flooding results were also found to be in line with the results and showed a greater recovery in the presence of LGS with an additional recovery of 24.6% which was much better the surfactant itself. Results showed that lysine grafted silica Nano-particle in combination with surfactant can be a potential candidate for EOR recovery in comparison to conventional flooding applied in the reservoirs.",19,19,3
Oil Recovery,Surfactant,"Riswati, Shabrina S.; Bae, Wisup; Park, Changhyup; Permadi, Asep K.; Efriza, Ivan; Min, Byungun",Experimental analysis to design optimum phase type and salinity gradient of Alkaline Surfactant Polymer flooding at low saline reservoir,Salinity gradient; ASP flooding; Low salinity; Phase behavior; Core flooding,ULTRALOW INTERFACIAL-TENSION; ENHANCED OIL-RECOVERY; SCREENING CRITERIA; 3-PHASE BEHAVIOR; SOLUBILIZATION; FORMULATION; ATTAIN,"This paper presents the experimental analysis to find the optimum alkaline-surfactant-polymer (ASP) formula and the effects of salinity gradient suitable for oil reservoirs with low salinity formation water. It has been challenging to obtain high oil recovery when the reservoir salinity is lower than the injection salinity of ASP formulation. This paper carried out phase behavior tests for 28 experiments with 22 kinds of surfactant and subsequent coreflooding for the optimum formula with pre-designed salinity gradient profiling for pre-flush, ASP slug, and polymer drive. The optimum ASP formula from the phase behavior study, i.e., 0.5 wt% Linear alkyl-benzene sulfonate (LAS), 2 wt% Diethylene glycol butyl ether (DGBE), and 1 wt% Na2CO3, results in the optimum salinity of 2.8 wt% NaCl with 10 cc/cc solubilization ratio, and the middle phase type III microemulsion occurs in the range of 2.5-3.4 wt% NaCl. The oil recovery implementing this formula and negative salinity gradient, i.e. Winsor type II-III-I for coreflooding experiments are about 75.8% which is better than the other salinity gradients such as Winsor type I-II-I and I-III-I Excluding high saline pre-flush, the salinity gradient consisted of Winsor type I-II-I and Winsor type I-III-I are able to recover the desirable amount of oil. The results could be applicable on designing the optimal ASP flooding at low salinity formation considering the formulation of surfactants and co-solvents, and the effects of salinity gradients.",19,19,0
Oil Recovery,Surfactant,"Dahkaee, Kaveh Padasht; Sadeghi, Mohammad Taghi; Fakhroueian, Zahra; Esmaeilzadeh, Pouriya",Effect of NiO/SiO2 nanofluids on the ultra interfacial tension reduction between heavy oil and aqueous solution and their use for wettability alteration of carbonate rocks,NiO/SiO2 nanocomposites; EOR; IFT reduction; Smart surface modification; Wettability alteration; Heavy oil,ZRO2 NANOPARTICLES; SILICA; SURFACTANT; RECOVERY; BEHAVIOR; SIO2; NANOCOMPOSITES; PERFORMANCE; WATER,"One of the important factors in enhanced oil recovery (EOR), which leads to better oil flow in reservoirs and increases the recovery efficiency of the reservoirs, is the reduction of surface tension (S.T) and interfacial tension (IFT). The effect of NiO and SiO2 nanoparticles and their nanocomposites as NiO/SiO2 on the reduction of oil/water interfacial tension was investigated for the heavy oil of Soroush field located in Iran with a density of 0.965 g/cm(3) and viscosity of 1310 cP at 22 degrees C. NiO and SiO2 nanoparticles were produced by sol-gel-hydrothermal process and NiO/SiO2 nanocomposites were synthesized by co-precipitation-hydrothermal method. The interfacial tension of water/Soroush oil was measured to be 29.02 mN/m, as the reference, in the absence of nanoparticles. Water-based nanofluid of 30 wt% NiO/SiO2 and 28 wt% Fe@ NiO/SiO2 nanocomposites that benefits the synergism of the Fe promotor, decreased the IFT to 1.28 mN/m and less than 1 mN/m, respectively. In addition, the key factors such as concentration, aging time and salinity affect were studied in variation of S.T and IFT. It was found that 8 v/v% of the 30 wt% NiO/SiO2 diluted in water had the best efficiency in reducing the S.T and IFT, while preheating time of nanofluids and salinity of water that the nanofluid dissolved in had negligible impacts on surface and interfacial tension. Moreover, as the 30 wt% NiO/SiO2 nanocomposites were essentially hydrophobic, novel hydrophilic and eco-friendly nanocomposites of 30 wt% NiO/SiO2 were also synthesized through smart surface modifications by polyethylene glycol (PEG 6000) and polydimethylsiloxane. It was shown that the surface-modified nanocomposites could reduce the S.T and IFT significantly and alter the wettability of a strong oil-wet carbonate rock to water-wet condition.",18,20,3
Oil Recovery,Surfactant,"Yang, Jun; Wang, Xiangzeng; Peng, Xiaolong; Du, Zhongwei; Zeng, Fanhua",Experimental studies on CO2 foam performance in the tight cores,Foam; Mobility control; Tight oil; EOR; Resistance factor; Relative mobility,IMPROVED OIL-RECOVERY; SURFACTANTS; INJECTION; RESERVOIR; BEHAVIOR; WELLS,"Enhanced oil recovery for tight reservoirs with extremely low permeability and porosity is becoming the new routine for reservoir engineering research. Foam flooding has already been proven as an effective approach to enhance the oil recovery in conventional reservoirs. However, limited research has been done on the phenomena and mechanism of foam performance in the tight porous media. In this study, a series of core flooding tests are performed to investigate the foam performance in the absence and presence of oil in tight core samples with different permeabilities from 0.1mD to 3.3 mD. The foam resistance factor, mobility reduction factor, and relative mobility of the displacing fluid are investigated by comparing the foam flooding processes with waterflooding and the co-injection processes of brine and gas. The effectiveness of applying foam flooding as a tertiary recovery method in the tight core samples is studied by comparing the production data, pressure drop data, and relative mobility of displacing fluid between foam flooding and waterflooding. Unlike conventional foam injection process, the increase of foam quality will not create more stable foam flow that gives significant higher foam resistance factor and much better mobility control as expected in the tight core samples. Also, the foam resistance factors even decrease with increasing injection rates at such a low permeability. These results suggest the foam with low foam quality and low injection rate may be the answer to tight reservoir EOR application. As for the oil production test, the experimental results support the effectiveness of foam flooding on reducing mobility compared with waterflooding and the co-injection of brine and gas. An additional 15-22% oil recovery factor is achieved by introducing foam flooding after waterflooding has done. Surprisingly, comparing with a long period of waterflooding without any oil production, the additional oil was successfully produced at a much lower pressure drop during the early stage of foam injection. Since extremely high pressure drop may not be a necessary constraint on foam flooding EOR process in tight reservoirs, it suggests the potential solution on questionable injectivity issue during foam flooding in the tight reservoirs by introducing an optimized discontinuous surfactant-alternating-gas gas process. Also, the relative mobility of displacing fluid is lowered by one order of magnitude compared with waterflooding in the presence of oil.",17,17,2
Oil Recovery,Surfactant,"Zhang, Chengli; Wang, Peng; Song, Guoliang",Study on enhanced oil recovery by multi-component foam flooding,New type of multi-component foam flooding system; Sulfonated fluorinated betaine (SFN); Foam ability; Oil displacement effect; EOR,SURFACTANT; BULK,"To obtain a foam system with better stability and oil resistance, this paper starts with the mechanism of enhanced oil recovery by foam flooding and makes use of a combination of surfactants to make foam more stable. A foam system with strong stability can be obtained by combining anionic surfactants with nonionic surfactants. Based on this idea, a new type of multi-component foam flooding system (system 1) is developed. The main molecule is zwitterionic surfactant with a concentration of 0.7% fourteen alkyl sulfonated fluorobetaine (SFN). The auxiliary surfactants are present at a concentration of 0.3% of Sodium Dodecyl Sulfate (SDS), a concentration of 1.8% of potassium chloride (KCL) and a concentration of 3.0% of anhydrous ethanol (C2H6O). In addition, adding a 1000 mg/L solution of partially hydrolyzed polyacrylamide (HPAM) into the system can enhance the strength of the interfacial film, increase the surface dilatation modulus and extend the equilibration time, thereby enhancing the stability of the foam. The comparative evaluation experiment results show that the foaming capacity, foam stability and comprehensive performance of system 1 are better than those of other common foam systems under the condition of 30% S-or and a 1:1 ratio of gas to liquid. For system 1, the number of bubble films L (lamella number) is less than 7, the boundary between the foam and crude oil is clear, and the interaction is small. The foam of system 1 has good oil resistance. The results of oil displacement show that the oil recovery using system 1 increases by 16.8 percentage points after polymer flooding, which is 4-6 percentage points higher than that of an ordinary foam system. The results of the oilfield test show that the development effect of polymer flooding in the B block is poor. In January 2017, system 1 was injected into the reservoir. The 23 wells in the B block responded well, and the effective ratio reached 92%. Compared with the previous stage, the daily fluid production increased by 215 m(3), the daily oil production increased by 141.0 t, the water cut decreased by 9.2 percentage points, and the reservoir effect was obvious. This result provides a new idea for the later development of high water cut reservoirs.",16,17,3
Oil Recovery,Surfactant,"Shi, Lanxiang; Ma, Desheng; Liu, Pengcheng; Li, Xiuluan; Xi, Changfeng; Wang, Chao",Experimental and numerical simulation studies on effects of viscosity reducers for steam assisted gravity drainage performances in extra-heavy oil reservoirs,Steam-assisted gravity drainage(SAGD); Viscosity reducer; Extra-heavy oil reservoirs; Steam-to-oil-ratio (SOR),INJECTION PROCESS; PHASE-BEHAVIOR; SAGD PROCESS; SOLVENT; SURFACTANTS; BITUMEN; WELLS,"Steam-Assisted Gravity Drainage (SAGD) has been demonstrated as an effective process for recovering extra - heavy oil. However, large volumes of steam are required to heat the viscous oil, resulting in high consumption of natural gas and water, which affects its economic benefit Therefore, research has long focused on improving the SAGD performance. In this study, a viscosity reducer (VR) assisted SAGD (VR-SAGD) process is systematically examined by experiment and numerical simulations based on an extra-heavy oil sample from a commercial SAGD block in Xinjiang oil fields, China. A scaled two-dimensional (2D) VR-SAGD experiment is carried out using a scale model to study the mechanisms of production dynamics and to observe the steam chamber development phases of the VR-SAGD process. A history match is conducted based on the 2D experimental data, and the recovery mechanisms of VR-SAGD are discussed. Heterogeneity in terms of barriers sandwiched in the pay zone is studied, and operational parameters are optimized based on the history match results. The 2D physical simulation results show that VR-SAGD accelerates the oil rate by a factor of 1.74 and reduces the instantaneous steam-to-oil-ratio by 49.7%. The VR co-injected with steam propagates in advance and accumulates at the front of the steam chamber and around the barriers to accelerate the effect of viscosity-reduction and reduce the heat loss to the overburden. Numerical simulation results indicate that the optimum time for VR injection is during and after the phase when the steam chamber expands sideways. The optimized VR/steam volume ratio and production/injection volume ratio are 1:9 and 1.2:1, respectively. The VR-SAGD process shows good potential to improve post-SAGD performance and reduces steam consumption in extra-heavy oil reservoirs.",16,16,1
Oil Recovery,Surfactant,"Duan, Ming; Li, Chengcheng; Wang, Xiaodong; Fang, Shenwen; Xiong, Yan; Shi, Peng",Solid separation from the heavy oil sludge produced from Liaohe Oilfield,Heavy oil sludge; Solid separation; Demulsification,PETROLEUM SLUDGE; STABILIZED EMULSIONS; TANK BOTTOM; CRUDE-OIL; CENTRIFUGATION; EXTRACTION,"Heavy oil sludge usually exists in the form of stable W/O emulsion, in which the water droplets were stabilized by natural surfactants and small solid particles. The oil recovery from the oil sludge is valuable, but the demulsification by using regular demulsifiers could be hindered by the solids. Therefore, the solid separation is important for oil recovery. In this paper, firstly, properties of heavy oil sludge produced from the Liaohe Oilfield were analyzed. Then, a multistage chemical treatment was proposed and chemicals were screened for solid separation. Limonene, sodium sulphate solution, (dioctadecyl dimethyl ammonium bromide + citric acid) were chosen for different purposes at different stages, respectively. At last, the rational separation conditions were investigated. After the treatment, the solid content in oil decreased from 18.57% to be 0.9% by mass. In addition, the mixture of recovered oil and fresh crude oil can be dehydrated easily by using regular demulsifiers.",14,15,4
Oil Recovery,Surfactant,"Panahpoori, Donya; Rezvani, Hosein; Parsaei, Rafat; Riazi, Masoud",A pore-scale study on improving CTAB foam stability in heavy crude oil-water system using TiO2 nanoparticles,TiO2 nanoparticle; CTAB foam; Foam stability; EOR; Glass micromodel,IMMISCIBLE FOAM; POROUS-MEDIA; CO2 FOAM; SURFACTANT; ZRO2; DISPLACEMENT; ASPHALTENE; ADSORPTION; RECOVERY; BULK,"The main challenge of foam injection for enhanced oil recovery (EOR) is foam stability at harsh reservoir conditions. With regard to this matter, this research aims to investigate the effect of TiO2 nanoparticles (NPs) in improving the stability of foam bubbles in porous media. The conductivity of hexadecyltrimethylammonium bromide (CTAB) solutions was measured to determine critical micelle concentration (CMC). Thereafter, TiO2 NPs were added into the foam solution and pH, contact angle, and interfacial tension (IFT) in the presence and absence of CTAB were measured. The stability of foam bubbles was evaluated through bulk foam tests and absorbance measurements. Finally, different nanofluids (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.10 wt%), nano-CTAB solutions (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs at the CMC of CTAB) and foams (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs and at the CMC of CTAB) were injected into a heavy oil saturated heterogeneous porous medium. The results of the conductivity measurements showed that the highest adsorption of CTAB molecules onto the NPs surfaces occurs at 0.03 wt% NPs and 0.03 wt% CTAB. The results of micro- and macroscopic images from bulk foam tests revealed improved foam stability for this nano-CTAB foam. Moreover, contact angle and IFT results showed further improvement in interfacial properties for the mixture of NPs and CTAB solutions. Ultimately, in terms of oil recovery, the highest oil recovery factor (54%) was observed upon injection of foam with 0.03 wt% TiO2 NPs and 0.03 wt% CTAB, compared to the 22% recovery factor of DW injection. The visualization experiments showed that 32% enhancement in the recovery factor was mainly due to oil production from dead-end pores. This was because of different functions of NPs including stabilization of foam bubbles, wettability alteration, and improved foam generation mechanisms.",13,13,4
Oil Recovery,Shale,"Liu, Junrong; Shen, James J.; Wang, Xiukun; Ge, Hongkui; Yao, Erdong",Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants,Shale oil; Spontaneous imbibition; Wettability alteration; Surfactant; IFT,CARBONATE RESERVOIRS; LOW-PERMEABILITY; RECOVERY; WATER; WET,"Wettability alteration exhibits a significant potential to improve the oil recovery of shale reservoirs by means of spontaneous imbibition through shifting the rock wetness from oil-wet to water-wet. The wettability of the oil-wet shale can be modified by adding surfactants in hydraulic fracturing fluids in the field practice. However, the mechanisms of wettability alteration in shale rocks are still unclear and there are reported discrepancies in different types of surfactants solutions. This work attempts to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of the Sichuan Basin in China, and to analyze their effects of wettability alteration and interfacial-tension (IFT) reduction on the spontaneous imbibition process of the oil-wet shale samples. By measuring the contact-angle, zeta-potential, and IFT, the efficiencies of different surfactants in terms of wettability alteration and IFT reduction are evaluated. The contact-angle experiments show that the water contact angle in rock/oil/water systems decreases when we add more surfactants, which indicates the hydrophilicity of shales is increased by surfactants. Specifically, for the anionic surfactant solutions, the contact angle doesn't immediately change, and it decreases with time, which is different from the sudden change of nonionic surfactants. Moreover, for different surfactants, the IFT decreases in a similar trend with the increase of surfactant concentration. Finally, spontaneous imbibition experiments are conducted and the results show that anionic surfactants are more favorable to recover shale oil than the nonionic surfactants. From the results obtained, it can be concluded that the anion surfactants and nonionic surfactant have different mechanisms for wettability alteration on the shale surface; anionic surfactants have better effect on wettability alteration than nonionic surfactants, however, the mechanism of wettability alteration in anionic surfactants have time delay. The wettability alteration dominates the oil recovery in the way of spontaneous imbibition. More water-wetness tends to yield a higher recovery. In addition, for anionic surfactant solutions, the reduction of IFT increases the final oil recovery and leads to a decrease of the imbibition rate. For nonionic surfactant solutions, the reduction of IFT increases both the imbibition rate and the final recovery, but the enhancement is not significant.",52,52,9
Oil Recovery,Shale,"Gao, Hui; Wang, Chen; Cao, Jie; He, Mengqing; Dou, Liangbin",Quantitative study on the stress sensitivity of pores in tight sandstone reservoirs of Ordos basin using NMR technique,Stress sensitivity of pores; NMR; Pore volume; Quantitative evaluation; Tight sandstone,NUCLEAR-MAGNETIC-RESONANCE; RESIDUAL OIL DISTRIBUTION; PERMEABILITY; GAS; POROSITY; SHALE; FLUID; ROCKS,"For tight sandstone reservoirs, the pore structure is sensitive to the stress variations during the production process. The alternation of pore structure influences the petrophysical properties and therefore the dynamic flow of tight sandstone reservoirs. In this research, Nuclear Magnetic Resonance (NMR) technique is employed to quantitatively study the pore volume variation under different confining pressures. Not only during the compression process, this research also investigated the sandstone pore sensitivity to stress during the recovery process of rock samples, which is equally important and happens during the production process when the formation pressure is building up due to the temporary well shut-in or water injection. The core samples selected from Ordos basin are first tested routinely for basic parameters like porosity, permeability and detrital components, and then through both compression and recovery processes where the pressure decreases and increases, respectively. It is found that the core samples with high permeability show stronger stress sensitivity of pores than those with low permeability due to the higher content of large pores. Besides permeability, detrital components and interstitial material can also affect the stress sensitivity of pores. During the recovery process, the low recovery degree of pore volume is related to the recoverable pore size (mainly smaller size pores) and the narrow distribution range of recovered pores. Furthermore, the power function relationship and the exponential relationship are suggested to evaluate the variation of pore volume in compression and recovery process, respectively. The results demonstrated that the compressibility of larger pores is bigger than that of smaller pores. During the compression process, the higher permeability rocks, containing a higher content of larger pores, are easier to be compressed, and has a greater decrease in permeability. Besides, the recoverability of the total pore volume after compression is mainly controlled by smaller pores, which results in the lower recoverability of the total pore volume and the permeability for the higher permeability core samples.",41,42,9
Oil Recovery,Shale,"Yekeen, Nurudeen; Padmanabhan, Eswaran; Idris, Ahmad Kamal; Ibad, Syed Muhammad","Surfactant adsorption behaviors onto shale from Malaysian formations: Influence of silicon dioxide nanoparticles, surfactant type, temperature, salinity and shale lithology",Surfactants; adsorption; nanoparticles; temperature; shale,ENHANCED OIL-RECOVERY; NONIONIC SURFACTANTS; IONIC LIQUIDS; CO2 FOAM; WETTABILITY; MINERALOGY; STABILITY; ADDITIVES; SALT,"The application of surfactants has proven important in the field of hydrocarbon recovery from the conventional and unconventional reservoirs. An experimental investigation of influence of silicon dioxide nanoparticles, temperature, salinity, as well as surfactant type and shale lithology, on the adsorption behaviours of three types of commonly used surfactants onto two types of shale found in specific Malaysian formations was investigated in this study. Shale samples were characterized using electron microscopy and FITR spectroscopy. Critical micelle concentration and zeta potential studies were performed on surfactants. Nanoparticles were analyzed in terms of elemental composition and wettability. A series of adsorption experiments was conducted. The amount of surfactant adsorbed on shale was determined through the batch experiments using UV-Visible spectroscopy. Adsorption isotherms data were analyzed by fitting with Linear, Langmuir, Freundlich and Temkin isotherm models. Surfactant adsorption onto shale increases with increasing salinity and decreases with increasing temperature and presence of nanoparticles in the surfactant solutions. The adsorption behaviours of surfactants and nanoparticles-surfactant mixtures onto shale were suited by different equilibrium adsorption isotherm models depending on the surfactant type, adsorbent lithology, as well as, critical parameters such as salinity and temperature conditions. Presence of clay minerals contributed significantly to the adsorption capacity of shale. There is a threshold surfactant concentration, below which there is almost complete adsorption of surfactant monomers on the adsorbent surfaces. The maximum amount of surfactant adsorbed onto shale rock with 55 wt% quartz content was in the increasing order of CTAB > SDBS > Triton X-100 while it was in the order of CTAB > Triton X-100 > SDBS for shale sample with 74 wt% quartz content. Electrostatic interaction between the charged surfaces of the SiO2 nanoparticles and the surfactant head-groups resulted in almost 50% decrease in amount of surfactant adsorbed onto shale at high salinity (3 wt% NaCl) and by 81% at high temperature (353K) conditions. The findings of the study have wide applications in surfactant flooding designs, surfactant adsorption minimization and optimization in the field.",40,40,5
Oil Recovery,Shale,"Wang, Shuhua; Chen, Zan; Chen, Shengnan",Applicability of deep neural networks on production forecasting in Bakken shale reservoirs,Production forecasting; Bakken formation; Deep neural networks; Hyperparameter optimization; Global sensitivity analysis,NEWTON OPTIMIZATION METHOD; TIGHT-OIL; GAS-PRODUCTION; MODEL; PREDICTION; DESIGN; STEAM,"The unconventional shale and tight formations, such as the Bakken in Williston Basin, are becoming an important hydrocarbon sources since the development of advanced horizontal drilling and multi-stage stimulation techniques. The appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery. Although reservoir simulations are commonly used for production analysis, the modeling of hydraulic fractures and intrinsic complexity of shale have restricted an understanding of the fluid flow behavior. Owing to the available of a large amount of data in unconventional tight and shale reservoirs, data-driven approaches, such as deep neural networks (DNNs), provide an alternative approach for production analysis in these formations. In this study, a total of 2919 wells including 2780 multi-stage hydraulic fractured horizontal wells and 139 vertical wells in Bakken Formation were collected and analyzed using a deep learning method and Sobol's global sensitivity analysis. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, and batch normalization were evaluated to develop a reliable deep neural network model. Moreover, k -fold cross validation was used to evaluate the prediction ability and robustness of models. Prior to the performance evaluation of DNN algorithms, an optimum DNN model was achieved by optimizing the dropout layer, activation function, and hyperparameters of DNN models. It is found that the number of hidden layers and neurons in each layer have significant effects on the performance of models. The optimized DNN model has 3 hidden layers and 200 neurons for each layer. The prediction performance of DNN models is acceptable with the low mean squared errors for both 6- and 18-months cumulative oil productions. Furthermore, the importance of each parameter was studied using the Sobol's analysis. Results show that the average proppant placed per stage is the most important parameter, which accounts for more than 35% of variability in both 6- and 18-months cumulative oil productions. These data-driven models can be readily updated when the new well information becomes available. It is worth mentioning that the proposed DNN models can be directly integrated into existing hydraulic fracturing design routines.",35,37,5
Oil Recovery,Shale,"Cheng, Zhilin; Ning, Zhengfu; Ye, Xiongfei; Wang, Qing; Zhang, Wentong",New insights into spontaneous imbibition in tight oil sandstones with NMR,Spontaneous imbibition; Tight oil sandstones; Gravity effect; Anisotropic pore structure; Viscosity effect,PORE STRUCTURE; UNDERSTANDING WETTABILITY; BOUNDARY-CONDITIONS; SHAPE FACTOR; RECOVERY; SHALE; WATER; RESERVOIRS; PRESSURE; FLUID,"Previous research has confirmed that substantial yield has been recovered in the soaking period after hydraulic fracturing. Spontaneous imbibition (SI) is the primary mechanism responsible for the enhanced oil production and has become an effective oil recovery method with regards to unconventional reservoirs. Despite the importance of SI, an in-depth understanding of the features of SI in tight reservoirs is still inadequate. In this article, nuclear magnetic resonance (NMR) T-2 was employed to study the dynamic behavior of imbibition in tight sandstone samples from Yanchang formation, Ordos Basin. Additionally, high-pressure mercury intrusion (HPMI) and the initial T-2 of a core sample were combined to characterize pore structures of tight rocks and oil distributions in various pores at different imbibition stages. Then, the effects of gravity, anisotropic pore structure, and non-wetting phase (NWP) viscosity on imbibition recovery were determined via the variations in T-2 spectra for each sample. The results show that the tight cores feature a multiscale pore structure. Sub-micropores is the dominant type providing the major contribution to oil recovery, while nanopores have largest imbibition efficiency due to the larger capillary force. Gravity of fluids has a non-trivial effect on SI and cannot be neglected in tight samples under two-ends-open (TEO) or one-end-open (OEO) conditions; this seemingly counterintuitive finding is because the capillary force is weakened by the resistance force caused by the intricate flow paths and other possible surface forces at the nanoscale. Imbibition performance in a tight medium is strongly related to its pore structure. The variations in directional permeabilities, relative permeabilities and capillary pressure functions resulting from highly anisotropic samples greatly affect both the ultimate oil recovery and imbibition rate for tight samples under TEO condition, but only impact imbibition rate under allfaces-open (AFO) condition. Furthermore, because tight oil has a narrow range of viscosity, the imbibition behavior in tight samples may not be sensitive to the oil viscosity. It would be hoped that the insights gained from this study can help to improve our understanding of imbibition characteristics in tight reservoirs and develop new scaling models for the predication of oil recovery.",32,34,10
Oil Recovery,Shale,"Ghasemi, Mehdi; Moslemizadeh, Aghil; Shahbazi, Khalil; Mohammadzadeh, Omid; Zendehboudi, Sohrab; Jafari, Sina",Primary evaluation of a natural surfactant for inhibiting clay swelling,Ginsenosides; Biosurfactant; Clay swelling inhibitor; Wettability; Compatibility,WELLBORE STABILITY; SHALE HYDRATION; REDUCING ADSORPTION; ANIONIC SURFACTANT; MODIFIED BENTONITE; IONIC LIQUID; WATER; GINSENG; COPOLYMER; MONTMORILLONITE,"Water-based drilling muds, a more environment-friendly candidate than oil-based drilling muds, are wildly used for drilling oil and gas wells. When water-based drilling mud is used for drilling formations with shale containing active clay constituents, it is challenging to preserve stability of the borehole due to clay swelling unless proper inhibition mechanisms are foreseen. In the current study, the feasibility of using Korean red Ginseng root extract was assessed as a clay swelling inhibitor. This root extract is rich in non-ionic surfactants such as Ginsenosides Rg3, Rg5, and RK1, and is referred to as ""biosurfactant"" throughout this manuscript. After preparation of mud systems containing problematic clay particles, the clay-swelling inhibition performance of the biosurfactant was systematically investigated through a series of tests, including mud formation, filtration, immersion, sedimentation assisted with optical microscopy, wettability by sessile drop technique, use of thermal gravimetric analysis (TGA), scanning electron microscopy (SEM) and Fourier-transform infrared spectroscopy (FTIR), and shale cuttings recovery. The clay-swelling inhibition performance of the biosurfactant was then compared against two clay swelling inhibitors namely CTAB (Cetrimonium bromide, a known cationic surfactant) and potassium chloride. There are some properties associated with the mud systems prepared with biosurfactant solution which makes this product unique. These properties include: remarkable loading capacity of sodium montmorillonite (Mt) which in turn resulted in low rheological profile, poor fluid loss control, creation of stable Mt pellets, creation of larger size and aggregated Mt particles with less hydrophilicity, creation of fully unstable dispersed Mt particles that resulted in good sedimentation over time, less mass loss, and higher shale cuttings recovery, all compared to the baseline fluid made without the presence of biosurfactant. The results of this study indicate that the biosurfactant provides excellent clay swelling inhibition properties, comparable to known inhibitors. The biosurfactant's compatibility with other drilling mud components was also checked, and it was found that the fluid properties are independent of the biosurfactant. The wettability and FTIR analyses were also performed to investigate the mechanisms involved in clay swelling inhibition of the biosurfactant, which are believed to be as a result of coating the clay active surfaces with a hydrophobic layer, hence repelling the water phase. This hydrophobic layer is probably formed by interactions of the hydrophilic group of the Ginsenosides and the oxygen atoms available on the Mt surfaces, when the hydrophobic tail is oriented toward the aqueous phase.",30,30,0
Oil Recovery,Shale,"Cui, Ronghao; Feng, Qihong; Chen, Hongwei; Zhang, Wei; Wang, Sen",Multiscale random pore network modeling of oil-water two-phase slip flow in shale matrix,Pore network model; Shale oil; Two-phase flow; Slip effect; Computational fluid dynamics,FRACTURED HORIZONTAL WELL; FAST MASS-TRANSPORT; POROUS-MEDIA; RELATIVE PERMEABILITY; DYNAMIC PROPERTIES; CO2 SEQUESTRATION; ORGANIC-MATTER; GAS-FLOW; NANOPORES; RESERVOIR,"The large-scale hydraulic fracturing technology is commonly employed to significantly improve oil recovery in shale. An exceptional phenomenon from many field tests is worthy of attention that the majority of fracturing fluid (mainly water) does not return to the surface during hydraulic fracturing, but flows into shale matrix. As a consequence of this phenomenon, oil-water two-phase flow would happen. However, the fluid transportation in nano-pores is different from that of the conventional sandstone reservoirs. To understand oil-water two-phase flow in shale, an integrated pore network model (PNM) framework including network construction and flow simulation is developed. In the network construction, combined with a pore-size distribution (PSD) curve of shale system, a shale multiscale random pore network model is proposed, where organic pores and inorganic pores can be distinguished appropriately. In the flow simulation, considering that the traditional Hagen-Poiseuille equation may not be applicable in shale system, new bulk fluid and corner film flow models with slip length in various geometric pores (circular, square, equilateral triangle) are developed using the computational fluid dynamic (CFD) method. Through the quasi-static simulation technique, we estimate the flow properties in shale including capillary pressure and relative permeability. Simulation results confirm the slip effect would significantly affect oil-water two-phase flow in shale. And then, influences of shale pore structure on two-phase flow are further investigated. Through coupling network construction and two-phase flow simulation, we believe our work could shed light on the further research for multi-phase transportation in shale.",23,24,9
Oil Recovery,Shale,"Li, Lei; Su, Yuliang; Hao, Yongmao; Zhan, Shiyuan; Lv, Yuting; Zhao, Qingmin; Wang, Haitao",A comparative study of CO2 and N-2 huff-n-puff EOR performance in shale oil production,Gas huff-n-puff; Shale oil; Oil component analysis; Vaporization effect; Injected gas mass,BAKKEN TIGHT OIL; INJECTION PRESSURE; RECOVERY; SIMULATION; RESERVOIRS; STORAGE; MECHANISMS; FIELD,"In this study, Huff-n-Puff (HnP) experiments were conducted to investigate the potential for producing hydrocarbons from the shale core samples using CO2 HnP and N-2 HnP, respectively. The compositions of crude oil, produced oil, and gas in the system were analyzed by Gas Chromatography/Mass Spectrometer (GC/MS). The results showed that at the end of six injection cycles, the cumulative oil recovery factors were 61.49% for CO2 injection and 34.85% for N2 injection. CO2 had better injectivity in the ultra-low permeability shale cores than N-2. The injected gas extracted and vaporized the light hydrocarbon components C3-8 into the gas phase. After six HnP cycles, the recovery factors of C3-4 were 91.6% for CO2 HnP and 75.1% for N-2 HnP. For the other components, the recovery factors were about 60% for CO2 HnP and 30% for N-2 HnP. After that, a core scale model was established to mimic the process of HnP and the mechanisms leading to the different performances of CO2 HnP and N-2 HnP were discussed. Different properties relating to the EOR mechanisms during HnP process were investigated. The results indicated that a significant amount of CO2 could dissolve into the crude oil and deposit as free gas phase existing in the core. During the CO2 HnP process, the oil and gas interfacial tension reduced to zero, and the oil viscosity was reduced by 40%-60%. The gas cap drive, dissolved gas drive, and miscible drive during CO2 HnP are more efficient than that during N-2 HnP. The change of the molecular diffusion rate resulted in an obvious change in oil recovery factor. Although simultaneous CO2 and N-2 is still improving the recovery, pure CO2 shows the best result. This study provides operators with valuable laboratory data about the produced hydrocarbon analysis on CO2 HnP and N-2 HnP in shale oil production and a better understanding of gas HnP mechanisms.",23,25,6
Oil Recovery,Shale,"Ado, Muhammad Rabiu; Greaves, Malcolm; Rigby, Sean P.",Numerical simulation of the impact of geological heterogeneity on performance and safety of THAI heavy oil production process,Bitumen; Shale inter-layer; Heterogeneity; Cap-rock; Thief-zone; THAI,ORIENTATION; RECOVERY,"The Toe-to-Heel Air Injection (THAI) in-situ combustion process is an efficient way to extract heavy oil and bitumen. However, such reservoirs are often geologically heterogeneous. This work studied the impact of a range of different geological heterogeneities, often found in bitumen deposits, on the performance and safety of THAI. These heterogeneities included random heterogeneity, layered reservoirs, shaly reservoirs, and semi-permeable cap-rocks. A further aim was to also develop potential remedial measures, such as selective well placement It was found that the degree of symmetry assumed for the reservoir model had a substantial impact on the predicted level of oil production. This is of particular relevance to otherwise apparently symmetrical well placement designs such as staggered line drive. While the presence of impermeable zones resulted in the decrease in the overall oxygen utilisation for shaly reservoirs, compared to simply low permeability reservoirs, there was no evidence of oxygen breakthrough due to preferential channelling into the production well. In layered reservoirs, the development of a rich oil bank during THAI operation depended upon the distribution of permeability around the horizontal producer (HP), and did not occur when there was high permeability just above the HP. It has been shown that the proper representation of the cap-rock in reservoir models for the simulation of THAI is essential in order to accurately mimic the full pattern of heat distribution into the oil zone of the reservoir, and, thence, fuel lay-down. While THAI can operate stably with a permeable cap-rock, vertical permeabilities above similar to 1-3 mD led to significant loss of combustion gases from the reservoir.",20,20,0
Oil Recovery,Shale,"Huang, Jingwei; Jin, Tianying; Chai, Zhi; Barrufet, Maria; Killough, John",Compositional simulation of fractured shale reservoir with distribution of nanopores using coupled multi-porosity and EDFM method,Pore size distribution; Multi-porosity coupled EDFM; Fractured shale reservoir; Phase behavior under confinement,CAPILLARY-PRESSURE; PHASE-BEHAVIOR; TIGHT-OIL; GAS; MODEL,"Shale reservoir contains highly heterogenous pore systems due to the wide-range distributions of nanopores in shale matrix and hydraulic/natural fractures. To explicitly include pore size distribution in simulation of shale reservoir, a multi-porosity model is applied to subdivide the matrix into multiple continua based on experimental pore size data. Each continuum has its own pore size, porosity and permeability, as well as other petrophysical properties. Besides, the embedded discrete fracture model (EDFM) is coupled with multi-porosity model to describe the complex fractures networks with any angles and intersections. To evaluate effects of pore size distribution on production, compositional simulation is conducted in a fractured shale reservoir using different number of continua in shale matrix. Simulation results show that the use of multiple continua results in lower oil and gas production. Different pressures, oil and gas saturations and compositions are observed in different continua. To further investigate the effects of distribution of nanopores, oil-gas capillary pressure is rigorously calculated in every continuum. The existence of large capillary pressure leads to different fluid properties in different size of nanopores. Moreover, capillary pressure reduces oil and gas recovery and alters compositions of residuals. The effects of capillary pressure are more significant in the low permeable continua due to smaller pore sizes.",19,19,0
Oil Recovery,Shale,"Khanal, Aadi; Weijermars, Ruud",Pressure depletion and drained rock volume near hydraulically fractured parent and child wells,Depth of investigation; Drained rock volume; Well interference; Eagle ford; Complex analysis methods; Velocity plots,FLOOD DISPLACEMENT FRONTS; EAGLE FORD SHALE; INTERFERENCE; RESERVOIRS; HISTORY; MULTIWELL; TEXAS; OIL,"Field development of unconventional reservoirs tends to downsize well spacing when commercial success of a shale play is proven. The earlier, so-called parent wells are joined by infill wells, commonly called child wells. Tighter well spacing improves the recovery factor but the risk of well interference increases. The flow interference and pressure communication of adjoining wells via the matrix and their hydraulic fractures was investigated using the depth of investigation and associated pressure depletion plots. A sensitivity analysis shows how the depth of investigation in an unconventional reservoir is impacted by matrix permeability, other fluid properties, and time lapse between drilling of parent and child wells. In all cases, the extent of the drained region of a reservoir with hydraulic fractures is controlled by the fluid particle paths guided by the depth of investigation and time-of-flight contours. Time-of-flight contours visualize the reservoir drainage by parent and child wells using complex analysis methods (CAM) in a case study of the Eagle Ford shale. Even after 30 years of production, the actual drained rock volume (DRV) remains small and lags the depth of investigation. A commercial numerical reservoir simulator provides history matched inputs for the CAM tool which then can model the flow near the discrete fractures in the reservoir at high resolution. The developed procedure provides a computationally efficient method to quantify and visualize the DRV for parent and child wells in hydraulically fractured reservoirs. Fluid particle tracking provides a practical method to determine fracture and well-interference in combination with depth of investigation and pressure depletion studies.",18,18,0
Oil Recovery,Shale,"Li, Wei; Yue, Dali; Wang, Wenfeng; Wang, Wurong; Wu, Shenghe; Li, Jian; Chen, Depo",Fusing multiple frequency-decomposed seismic attributes with machine learning for thickness prediction and sedimentary facies interpretation in fluvial reservoirs,Fluvial reservoirs; Spectral decomposition; Seismic attributes; Machine learning; RGB blending; Sand thickness,MANSURI OIL-FIELD; BOHAI BAY BASIN; PROSPECT IDENTIFICATION; 90-DEGREES-PHASE WAVELETS; SPECTRAL DECOMPOSITION; SEQUENCE STRATIGRAPHY; WELL LOGS; INVERSION; SHALE; CLASSIFICATION,"Defining the boundaries, thicknesses and sedimentary facies of fluvial reservoirs (sand bodies) is critical for predicting hydrocarbon volumes, designing schemes for petroleum exploration and development and improving oil recovery. Most reservoirs contain thick and thin sand bodies at the same intervals, while the amplitude values of seismic data usually highlight sand bodies near the 1/4 wavelength for the tuning phenomena. Hence, the application of spectral decomposition to seismic attributes and the combination of multiple frequency-decomposed (spectral-decomposed) seismic attributes have gained increasing attention for the readjustment of tuning thickness to predict sand bodies of various thicknesses. However, the popular method of red-green-blue blending is a simple linear combination of three frequency-decomposed seismic attributes that qualitatively analyzes the sand thickness without well-log interpretation. This research proposes machine learning fusion as a new nonlinear method for fusing high-, middle-, and low-frequency seismic attributes. This method uses machine learning to link well-log interpretation and multiple-frequency seismic attributes for the quantitative prediction of sand thickness, which is important for development work in a mature field. Test results of the conceptual model and the real case indicate that the predicted sand thickness after fusing multiple frequency-decomposed seismic attributes is approximately in line with the actual thickness (correlations between 80 and 90%). Combined with the coherence attribute and the red-green-blue blending results, the distributions and histories of sedimentary facies are analyzed based on the predicted sand thickness and well data. The results suggest that the proposed method can effectively readjust the tuning thickness and improve the resolution of seismic interpretation. This method is a potentially effective technique to characterize the sand thickness and sedimentary facies in other fields using a similar geological setting and dataset.",17,17,10
Oil Recovery,Shale,"Wang, Deqiang; Cheng, Linsong; Cao, Renyi; Jia, Pin; Fang, Sidong; Rao, Xiang; Wu, Yonghui; Dai, Dan",The effects of the boundary layer and fracture networks on the water huff-n-puff process of tight oil reservoirs,Tight reservoir; Water huff-n-puff; Volume fracture; Boundary layer; Embedded discrete fracture model,PERMEABILITY STRESS SENSITIVITY; HORIZONTAL WELLS; RELATIVE PERMEABILITY; SEMIANALYTICAL MODEL; FLOW BEHAVIOR; SHALE; PERFORMANCE; SIMULATION; SCALE,"Application of multi-fractured horizontal wells has led to significant progress in the development of tight oil reservoirs. However, oil production rapidly decreases and the estimated ultimate recovery is still low when the well is in production and approaching depletion. Water huff-n-puff is regarded as a useful measure to improve oil recovery due to oil-water imbibition and drainage. Additionally, complex fracture networks consisting of natural fractures (NF) and hydraulic fractures can significantly enhance oil recovery in the process of water huff-n-puff after multi-stage hydraulic fracturing. However, there is a non-flowing thin film on the solid-liquid wall surface in the pore-throats of the matrix, and the so-called boundary layer effect (BLE) is quite significant at the nanoscale. This effect reduces the effective flow space and effective permeability of the reservoir, leading to production damage. To date, few numerical simulation studies have considered the impact of the BLE and complex fracture networks in water huff-n-puff process simulation studies. In this study, the process of water huff-n-puff is evaluated considering complex fracture networks and formation damage in a matrix. The embedded discrete fracture model (EDMF), validated by local grid refinement (LGR), is applied to describe the distribution of hydraulic fractures and NF. The well performance considering the BLE is analyzed by a vectorization programming. The results show that the BLE reduces production and accelerates the production decline, so the BLE should be considered in reservoir simulations and productivity evaluations of water huff-n-puff processes. A certain degree of natural fracture development is conducive to improving the sweep efficiency of the water huff-n-puff, which could significantly improve oil recovery compared to depletion. By considering the impact of the BLE in water huff-n-puff simulations in tight oil reservoirs, it is possible to accurately evaluate the well performance and provide a theoretical basis for the optimization of water huff-n-puff.",17,16,5
Oil Recovery,Shale,"Huang, Xianfu; Zhao, Ya-Pu; Wang, Xiaohe; Pan, Lisheng",Adsorption-induced pore blocking and its mechanisms in nanoporous shale due to interactions with supercritical CO2,Shale oil and gas; CO2 sequestration; Swelling; Chemical reaction; Nitrogen adsorption isotherm; XPS,GAS-ADSORPTION; STORAGE CAPACITY; MARCELLUS SHALE; SURFACE-AREA; NATURAL-GAS; METHANE; MODEL; TRANSPORT; PRESSURE; RECOVERY,"Supercritical carbon dioxide (sCO(2)) has recently been used to recover hydrocarbons from shale formations due to its advantages in boosting production, saving water, and minimizing environmental impacts. Meanwhile, CO2 is sealed up underground, which would cut down the greenhouse gas emissions and reduce global warming. However, current knowledge regarding how sCO(2) interacts with shale, especially its nanopores which are responsible for adsorption, migration and storage of oil and gas, has been lacking. Here we show that after sCO(2) adsorption, the total pore volume decreases by similar to 20% in nanoporous shale, majorly by up to 60% in the range of 0.85-2.0 nm. We analyze the morphology and composition changes in shale, and show that the nanopore is either closed up or newly opened, with more closed pores than new ones. We for the first time propose that this adsorption-induced pore blocking phenomenon is jointly voluminal and geochemical resulted from physisorpfion, associative chemisorption and dissociative chemisorption of sCO(2) in shale. Our results help to effectively assess the hydrocarbon production capacity in shale gas reservoirs using CO2-fracking technique, and the CO2 storage potential in shale formations.",17,18,5
Oil Recovery,Shale,"Weijermars, Ruud; Nandlal, Kiran; Khanal, Aadi; Tugan, Murat Fatih",Comparison of pressure front with tracer front advance and principal flow regimes in hydraulically fractured wells in unconventional reservoirs,Shale reservoirs; Pressure front; Tracer front; Depth of investigation; Drained rock volume; Flow regimes,VERTICAL WELL; INTERFERENCE,"Pressure depletion patterns near hydraulically fractured wells in ultra-low permeability reservoirs occupy a much larger region than outlined by fluid withdrawal contours. When used for reservoirs with moderate or high permeability (say k>1 mD), industry never needed to caution using pressure depletion plots as a proxy for fluid removal or drained rock volume (DRV). For such conventional reservoirs, pressure depletion plots are good proxies for fluid removal or drained rock volume (DRV). The fluid that moves from the margins of a pressure front, indicative of the so-called diffusive depth of investigation (DOI), will reach the well on the time-scale of economic life of the well. However, a whole new way of thinking is required when studying ultra-low permeability shales (nanoDarcy range), where the distinction between pressure depletion zones and the DRV regions (where fluid is recovered from) becomes crucial to understand which factors control the hydrocarbon recovery process. Our detailed analysis compares the diffusive DOI, of the leading edge of the pressure depletion front, and that of the convective DRV given by a tracer front. Results show that the pressure depletion front between the fractures quickly approaches the adjoining fracture pressure, and most of the production originates from the fracture tips after 12 months. The pressure depletion pattern vastly overestimates the DRV, whereas the tracer front shows the actual produced rock volume. A final section evaluates the specific flow regimes that correspond to certain diffusive DOI and convective DRV growth stages in the life of the well. The discussion section explains how production diagnostic plots can be used to identify the moment in the well life when enhanced oil recovery methods should be applied. This study can facilitate a better understanding of the fluid flow in fractured porous media and can be used to optimize fracture and well spacing to maximize the DRV.",16,16,0
Oil Recovery,Shale,"Ding, Mingchen; Gao, Miao; Wang, Yefei; Qu, Zhengtian; Chen, Xu","Experimental study on CO2-EOR in fractured reservoirs: Influence of fracture density, miscibility and production scheme",Fractured reservoirs; Fracture density; Miscibility; CO2 flooding; Recovery mechanism; CO2 huff-n-puff,HUFF-N-PUFF; BYPASSED-OIL-RECOVERY; MISCIBLE CO2; CARBON-DIOXIDE; INJECTION; SHALE; WATER; MATRIX; PERMEABILITY; DIFFUSION,"The effects of fracture density, miscibility and production scheme on CO2 enhanced oil recovery (EOR) in fractured reservoirs were investigated. A series of CO2 injection experiments were performed in various lengths of core plugs at both fractured and unfractured condition. Results demonstrate that although presence of fractures dramatically reduces the effectiveness of CO2 flooding, increasing fracture density clearly benefits its recovery potential. The oil recovery mechanism is mainly recognized to be oil swelling at the beginning of CO2 continuous injection and gradually turns to extraction of lighter hydrocarbons (C-5-C-30) with increased injection time. First-contact miscible flooding is more effective than both multi-contact miscible and immiscible flooding and proves its feasibility when fracture density exceeded 5.0 fractures per meter, with the maximum recovery up to 68.1% of original oil in place (OOIP). CO2 huff-n-puff is very powerful in recovering the residual oil after CO2 flooding. Fracture density has no major effect on huff-n-puff performance while at lower fracture-density condition, more cycles are required to reach the ultimate oil recovery. Multi-contact miscible CO2 huff-n-puff has the greatest potential of EOR ability in fractured reservoirs, which can increase the oil recovery to 86.2% OOIP on the basis of CO2 flooding test.",15,15,5
Oil Recovery,Shale,"Fu, Lipei; Liao, Kaili; Ge, Jijiang; Zhang, Guicai; He, Yanfeng; Wang, Xiang; Zhang, Shifeng; Deng, Song",Study of ethylenediammonium dichloride as a clay stabilizer used in the fracturing fluid,Clay stabilizer; Ethylenediammonium dichloride; Inhibition mechanism; Clay hydration; Fracturing fluid,OIL-RECOVERY; SHALE; NANOTECHNOLOGY; NANOPARTICLES; POLYMER,"Clay stabilizer is the topic of a great number of studies, particularly in petroleum engineering. The organic cationic polymer is a kind of clay stabilizer with excellent anti-swelling effect. However, for tight reservoirs, the organic cationic polymer type clay stabilizers tend to increase the permeability damage caused by retention and blockage of stabilizers. Therefore, stabilizers with low molecular weight are necessary for tight reservoirs. The inhibition properties and the mechanisms of ethylenediammonium dichloride (EDD) were studied in this paper. The clay inhibition properties were studied from three aspects: swelling inhibition, clay sedimentation, and particle size distribution. Results showed that the anti-swelling rate reaches 91.98%. Control experiments showed that EDD had better inhibition property than KCl, NH4Cl, and poly dimethyldiallyl ammonium chloride (PDMDAAC). The inhibition mechanisms, studied from the aspect of surface hydrophobicity, surface charge, interlayer water content, and crystal spacing, can be concluded as that EDD reduces clay electronegativity and enhances the hydrophobicity of the clay surface, thereby keeping clay in a stable state. Compatibility tests showed that EDD can be used in guar based fracturing fluid. This study provides an alternative clay stabilizer for hydraulic fracturing.",14,16,9
Oil Recovery,Shale,"Cui, Jiangfeng",Oil transport in shale nanopores and micro-fractures: Modeling and analysis,Shale oil; Asphaltenes; Mixed wettability; Adsorption; Mathematical model,MOLECULAR-DYNAMICS SIMULATION; ASPHALTENE PRECIPITATION; APPARENT PERMEABILITY; LIQUID PERMEABILITY; ORGANIC NANOPORES; FLOW; ENHANCEMENT; DIFFUSION; WATER; SLIP,"The mathematical modeling and analysis for the apparent permeability of shale oil with complicated compositions in dual-wettability shales (superior to existing single-component or single-wettability analysis), which is the core of this work, will help understand the detailed contributions of the considered mechanisms. Based on a previously established flow enhancement model, the effects of the mixed wettability and those triggered by asphaltenes, namely, the wettability alteration, the pore radius reduction, and the viscosity increment, are taken into account by respective corrections of the variables in the model. The effect of the mixed wettability is quantified by the water-wet area ratio, while the surface coverage, the adsorption thickness, and the volume fraction in the free phase are utilized to quantify the effects of asphaltenes. The volume fraction of asphaltenes in the free phase is related to that in both phases by the volume conservation equation. The full mathematical model and its several simplifications are achieved. Comprehensive sensitivity analysis and comparisons are carried out to demonstrate the effects of each variable (i.e., the pore radius, the initial water-wet surface ratio, the relative adsorption thickness, and the surface coverage) on: (1) the flow enhancement; (2) the relative importance of all mechanisms; (3) the differences among organic pores/inorganic pores/micro-fractures; and (4) the overall contribution of asphaltenes. The effect of different adsorption patterns (characterized by the relative adsorption thickness and the surface coverage) is also discussed.",14,14,3
Oil Recovery,Heavy Oil,"Wang, Yanwei; Liu, Huiqing; Wang, Jing; Dong, Xiaohu; Chen, Fangxuan",Formulation development and visualized investigation of temperature-resistant and salt-tolerant surfactant-polymer flooding to enhance oil recovery,Surfactant-polymer flooding; Enhanced oil recovery; Anti-temperature; Salt-tolerance; Visualized experiment; Microscopic mechanisms analysis,INTERFACIAL-TENSION; ZWITTERIONIC SURFACTANT; OPTIMIZATION; PERFORMANCE; SYSTEM,"As a tertiary oil recovery technique with broad application prospects, surfactant-polymer flooding can significantly improve sweep efficiency and enhance oil recovery, while eliminate the negative effects of alkali thoroughly. However, for most oil reservoirs abroad, belonging to marine carbonate reservoirs with high temperature and high salt content, SP flooding is largely limited. In this paper, the surface (interface) chemical properties of different types of surfactants were evaluated to select a mixed surfactant system with better performance and synergistic effect. And experiments on the physicochemical properties evaluation of polymers were performed to select a more suitable polymer. On this basis, the formulation of the surfactant-polymer binary composite system was optimized and the performance was evaluated. A visualized model was adopted to study the process of SP flooding, which vividly reflected the interaction of chemical agents with crude oil and the migration of chemical agents in porous media, as well as macroscopic and microscopic EOR mechanisms of SP Flooding. The results showed that Hexadecyl dimethyl carboxybetaine (C16HSB), heavy alkyl the linear alkylated diphenylmethane sulfonate (C-14-DSDM) and the hydrophobically modified polyacrylamide-based novel functional polymer GT-1 were selected. The optimized formulation of the SP flooding system was selected for 2000 mg/L GT-1 + 3000 mg/L C-14-DSDM + 1000 mg/L C16HSB, which showed higher apparent viscosity and lower interfacial tension (7.2 x 10(-3) mN/m) under the condition of 70 degrees C and 9780.5 mg/L formation water salinity. The system showed a certain resistance to temperature and salt, and stability under the conditions of temperature below 80 degrees C and salinity below 40000 mg/L and an EOR value of 31.2% in the visualized displacement experiment. Surfactants in the SP flooding system can emulsify the residual oil into spherical and flocculent emulsions, which are then stripped, drawn into filaments, and easily motivated. The retention of more polymer molecules in the throat causes the intermolecular association of polymer molecules to form a denser network structure, which plays an important role in increasing flow resistance and changing the direction of liquid flow, and its viscoelasticity contributes to the discharge of residual oil. Under the synergistic effect of surfactants and polymer, hydrodynamic residual oil, membrane residual oil, and residual oil droplets can be mobilized, thus beneficial to enhance oil recovery.",26,29,4
Oil Recovery,Heavy Oil,"Divandari, Hassan; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin; Ranjbar, Mohammad",Integrating synthesized citric acid-coated magnetite nanoparticles with magnetic fields for enhanced oil recovery: Experimental study and mechanistic understanding,Enhanced oil recovery; Nanofluid; Citric acid-coated Fe3O4 nanoparticles; Magnetic field; Wettability alteration; IFT; Micromodel,HEAVY OIL; ALPHA-FE2O3 NANOPARTICLES; MAGNETORHEOLOGICAL FLUID; WETTABILITY ALTERATION; SANDSTONE CORES; NANO-PARTICLES; CRUDE-OIL; WATER; WET; NANOFLUID,"Nanofluid injection has emerged as an attractive enhanced oil recovery (EOR) process in the past decade. These fluids improve oil recovery by reducing interfacial tension (IFT), modifying wettability, and reducing mobility ratio. In this communication, magnetite citric acid-coated nanoparticles (NPs) were synthesized by an affordable, facile and one step method and then characterized using Field emission scanning electron microscopy (FESEM), X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR), and Dynamic light scattering (DLS). Afterward, the microscopic and macroscopic efficiencies of oil recovery in heterogeneous and homogeneous 2D micromodels were investigated in the presence of magnetic field. Citric acid-coated magnetite NPs started to respond to the magnetic field around the intensity of 800 Gauss and also showed the maximum ultimate recovery factor at the intensity of 2750 Gauss. In addition, citric acid coated magnetite NPs provided more enhanced oil recovery factor compared to hematite NPs, because of reducing interfacial tension (IFT) between the oil and injection fluid, altering surface wettability from oil-wet to water-wet, promoting the NPs distribution in porous media, and generating column-like structure in the presence of magnetic field. In fact, magnetite NPs act as piston toward the magnetic field by creating a column which sweeps the oil and increases production. Furthermore, citric acid-coated magnetite NPs flooding increased ultimate recovery factor more than polymer and hematite NPs flooding.",24,25,10
Oil Recovery,Heavy Oil,"Giraldo, Lady J.; Gallego, Jaime; Villegas, Juan P.; Franco, Camilo A.; Cortes, Farid B.",Enhanced waterflooding with NiO/SiO2 0-D Janus nanoparticles at low concentration,Janus nanoparticles; Nanofluid flooding; Capillary number (N-C); Enhanced oil recovery (EOR),HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SILICA NANOPARTICLES; POROUS-MEDIA; SIO2 NANOPARTICLES; ADSORPTION ENERGY; RECOVERY; WATER; ASPHALTENES; BEHAVIOR,"The nanofluid (nanoparticles dispersed in determined carrier fluid) flooding has been studied for reducing the interfacial tension (IFT), increasing the viscosity of the displacement phase and to alter the rock wettability, which impact the capillary number and hence increase the crude oil recovery. However, this technique requires commonly large concentration of nanoparticles for being efficient in enhanced oil recovery (EOR) processes. Hence, the primary objective of this manuscript is to develop NiO-containing Janus nanoparticles based on zero-dimension (0-D) SiO2 nanoparticles which can be effective at low concentrations. The synthesized nanoparticles were characterized by transmission electron microscopy (TEM), surface area (S-BET), zeta potential, interfacial tension (IFT), rheology, contact angle measurements and coreflooding tests. The results showed a sharply increase of the capillary number (Nc) at a very low concentration of 100 mg/L of Janus nanoparticles, mainly attributed to the decrease in the interfacial tension, which can lead to the increase of the oil recovery. Displacement tests using a SiO2 nanoparticles-based nanofluid at a concentration of 100 mg/L did not show an increase in oil recovery regarding the one obtained in the waterflooding step. Meanwhile, the nanofluid based on NiO/SiO2 Janus nanoparticles at the same concentration of 100 mg/L showed an increase in oil recovery up to 50%.",21,22,6
Oil Recovery,Heavy Oil,"Wang, Yanyong; Ren, Shaoran; Zhang, Liang",Mechanistic simulation study of air injection assisted cyclic steam stimulation through horizontal wells for ultra heavy oil reservoirs,Air injection process; Low temperature oxidation; Ultra heavy oil; Steam injection; Horizontal well,LOW-TEMPERATURE OXIDATION; IN-SITU COMBUSTION; ENERGY EFFICIENCY; EMISSIONS; SYSTEMS; PHASE; MODEL; CO2,"Air injection assisted cyclic steam stimulation (CSS) through horizontal wells is a new technique for the exploitation of ultra heavy oil reservoirs, which has an advantage over other gas or solvent injection processes from the economic point of view. Different from in-situ combustion (ISC) process, the dominating chemical reactions occurring underground in air injection assisted CSS process are low temperature oxidation (LTO) reactions, and owing to the complicated LTO reaction mechanism, this process is still not clearly understood. Therefore, an indepth learning of this process will be of great benefit to its field application and specific project design. In this study, a comprehensive numerical simulation model was established, which accounted for the LTO reactions of different oil components in terms of SARA fractions, as well as permeability reduction induced by coke deposition. A series of simulations were then performed to explore the production performance and elucidate the impacts of various factors. The simulation results demonstrate that air injection assisted CSS using horizontal wells can enhance ultra heavy oil recovery and reduce cSOR in comparison with steam injection alone, which can be attributed to the synergistic effect of steam and air coinjection. Injection of air along with steam can have the same effect as the initial solution gas in reservoir, and the potential of air injection assisted CSS to enhance oil recovery will be more pronounced in oil layers with lean solution gas. In addition, normal air injection can be a viable choice considering the free availability of air, and injection of oxygen-reduced air can become a good option for ultra heavy oils featured with poor LTO reactivity for the sake of safe production.",20,21,1
Oil Recovery,Heavy Oil,"Ado, Muhammad Rabiu; Greaves, Malcolm; Rigby, Sean P.",Numerical simulation of the impact of geological heterogeneity on performance and safety of THAI heavy oil production process,Bitumen; Shale inter-layer; Heterogeneity; Cap-rock; Thief-zone; THAI,ORIENTATION; RECOVERY,"The Toe-to-Heel Air Injection (THAI) in-situ combustion process is an efficient way to extract heavy oil and bitumen. However, such reservoirs are often geologically heterogeneous. This work studied the impact of a range of different geological heterogeneities, often found in bitumen deposits, on the performance and safety of THAI. These heterogeneities included random heterogeneity, layered reservoirs, shaly reservoirs, and semi-permeable cap-rocks. A further aim was to also develop potential remedial measures, such as selective well placement It was found that the degree of symmetry assumed for the reservoir model had a substantial impact on the predicted level of oil production. This is of particular relevance to otherwise apparently symmetrical well placement designs such as staggered line drive. While the presence of impermeable zones resulted in the decrease in the overall oxygen utilisation for shaly reservoirs, compared to simply low permeability reservoirs, there was no evidence of oxygen breakthrough due to preferential channelling into the production well. In layered reservoirs, the development of a rich oil bank during THAI operation depended upon the distribution of permeability around the horizontal producer (HP), and did not occur when there was high permeability just above the HP. It has been shown that the proper representation of the cap-rock in reservoir models for the simulation of THAI is essential in order to accurately mimic the full pattern of heat distribution into the oil zone of the reservoir, and, thence, fuel lay-down. While THAI can operate stably with a permeable cap-rock, vertical permeabilities above similar to 1-3 mD led to significant loss of combustion gases from the reservoir.",20,20,0
Oil Recovery,Heavy Oil,"Gharibshahi, Reza; Jafari, Arezou; Ahmadi, Hamid",CFD investigation of enhanced extra-heavy oil recovery using metallic nanoparticles/steam injection in a micromodel with random pore distribution,Oil recovery factor; Steam; Nanoparticles; CFD; Design experiment; Taguchi method; Optimization; Micromodel,MULTIPHASE MIXTURE MODEL; CAPILLARY-POROUS MEDIA; MULTICOMPONENT TRANSPORT; WETTABILITY ALTERATION; STEAM INJECTION; SANDSTONE CORES; SIMULATION; NANOFLUID; CATALYST,"The present study simulated thermal enhanced oil recovery (steam and nanoparticles) for the first time using computational fluid dynamics. To better visualize fluid flow in the reservoir, a 2D micromodel generated by commercial grid generation tools was used as the porous medium. Four parameters that have a great impaction on the process were studied to determine the best combination of factors to attain maximum oil recovery. Type of nanoparticle, volume fraction of nanoparticles, diameter of nanoparticles and temperature of injected fluid were examined using the Taguchi method. All governing equations were solved in Fluent software based on finite volume. The numerical results were in a good agreement with the experimental results and the data shows that Al2O3 nanoparticles have the greatest potential for enhanced oil recovery in comparison with CuO and Fe3O4 nanoparticles. Decreasing the diameter of the nanoparticles and increasing their volume fraction in the base fluid and the temperature of the injected fluid improved oil recovery and a large amount of oil was produced from the porous medium. Injecting the nanofluid at an optimal level decreased the viscosity of the extra heavy oil from 35 to 25 Pas.",18,20,6
Oil Recovery,Heavy Oil,"Dahkaee, Kaveh Padasht; Sadeghi, Mohammad Taghi; Fakhroueian, Zahra; Esmaeilzadeh, Pouriya",Effect of NiO/SiO2 nanofluids on the ultra interfacial tension reduction between heavy oil and aqueous solution and their use for wettability alteration of carbonate rocks,NiO/SiO2 nanocomposites; EOR; IFT reduction; Smart surface modification; Wettability alteration; Heavy oil,ZRO2 NANOPARTICLES; SILICA; SURFACTANT; RECOVERY; BEHAVIOR; SIO2; NANOCOMPOSITES; PERFORMANCE; WATER,"One of the important factors in enhanced oil recovery (EOR), which leads to better oil flow in reservoirs and increases the recovery efficiency of the reservoirs, is the reduction of surface tension (S.T) and interfacial tension (IFT). The effect of NiO and SiO2 nanoparticles and their nanocomposites as NiO/SiO2 on the reduction of oil/water interfacial tension was investigated for the heavy oil of Soroush field located in Iran with a density of 0.965 g/cm(3) and viscosity of 1310 cP at 22 degrees C. NiO and SiO2 nanoparticles were produced by sol-gel-hydrothermal process and NiO/SiO2 nanocomposites were synthesized by co-precipitation-hydrothermal method. The interfacial tension of water/Soroush oil was measured to be 29.02 mN/m, as the reference, in the absence of nanoparticles. Water-based nanofluid of 30 wt% NiO/SiO2 and 28 wt% Fe@ NiO/SiO2 nanocomposites that benefits the synergism of the Fe promotor, decreased the IFT to 1.28 mN/m and less than 1 mN/m, respectively. In addition, the key factors such as concentration, aging time and salinity affect were studied in variation of S.T and IFT. It was found that 8 v/v% of the 30 wt% NiO/SiO2 diluted in water had the best efficiency in reducing the S.T and IFT, while preheating time of nanofluids and salinity of water that the nanofluid dissolved in had negligible impacts on surface and interfacial tension. Moreover, as the 30 wt% NiO/SiO2 nanocomposites were essentially hydrophobic, novel hydrophilic and eco-friendly nanocomposites of 30 wt% NiO/SiO2 were also synthesized through smart surface modifications by polyethylene glycol (PEG 6000) and polydimethylsiloxane. It was shown that the surface-modified nanocomposites could reduce the S.T and IFT significantly and alter the wettability of a strong oil-wet carbonate rock to water-wet condition.",18,20,3
Oil Recovery,Heavy Oil,"Shi, Lanxiang; Ma, Desheng; Liu, Pengcheng; Li, Xiuluan; Xi, Changfeng; Wang, Chao",Experimental and numerical simulation studies on effects of viscosity reducers for steam assisted gravity drainage performances in extra-heavy oil reservoirs,Steam-assisted gravity drainage(SAGD); Viscosity reducer; Extra-heavy oil reservoirs; Steam-to-oil-ratio (SOR),INJECTION PROCESS; PHASE-BEHAVIOR; SAGD PROCESS; SOLVENT; SURFACTANTS; BITUMEN; WELLS,"Steam-Assisted Gravity Drainage (SAGD) has been demonstrated as an effective process for recovering extra - heavy oil. However, large volumes of steam are required to heat the viscous oil, resulting in high consumption of natural gas and water, which affects its economic benefit Therefore, research has long focused on improving the SAGD performance. In this study, a viscosity reducer (VR) assisted SAGD (VR-SAGD) process is systematically examined by experiment and numerical simulations based on an extra-heavy oil sample from a commercial SAGD block in Xinjiang oil fields, China. A scaled two-dimensional (2D) VR-SAGD experiment is carried out using a scale model to study the mechanisms of production dynamics and to observe the steam chamber development phases of the VR-SAGD process. A history match is conducted based on the 2D experimental data, and the recovery mechanisms of VR-SAGD are discussed. Heterogeneity in terms of barriers sandwiched in the pay zone is studied, and operational parameters are optimized based on the history match results. The 2D physical simulation results show that VR-SAGD accelerates the oil rate by a factor of 1.74 and reduces the instantaneous steam-to-oil-ratio by 49.7%. The VR co-injected with steam propagates in advance and accumulates at the front of the steam chamber and around the barriers to accelerate the effect of viscosity-reduction and reduce the heat loss to the overburden. Numerical simulation results indicate that the optimum time for VR injection is during and after the phase when the steam chamber expands sideways. The optimized VR/steam volume ratio and production/injection volume ratio are 1:9 and 1.2:1, respectively. The VR-SAGD process shows good potential to improve post-SAGD performance and reduces steam consumption in extra-heavy oil reservoirs.",16,16,1
Oil Recovery,Heavy Oil,"Yu, Fuwei; Jiang, Hanqiao; Xu, Fei; Zhen, Fan; Wang, Jitao; Cheng, Baoyang; Su, Hang; Li, Junjian",A multi-scale experimental study of hydrophobically-modified polyacrylamide flood and surfactant-polymer flood on enhanced heavy oil recovery,Heavy oil; Surfactant-polymer flood; Hydrophobically-modified polyacrylamide flood; Multi-scale experiments,IN-WATER EMULSIONS; INTERFACIAL-TENSION; CONFORMANCE CONTROL; POROUS-MEDIA; PORE-SCALE; INJECTION; SALINITY; RESERVOIR; METHODOLOGY; IMBIBITION,"A large amount of residual oil remained in heavy oil reservoirs after water flood due to its viscosity nature. And it has been validated that chemical flood, if applied appropriately, is an efficient and economical EOR method for deeply buried or thin heavy oil reservoirs. A multi-scale experimental evaluation workflow was designed to explore the mechanisms behind the production of residual oil in heavy oil reservoirs by chemical flood. And we conducted three multi-scale experiments to evaluate the performance of hydrophobically-modified polyacrylamide (HMHPAM) flood, surfactant-polymer (SP) flood and their combination. Based on the results of corefloods and medical CT scans, we demonstrated the EOR potential of HMHPAM flood (HPF) synergy with SP flood (SPF). After each coreflood, two samples were drilled from the heterogenous core used in the macro-scale experiment. And the micro-CT scan results of these samples visualized the distribution of oil phase and aqueous phase in each coreflood at the pore scale, and further quantified the decrease of continuous oil clusters caused by the HMHPAM solution and following injected fluids. Besides, we also observed the linear relationship between the volume of each oil cluster against its surface area and the logarithmic relationship between the volume of discontinuous oil cluster and its cumulative contribution to total oil volume. Moreover, a simple method to calculate the oil-water proportion in pores was developed to correlate the relationship between the displacement efficiency of each pore and its pore size. Results showed that the relationship between oil saturation in each pore and its pore size followed the power law correlation. Moreover, the pore-scale analysis also validated that the residual oil in most pores after water flood was effectively mobilized by the synergy of HPF and SPF.",15,18,5
Oil Recovery,Heavy Oil,"Chen, Ya-fei; Pu, Wan-fen; Liu, Xue-li; Li, Yi-bo; Varfolomeev, Mikhail A.; Hui, Jian",A preliminary feasibility analysis of in situ combustion in a deep fractured-cave carbonate heavy oil reservoir,In-situ combustion; Heavy oil; Adiabatic oxidation; Deposited coke; Thermal analysis; FTIR,LOW-TEMPERATURE OXIDATION; PRESSURE AIR INJECTION; KINETIC-ANALYSIS; RECOVERY; MODELS; PYROLYSIS; SYSTEM; LIGHT,"As an effective thermal-enhanced oil recovery technique, in-situ combustion (ISC) can achieve large oil displacement efficiency and upgrade the heavy oil technically, but there are still various barriers for ISC application in naturally fractured carbonate heavy reservoirs. In addition, the potential risk of wellbore plugging and formation collapse, caused by the possibility of carbonate rock decomposition at high temperatures, furtherly hinders the application of ISC technique and focuses more attention on feasibility evaluation. Hence, this paper attempted to estimate the preliminary feasible application of ISC in Tahe oilfield, characterized with fractured-cave carbonate heavy reservoir. From macro and micro aspects, results indicated that owing to large microscopic surface area and high oxygen contact ability between the deposited coke and oxygen, the oxidized ultra-heavy oil, under adiabatic condition, in simulative fractured-cave carbonate oil reservoir was successfully ignited and maintained the combustion process with the combustion front temperature. Besides, a large amount of heat generation from the combustion front can activate the ultra-heavy oil with better mobility ability. Additionally, in this process, the decomposition process of Tahe carbonate rock was not triggered ( similar to 631.6 degrees C) where the decomposition risk of running in-situ combustion process in Tahe carbonate reservoir can be neglected. Preliminarily, it implied that ISC is a feasible technique to upgrade the ultra-heavy oil for Tahe oilfield.",15,15,1
Oil Recovery,Heavy Oil,"Pang, Shishi; Pu, Wanfen; Xie, Jianyong; Chu, Yanjie; Wang, Chongyang; Shen, Chao",Investigation into the properties of water-in-heavy oil emulsion and its role in enhanced oil recovery during water flooding,Water-in-heavy oil emulsion; Emulsion properties; Salinity; pH; Mobility control ability,CRUDE-OIL; STABILITY; SALINITY; ASPHALTENES; DESTABILIZATION; AROMATICITY; PERFORMANCE; BEHAVIOR; RESINS; RATIO,"This paper described an investigation into the properties of water-in-heavy oil emulsion and its role in enhanced oil recovery (EOR). Effect of pH and salinity on emulsion stability, droplet size and distribution as well as rheological behavior were researched. Core flooding experiments were conducted to study the role of emulsion on EOR. Results indicated that stability of emulsions decreased as salinity increased. The presence of salt leads to a rise in droplet size and a drop in uniformity of distribution. Besides, emulsion formed at pH of 7 was characterized by the least stability, largest droplet size and unevenest droplet size distribution. An increase or decrease in pH both improved emulsion stability and reduced droplet size. Equally, rheological property of emulsion was greatly affected by salinity and pH. In relatively low shear rate region (< 250 s(-1)), emulsion viscosity decreased as salinity increased; opposite trend was confirmed when shear rate exceeded 250 s(-1). As a whole, shear thinning behavior was more pronounced in lower salinity and pH environment. Specifically, Newtonian behavior of emulsions were observed in high salinity and non-acidic condition in shear rate region of 60s(-1)-400s(-1). The core flooding experiments showed that the formation of in-situ emulsion exhibited good mobility control ability, resulting in the improvement of sweep efficiency. In-situ emulsion prolonged the low-water-cut production period, giving rise to the enhancement of heavy oil recovery during waterflooding.",15,15,1
Oil Recovery,Heavy Oil,"Duan, Ming; Li, Chengcheng; Wang, Xiaodong; Fang, Shenwen; Xiong, Yan; Shi, Peng",Solid separation from the heavy oil sludge produced from Liaohe Oilfield,Heavy oil sludge; Solid separation; Demulsification,PETROLEUM SLUDGE; STABILIZED EMULSIONS; TANK BOTTOM; CRUDE-OIL; CENTRIFUGATION; EXTRACTION,"Heavy oil sludge usually exists in the form of stable W/O emulsion, in which the water droplets were stabilized by natural surfactants and small solid particles. The oil recovery from the oil sludge is valuable, but the demulsification by using regular demulsifiers could be hindered by the solids. Therefore, the solid separation is important for oil recovery. In this paper, firstly, properties of heavy oil sludge produced from the Liaohe Oilfield were analyzed. Then, a multistage chemical treatment was proposed and chemicals were screened for solid separation. Limonene, sodium sulphate solution, (dioctadecyl dimethyl ammonium bromide + citric acid) were chosen for different purposes at different stages, respectively. At last, the rational separation conditions were investigated. After the treatment, the solid content in oil decreased from 18.57% to be 0.9% by mass. In addition, the mixture of recovered oil and fresh crude oil can be dehydrated easily by using regular demulsifiers.",14,15,4
Oil Recovery,Heavy Oil,"Panahpoori, Donya; Rezvani, Hosein; Parsaei, Rafat; Riazi, Masoud",A pore-scale study on improving CTAB foam stability in heavy crude oil-water system using TiO2 nanoparticles,TiO2 nanoparticle; CTAB foam; Foam stability; EOR; Glass micromodel,IMMISCIBLE FOAM; POROUS-MEDIA; CO2 FOAM; SURFACTANT; ZRO2; DISPLACEMENT; ASPHALTENE; ADSORPTION; RECOVERY; BULK,"The main challenge of foam injection for enhanced oil recovery (EOR) is foam stability at harsh reservoir conditions. With regard to this matter, this research aims to investigate the effect of TiO2 nanoparticles (NPs) in improving the stability of foam bubbles in porous media. The conductivity of hexadecyltrimethylammonium bromide (CTAB) solutions was measured to determine critical micelle concentration (CMC). Thereafter, TiO2 NPs were added into the foam solution and pH, contact angle, and interfacial tension (IFT) in the presence and absence of CTAB were measured. The stability of foam bubbles was evaluated through bulk foam tests and absorbance measurements. Finally, different nanofluids (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.10 wt%), nano-CTAB solutions (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs at the CMC of CTAB) and foams (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs and at the CMC of CTAB) were injected into a heavy oil saturated heterogeneous porous medium. The results of the conductivity measurements showed that the highest adsorption of CTAB molecules onto the NPs surfaces occurs at 0.03 wt% NPs and 0.03 wt% CTAB. The results of micro- and macroscopic images from bulk foam tests revealed improved foam stability for this nano-CTAB foam. Moreover, contact angle and IFT results showed further improvement in interfacial properties for the mixture of NPs and CTAB solutions. Ultimately, in terms of oil recovery, the highest oil recovery factor (54%) was observed upon injection of foam with 0.03 wt% TiO2 NPs and 0.03 wt% CTAB, compared to the 22% recovery factor of DW injection. The visualization experiments showed that 32% enhancement in the recovery factor was mainly due to oil production from dead-end pores. This was because of different functions of NPs including stabilization of foam bubbles, wettability alteration, and improved foam generation mechanisms.",13,13,4
Oil Recovery,Contact Angle,"Liu, Junrong; Shen, James J.; Wang, Xiukun; Ge, Hongkui; Yao, Erdong",Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants,Shale oil; Spontaneous imbibition; Wettability alteration; Surfactant; IFT,CARBONATE RESERVOIRS; LOW-PERMEABILITY; RECOVERY; WATER; WET,"Wettability alteration exhibits a significant potential to improve the oil recovery of shale reservoirs by means of spontaneous imbibition through shifting the rock wetness from oil-wet to water-wet. The wettability of the oil-wet shale can be modified by adding surfactants in hydraulic fracturing fluids in the field practice. However, the mechanisms of wettability alteration in shale rocks are still unclear and there are reported discrepancies in different types of surfactants solutions. This work attempts to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of the Sichuan Basin in China, and to analyze their effects of wettability alteration and interfacial-tension (IFT) reduction on the spontaneous imbibition process of the oil-wet shale samples. By measuring the contact-angle, zeta-potential, and IFT, the efficiencies of different surfactants in terms of wettability alteration and IFT reduction are evaluated. The contact-angle experiments show that the water contact angle in rock/oil/water systems decreases when we add more surfactants, which indicates the hydrophilicity of shales is increased by surfactants. Specifically, for the anionic surfactant solutions, the contact angle doesn't immediately change, and it decreases with time, which is different from the sudden change of nonionic surfactants. Moreover, for different surfactants, the IFT decreases in a similar trend with the increase of surfactant concentration. Finally, spontaneous imbibition experiments are conducted and the results show that anionic surfactants are more favorable to recover shale oil than the nonionic surfactants. From the results obtained, it can be concluded that the anion surfactants and nonionic surfactant have different mechanisms for wettability alteration on the shale surface; anionic surfactants have better effect on wettability alteration than nonionic surfactants, however, the mechanism of wettability alteration in anionic surfactants have time delay. The wettability alteration dominates the oil recovery in the way of spontaneous imbibition. More water-wetness tends to yield a higher recovery. In addition, for anionic surfactant solutions, the reduction of IFT increases the final oil recovery and leads to a decrease of the imbibition rate. For nonionic surfactant solutions, the reduction of IFT increases both the imbibition rate and the final recovery, but the enhancement is not significant.",52,52,9
Oil Recovery,Contact Angle,"Pal, Nilanjan; Kumar, Narendra; Saw, Rohit Kumar; Mandal, Ajay",Gemini surfactant/polymer/silica stabilized oil-in-water nanoemulsions: Design and physicochemical characterization for enhanced oil recovery,Nanoemulsions; Surfactant-polymer-nanoparticle systems; Dynamic light scattering; Viscosity; Wettability alteration; Chemical flooding,SURFACTANT-POLYMER; EMULSIONS; EOR; PERFORMANCE; MICROEMULSIONS; BEHAVIOR,"The present study deals with the synthesis and characterization of oil-in-water nanoemulsion systems for application in enhanced oil recovery (EOR). Nanoemulsions stabilized by N,N'-bis((dimethyltetradecyl)-1,6-hexanediammonium bromide) gemini surfactant (14-6-14 GS), partially hydrolyzed poly-acrylamide (PHPA) polymer and/or silica (SiO2) nanoparticle were synthesized by ultrasonication technique. Nanoparticles strengthen the mechanical barrier (electrostatic repulsion + steric hindrance) at oil-aqueous interfaces, resulting in increased ionic strength and droplet stability. Dynamic light scattering (DLS) results confirmed the formation of nano-sized (< 500 nm) oil droplets within bulk emulsion phase. Kinetic stabilities of nanoemulsions were investigated by zeta potential and phase behavior analyses. Surface tension of surfactant-stabilized nanoemulsions increased with PHPA addition. However, silica particles improved adsorption ability of surfactant-polymer-nanoparticle (SPN) systems, causing decrease in surface tension. Rheological experiments were conducted as screening experiment at different temperatures to identify pseudoplastic character, and flow parameters were fitted using the Power law model. Contact angle studies showed that nanoemulsions alter the wetting characteristics of rock from intermediate-wet to favorable water-wet condition. Core-flooding studies revealed tertiary oil recovery percentage of 26.25% of original oil in place (OOIP) by chemical injections of {14-6-14 GS + PHPA + SiO2} nanoemulsions, after conventional water-flooding.",36,37,8
Oil Recovery,Contact Angle,"Nowrouzi, Iman; Manshad, Abbas Khaksar; Mohammadi, Amir H.",Effects of concentration and size of TiO2 nano-particles on the performance of smart water in wettability alteration and oil production under spontaneous imbibition,Smart water; TiO2; Wettability; Contact angle; Nano-fluids; Chemical enhanced oil recovery,INTERFACIAL-TENSION IFT; DISSOLVED CARBON-DIOXIDE; LOW-SALINITY; CRUDE-OIL; THERMAL-CONDUCTIVITY; PHYSICAL-PROPERTIES; INJECTION PROCESSES; CONTACT-ANGLE; POROUS-MEDIA; RECOVERY EOR,"Using smart nano-fluids with respect to enhanced oil recovery (EOR) is an emerging technology, which is normally studied in combination with other methods. Nano-fluid performance depends on type, size and concentration of the dispersed nano-particles in it. In the current work, effects of size and concentration of seawater-based nano-fluid of TiO2 in different salinities (resulted from dilution) on enhanced oil recovery parameters including contact angle, wettability and interfacial tension (IFT) have been investigated using the pendant drop method. Eventually, effect of TiO2 nano-particles in nano-fluids on recovered quantity has been investigated using imbibition experiment mechanism, which is one of the most important mechanisms in oil production from fractured reservoirs. Results of the experiments show that using higher concentration and smaller particle sizes of TiO2 would decrease the IFT and contact angle. Higher concentration and larger particle sizes of TiO2 in nano-fluid would increase the viscosity. Imbibition experiments show that the nanofluids containing smaller TiO2 nanoparticles are more efficient.",30,30,9
Oil Recovery,Contact Angle,"Gbadamosi, Afeez O.; Junin, Radzuan; Manan, Muhammad A.; Agi, Augustine; Oseh, Jeffrey O.; Usman, Jamilu",Synergistic application of aluminium oxide nanoparticles and oilfield polyacrylamide for enhanced oil recovery,Enhanced oil recovery; Polymers; Nanoparticles; Polymeric nanofluid; Aluminium oxide; Nanotechnology,PARTIALLY HYDROLYZED POLYACRYLAMIDE; ACRYLAMIDE-BASED POLYMER; HEAVY-OIL; WETTABILITY ALTERATION; SILICA NANOPARTICLES; RHEOLOGICAL PROPERTIES; ADSORPTION MECHANISM; SIO2 NANOPARTICLES; THERMAL-STABILITY; NANOFLUIDS,"Due to the inherent limitation of oilfield polyacrylamide in reservoir temperature and salinity, nanoparticles (NPs) have been extensively studied for their application in enhanced oil recovery (EOR) because of their unique properties and availability in large quantities. Recent trend in nanotechnology involves incorporating NPs as additive with polymer to form novel materials termed polymeric nanofluids (PNF's) for EOR. However, previous studies have investigated and focussed more on the suitability of silica (SiO2) polymeric nanofluids. In this work, the potential application of metal oxide polymeric nanofluid for EOR was explored and evaluated. Aqueous HPAM-based Al2O3 PNF's were formulated and characterised using Transmission Electron Microscopy (TEM) and Fourier-transform infrared (FTIR) spectroscopy. The performance of aluminium oxide (Al2O3) NP on the rheological properties of HPAM in the presence of different electrolyte concentrations representative of field brine and typical reservoir temperatures were investigated. Wettability alteration study of Al2O3 PNF was carried out using DataPhysics optical contact angle (OCA) instrument. Results obtained for Al2O3 PNF were compared to the widely reported SiO2 PNF and base polymer without nanomaterial. Experimental results show that the rheological properties improved while degradation of HPAM macromolecule was inhibited due to the addition of NPs. At 2,000 ppm HPAM solution (25 mol. % degree of hydrolysis), 0.1 wt% NP concentration was found to be the optimal choice for Al2O3 NP which gives rise to the highest viscosity on the rheological characterization. Al2O3 PNF exhibited better steady shear viscosity performance under the different electrolyte concentrations and temperatures studied. Al2O3 PNF altered the wettability of the porous media from oil-wet to water-wetting condition. Finally, oil displacement test in sandstone cores at typical reservoir temperature and salinity showed that Al2O3 PNF had 11.3% incremental oil recovery over conventional HPAM. This study is beneficial for extending the frontier of knowledge in nanotechnology application for EOR.",28,28,9
Oil Recovery,Contact Angle,"Moradi, Siyamak; Isari, Ali Akbar; Bachari, Zahra; Mahmoodi, Hossien",Combination of a new natural surfactant and smart water injection for enhanced oil recovery in carbonate rock: Synergic impacts of active ions and natural surfactant concentration,Enhanced oil recovery; Tribulus terrestris surfactant; Smart water; Interfacial tension; Wettability alteration; Carbonate rock,LOW-SALINITY BRINE; WETTABILITY ALTERATION; INTERFACIAL-TENSION; NONIONIC SURFACTANT; CRUDE-OIL; SPONTANEOUS IMBIBITION; TRIBULUS-TERRESTRIS; WASTE-WATER; ADSORPTION; CHALK,"By increasing oil demand in carbonate reservoirs, enhanced oil recovery techniques play key role in improving oil production. Surfactant flooding and smart water injection are already well known as effective enhanced oil recovery techniques that increase oil recovery by reduction of oil-water interfacial tension and the alteration of rock wettability. In this work, a new plant-base natural surfactant, named Tribulus Terrestris is introduced and combined with smart water samples (i.e. synthetic seawater with different concentrations of active Ca2+, Mg(2+ )and SO42- ions) to determine their individual and integrated effects on reduction in interfacial tension, wettability alteration and oil recovery in carbonate rock samples. It was observed that increasing concentrations of SO42- up to 2.5 times resulted in maximum wettability restoration among active ions (by changing contact angle from 145.9 degrees to 54.4 degrees). Experimental results also showed that the effect of the concentration of active ions on wettability alteration was more significant compared to their effect on decreasing oil-water interfacial tension. In addition, the Tribulus Terrestris surfactant reduced oil-water interfacial tension considerably (from 45.3 mN/m to 13.5 mN/m at Critical Micelle Concentration of 0.3 wt %); hence, it was used as smart water modifier to integrate effects of wettability alteration (by smart water) and reduction in interfacial tension (by new natural surfactant). Core flooding experiments demonstrated increased oil recovery from 45.2% for distilled water injection up to 64% and 72% for smart water and combined smart water-surfactant respectively.",25,25,0
Oil Recovery,Contact Angle,"Giraldo, Lady J.; Gallego, Jaime; Villegas, Juan P.; Franco, Camilo A.; Cortes, Farid B.",Enhanced waterflooding with NiO/SiO2 0-D Janus nanoparticles at low concentration,Janus nanoparticles; Nanofluid flooding; Capillary number (N-C); Enhanced oil recovery (EOR),HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SILICA NANOPARTICLES; POROUS-MEDIA; SIO2 NANOPARTICLES; ADSORPTION ENERGY; RECOVERY; WATER; ASPHALTENES; BEHAVIOR,"The nanofluid (nanoparticles dispersed in determined carrier fluid) flooding has been studied for reducing the interfacial tension (IFT), increasing the viscosity of the displacement phase and to alter the rock wettability, which impact the capillary number and hence increase the crude oil recovery. However, this technique requires commonly large concentration of nanoparticles for being efficient in enhanced oil recovery (EOR) processes. Hence, the primary objective of this manuscript is to develop NiO-containing Janus nanoparticles based on zero-dimension (0-D) SiO2 nanoparticles which can be effective at low concentrations. The synthesized nanoparticles were characterized by transmission electron microscopy (TEM), surface area (S-BET), zeta potential, interfacial tension (IFT), rheology, contact angle measurements and coreflooding tests. The results showed a sharply increase of the capillary number (Nc) at a very low concentration of 100 mg/L of Janus nanoparticles, mainly attributed to the decrease in the interfacial tension, which can lead to the increase of the oil recovery. Displacement tests using a SiO2 nanoparticles-based nanofluid at a concentration of 100 mg/L did not show an increase in oil recovery regarding the one obtained in the waterflooding step. Meanwhile, the nanofluid based on NiO/SiO2 Janus nanoparticles at the same concentration of 100 mg/L showed an increase in oil recovery up to 50%.",21,22,6
Oil Recovery,Contact Angle,"Aghajanzadeh, Mohammad Reza; Ahmadi, Pouyan; Sharifi, Mohammad; Riazi, Masoud",Wettability modification of oil-wet carbonate reservoirs using silica-based nanofluid: An experimental approach,Wettability alteration (WA); Nanoparticles; Spontaneous imbibition; Oil recovery; Carbonate rocks; Relative permeability,RECOVERY; NANOPARTICLES; IMBIBITION; CALCITE,"Wettability is an important factor which controls oil recovery and fluids displacement efficiency in the porous media. Wettability alteration (WA) from strongly oil-wet towards water wet or neutral states is one of the most effective methods of oil recovery increment. Many studies have shown that nanofluid can change the wettability of rock surface towards a desirable state and base on literature structural disjoining pressure is the main mechanism of wettability alteration via nano-treatment. However, there is a lack of information regarding the impact of salinity on nanofluid performance in porous media. Therefore, in this work, the effects of salinity, nanofluid concentration and rock type (i.e. limestone and dolomite surfaces) on wettability alteration of oil wet carbonate substrates under ambient condition were investigated. For this purpose, various static and dynamic experiments including contact angle, imbibition and core flood tests have been performed. The results on contact angle measurements showed that by increasing nanoparticles and electrolyte concentration the wettability alteration from oil wet to water wet was significantly enhanced. Moreover, the wettability alteration of dolomite substrate is much more than that of limestone substrate. In the following, the impact of nanofluid on the spontaneous imbibition for strongly oil-wet carbonate cores was closely examined. Finding results showed an increase as much as 15% of oil recovery for nanofluid imbibition in comparison to that of formation brine. Final evaluation of the nanofluid treatment in terms of its effectiveness was measured by core flood experimental runs. Comparison of relative permeability curves before and after treating have outlined that after the treatment process, the relative permeability curve has shifted to the right and the water relative permeability has reduced from 0.43 mD to 0.23 mD at the residual oil saturation due to wettability alteration of rock surface from strongly oil wet to water wet state.",21,21,6
Oil Recovery,Contact Angle,"Tabar, Mohammad Azadi; Ghazanfari, Mohammad Hossein; Monfared, Abolfazl Dehghan",On the size-dependent behavior of drop contact angle in wettability alteration of reservoir rocks to preferentially gas wetting using nanofluid,Gas condensate reservoir; Wettability alteration; Size dependent wettability; Pseudo-line tension; Surface roughness,LINE-TENSION; YOUNGS EQUATION; SURFACE-TENSION; NANO-SILICA; WIDE-RANGE; EVAPORATION; WATER; ENERGY; ENHANCEMENT; HYSTERESIS,"Wettability alteration of rock surfaces toward gas wetting have been recognized as a practical approach for maximizing the production from the gas condensate reservoirs. Most of the reported work in this area applied the so called sessile drop contact angle measurement technique to examine the change in wetting state of a surface. However, the size-dependent wetting behavior of drop which could affect the exact determination of wettability and wettability changes was not well discussed in the previous studies. Therefore, in this work, the size dependency of contact angle for four different liquid-solid-gas systems; i.e., water-calcite-air, water-treated calciteair (nanofluid treated calcite), oil-calcite-air, and oil-treated calcite-air, were investigated. To provide a better understanding of the displacement of reservoir gas and liquid following the wettability alteration process, a dynamic contact angle measurement approach was designed. The effect of drop size and surface roughness on the wetting state of calcite rock samples at the initial and altered condition of wettability was then investigated through experimental and modeling approaches. The surface roughness of calcite samples and drop contact angles were determined using Atomic Force Microscopy and Low bond axisymmetric drop shape analysis method, respectively. Analysis of results demonstrated that size dependency of contact angle imposed an error as high as 22.2 degrees on the measurement of achieved wettability alteration in the case of water-calcite/treated calciteair system. On the basis of calculated pseudo-line tension from the modeling schemes, it was also revealed that the surface roughness had a significant impact on wettability measurements. Both low and high pseudo-line tension values of order 10(-9) and 10(-6) N, respectively, could dictate some level of errors in contact angle measurements. However, high values were supposed to have a considerable degree of importance in gas condensate applications. The results of this study could provide a better understanding of the contact angle measurement experiments for petroleum engineers to evaluate the wettability alteration schemes.",21,21,1
Oil Recovery,Contact Angle,"Pan, Bin; Li, Yajun; Xie, Liujuan; Wang, Xiaopu; He, Qingkun; Li, Yanchao; Hejazi, Seyed Hossein; Iglauer, Stefan",Role of fluid density on quartz wettability,Quartz wettability; Non-aqueous density; Hydrocarbon recovery,CARBON GEO-SEQUESTRATION; CONTACT ANGLES; INTERFACIAL-TENSIONS; SIZE DISTRIBUTION; CO2 WETTABILITY; DISSOLVED-GASES; OIL-WET; STORAGE; SIMULATION; ADSORPTION,"Hydrocarbon recovery and reserves estimation largely depend upon the hydrocarbon-water-mineral wettability. However, wettability is a complex parameter and experimental measurements are still open to large uncertainty. We thus demonstrate here that quartz wettability correlates with the density of the non-aqueous fluid, e.g. oil, CO2, N-2 , etc. - which can be in a liquid, gaseous or supercritical form. This insight significantly simplifies wettability assessments, thus enhancing fundamental understanding of wettability and the related fluid dynamics in siliciclastic hydrocarbon reservoirs. Furthermore, this observed correlation may promote hydrocarbon recovery and reserves prediction in siliciclastic reservoirs.",20,21,9
Oil Recovery,Contact Angle,"Lee, Yeonkyeong; Lee, Wonsuk; Jang, Youngho; Sung, Wonmo",Oil recovery by low-salinity polymer flooding in carbonate oil reservoirs,Polymer adsorption; Wettability alteration; PDI; Low-salinity polymer flooding; Carbonate reservoir,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; WATER; INJECTION; IMPACT; CHALK; EOR; MECHANISMS; EFFICIENCY; RETENTION,"Low-salinity polymer flooding (LSPF) is a promising enhanced oil recovery (EOR) method with a synergetic effect of combining the polymer injection and low-salinity water injection methods. To maximize EOR efficiency, it is essential to design the compositions of low-salinity water appropriately while considering polymer properties. The goal of this study was to investigate the effects of pH and potential determining ions (PDI; SO42- and Ca2+) in low-salinity polymer solution used as injection water on oil production when applying LSPF to a carbonate oil reservoir. From the experimental results, the SO42- ions interfered with polymer adsorption in the neutral SO42--containing polymer solution, while the adsorption was greatly promoted in the acidic conditions, reducing the permeability. In the Ca2+-containing polymer solution, the adsorption trend was different from the SO42- case. In examining the wettability alteration, the change in residual oil saturation between after-LSWF and after-LSPF (Delta S-or) was greater with higher SO42- concentration under the neutral state. This means that the end-point of the relative permeability-saturation curves shifted to the right, indicating that wettability was altered to a more water-wet state. Under acidic conditions, Delta S-or was smaller compared to the neutral state due to greater polymer adsorption. A small Delta S-or was observed when Ca2+ ions were contained in the neutral polymer solution, causing less wettability alteration. This is because Ca2+ ions are involved in precipitation as well as adsorption, thus reducing the permeability more than SO42--containing case. We confirmed these changes also in the contact angle analysis. In conclusion, since SO42- ions interfered with adsorption of polymer molecules and adsorption occurred less in the neutral state, a neutral polymer solution with high SO42- ion concentration as an injection water provided the highest enhancement in the EOR efficiency.",16,16,1
Oil Recovery,Contact Angle,"Al-Busaidi, Intisar K.; Al-Maamari, Rashid S.; Karimi, Mahvash; Naser, Jamil",Effect of different polar organic compounds on wettability of calcite surfaces,Wettability; Calcite; Double bond; Benzene ring; Carboxylic acids; Asphaltene,FATTY-ACIDS; CRUDE-OIL; WATER; ADSORPTION; CHALK; ASPHALTENES; SOLUBILITY; PETROLEUM,"The average oil recovery by conventional water flooding from oil-wet and naturally fractured carbonate reservoirs is often less than 30%. Removal of adsorbed acidic components and/or asphaltene from the carbonate surface results in wettability alteration towards water-wet which is an effective approach to enhance oil recovery. Long chain fatty acids, long chain naphthenic acids and asphaltene are major components in crude oil which are responsible for wettability alteration in carbonate reservoirs while unsaturated acids have minor effect. In this study, a more accurate quantification of the effects of different types and structures of polar components that contribute to the initial oil-wetting extent of the reservoir rocks were used (aliphatic saturated acids, aliphatic unsaturated acids, naphthenic acids, aromatic acids and asphaltene). Different analytical tools (contact angle, zeta potential, Fourier transform infrared spectroscopy and thermal analysis) were utilized for all acids in order to study surface characteristics. The results indicated that polar organic compounds act in different ways according to their structure and properties. Presence of double bond could make the acid molecule more polar, reactive and less hydrophobic. In addition, it can affect the spatial arrangement of the molecule and hence its orientation on the surface. Presence of benzene ring increases the reactivity and polarity of carboxylic group. Moreover, it enhances hydrophilic properties of the acid due to electrons of pi double bonds that can resonate over aromatic carbon atoms. The results revealed that, in the presence of water film, combination of acid dissociation in water, surface activity of acid and water solubility controls the acid adsorption and hence wettability alteration of the surface during aging process. Chemisorption of carboxylic acids/asphaltene changes the wettability of calcite surface. In addition to chemical adsorption, some acids adsorb physically on the surface. Physical adsorption of polar compounds may happen via hydrogen bonding between carboxylic groups and carbonate ions on the surface. Although physical adsorption is reversible and forms weak bonds between adsorbate and adsorbent, it may partially contribute to wettability alteration.",14,14,2
Oil Recovery,Contact Angle,"Panahpoori, Donya; Rezvani, Hosein; Parsaei, Rafat; Riazi, Masoud",A pore-scale study on improving CTAB foam stability in heavy crude oil-water system using TiO2 nanoparticles,TiO2 nanoparticle; CTAB foam; Foam stability; EOR; Glass micromodel,IMMISCIBLE FOAM; POROUS-MEDIA; CO2 FOAM; SURFACTANT; ZRO2; DISPLACEMENT; ASPHALTENE; ADSORPTION; RECOVERY; BULK,"The main challenge of foam injection for enhanced oil recovery (EOR) is foam stability at harsh reservoir conditions. With regard to this matter, this research aims to investigate the effect of TiO2 nanoparticles (NPs) in improving the stability of foam bubbles in porous media. The conductivity of hexadecyltrimethylammonium bromide (CTAB) solutions was measured to determine critical micelle concentration (CMC). Thereafter, TiO2 NPs were added into the foam solution and pH, contact angle, and interfacial tension (IFT) in the presence and absence of CTAB were measured. The stability of foam bubbles was evaluated through bulk foam tests and absorbance measurements. Finally, different nanofluids (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.10 wt%), nano-CTAB solutions (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs at the CMC of CTAB) and foams (at the concentrations of 0.00, 0.01, 0.03, 0.06, and 0.1 wt% NPs and at the CMC of CTAB) were injected into a heavy oil saturated heterogeneous porous medium. The results of the conductivity measurements showed that the highest adsorption of CTAB molecules onto the NPs surfaces occurs at 0.03 wt% NPs and 0.03 wt% CTAB. The results of micro- and macroscopic images from bulk foam tests revealed improved foam stability for this nano-CTAB foam. Moreover, contact angle and IFT results showed further improvement in interfacial properties for the mixture of NPs and CTAB solutions. Ultimately, in terms of oil recovery, the highest oil recovery factor (54%) was observed upon injection of foam with 0.03 wt% TiO2 NPs and 0.03 wt% CTAB, compared to the 22% recovery factor of DW injection. The visualization experiments showed that 32% enhancement in the recovery factor was mainly due to oil production from dead-end pores. This was because of different functions of NPs including stabilization of foam bubbles, wettability alteration, and improved foam generation mechanisms.",13,13,4
Oil Recovery,Hydraulic Fractures,"Liu, Junrong; Shen, James J.; Wang, Xiukun; Ge, Hongkui; Yao, Erdong",Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants,Shale oil; Spontaneous imbibition; Wettability alteration; Surfactant; IFT,CARBONATE RESERVOIRS; LOW-PERMEABILITY; RECOVERY; WATER; WET,"Wettability alteration exhibits a significant potential to improve the oil recovery of shale reservoirs by means of spontaneous imbibition through shifting the rock wetness from oil-wet to water-wet. The wettability of the oil-wet shale can be modified by adding surfactants in hydraulic fracturing fluids in the field practice. However, the mechanisms of wettability alteration in shale rocks are still unclear and there are reported discrepancies in different types of surfactants solutions. This work attempts to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of the Sichuan Basin in China, and to analyze their effects of wettability alteration and interfacial-tension (IFT) reduction on the spontaneous imbibition process of the oil-wet shale samples. By measuring the contact-angle, zeta-potential, and IFT, the efficiencies of different surfactants in terms of wettability alteration and IFT reduction are evaluated. The contact-angle experiments show that the water contact angle in rock/oil/water systems decreases when we add more surfactants, which indicates the hydrophilicity of shales is increased by surfactants. Specifically, for the anionic surfactant solutions, the contact angle doesn't immediately change, and it decreases with time, which is different from the sudden change of nonionic surfactants. Moreover, for different surfactants, the IFT decreases in a similar trend with the increase of surfactant concentration. Finally, spontaneous imbibition experiments are conducted and the results show that anionic surfactants are more favorable to recover shale oil than the nonionic surfactants. From the results obtained, it can be concluded that the anion surfactants and nonionic surfactant have different mechanisms for wettability alteration on the shale surface; anionic surfactants have better effect on wettability alteration than nonionic surfactants, however, the mechanism of wettability alteration in anionic surfactants have time delay. The wettability alteration dominates the oil recovery in the way of spontaneous imbibition. More water-wetness tends to yield a higher recovery. In addition, for anionic surfactant solutions, the reduction of IFT increases the final oil recovery and leads to a decrease of the imbibition rate. For nonionic surfactant solutions, the reduction of IFT increases both the imbibition rate and the final recovery, but the enhancement is not significant.",52,52,9
Oil Recovery,Hydraulic Fractures,"Wang, Shuhua; Chen, Zan; Chen, Shengnan",Applicability of deep neural networks on production forecasting in Bakken shale reservoirs,Production forecasting; Bakken formation; Deep neural networks; Hyperparameter optimization; Global sensitivity analysis,NEWTON OPTIMIZATION METHOD; TIGHT-OIL; GAS-PRODUCTION; MODEL; PREDICTION; DESIGN; STEAM,"The unconventional shale and tight formations, such as the Bakken in Williston Basin, are becoming an important hydrocarbon sources since the development of advanced horizontal drilling and multi-stage stimulation techniques. The appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery. Although reservoir simulations are commonly used for production analysis, the modeling of hydraulic fractures and intrinsic complexity of shale have restricted an understanding of the fluid flow behavior. Owing to the available of a large amount of data in unconventional tight and shale reservoirs, data-driven approaches, such as deep neural networks (DNNs), provide an alternative approach for production analysis in these formations. In this study, a total of 2919 wells including 2780 multi-stage hydraulic fractured horizontal wells and 139 vertical wells in Bakken Formation were collected and analyzed using a deep learning method and Sobol's global sensitivity analysis. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, and batch normalization were evaluated to develop a reliable deep neural network model. Moreover, k -fold cross validation was used to evaluate the prediction ability and robustness of models. Prior to the performance evaluation of DNN algorithms, an optimum DNN model was achieved by optimizing the dropout layer, activation function, and hyperparameters of DNN models. It is found that the number of hidden layers and neurons in each layer have significant effects on the performance of models. The optimized DNN model has 3 hidden layers and 200 neurons for each layer. The prediction performance of DNN models is acceptable with the low mean squared errors for both 6- and 18-months cumulative oil productions. Furthermore, the importance of each parameter was studied using the Sobol's analysis. Results show that the average proppant placed per stage is the most important parameter, which accounts for more than 35% of variability in both 6- and 18-months cumulative oil productions. These data-driven models can be readily updated when the new well information becomes available. It is worth mentioning that the proposed DNN models can be directly integrated into existing hydraulic fracturing design routines.",35,37,5
Oil Recovery,Hydraulic Fractures,"Cheng, Zhilin; Ning, Zhengfu; Ye, Xiongfei; Wang, Qing; Zhang, Wentong",New insights into spontaneous imbibition in tight oil sandstones with NMR,Spontaneous imbibition; Tight oil sandstones; Gravity effect; Anisotropic pore structure; Viscosity effect,PORE STRUCTURE; UNDERSTANDING WETTABILITY; BOUNDARY-CONDITIONS; SHAPE FACTOR; RECOVERY; SHALE; WATER; RESERVOIRS; PRESSURE; FLUID,"Previous research has confirmed that substantial yield has been recovered in the soaking period after hydraulic fracturing. Spontaneous imbibition (SI) is the primary mechanism responsible for the enhanced oil production and has become an effective oil recovery method with regards to unconventional reservoirs. Despite the importance of SI, an in-depth understanding of the features of SI in tight reservoirs is still inadequate. In this article, nuclear magnetic resonance (NMR) T-2 was employed to study the dynamic behavior of imbibition in tight sandstone samples from Yanchang formation, Ordos Basin. Additionally, high-pressure mercury intrusion (HPMI) and the initial T-2 of a core sample were combined to characterize pore structures of tight rocks and oil distributions in various pores at different imbibition stages. Then, the effects of gravity, anisotropic pore structure, and non-wetting phase (NWP) viscosity on imbibition recovery were determined via the variations in T-2 spectra for each sample. The results show that the tight cores feature a multiscale pore structure. Sub-micropores is the dominant type providing the major contribution to oil recovery, while nanopores have largest imbibition efficiency due to the larger capillary force. Gravity of fluids has a non-trivial effect on SI and cannot be neglected in tight samples under two-ends-open (TEO) or one-end-open (OEO) conditions; this seemingly counterintuitive finding is because the capillary force is weakened by the resistance force caused by the intricate flow paths and other possible surface forces at the nanoscale. Imbibition performance in a tight medium is strongly related to its pore structure. The variations in directional permeabilities, relative permeabilities and capillary pressure functions resulting from highly anisotropic samples greatly affect both the ultimate oil recovery and imbibition rate for tight samples under TEO condition, but only impact imbibition rate under allfaces-open (AFO) condition. Furthermore, because tight oil has a narrow range of viscosity, the imbibition behavior in tight samples may not be sensitive to the oil viscosity. It would be hoped that the insights gained from this study can help to improve our understanding of imbibition characteristics in tight reservoirs and develop new scaling models for the predication of oil recovery.",32,34,10
Oil Recovery,Hydraulic Fractures,"Cui, Ronghao; Feng, Qihong; Chen, Hongwei; Zhang, Wei; Wang, Sen",Multiscale random pore network modeling of oil-water two-phase slip flow in shale matrix,Pore network model; Shale oil; Two-phase flow; Slip effect; Computational fluid dynamics,FRACTURED HORIZONTAL WELL; FAST MASS-TRANSPORT; POROUS-MEDIA; RELATIVE PERMEABILITY; DYNAMIC PROPERTIES; CO2 SEQUESTRATION; ORGANIC-MATTER; GAS-FLOW; NANOPORES; RESERVOIR,"The large-scale hydraulic fracturing technology is commonly employed to significantly improve oil recovery in shale. An exceptional phenomenon from many field tests is worthy of attention that the majority of fracturing fluid (mainly water) does not return to the surface during hydraulic fracturing, but flows into shale matrix. As a consequence of this phenomenon, oil-water two-phase flow would happen. However, the fluid transportation in nano-pores is different from that of the conventional sandstone reservoirs. To understand oil-water two-phase flow in shale, an integrated pore network model (PNM) framework including network construction and flow simulation is developed. In the network construction, combined with a pore-size distribution (PSD) curve of shale system, a shale multiscale random pore network model is proposed, where organic pores and inorganic pores can be distinguished appropriately. In the flow simulation, considering that the traditional Hagen-Poiseuille equation may not be applicable in shale system, new bulk fluid and corner film flow models with slip length in various geometric pores (circular, square, equilateral triangle) are developed using the computational fluid dynamic (CFD) method. Through the quasi-static simulation technique, we estimate the flow properties in shale including capillary pressure and relative permeability. Simulation results confirm the slip effect would significantly affect oil-water two-phase flow in shale. And then, influences of shale pore structure on two-phase flow are further investigated. Through coupling network construction and two-phase flow simulation, we believe our work could shed light on the further research for multi-phase transportation in shale.",23,24,9
Oil Recovery,Hydraulic Fractures,"Zhao, Jinzhou; Wang, Qiang; Hu, Yongquan; Ren, Lan; Zhao, Chaoneng",Numerical investigation of shut-in time on stress evolution and tight oil production,Energy accumulation; Shut-in; Stress evolution; Optimum shut-in time; Geomechanics/fluid flow,SHALE-GAS-PRODUCTION; RESERVOIR; FLOW; GEOMECHANICS; SIMULATION; PRESSURE; FRACTURE; LEAKOFF; BASIN,"Among investigations on the mechanics of energy accumulation via well shut-in to increase oil production, reservoir imbibition is deemed effective. However, another element, i.e., the coupling effect of fluid flow and geomechanics has always been underrated in production. Hence, this is discussed herein based on seepage mechanics, elastic mechanics, and Biot pore elastic theory. Further, an integral mechanical coupling numerical model is established from staged fracturing on a horizontal well to analyze well shut-in and production, to simulate stress variation during the shut-in period and the impact of shut-in time on oil production. The model considers the coupling effect of oil and water flow, and geomechanics on the stress distribution of reservoir adjacent to hydraulic cracks during fracturing, well shut-in, and production. From the study of reservoir stress and physical parameters in different shut-down times, it is found that reservoir stress and physical parameters demonstrate some regular changes. The pore pressure and saturation demonstrate pressure diffusion and oil phase saturation recovery with increasing well shut-in time. Owing to pressure diffusion, horizontal maximum principal stress, and horizontal minimum principal stress, the shear stress and stress difference demonstrate high complexity. Meanwhile, permeability and porosity exhibit a complex distribution subject to effective stress; the characteristic parameters of reservoir rock based on construction parameters (total injection volume, injection rate, and shut-in time) affect the subsequent production considerably. The correlation curves drawn upon a simulated experiment that reflect the construction parameters against cumulative oil production indicate that cumulative oil production is in direct proportion to shut-in time and in reverse proportion to injection rate. The optimum shut-in time is correlated positively with both the total injection volume and injection rate.",19,19,5
Oil Recovery,Hydraulic Fractures,"Khanal, Aadi; Weijermars, Ruud",Pressure depletion and drained rock volume near hydraulically fractured parent and child wells,Depth of investigation; Drained rock volume; Well interference; Eagle ford; Complex analysis methods; Velocity plots,FLOOD DISPLACEMENT FRONTS; EAGLE FORD SHALE; INTERFERENCE; RESERVOIRS; HISTORY; MULTIWELL; TEXAS; OIL,"Field development of unconventional reservoirs tends to downsize well spacing when commercial success of a shale play is proven. The earlier, so-called parent wells are joined by infill wells, commonly called child wells. Tighter well spacing improves the recovery factor but the risk of well interference increases. The flow interference and pressure communication of adjoining wells via the matrix and their hydraulic fractures was investigated using the depth of investigation and associated pressure depletion plots. A sensitivity analysis shows how the depth of investigation in an unconventional reservoir is impacted by matrix permeability, other fluid properties, and time lapse between drilling of parent and child wells. In all cases, the extent of the drained region of a reservoir with hydraulic fractures is controlled by the fluid particle paths guided by the depth of investigation and time-of-flight contours. Time-of-flight contours visualize the reservoir drainage by parent and child wells using complex analysis methods (CAM) in a case study of the Eagle Ford shale. Even after 30 years of production, the actual drained rock volume (DRV) remains small and lags the depth of investigation. A commercial numerical reservoir simulator provides history matched inputs for the CAM tool which then can model the flow near the discrete fractures in the reservoir at high resolution. The developed procedure provides a computationally efficient method to quantify and visualize the DRV for parent and child wells in hydraulically fractured reservoirs. Fluid particle tracking provides a practical method to determine fracture and well-interference in combination with depth of investigation and pressure depletion studies.",18,18,0
Oil Recovery,Hydraulic Fractures,"Wang, Deqiang; Cheng, Linsong; Cao, Renyi; Jia, Pin; Fang, Sidong; Rao, Xiang; Wu, Yonghui; Dai, Dan",The effects of the boundary layer and fracture networks on the water huff-n-puff process of tight oil reservoirs,Tight reservoir; Water huff-n-puff; Volume fracture; Boundary layer; Embedded discrete fracture model,PERMEABILITY STRESS SENSITIVITY; HORIZONTAL WELLS; RELATIVE PERMEABILITY; SEMIANALYTICAL MODEL; FLOW BEHAVIOR; SHALE; PERFORMANCE; SIMULATION; SCALE,"Application of multi-fractured horizontal wells has led to significant progress in the development of tight oil reservoirs. However, oil production rapidly decreases and the estimated ultimate recovery is still low when the well is in production and approaching depletion. Water huff-n-puff is regarded as a useful measure to improve oil recovery due to oil-water imbibition and drainage. Additionally, complex fracture networks consisting of natural fractures (NF) and hydraulic fractures can significantly enhance oil recovery in the process of water huff-n-puff after multi-stage hydraulic fracturing. However, there is a non-flowing thin film on the solid-liquid wall surface in the pore-throats of the matrix, and the so-called boundary layer effect (BLE) is quite significant at the nanoscale. This effect reduces the effective flow space and effective permeability of the reservoir, leading to production damage. To date, few numerical simulation studies have considered the impact of the BLE and complex fracture networks in water huff-n-puff process simulation studies. In this study, the process of water huff-n-puff is evaluated considering complex fracture networks and formation damage in a matrix. The embedded discrete fracture model (EDMF), validated by local grid refinement (LGR), is applied to describe the distribution of hydraulic fractures and NF. The well performance considering the BLE is analyzed by a vectorization programming. The results show that the BLE reduces production and accelerates the production decline, so the BLE should be considered in reservoir simulations and productivity evaluations of water huff-n-puff processes. A certain degree of natural fracture development is conducive to improving the sweep efficiency of the water huff-n-puff, which could significantly improve oil recovery compared to depletion. By considering the impact of the BLE in water huff-n-puff simulations in tight oil reservoirs, it is possible to accurately evaluate the well performance and provide a theoretical basis for the optimization of water huff-n-puff.",17,16,5
Oil Recovery,Hydraulic Fractures,"Weijermars, Ruud; Nandlal, Kiran; Khanal, Aadi; Tugan, Murat Fatih",Comparison of pressure front with tracer front advance and principal flow regimes in hydraulically fractured wells in unconventional reservoirs,Shale reservoirs; Pressure front; Tracer front; Depth of investigation; Drained rock volume; Flow regimes,VERTICAL WELL; INTERFERENCE,"Pressure depletion patterns near hydraulically fractured wells in ultra-low permeability reservoirs occupy a much larger region than outlined by fluid withdrawal contours. When used for reservoirs with moderate or high permeability (say k>1 mD), industry never needed to caution using pressure depletion plots as a proxy for fluid removal or drained rock volume (DRV). For such conventional reservoirs, pressure depletion plots are good proxies for fluid removal or drained rock volume (DRV). The fluid that moves from the margins of a pressure front, indicative of the so-called diffusive depth of investigation (DOI), will reach the well on the time-scale of economic life of the well. However, a whole new way of thinking is required when studying ultra-low permeability shales (nanoDarcy range), where the distinction between pressure depletion zones and the DRV regions (where fluid is recovered from) becomes crucial to understand which factors control the hydrocarbon recovery process. Our detailed analysis compares the diffusive DOI, of the leading edge of the pressure depletion front, and that of the convective DRV given by a tracer front. Results show that the pressure depletion front between the fractures quickly approaches the adjoining fracture pressure, and most of the production originates from the fracture tips after 12 months. The pressure depletion pattern vastly overestimates the DRV, whereas the tracer front shows the actual produced rock volume. A final section evaluates the specific flow regimes that correspond to certain diffusive DOI and convective DRV growth stages in the life of the well. The discussion section explains how production diagnostic plots can be used to identify the moment in the well life when enhanced oil recovery methods should be applied. This study can facilitate a better understanding of the fluid flow in fractured porous media and can be used to optimize fracture and well spacing to maximize the DRV.",16,16,0
Oil Recovery,Hydraulic Fractures,"Fu, Lipei; Liao, Kaili; Ge, Jijiang; Zhang, Guicai; He, Yanfeng; Wang, Xiang; Zhang, Shifeng; Deng, Song",Study of ethylenediammonium dichloride as a clay stabilizer used in the fracturing fluid,Clay stabilizer; Ethylenediammonium dichloride; Inhibition mechanism; Clay hydration; Fracturing fluid,OIL-RECOVERY; SHALE; NANOTECHNOLOGY; NANOPARTICLES; POLYMER,"Clay stabilizer is the topic of a great number of studies, particularly in petroleum engineering. The organic cationic polymer is a kind of clay stabilizer with excellent anti-swelling effect. However, for tight reservoirs, the organic cationic polymer type clay stabilizers tend to increase the permeability damage caused by retention and blockage of stabilizers. Therefore, stabilizers with low molecular weight are necessary for tight reservoirs. The inhibition properties and the mechanisms of ethylenediammonium dichloride (EDD) were studied in this paper. The clay inhibition properties were studied from three aspects: swelling inhibition, clay sedimentation, and particle size distribution. Results showed that the anti-swelling rate reaches 91.98%. Control experiments showed that EDD had better inhibition property than KCl, NH4Cl, and poly dimethyldiallyl ammonium chloride (PDMDAAC). The inhibition mechanisms, studied from the aspect of surface hydrophobicity, surface charge, interlayer water content, and crystal spacing, can be concluded as that EDD reduces clay electronegativity and enhances the hydrophobicity of the clay surface, thereby keeping clay in a stable state. Compatibility tests showed that EDD can be used in guar based fracturing fluid. This study provides an alternative clay stabilizer for hydraulic fracturing.",14,16,9
Oil Recovery,Formation Damage,"Dong, Bingqiang; Meng, Meng; Qiu, Zhengsong; Lu, Zhaohui; Zhang, Ye; Zhong, Hanyi",Formation damage prevention using microemulsion in tight sandstone gas reservoir,Damage mechanism; Water blocking; Sensitivity damages; Protective drilling fluid,STRESS SENSITIVITY; LOW-PERMEABILITY; DRILLING-FLUID; OIL; REMOVAL; MODEL; SAND; FLOW,"Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production.",43,45,1
Oil Recovery,Formation Damage,"Yang, Yongfei; Li, Yingwen; Yao, Jun; Zhang, Kai; Iglauer, Stefan; Luquot, Linda; Wang, Zengbao",Formation damage evaluation of a sandstone reservoir via pore-scale X-ray computed tomography analysis,X-ray computed tomography; In-situ imaging; Permeability change; Fines migration; Clay swelling; Formation damage,FINES MIGRATION; MULTIPHASE FLOW; OIL-RECOVERY; RELATIVE PERMEABILITY; SALINITY; WETTABILITY; ROCKS; MICROTOMOGRAPHY; SENSITIVITY; SATURATION,"The incompatibility between workover fluid and reservoir rock is one of the causes of formation damage. Fines migration and clay swelling are considered as the major mechanisms responsible for formation damage, which results in declining productivity. However, there has been limited visualized evidence of pore structural changes during formation damage. This paper establishes a formation damage evaluation method for sandstone reservoirs based on X-ray micro-computed tomography (CT) analysis. We presented conclusive evidence for clay swelling and fines migration during workover fluid flooding and formation liquid flooding. Water sensitivity and flow rate sensitivity tests were performed on a Dongying sandstone (heterogeneous argillaceous sandstone) plug. In addition, the plug was micro-CT imaged before and after flooding with workover fluid and formation liquid at medium resolution (24 mu m voxel size); the changes in core permeability and the associated changes in 2D and 3D pore space were analyzed. We found that the sandstone pore space was partially blocked by clay minerals and moving particles, leading to significantly decreased porosity (5.17%-4.19% for sample 1, 5.38%-2.76% for sample 2) and permeability (3.38 x 10(-3) mu m(2) to 1.28 x 10(-3) mu m(2) for sample 1, 13.30 x 10(-3) mu m(2) to 3.15 x 10(-3) mu m(2) for sample 2). This permeability decrease was caused by a decrease in the average pore radius and coordination number. Moreover, increased micro-CT intensity was measured by comparison of initial and final tomogram images, representing clay swelling & blockage of pores during the displacement and a generally lower porosity. This work visualized microscale formation damage, which reminds that incompatibility between workover fluid and reservoir rock damages formation seriously and the fluid injection rate should be lower than the critical flow rate when developing a reservoir with a strong water sensitivity and flow rate sensitivity.",35,35,1
Oil Recovery,Formation Damage,"Ghasemian, Javad; Riahi, Siavash; Ayatollahi, Shahab; Mokhtari, Rasoul",Effect of salinity and ion type on formation damage due to inorganic scale deposition and introducing optimum salinity,Water flooding; Smart water; Potential determining ions; Scale; Optimum composition; Enhanced oil recovery,CALCIUM-SULFATE SCALE; IMPROVED OIL-RECOVERY; WETTABILITY ALTERATION; BRINE COMPOSITION; CRUDE-OIL; INJECTION; SEAWATER; CHALK; TEMPERATURE; DISSOLUTION,"Smart water injection is recognized as an effective EOR process to alter the wettability and interfacial tension to obtain higher micro/macro sweep efficiencies. This water contains reactive ions such as Mg2+, Ca2+ and SO42- which can act as potential-determining ions and change the surface charge of calcite rocks. One of the major concerns in the execution of an effective water-flood process, especially in tight carbonate reservoirs, is the chemical incompatibility between the formation brine and the injecting water. In the present study, laboratory fluid compatibility tests were carried out and software simulation was done to investigate the most important challenges of the water-flooding process in one of the West Iranian oil fields with the possibility of developing formation damage. The chemical incompatibility between injected smart water and formation water leads to inorganic scale deposition. For this purpose, sea water as the basis of smart water was prepared to examine the impact of determining ions such as Mg2+, Ca2+ and SO42- and, to examine the effect of the salinity of the injected brine on the total amount of CaSO4 scale precipitation. According to the obtained results, as the concentration of SO42- in the injecting sea water increases from 1/4 to 1 times its concentration in ordinary sea water, the CaSO4 precipitation increases smoothly, and then it is accelerated as the concentration increases beyond that. Therefore, even though the increasing of the sulfate concentration improved the wettability alteration ability of the smart water, calcium sulfate deposition was noticed, resulting in permanent formation damage. The test results also showed that CaSO4 deposition increases as the concentration of Ca2+ in the sea water increases. On the other hand, the presence of Mg(2+ )ion in sea water increases the solubility of CaSO4 and subsequently, lower scale formation was noticed by increasing the concentration of magnesium. This study also showed that there is an optimum salinity in which the minimum amount of mineral scale is deposited, and 5 times dilution of sea water is determined as the optimum salinity. The findings would enable us to optimize the ion contents of smart water for both, better oil sweep efficiency and lower risk of formation damage. In the end, this paper discusses the laboratory fluid compatibility results and scale prediction analysis for different smart water injection utilizations.",27,29,2
Oil Recovery,Formation Damage,"Yu, M.; Zeinijahromi, A.; Bedrikovetsky, P.; Genolet, L.; Behr, A.; Kowollik, P.; Hussain, F.",Effects of fines migration on oil displacement by low-salinity water,Fines migration; Low-salinity waterflooding; Oil recovery; Water relative permeability; SEM-EDS analysis,BRINE COMPOSITION; ANALYTICAL-MODEL; 2-PHASE FLOW; RECOVERY; INJECTION; PERMEABILITY; SANDSTONE; RESERVOIR,"Enhanced oil recovery by low-salinity waterflooding (LSW) has been shown to result from the combined effect of various physical mechanisms. In this study, laboratory experiments were designed in such a way that only fines migration mechanism remains active. Then, experimental observations and detailed characterizations of core plugs and produced fluids (water and oil) were used to analyze the effect of fines migration-induced formation damage on displacement efficiency. In the first set of experiments, core plugs of Berea and Obernkirchener sandstones were subjected to single-phase injections of water at salinities 40, 30, 20, 10, 5, 2.5, 0.5 and 0 g/L NaCl. An order-of-magnitude decrease in permeability was observed for both core plugs and was associated with an increase in fines concentration in the produced water. SEM-EDS images of the produced fines showed that kaolinite is mobilized as the salinity is reduced. SEM images of the pores before and after injection also showed fines retention and blockage. In the second set of experiments, two-phase LSW was performed on a pair of core plugs comparable to those in the first set of experiments. Kaolinite migration results were consistent with those of single-phase LSW. The two-phase LSW experiments showed 50% reduction in water relative permeability and 3% increase in oil recovery. Because no wettability alteration mechanism was active, the increase in oil recovery is attributed solely to enhanced displacement due to fines migration.",27,27,1
Oil Recovery,Formation Damage,"Wang, Deqiang; Cheng, Linsong; Cao, Renyi; Jia, Pin; Fang, Sidong; Rao, Xiang; Wu, Yonghui; Dai, Dan",The effects of the boundary layer and fracture networks on the water huff-n-puff process of tight oil reservoirs,Tight reservoir; Water huff-n-puff; Volume fracture; Boundary layer; Embedded discrete fracture model,PERMEABILITY STRESS SENSITIVITY; HORIZONTAL WELLS; RELATIVE PERMEABILITY; SEMIANALYTICAL MODEL; FLOW BEHAVIOR; SHALE; PERFORMANCE; SIMULATION; SCALE,"Application of multi-fractured horizontal wells has led to significant progress in the development of tight oil reservoirs. However, oil production rapidly decreases and the estimated ultimate recovery is still low when the well is in production and approaching depletion. Water huff-n-puff is regarded as a useful measure to improve oil recovery due to oil-water imbibition and drainage. Additionally, complex fracture networks consisting of natural fractures (NF) and hydraulic fractures can significantly enhance oil recovery in the process of water huff-n-puff after multi-stage hydraulic fracturing. However, there is a non-flowing thin film on the solid-liquid wall surface in the pore-throats of the matrix, and the so-called boundary layer effect (BLE) is quite significant at the nanoscale. This effect reduces the effective flow space and effective permeability of the reservoir, leading to production damage. To date, few numerical simulation studies have considered the impact of the BLE and complex fracture networks in water huff-n-puff process simulation studies. In this study, the process of water huff-n-puff is evaluated considering complex fracture networks and formation damage in a matrix. The embedded discrete fracture model (EDMF), validated by local grid refinement (LGR), is applied to describe the distribution of hydraulic fractures and NF. The well performance considering the BLE is analyzed by a vectorization programming. The results show that the BLE reduces production and accelerates the production decline, so the BLE should be considered in reservoir simulations and productivity evaluations of water huff-n-puff processes. A certain degree of natural fracture development is conducive to improving the sweep efficiency of the water huff-n-puff, which could significantly improve oil recovery compared to depletion. By considering the impact of the BLE in water huff-n-puff simulations in tight oil reservoirs, it is possible to accurately evaluate the well performance and provide a theoretical basis for the optimization of water huff-n-puff.",17,16,5
Oil Recovery,Formation Damage,"Sharifipour, M.; Nakhaee, A.; Pourafshary, P.",Model development of permeability impairment due to clay swelling in porous media using micromodels,LSW flooding; Clay swelling; Permeability impairment; Micromodel; Image processing,OIL-RECOVERY FACTOR; CAPILLARY-PRESSURE; WATER; GAS; MONTMORILLONITE; WETTABILITY; SURFACE,"Swelling and displacement of clay minerals during drilling and production of oil and gas reservoirs are among the main mechanisms of formation damage. Most reservoirs contain clay minerals, either originally deposited during sedimentation phase, or precipitated from fluids flowing through matrix. Owing to the large specific surface area of clay particles, their swelling, detachment, and migrationmay lead to permeability impairment in porous media. Therefore, an accurate interpretation of the behaviour of clay particles in the porous media may enable us to prevent and possibly reverse the respective damage mechanisms. In this work, the pore-scale swelling behaviour of clays are studied using glass micro models as porous medium and Sodium bentonite as swelling clay. By image processing technique, effective porosity of model during low salinity water (LSW) flooding are estimated. The effect of different parameters such as porous medium aspect ratio and clay concentration on permeability impairment is studied. According to this study, besides higher clay concentrations, the permeability is also affected adversely by larger aspect ratio of pore bodies. Based on our experiments, a model is developed to estimate permeability impairment by clay swelling as a function of pore geometry and clay concentration.",14,14,2
Oil Recovery,CO2 Huff-n-puff,"Li, Lei; Su, Yuliang; Hao, Yongmao; Zhan, Shiyuan; Lv, Yuting; Zhao, Qingmin; Wang, Haitao",A comparative study of CO2 and N-2 huff-n-puff EOR performance in shale oil production,Gas huff-n-puff; Shale oil; Oil component analysis; Vaporization effect; Injected gas mass,BAKKEN TIGHT OIL; INJECTION PRESSURE; RECOVERY; SIMULATION; RESERVOIRS; STORAGE; MECHANISMS; FIELD,"In this study, Huff-n-Puff (HnP) experiments were conducted to investigate the potential for producing hydrocarbons from the shale core samples using CO2 HnP and N-2 HnP, respectively. The compositions of crude oil, produced oil, and gas in the system were analyzed by Gas Chromatography/Mass Spectrometer (GC/MS). The results showed that at the end of six injection cycles, the cumulative oil recovery factors were 61.49% for CO2 injection and 34.85% for N2 injection. CO2 had better injectivity in the ultra-low permeability shale cores than N-2. The injected gas extracted and vaporized the light hydrocarbon components C3-8 into the gas phase. After six HnP cycles, the recovery factors of C3-4 were 91.6% for CO2 HnP and 75.1% for N-2 HnP. For the other components, the recovery factors were about 60% for CO2 HnP and 30% for N-2 HnP. After that, a core scale model was established to mimic the process of HnP and the mechanisms leading to the different performances of CO2 HnP and N-2 HnP were discussed. Different properties relating to the EOR mechanisms during HnP process were investigated. The results indicated that a significant amount of CO2 could dissolve into the crude oil and deposit as free gas phase existing in the core. During the CO2 HnP process, the oil and gas interfacial tension reduced to zero, and the oil viscosity was reduced by 40%-60%. The gas cap drive, dissolved gas drive, and miscible drive during CO2 HnP are more efficient than that during N-2 HnP. The change of the molecular diffusion rate resulted in an obvious change in oil recovery factor. Although simultaneous CO2 and N-2 is still improving the recovery, pure CO2 shows the best result. This study provides operators with valuable laboratory data about the produced hydrocarbon analysis on CO2 HnP and N-2 HnP in shale oil production and a better understanding of gas HnP mechanisms.",23,25,6
Oil Recovery,CO2 Huff-n-puff,"Ma, Quanzheng; Yang, Shenglai; Lv, Daoping; Wang, Mibang; Chen, Jianxun; Kou, Gen; Yang, Long",Experimental investigation on the influence factors and oil production distribution in different pore sizes during CO2 huff-n-puff in an ultra-high-pressure tight oil reservoir,Tight oil reservoir; MMP; CO2 huff-n-puff; Producing gas-oil ratio; NMR,CARBON-DIOXIDE; RECOVERY; PERFORMANCE; SIMULATION; INJECTION,"The Xinjiang tight oil reservoir has a low depletion recovery rate and high remaining oil content. The target reservoir has ultra-low permeability and complex pore structure. Therefore, performing water injection is very difficult, resulting in ineffective waterflooding. In this study, a series of experiments were conducted to study the effects of cycle numbers, production pressure, and permeability in CO2 huff-n-puff. The remaining oil production distribution in different pore sizes was also analyzed by the nuclear magnetic resonance (NMR) technique. The results showed that the cumulative oil recovery logarithmically increases with an increase in number of cycles, whereas, the oil recovery cycle decreases. Low production pressure and high permeability result in a higher oil recovery factor (ORF) of CO2 huff-n-puff. In addition, the optimal production pressure is 22 MPa. After the eighth cycle, the cumulative oil recovery can increase by 16.5%-44.5%, approximately 4.7-7.6 times that of the depletion recovery rate, indicating that CO2 huff-n-puff is a feasible way to enhance the ORF of a tight oil reservoir. HPR Chinaowever, the oil production in the first five cycles accounts for 84%-91.7% of the total enhanced recovery. Therefore, CO2 huff-n-puff operations should not have more than five cycles. NMR T-2 spectrum analysis shows that in the first cycle, the oil in macro and medium pores ( > 50 ms) is produced first, followed by small pores (10-50 ms), accounting for 49.5%-79% and 8%-37% of the total ORF, respectively, whereas, oil from the micropores ( < 10 ms) is rarely produced. However, for the subsequent cycles, the oil production in macro pores and medium pores decreases while that in small pores and micropores increases. Thus, the small pores and micropores become the main oil producing areas.",22,25,1
Oil Recovery,CO2 Huff-n-puff,"Peng, Xiyi; Wang, Yanyong; Diao, Yuqian; Zhang, Liang; Yazid, Iddi M.; Ren, Shaoran",Experimental investigation on the operation parameters of carbon dioxide huff-n-puff process in ultra low permeability oil reservoirs,Low permeability oil reservoirs; CO2 huff-n-puff; Enhanced oil recovery; Oil swelling; CO2 injection,CYCLIC STEAM STIMULATION; CO2 INJECTION PROCESS; TIGHT OIL; ASPHALTENE PRECIPITATION; PERFORMANCE EVALUATION; RECOVERY PERFORMANCE; ENERGY EFFICIENCY; MOBILITY CONTROL; SIMULATION; STORAGE,"For oil reservoirs featured with ultra low permeability, CO2 huff-n-puff can be a promising approach for enhanced oil recovery. To understand its production performance and the effects of different factors in field operation, a series of CO2 huff-n-puff experiments under various conditions were conducted using a 1D sandpack model, and the extraction effect of CO2 and its influence on oil production have been analyzed. The experimental results show that, as cyclic CO2 injection quantity increases, the cyclic oil recovery factor is improved, but the CO2 utilization factor is reduced, and there will be an optimum cyclic injection quantity from economic point of view. Both cyclic oil recovery factor and CO2 utilization factor are improved with the increasing reservoir temperature, while injection of low temperature CO2 may impose an adverse influence on oil recovery performance. In addition, the cyclic oil recovery factor and CO2 utilization factor firstly rise and then fall with the increasing soaking period. The results presented in this study are expected to provide some guidance to the field implementation of CO2 huff-n-puff technique in ultra low permeability oil reservoirs.",16,17,7
Oil Recovery,CO2 Huff-n-puff,"Ding, Mingchen; Gao, Miao; Wang, Yefei; Qu, Zhengtian; Chen, Xu","Experimental study on CO2-EOR in fractured reservoirs: Influence of fracture density, miscibility and production scheme",Fractured reservoirs; Fracture density; Miscibility; CO2 flooding; Recovery mechanism; CO2 huff-n-puff,HUFF-N-PUFF; BYPASSED-OIL-RECOVERY; MISCIBLE CO2; CARBON-DIOXIDE; INJECTION; SHALE; WATER; MATRIX; PERMEABILITY; DIFFUSION,"The effects of fracture density, miscibility and production scheme on CO2 enhanced oil recovery (EOR) in fractured reservoirs were investigated. A series of CO2 injection experiments were performed in various lengths of core plugs at both fractured and unfractured condition. Results demonstrate that although presence of fractures dramatically reduces the effectiveness of CO2 flooding, increasing fracture density clearly benefits its recovery potential. The oil recovery mechanism is mainly recognized to be oil swelling at the beginning of CO2 continuous injection and gradually turns to extraction of lighter hydrocarbons (C-5-C-30) with increased injection time. First-contact miscible flooding is more effective than both multi-contact miscible and immiscible flooding and proves its feasibility when fracture density exceeded 5.0 fractures per meter, with the maximum recovery up to 68.1% of original oil in place (OOIP). CO2 huff-n-puff is very powerful in recovering the residual oil after CO2 flooding. Fracture density has no major effect on huff-n-puff performance while at lower fracture-density condition, more cycles are required to reach the ultimate oil recovery. Multi-contact miscible CO2 huff-n-puff has the greatest potential of EOR ability in fractured reservoirs, which can increase the oil recovery to 86.2% OOIP on the basis of CO2 flooding test.",15,15,5
Oil Recovery,Clay Swelling,"Yang, Yongfei; Li, Yingwen; Yao, Jun; Zhang, Kai; Iglauer, Stefan; Luquot, Linda; Wang, Zengbao",Formation damage evaluation of a sandstone reservoir via pore-scale X-ray computed tomography analysis,X-ray computed tomography; In-situ imaging; Permeability change; Fines migration; Clay swelling; Formation damage,FINES MIGRATION; MULTIPHASE FLOW; OIL-RECOVERY; RELATIVE PERMEABILITY; SALINITY; WETTABILITY; ROCKS; MICROTOMOGRAPHY; SENSITIVITY; SATURATION,"The incompatibility between workover fluid and reservoir rock is one of the causes of formation damage. Fines migration and clay swelling are considered as the major mechanisms responsible for formation damage, which results in declining productivity. However, there has been limited visualized evidence of pore structural changes during formation damage. This paper establishes a formation damage evaluation method for sandstone reservoirs based on X-ray micro-computed tomography (CT) analysis. We presented conclusive evidence for clay swelling and fines migration during workover fluid flooding and formation liquid flooding. Water sensitivity and flow rate sensitivity tests were performed on a Dongying sandstone (heterogeneous argillaceous sandstone) plug. In addition, the plug was micro-CT imaged before and after flooding with workover fluid and formation liquid at medium resolution (24 mu m voxel size); the changes in core permeability and the associated changes in 2D and 3D pore space were analyzed. We found that the sandstone pore space was partially blocked by clay minerals and moving particles, leading to significantly decreased porosity (5.17%-4.19% for sample 1, 5.38%-2.76% for sample 2) and permeability (3.38 x 10(-3) mu m(2) to 1.28 x 10(-3) mu m(2) for sample 1, 13.30 x 10(-3) mu m(2) to 3.15 x 10(-3) mu m(2) for sample 2). This permeability decrease was caused by a decrease in the average pore radius and coordination number. Moreover, increased micro-CT intensity was measured by comparison of initial and final tomogram images, representing clay swelling & blockage of pores during the displacement and a generally lower porosity. This work visualized microscale formation damage, which reminds that incompatibility between workover fluid and reservoir rock damages formation seriously and the fluid injection rate should be lower than the critical flow rate when developing a reservoir with a strong water sensitivity and flow rate sensitivity.",35,35,1
Oil Recovery,Clay Swelling,"Ghasemi, Mehdi; Moslemizadeh, Aghil; Shahbazi, Khalil; Mohammadzadeh, Omid; Zendehboudi, Sohrab; Jafari, Sina",Primary evaluation of a natural surfactant for inhibiting clay swelling,Ginsenosides; Biosurfactant; Clay swelling inhibitor; Wettability; Compatibility,WELLBORE STABILITY; SHALE HYDRATION; REDUCING ADSORPTION; ANIONIC SURFACTANT; MODIFIED BENTONITE; IONIC LIQUID; WATER; GINSENG; COPOLYMER; MONTMORILLONITE,"Water-based drilling muds, a more environment-friendly candidate than oil-based drilling muds, are wildly used for drilling oil and gas wells. When water-based drilling mud is used for drilling formations with shale containing active clay constituents, it is challenging to preserve stability of the borehole due to clay swelling unless proper inhibition mechanisms are foreseen. In the current study, the feasibility of using Korean red Ginseng root extract was assessed as a clay swelling inhibitor. This root extract is rich in non-ionic surfactants such as Ginsenosides Rg3, Rg5, and RK1, and is referred to as ""biosurfactant"" throughout this manuscript. After preparation of mud systems containing problematic clay particles, the clay-swelling inhibition performance of the biosurfactant was systematically investigated through a series of tests, including mud formation, filtration, immersion, sedimentation assisted with optical microscopy, wettability by sessile drop technique, use of thermal gravimetric analysis (TGA), scanning electron microscopy (SEM) and Fourier-transform infrared spectroscopy (FTIR), and shale cuttings recovery. The clay-swelling inhibition performance of the biosurfactant was then compared against two clay swelling inhibitors namely CTAB (Cetrimonium bromide, a known cationic surfactant) and potassium chloride. There are some properties associated with the mud systems prepared with biosurfactant solution which makes this product unique. These properties include: remarkable loading capacity of sodium montmorillonite (Mt) which in turn resulted in low rheological profile, poor fluid loss control, creation of stable Mt pellets, creation of larger size and aggregated Mt particles with less hydrophilicity, creation of fully unstable dispersed Mt particles that resulted in good sedimentation over time, less mass loss, and higher shale cuttings recovery, all compared to the baseline fluid made without the presence of biosurfactant. The results of this study indicate that the biosurfactant provides excellent clay swelling inhibition properties, comparable to known inhibitors. The biosurfactant's compatibility with other drilling mud components was also checked, and it was found that the fluid properties are independent of the biosurfactant. The wettability and FTIR analyses were also performed to investigate the mechanisms involved in clay swelling inhibition of the biosurfactant, which are believed to be as a result of coating the clay active surfaces with a hydrophobic layer, hence repelling the water phase. This hydrophobic layer is probably formed by interactions of the hydrophilic group of the Ginsenosides and the oxygen atoms available on the Mt surfaces, when the hydrophobic tail is oriented toward the aqueous phase.",30,30,0
Oil Recovery,Clay Swelling,"Fu, Lipei; Liao, Kaili; Ge, Jijiang; Zhang, Guicai; He, Yanfeng; Wang, Xiang; Zhang, Shifeng; Deng, Song",Study of ethylenediammonium dichloride as a clay stabilizer used in the fracturing fluid,Clay stabilizer; Ethylenediammonium dichloride; Inhibition mechanism; Clay hydration; Fracturing fluid,OIL-RECOVERY; SHALE; NANOTECHNOLOGY; NANOPARTICLES; POLYMER,"Clay stabilizer is the topic of a great number of studies, particularly in petroleum engineering. The organic cationic polymer is a kind of clay stabilizer with excellent anti-swelling effect. However, for tight reservoirs, the organic cationic polymer type clay stabilizers tend to increase the permeability damage caused by retention and blockage of stabilizers. Therefore, stabilizers with low molecular weight are necessary for tight reservoirs. The inhibition properties and the mechanisms of ethylenediammonium dichloride (EDD) were studied in this paper. The clay inhibition properties were studied from three aspects: swelling inhibition, clay sedimentation, and particle size distribution. Results showed that the anti-swelling rate reaches 91.98%. Control experiments showed that EDD had better inhibition property than KCl, NH4Cl, and poly dimethyldiallyl ammonium chloride (PDMDAAC). The inhibition mechanisms, studied from the aspect of surface hydrophobicity, surface charge, interlayer water content, and crystal spacing, can be concluded as that EDD reduces clay electronegativity and enhances the hydrophobicity of the clay surface, thereby keeping clay in a stable state. Compatibility tests showed that EDD can be used in guar based fracturing fluid. This study provides an alternative clay stabilizer for hydraulic fracturing.",14,16,9
Oil Recovery,Clay Swelling,"Sharifipour, M.; Nakhaee, A.; Pourafshary, P.",Model development of permeability impairment due to clay swelling in porous media using micromodels,LSW flooding; Clay swelling; Permeability impairment; Micromodel; Image processing,OIL-RECOVERY FACTOR; CAPILLARY-PRESSURE; WATER; GAS; MONTMORILLONITE; WETTABILITY; SURFACE,"Swelling and displacement of clay minerals during drilling and production of oil and gas reservoirs are among the main mechanisms of formation damage. Most reservoirs contain clay minerals, either originally deposited during sedimentation phase, or precipitated from fluids flowing through matrix. Owing to the large specific surface area of clay particles, their swelling, detachment, and migrationmay lead to permeability impairment in porous media. Therefore, an accurate interpretation of the behaviour of clay particles in the porous media may enable us to prevent and possibly reverse the respective damage mechanisms. In this work, the pore-scale swelling behaviour of clays are studied using glass micro models as porous medium and Sodium bentonite as swelling clay. By image processing technique, effective porosity of model during low salinity water (LSW) flooding are estimated. The effect of different parameters such as porous medium aspect ratio and clay concentration on permeability impairment is studied. According to this study, besides higher clay concentrations, the permeability is also affected adversely by larger aspect ratio of pore bodies. Based on our experiments, a model is developed to estimate permeability impairment by clay swelling as a function of pore geometry and clay concentration.",14,14,2
Oil Recovery,Well Placement,"Janiga, Damian; Czarnota, Robert; Stopa, Jerzy; Wojnarowski, Pawel",Self-adapt reservoir clusterization method to enhance robustness of well placement optimization,Kohonen network; Well placement optimization; Genetic algorithm; Particle swarm optimization,PARTICLE SWARM OPTIMIZATION; OIL-RECOVERY; ALGORITHM; EOR; CONVERGENCE; TEMPERATURE; SIMULATION; INJECTION; PROTOTYPE; SEARCH,"One of the most crucial tasks in hydrocarbon field development, it is an optimal wells placement Simulation-based well placement optimization can be intricate to implement or computationally expensive. In this paper, a novel approach for the reduction of computational challenges by combining population-base optimization algorithm with self-adapt reservoir clusterization method to determine initial well placement position for the similar producing zones is presented. The developed methodology supported initial well placement location and allowed to shrink search space area. As a result, the computational time was decreased by 18% for particle swarm optimization and by 21% for genetic algorithm. Additionally, the project profitability was increased by 0.24% in case of genetic algorithm utilization and 0.59% for particle swarm optimization, what confirms the necessity for precise well placement localization. The average convergence factor for the employed algorithms increased from 18.43% to 60.78% for genetic algorithm and from 41.71% to 46.96% for particle swarm algorithm. An additional advantage of the developed clustering method is a notable reduction in time to reach high solution diversity in particle swarm algorithm. Increasing SOM training time for the large data set is negligible in comparison with full reservoir simulation run. The proposed methodology is based on the typical numerical model without requirement of additional dataset or streamline and can be easily transferred from field to field. The power and the workflow utility are demonstrated by the results of significant improvement for the algorithm's convergence rate and time.",24,24,1
Oil Recovery,Well Placement,"Ado, Muhammad Rabiu; Greaves, Malcolm; Rigby, Sean P.",Numerical simulation of the impact of geological heterogeneity on performance and safety of THAI heavy oil production process,Bitumen; Shale inter-layer; Heterogeneity; Cap-rock; Thief-zone; THAI,ORIENTATION; RECOVERY,"The Toe-to-Heel Air Injection (THAI) in-situ combustion process is an efficient way to extract heavy oil and bitumen. However, such reservoirs are often geologically heterogeneous. This work studied the impact of a range of different geological heterogeneities, often found in bitumen deposits, on the performance and safety of THAI. These heterogeneities included random heterogeneity, layered reservoirs, shaly reservoirs, and semi-permeable cap-rocks. A further aim was to also develop potential remedial measures, such as selective well placement It was found that the degree of symmetry assumed for the reservoir model had a substantial impact on the predicted level of oil production. This is of particular relevance to otherwise apparently symmetrical well placement designs such as staggered line drive. While the presence of impermeable zones resulted in the decrease in the overall oxygen utilisation for shaly reservoirs, compared to simply low permeability reservoirs, there was no evidence of oxygen breakthrough due to preferential channelling into the production well. In layered reservoirs, the development of a rich oil bank during THAI operation depended upon the distribution of permeability around the horizontal producer (HP), and did not occur when there was high permeability just above the HP. It has been shown that the proper representation of the cap-rock in reservoir models for the simulation of THAI is essential in order to accurately mimic the full pattern of heat distribution into the oil zone of the reservoir, and, thence, fuel lay-down. While THAI can operate stably with a permeable cap-rock, vertical permeabilities above similar to 1-3 mD led to significant loss of combustion gases from the reservoir.",20,20,0
Oil Recovery,Well Placement,"Hutahaean, Junko; Demyanov, Vasily; Christie, Mike",Reservoir development optimization under uncertainty for infill well placement in brownfield redevelopment,Reservoir development optimization under uncertainty; Multi-objective optimization; Model selection; History matching; Posterior approximation; Economic risk evaluation,PARTICLE SWARM OPTIMIZATION; ALGORITHM,"In an uncertain oil price environment, brownfield redevelopment is becoming an increasingly attractive option to manage production decline. One of the essential strategies in brownfield redevelopment is optimally placing the infill well to maximize recovery from the field and minimize operational expenditure. Optimal decisions are the ones that maximize the recovery and keep the cost down. Robust optimal decisions are the ones that would hold in the presence of geological uncertainty, such as when the realization of reservoir setting deviates from the base case. The decision optimized for the base case would still be optimal for the updated reservoir condition. Hence, optimization across multiple realizations is required. While attempts on the optimization across multiple realizations have been conducted in the literature, the computational cost involved in performing the task and resulting in the proper estimation of uncertainty remains a great challenge. This paper introduces a new workflow for robust and reliable well placement optimization under geological uncertainty. The proposed workflow combines multi-objective assisted history matching, Bayesian posterior inference, and well placement optimization in multi-objective setting across multiple geological models. It is applied to an industry-standard reservoir benchmark case study and compared with several uncertainty quantification approaches conventionally used for decision making. The proposed workflow provides robust and reliable optimal decisions in placing the infill well over multiple history match models. The workflow results in a good estimation of uncertainty in respect of the optimized decision. Increase in the number of flow simulations due to the optimization over the multiple realizations to cover the geological uncertainty is reduced to a manageable size.",16,16,1
Oil Recovery,Salinity Gradient,"Aldousary, Salem; Kovscek, Anthony R.",The diffusion of water through oil contributes to spontaneous emulsification during low salinity waterflooding,Waterflooding; Microfluidics; Low salinity; Emulsion; Spontaneous,BRINE COMPOSITION; CRUDE-OIL; RECOVERY; MECHANISMS; EOR,"Increases in oil recovery due to Low Salinity Waterfloods (LSW) have been widely investigated. Literature is abundant with studies attempting to pinpoint the relevant mechanisms involved in the LSW process. Recently, there was clear evidence of spontaneous formation of emulsions during LSW under certain conditions. This work examines the diffusion of water through oil as a contributing factor for spontaneous emulsification during LSW. Experimental observations are pore scale using etched-silicon micromodels. Observations are accompanied by pore-scale mass transfer calculations. Spontaneous emulsification is observed as a result of so-called ""low salinity water"" and crude oil phases contacting under non-equilibrium conditions. The experimental observations provide clear evidence that physical contact between oil and low salinity water phases is imperative for emulsification. In addition, it is concluded that a larger salinity gradient results in greater emulsion concentrations. In such cases, the crude oil is preequilibrated through exposure to a formation brine that has substantial salinity and divalent cations. Emulsification results as the oil phase comes into equilibrium with a brine of lower salinity and different composition. A key mechanism is the osmotic pressure imbalance between water and oil phases that drives water into the oil phase by diffusion. Water reaches a supersaturated state and spontaneous nucleation of the water phase results in emulsions, under appropriate conditions. The experimental and numerical modeling schemes presented here demonstrate and quantify time scales of water-in-oil emulsion formation.",25,25,2
Oil Recovery,Salinity Gradient,"Riswati, Shabrina S.; Bae, Wisup; Park, Changhyup; Permadi, Asep K.; Efriza, Ivan; Min, Byungun",Experimental analysis to design optimum phase type and salinity gradient of Alkaline Surfactant Polymer flooding at low saline reservoir,Salinity gradient; ASP flooding; Low salinity; Phase behavior; Core flooding,ULTRALOW INTERFACIAL-TENSION; ENHANCED OIL-RECOVERY; SCREENING CRITERIA; 3-PHASE BEHAVIOR; SOLUBILIZATION; FORMULATION; ATTAIN,"This paper presents the experimental analysis to find the optimum alkaline-surfactant-polymer (ASP) formula and the effects of salinity gradient suitable for oil reservoirs with low salinity formation water. It has been challenging to obtain high oil recovery when the reservoir salinity is lower than the injection salinity of ASP formulation. This paper carried out phase behavior tests for 28 experiments with 22 kinds of surfactant and subsequent coreflooding for the optimum formula with pre-designed salinity gradient profiling for pre-flush, ASP slug, and polymer drive. The optimum ASP formula from the phase behavior study, i.e., 0.5 wt% Linear alkyl-benzene sulfonate (LAS), 2 wt% Diethylene glycol butyl ether (DGBE), and 1 wt% Na2CO3, results in the optimum salinity of 2.8 wt% NaCl with 10 cc/cc solubilization ratio, and the middle phase type III microemulsion occurs in the range of 2.5-3.4 wt% NaCl. The oil recovery implementing this formula and negative salinity gradient, i.e. Winsor type II-III-I for coreflooding experiments are about 75.8% which is better than the other salinity gradients such as Winsor type I-II-I and I-III-I Excluding high saline pre-flush, the salinity gradient consisted of Winsor type I-II-I and Winsor type I-III-I are able to recover the desirable amount of oil. The results could be applicable on designing the optimal ASP flooding at low salinity formation considering the formulation of surfactants and co-solvents, and the effects of salinity gradients.",19,19,0
Drilling Fluid,Reservoir,"Zhao, Xin; Qiu, Zhengsong; Sun, Baojiang; Liu, Shujie; Xing, Xijin; Wang, Mingliang",Formation damage mechanisms associated with drilling and completion fluids for deepwater reservoirs,Formation damage; Deepwater reservoir; Drilling and completion fluids; Sensitivity damage; Invasion of solid and filtrate; Rock-fluid incompatibilities,INVASION; FILTRATE; QUALITY; SHALE; MODEL; BASIN,"Immense oil and gas reserves exist in the deepwater of the South China Sea, and the first priority for implementing successful drilling and completion operations without reservoir damage is to understand the damaging mechanisms to the reservoir formation. With the use of deepwater reservoir cores from the western South China Sea, the mineral composition, microstructure, porosity, and permeability characteristics of the reservoir formation were analyzed. With the use of core flow tests, potential fluid sensitivity was analyzed to determine how and which fluids can damage the reservoir formation during drilling and completion. The results show that the reservoir formation is composed of unconsolidated siltstone with a clay mineral content of 6-19%, and has high porosity and permeability with large pore throats. Sensitivity damage due to the increasing flow rate is strong, and an unusual salinity sensitivity exists with a critical salinity at 40,000-45,000 mg/L. Moderate alkali fluids sensitivity damage exists, with water sensitivity being weak. The main mechanisms of formation damage by drilling and completion fluids were analyzed as following: plugging of pore throats by solid invasion occurs because the sizes of the solid materials in the drilling fluids are just ideal for the formation of an external filter. Rock-fluid incompatibilities occur due to the increasing flow rate and salinity of the fluids because the formation rock is unconsolidated and the fines will easily detach and migrate, plugging the pore throats. Therefore, effective temporary plugging of the pore throats with a large diameter is important for protecting the reservoir. This study provides basic data for the design and implementation of reservoir protection measures in deepwater oil and gas exploration.",73,75,6
Drilling Fluid,Reservoir,"Dong, Bingqiang; Meng, Meng; Qiu, Zhengsong; Lu, Zhaohui; Zhang, Ye; Zhong, Hanyi",Formation damage prevention using microemulsion in tight sandstone gas reservoir,Damage mechanism; Water blocking; Sensitivity damages; Protective drilling fluid,STRESS SENSITIVITY; LOW-PERMEABILITY; DRILLING-FLUID; OIL; REMOVAL; MODEL; SAND; FLOW,"Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production.",43,45,1
Drilling Fluid,Reservoir,"Aramendiz, Jose; Imqam, Abdulmohsin",Water-based drilling fluid formulation using silica and graphene nanoparticles for unconventional shale applications,,DESIGN; MUD,"The development of unconventional shales started a new era in the oil and gas industry. These reservoirs represent a challenge to conventional drilling fluids since the fluid invasion, cutting dispersion, or shale swelling can lead to wellbore instability problems. Although oil-based drilling fluids (OBM) are capable to control these issues, environmental and economic concerns limit its application. Recently, nanoparticles (NPs) have introduced a new perspective in drilling fluid technology, offering a unique alternative to improve the performance of water-based drilling fluids (WBM) for shale applications. This research evaluates the potential of using silica nanoparticles (SiO2-NPs) and graphene nanoplatelets (GNPs) to formulate a nanoparticle water-based drilling fluid (NP-WBM). The study considers a bottom-up approach, selecting the NPs based on the Woodford Shale's characterization and focuses its primary objective in finding the most suitable NP combination to enhance the rheological, filtration and inhibition properties of the customized NP-WBM. The shale characterization included X-ray diffraction (XRD), cation exchange capacity (CEC), and scanning electron microscopy (SEM). The zeta-potential technique was used to assess the stability of the NPs. The NP-WBM was evaluated by means of API filtration test (LTLP), high-temperature/high-pressure (HTHP) filtration test and rheological measurements using a conventional viscometer. Finally, the inhibition capability of the NP-WBM was tested against the Woodford shale through immersion and cutting dispersion tests. NPs' characterization revealed that both additives can provide stable suspensions with zeta-potential values < - 30 mV. A total NP concentration of 0.75 wt% (0.5 wt% of SiO2-NPs and 0.25 wt% of GNPs) yielded to the maximum reduction in filtrate volume at both, LTLP and HTHP conditions. The less permeable filter cake resulted in no spurt-losses, supporting the NPs' plugging effect. A strong cross-linked network created between the NPs and the conventional additives increased the cutting carrying capacity of the NP-WBM with slight effects on its plastic viscosity (PV). The immersion test carried out in water revealed that illitic shales might experience micro-fractures along the bedding planes in the absence of bridging materials. Contrarily, the NP-WBM provided an adequate plugging network between grain boundaries, resulting in no micro-fractures, and the reduction of the cutting erosion by 35.61%. Overall, this study highlights the capability of nanomaterials to extend the reliability of WBM to harsher environments while seeking an eco-friendlier alternative.",38,38,3
Drilling Fluid,Reservoir,Zhang Lufeng; Zhou Fujian; Zhang Shicheng; Li Zhu; Wang Ji; Wang Yuechun,Evaluation of permeability damage caused by drilling and fracturing fluids in tight low permeability sandstone reservoirs,Permeability damage; Pressure transmission test; Fracturing fluids; Drilling fluids; Tight sandstone reservoir,PULSE-DECAY METHOD; TRANSIENT LABORATORY METHOD; HYDRAULIC-PROPERTIES; GAS-PERMEABILITY; MECHANISM; METHODOLOGY; PERFORMANCE; RELAXATION; ROCKS; FLOW,"Tight sandstone reservoirs with low porosity and permeability are always vulnerable to damage due to drilling and fracturing fluids, which significantly impedes hydrocarbon production. Therefore, exploring damage evaluation methods has been an undeniable demand of formation protection and efficient development. However, the common steady-state core flow method is time-consuming and inaccurate for evaluating permeability damage in tight low permeability reservoirs. Aiming at this problem, this paper introduced pressure transmission test (PIT), a time-saving and accurate method, to quantitatively evaluate the core permeability damage degree from macroscopic perspective. Furthermore, nuclear magnetic resonance (NMR) was also used to analyze the damage mechanisms of fracturing fluids from microscopic perspective. In the fracturing fluids damage experiments, the results of PTT show that the ultimate damage degree of fracturing fluids is approximately 40%, of which water-sensitivity, water-block, and solid-phase are approximately 10%, 12% and 16%, respectively. With the technique of NMR, the damage mechanisms due to fracturing fluids are also investigated. In the drilling and fracturing fluids damage experiments, the results of PIT show that the drilling fluids cause the major damage. In the experiments of acidizing treatment, the chelating acid shows excellent properties in reliving core permeability damage caused by drilling and fracturing fluids. This study provides a new idea for evaluating permeability damage in low permeability reservoirs, such as shale, tight sandstone reservoirs, bedrock reservoirs, and so on.",37,38,12
Drilling Fluid,Reservoir,"Wang, Shuhua; Chen, Zan; Chen, Shengnan",Applicability of deep neural networks on production forecasting in Bakken shale reservoirs,Production forecasting; Bakken formation; Deep neural networks; Hyperparameter optimization; Global sensitivity analysis,NEWTON OPTIMIZATION METHOD; TIGHT-OIL; GAS-PRODUCTION; MODEL; PREDICTION; DESIGN; STEAM,"The unconventional shale and tight formations, such as the Bakken in Williston Basin, are becoming an important hydrocarbon sources since the development of advanced horizontal drilling and multi-stage stimulation techniques. The appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery. Although reservoir simulations are commonly used for production analysis, the modeling of hydraulic fractures and intrinsic complexity of shale have restricted an understanding of the fluid flow behavior. Owing to the available of a large amount of data in unconventional tight and shale reservoirs, data-driven approaches, such as deep neural networks (DNNs), provide an alternative approach for production analysis in these formations. In this study, a total of 2919 wells including 2780 multi-stage hydraulic fractured horizontal wells and 139 vertical wells in Bakken Formation were collected and analyzed using a deep learning method and Sobol's global sensitivity analysis. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, and batch normalization were evaluated to develop a reliable deep neural network model. Moreover, k -fold cross validation was used to evaluate the prediction ability and robustness of models. Prior to the performance evaluation of DNN algorithms, an optimum DNN model was achieved by optimizing the dropout layer, activation function, and hyperparameters of DNN models. It is found that the number of hidden layers and neurons in each layer have significant effects on the performance of models. The optimized DNN model has 3 hidden layers and 200 neurons for each layer. The prediction performance of DNN models is acceptable with the low mean squared errors for both 6- and 18-months cumulative oil productions. Furthermore, the importance of each parameter was studied using the Sobol's analysis. Results show that the average proppant placed per stage is the most important parameter, which accounts for more than 35% of variability in both 6- and 18-months cumulative oil productions. These data-driven models can be readily updated when the new well information becomes available. It is worth mentioning that the proposed DNN models can be directly integrated into existing hydraulic fracturing design routines.",35,37,5
Drilling Fluid,Reservoir,"Zhang, Dujie; Kang, Yili; Selvadurai, A. P. S.; You, Lijun; Tian, Jian",The role of phase trapping on permeability reduction in an ultra-deep tight sandstone gas reservoirs,Ultra-deep tight gas reservoirs; Phase trapping damage; Drill-in fluids; Invasion depth; Permeability damage ratio; Numerical simulation model,MERCURY INTRUSION POROSIMETRY; PORE-SIZE DISTRIBUTIONS; SPONTANEOUS IMBIBITION; RELATIVE PERMEABILITY; WATER IMBIBITION; TARIM BASIN; PRESSURE; HYSTERESIS; ADSORPTION; IMPACT,"As the first external liquids that are introduced into a reservoir rock, suitable drill-in fluids not only prevent phase trapping-induced permeability reduction (also referred to as phase trapping damage) caused by the drill-in fluid itself but also minimize any phase trapping damage caused by the invasion of subsequent working fluids. An ultra-deep tight sandstone reservoir in the Tarim Basin, NW China is considered as a case study, and this paper presents the results of an extensive series of phase trapping damage investigations that were carried out to determine the permeability reduction in the reservoir rock that comes into contact with different working fluids during the processes of drilling, drill stem tests, completion and well tests. Both the pore microstructure and surface properties were also investigated. The experimental results showed that the integrated phase trapping damage ratio (PDR) of water-based drill-in fluids (WBDF)-organic salt completion fluids (PDR = 0.99) was greater than that of oil-based drill-in fluids (OBDF)-organic salt completion fluids (PDR = 0.88). The analysis suggests that the OBDF is more effectively in inhibiting the absorption of the filtrate of the completion fluids compared with WBDF. A procedure for reducing phase trapping damage by OBDF is presented, and a numerical simulation model is developed to validate the procedure. The results could be useful in understanding and selecting the best drill-in fluids and completion fluids to minimize phase trapping damage in ultra-deep tight gas reservoirs.",18,20,1
Drilling Fluid,Reservoir,"Khanal, Aadi; Weijermars, Ruud",Pressure depletion and drained rock volume near hydraulically fractured parent and child wells,Depth of investigation; Drained rock volume; Well interference; Eagle ford; Complex analysis methods; Velocity plots,FLOOD DISPLACEMENT FRONTS; EAGLE FORD SHALE; INTERFERENCE; RESERVOIRS; HISTORY; MULTIWELL; TEXAS; OIL,"Field development of unconventional reservoirs tends to downsize well spacing when commercial success of a shale play is proven. The earlier, so-called parent wells are joined by infill wells, commonly called child wells. Tighter well spacing improves the recovery factor but the risk of well interference increases. The flow interference and pressure communication of adjoining wells via the matrix and their hydraulic fractures was investigated using the depth of investigation and associated pressure depletion plots. A sensitivity analysis shows how the depth of investigation in an unconventional reservoir is impacted by matrix permeability, other fluid properties, and time lapse between drilling of parent and child wells. In all cases, the extent of the drained region of a reservoir with hydraulic fractures is controlled by the fluid particle paths guided by the depth of investigation and time-of-flight contours. Time-of-flight contours visualize the reservoir drainage by parent and child wells using complex analysis methods (CAM) in a case study of the Eagle Ford shale. Even after 30 years of production, the actual drained rock volume (DRV) remains small and lags the depth of investigation. A commercial numerical reservoir simulator provides history matched inputs for the CAM tool which then can model the flow near the discrete fractures in the reservoir at high resolution. The developed procedure provides a computationally efficient method to quantify and visualize the DRV for parent and child wells in hydraulically fractured reservoirs. Fluid particle tracking provides a practical method to determine fracture and well-interference in combination with depth of investigation and pressure depletion studies.",18,18,0
Drilling Fluid,Reservoir,"Lyu, Shuaifeng; Wang, Shengwei; Chen, Xiaojun; Shah, S. M.; Li, Rui; Xiao, Yuhang; Dong, Qingxiang; Gu, Yuanyuan",Experimental study of a degradable polymer drilling fluid system for coalbed methane well,Degradable polymer drilling fluid; Bio-enzymes; Permeability recovery; Polymer removal; Coal cuttings carrying; South Qinshui Basin,WATER; NANOPARTICLES; PERFORMANCE; PRESSURE; BENTONITE; SEAM,"Drilling along the coal seam is an effective way to improve gas recovery. Due to complex coal body structure and natural fractures, there are many difficulties, including a low abilities of cutting carrying, leakage while crossing the fracture zone and reservoir damage. In this work, a low density degradable polymer drilling fluid system is developed to solve these difficulties to enhance coalbed methane (CBM) production. In the laboratory, the properties of the polymer drilling fluid were evaluated using the coal cuttings suspension experiment, borehole stability simulation test, viscosity attenuation method, laser particle size analysis, polymer removal and core permeability recovery method. The experimental result indicates that the developed drilling fluid has good rheology and filtration, a high yield point and a strong inhibition, thereby meeting conventional drilling requirements and carrying coal cuttings effectively. Under the bio-enzymes, the viscosity of degradable drilling fluid can be initially reduced to 16%. The optimum temperature and pH for the enzyme activity is obtained, and enzymes with small weight fraction of 0.01% can dramatically alter rheological properties of drilling fluid and thereby the high biological activity. After degradation, the particle size in drilling fluid decreases greatly. During immersion test, the polymer film on the surface of the lump coal and thin sections is almost removed by enzyme solution. The reservoir's permeability damage rate may be reduced from 50% to 25% via the functionality of the enzymes, and it is noticeable that the relationships between effective stress and gas permeability treated by the drilling fluid and enzyme still obey the exponential function. Field applications show that the drilling fluid has a good coal fines resistance and compatibility with conventional plugging materials, which ensures the long horizontal footage of 901 m with the short construction period. The later decreased viscosity of the drilling fluid by the enzymes is conducive to reduce the damage to the coal reservoirs.",16,16,7
Drilling Fluid,Reservoir,"Yu, Fuwei; Jiang, Hanqiao; Xu, Fei; Zhen, Fan; Wang, Jitao; Cheng, Baoyang; Su, Hang; Li, Junjian",A multi-scale experimental study of hydrophobically-modified polyacrylamide flood and surfactant-polymer flood on enhanced heavy oil recovery,Heavy oil; Surfactant-polymer flood; Hydrophobically-modified polyacrylamide flood; Multi-scale experiments,IN-WATER EMULSIONS; INTERFACIAL-TENSION; CONFORMANCE CONTROL; POROUS-MEDIA; PORE-SCALE; INJECTION; SALINITY; RESERVOIR; METHODOLOGY; IMBIBITION,"A large amount of residual oil remained in heavy oil reservoirs after water flood due to its viscosity nature. And it has been validated that chemical flood, if applied appropriately, is an efficient and economical EOR method for deeply buried or thin heavy oil reservoirs. A multi-scale experimental evaluation workflow was designed to explore the mechanisms behind the production of residual oil in heavy oil reservoirs by chemical flood. And we conducted three multi-scale experiments to evaluate the performance of hydrophobically-modified polyacrylamide (HMHPAM) flood, surfactant-polymer (SP) flood and their combination. Based on the results of corefloods and medical CT scans, we demonstrated the EOR potential of HMHPAM flood (HPF) synergy with SP flood (SPF). After each coreflood, two samples were drilled from the heterogenous core used in the macro-scale experiment. And the micro-CT scan results of these samples visualized the distribution of oil phase and aqueous phase in each coreflood at the pore scale, and further quantified the decrease of continuous oil clusters caused by the HMHPAM solution and following injected fluids. Besides, we also observed the linear relationship between the volume of each oil cluster against its surface area and the logarithmic relationship between the volume of discontinuous oil cluster and its cumulative contribution to total oil volume. Moreover, a simple method to calculate the oil-water proportion in pores was developed to correlate the relationship between the displacement efficiency of each pore and its pore size. Results showed that the relationship between oil saturation in each pore and its pore size followed the power law correlation. Moreover, the pore-scale analysis also validated that the residual oil in most pores after water flood was effectively mobilized by the synergy of HPF and SPF.",15,18,5
Drilling Fluid,Reservoir,"Bhattacharya, Shuvajit; Ghahfarokhi, Payam Kavousi; Carr, Timothy R.; Pantaleone, Scott","Application of predictive data analytics to model daily hydrocarbon production using petrophysical, geomechanical, fiber-optic, completions, and surface data: A case study from the Marcellus Shale, North America",Marcellus Shale; Fiber optic; Data analytics; Machine learning; Predicting gas production,APPALACHIAN BASIN; LITHOFACIES,"Predicting gas production from stimulated unconventional reservoirs has always been a challenge to oil and gas companies because the physics of fluid flow through such reservoirs is not well understood. On the other hand, modeling gas production from shale reservoirs is a complex multi-variate problem that requires proper integration of data from multiple disciplines, such as geology, petrophysics, geomechanics, completions, and surface-based measurements, etc. This study demonstrates the application of data-driven machine learning algorithms, integrating geoscientific, distributed acoustic sensing (DAS), distributed temperature sensing (DTS) fiber-optic, completions, flow scanner production log, and surface data to model daily gas production from a 28-stage stimulated horizontal well drilled in the Marcellus Shale of the Appalachian basin in North America. In addition, this study aims to utilize the data from a fiber-optic monitoring system, such as DAS and DTS to evaluate the well performance. We build supervised data-driven machine learning models using Random Forest (RF), Artificial Neural Network (ANN), and Support Vector Machine (SVM) algorithms to understand the well performance and forecast the daily gas production. The study compares the forecasted results, tests the level of accuracy, and addresses different issues with these machine learning algorithms. A spatio-temporal database is constructed and used to perform sensitivity analyses to identify the key drivers for gas production. The results show that RF and ANN algorithms can be used to predict daily gas production with significantly high accuracy; however, RF algorithm is the best predictor in terms of highest accuracy (96%), less computational time and cost. Based on sensitivity analysis, it appears that Poisson's ratio, minimum horizontal stress, DAS, casing pressure, gamma log are the most important parameters to predict gas production.",14,15,4
Drilling Fluid,Reservoir,"Sharifipour, M.; Nakhaee, A.; Pourafshary, P.",Model development of permeability impairment due to clay swelling in porous media using micromodels,LSW flooding; Clay swelling; Permeability impairment; Micromodel; Image processing,OIL-RECOVERY FACTOR; CAPILLARY-PRESSURE; WATER; GAS; MONTMORILLONITE; WETTABILITY; SURFACE,"Swelling and displacement of clay minerals during drilling and production of oil and gas reservoirs are among the main mechanisms of formation damage. Most reservoirs contain clay minerals, either originally deposited during sedimentation phase, or precipitated from fluids flowing through matrix. Owing to the large specific surface area of clay particles, their swelling, detachment, and migrationmay lead to permeability impairment in porous media. Therefore, an accurate interpretation of the behaviour of clay particles in the porous media may enable us to prevent and possibly reverse the respective damage mechanisms. In this work, the pore-scale swelling behaviour of clays are studied using glass micro models as porous medium and Sodium bentonite as swelling clay. By image processing technique, effective porosity of model during low salinity water (LSW) flooding are estimated. The effect of different parameters such as porous medium aspect ratio and clay concentration on permeability impairment is studied. According to this study, besides higher clay concentrations, the permeability is also affected adversely by larger aspect ratio of pore bodies. Based on our experiments, a model is developed to estimate permeability impairment by clay swelling as a function of pore geometry and clay concentration.",14,14,2
Drilling Fluid,Degrees C.,"Zhong, Hanyi; Shen, Guangcheng; Qiu, Zhengsong; Lin, Yongxue; Fan, Lijun; Xing, Xiaodong; Li, Jia",Minimizing the HTHP filtration loss of oil-based drilling fluid with swellable polymer microspheres,Oil-based drilling fluid; Filtration; Swellable polymer; High temperature; Microsphere,PERFORMANCE; ADDITIVES,"Filtration control of drilling fluid plays an important role in the process of well-bore construction and ensures the success of drilling operation. A swellable polymer microsphere (SPM) of methylmethacrylate (MMA), butyl acrylate (BA), and lauryl methacrylate (LMA) was synthesized with suspension polymerization. Its swelling property was characterized by oil adsorption capacity measurement. First, the effect of SPM on the filtration and rheological properties of virgin organic clay dispersion was investigated. Then the filtration and rheological properties of mineral oil-based drilling fluid in the presence of SPM were elucidated under the respective conditions of hot aging temperature, oil to water ratio and density. Furthermore, the filtration control properties between SPM and two traditional filtration loss additives including modified lignite and asphaltic additive was compared. Addition of SPM exhibited obvious influence on the viscosity of oil-based drilling fluid especially at high concentration of 3 w/v%, therefore, a concentration of lower than 1.5 w/v% was recommended. After hot aging at 200 degrees C, the oil-based drilling fluid containing 1 w/v% SPM exhibited an API filtration loss decrease of 85%, and HTHP filtration loss decrease of 79% in comparison with the base fluid. After hot rolling at 180 degrees C, the API filtration loss decreased by 2%, 24% and 53%, and the HTHP filtration loss decreased by 42%, 54% and 65% respectively when 1 w/v% asphaltic additive, modified lignite and SPM are in the presence of the base fluid. Besides decreasing the filtration loss volume under high temperatures, incorporation of SPM also improves the filter cake quality of oil-based drilling fluid. SPM is capable of adsorbing considerable base oil and become swellable. The swellable polymer microspheres with favorably deformable and compressible properties can effectively fill the voids of filter cake and reduce the permeability, which leads to low filtration loss and minimization of solids invasion.",44,44,7
Drilling Fluid,Degrees C.,"He, Cong; Ji, Liming; Su, Ao; Wu, Yuandong; Zhang, Mingzhen; Zhou, Shixin; Li, Jing; Hao, Lewei; Ma, Yu","Source-rock evaluation and depositional environment of black shales in the Triassic Yanchang Formation, southern Ordos Basin, north-central China",Source rock evaluation; Black shale; Geochemical element; Yanchang formation; Ordos basin,ORGANIC-RICH SHALE; CHANG 7 MEMBER; ELEMENT GEOCHEMISTRY; TRACE-ELEMENTS; TRANSITION; ENRICHMENT; MAGNETITE; SYSTEMS; TUFF,"A recent drilling operation in the Triassic Yanchang Formation (Tongchuan District of the Ordos Basin, north-central China) reached a black shale bed with an average in-situ gas content of 1.11 g/ml. Subsequent total organic carbon (TOC) content measurements and rock-eval analysis showed that the black shale section was generally classified as excellent source rock, with TOC contents commonly over 12% and an average genetic potential reaching 90 mg HC/g rock. The black shale samples of the Yanchang Formation contain kerogen of types I and II1, indicating the presence of oil source rocks, and the T-max values range from 438 to 442 degrees C, which indicate a maturity stage in the early oil window. To reconstruct the depositional environment of the black shales with high TOC contents, various geochemical elements and their ratios were analyzed, yielding a number of interesting results: (i) the paleoclimate indexes CIA, CIW and C-values range from 50 to 72 (mean 65), 56 to 85 (mean 75), and 0.8 to 2.6 (mean 1.5), respectively, indicating humid conditions during the sedimentation period of the black shales; (ii) the redox conditions during the sedimentation of the black shales were dysoxic to anoxic as evidenced by the cross-plot of V/Cr vs. V/(V + Ni); (iii) the water column environment was a deep, fresh-water lake, further confirming the moist paleoclimate and reducing environment; and (iv) the high TOC contents of the black shales are attributed to inputs from hydrothermal fluids as evidenced by the samples falling into or near to the hydrothermal area of the Ni/Cr vs. Ti plot and the Ti vs. V plot.",33,36,2
Drilling Fluid,Degrees C.,"Kok, Mustafa Versan; Bal, Berk",Effects of silica nanoparticles on the performance of water-based drilling fluids,Drilling fluid; Nanofluid; Silica; Nanoparticle; Fluid loss; Rheology,,"In this research, two groups of experiments were conducted to investigate the effects of silica (SiO2) nanoparticles on the filtration and rheological properties of water-based drilling fluids. In the first group, bentonite, chrome-free lignosulfonate (CFL) and carboxymethyl cellulose (CMC) were used in different concentrations to obtain base fluids. Nanofluids were prepared by adding 0.5 g of four different silica nanoparticles into these drilling fluids. Comparison of rheological properties, fluid loss amounts and mud cake thicknesses were performed at two different temperatures (25 degrees C and 49 degrees C). It was concluded that all of the nanoparticles reduced the filtration efficiency of bentonite muds. On the contrary, a reduction in fluid loss was observed for some lignosulfonate muds containing nanoparticle. However, no significant change in mud cake thickness and rheological properties was seen for both drilling fluids. Since no positive effect was observed in the first part, further investigation was done with higher bentonite and nanoparticle concentrations than previous experiments. Moreover, only bentonite was used as additive to eliminate other parameters and to see more clearly the effect of nanoparticles in bentonite mud. Samples were formulated with 7% by weight of bentonite and 0.5% and 1.5% by weight of nanoparticles. It was seen that the amount of fluid loss is directly proportional to the nanoparticle concentration. Therefore, Darcy's Law was used to compare the permeability of mud cakes and it was confirmed that nanofluids form permeable mud cakes compared to base fluid.",25,24,2
Drilling Fluid,Degrees C.,"Davoodi, Shadfar; Ramazani, Ahmad S. A.; Soleimanian, Alireza; Jahromi, Arash Fellah",Application of a novel acrylamide copolymer containing highly hydrophobic comonomer as filtration control and rheology modifier additive in water-based drilling mud,Drilling fluid; Acrylamide styrene copolymer; Starch; Filtration behavior; Rheological characteristics,FLUID-LOSS; POLYMER; NANOPARTICLES; REDUCER; SILICA,"Deep wells suffer from the instability and disintegration of natural polymers and other commonly used additives under high pressure and high temperature condition. As a result, serious problems such as hydraulic loss, stuck pipe, and high torque and drag are expected to take place which leads to a dramatic increase in cost and time. This study presents the functionality of a novel synthetic based acrylamide-styrene copolymer (SBASC) as a supersede additive for water-based drilling mud. First, the SBASC was synthesized using an emulsion polymerization process and its particle morphological and polymer chain structural properties were determined by Field Emission Scanning Electron Microscopy (FESEM) and Fourier-Transform Infrared Spectroscopy (FTIR), respectively. Then, the designated copolymer was added into a mud formulation which is applicable in oil and gas fields, and its performance in the mud was investigated with respect to filtration properties and rheological characteristics. In addition, the rheological characteristics and filtration behavior of drilling fluids containing SBASC were compared with those of a field applicable fluid that contained 9 g of HT starch which is a commercial natural polymer commonly used in drilling fluid industry. Furthermore, the thermal stability of SBASC was determined by conducting hot rolling and high pressure-high temperature (HP-HT) filtration tests. The obtained results confirmed that the addition of the copolymer enhances the rheological characteristics of the drilling fluid before and after aging at 121.1 degrees C. Moreover, the filtration behavior at both conditions was improved by introducing SBASC into the fluid, while the best performance was observed for the fluid containing 3 g of SBASC which shows 38.8% and 47.5% fluid loss reduction for HP-HT and LP-LT conditions, respectively. Furthermore, the solubility of SBASC in saline and fresh water is verified by demonstrating a promising solubility in high salinity water sample with different concentrations of a monovalent salt.",23,25,7
Drilling Fluid,Degrees C.,"Chu, Qi; Lin, Ling; Zhao, Yukun",Hyperbranched polyethylenimine modified with silane coupling agent as shale inhibitor for water-based drilling fluids,Silane coupling agent; Hyperbranched polyethylenimine; Shale inhibitor; Adsorption; Water-based drilling fluid; Application,POLYETHER DIAMINE; ADSORPTION; BENTONITE; MECHANISM; HYDRATION; AMINE; CORE,"Hyperbranched polyethylenimine modified with a silane coupling agent (Si-HPEI) as a shale inhibitor was synthesized by the Michael addition reaction of hyperbranched polyethylenimine (HPEI) and methacryloxypropyltrimethoxysilane. The structure of Si-HPEI was characterized by Fourier transform infrared spectroscopy and proton nuclear magnetic resonance. The inhibitory properties of Si-HPEI in comparison with currently available inhibitors were evaluated using linear swelling tests, cuttings dispersion tests, and bentonite inhibition tests. The inhibitory mechanism was investigated via X-ray diffraction measurements, adsorption measurements, and atomic force microscopy observations. The results indicated that Si-HPEI effectively inhibited the hydration and expansion of shale and exhibited excellent temperature resistance in comparison with HPEI and traditional shale inhibitors. The shale cuttings recovery in the case of Si-HPEI remained above 68% up to a hot rolling aging temperature of 140 degrees C, which demonstrated an excellent ability to inhibit hydration and dispersion that was significantly less affected by the hot rolling aging temperature than in the cases of other inhibitors. In addition, Si-HPEI inhibited the formation of a bentonite slurry more effectively at high temperatures. A mechanistic analysis showed that the siloxane groups present in the molecular chains of Si-HPEI caused strong and stable chemical adsorption of Si-HPEI on water-sensitive clay minerals, which thus hindered the penetration of water molecules and ultimately inhibited the hydration expansion and dispersion of water-sensitive clay minerals. In field application, Si-HPEI was successfully applied on Su 4-4HF well.",16,17,6
Drilling Fluid,Degrees C.,"Vryzas, Zisis; Nalbandian, Lori; Zaspalis, Vassilis T.; Kelessidis, Vassilios C.",How different nanoparticles affect the rheological properties of aqueous Wyoming sodium bentonite suspensions,Nanoparticles; Bentonite; Water-based drilling fluids; Nano-based drilling fluids; Rheology; Yield stress; High temperature,IRON-OXIDE NANOPARTICLES; DRILLING-FLUIDS; MAGNETIC NANOPARTICLES; HUMIC-ACID; WATER; PH; AGGREGATION; PARAMETERS; ADDITIVES; BEHAVIOR,"Clay suspensions present complex microstructures in different environments and deep understanding of such microstructures is crucial to control their flow properties. Their rheological profile is closely linked with the structural association (3-D network) of bentonite particles. Nanomaterials are considered very good candidates for smart fluids formulation which can improve the performance of conventional drilling fluids. Their incorporation in water-bentonite suspensions endow complex microstructures and hence complex rheological behavior, which is still under investigation. This study aims to explore the micro-mechanisms involved on shaping this rheological behavior with samples of 7 wt% water-sodium bentonite suspensions containing 0.5 wt % each of, commercial Fe3O4, commercial SiO2 NP and custom-made (bare or citric acid coated) Fe3O4 NP at alkaline pH. We tried to achieve this by combining macroscopic measurements (rheological measurements) with microscopic measurements (i.e. TEM). A comprehensive physico-chemical characterization of the materials and suspensions was performed using X-Ray Diffraction (XRD), X-Ray Fluorescence (XRF), N-2 adsorption-desorption isotherms and Fourier-transform infrared spectroscopy (FTIR). An effective drying process was adopted using freeze-granulation and freeze-drying (FG-FD) techniques in order to capture as accurately as possible the evolved microstructures of these aqueous bentonite suspensions at the different temperatures (25-60 degrees C). The results indicated that all samples exhibited a yield stress followed by a shear thinning behavior. The three parameter Herschel-Bulkley model provided excellent fit of the experimental data for all samples. HR-TEM images revealed that the association of the nanoparticles with bentonite particles in different configurations plays a crucial role in their rheological characteristics with the charge and the coaling of the added nanoparticles being important factors in determining the magnitude of the effects observed. We hypothesize that attractive magnetic forces between the magnetite nanoparticles may suppress the electrostatic repulsions and thus they may play a key role in promoting the observed aggregation of the nanoparticles which in turn plausibly affected their rheological profile. A thorough examination and understanding of the evolution of such complex inter-particle structures may lead towards an optimal rheology control of such suspensions in a wide range of applications.",16,16,3
Drilling Fluid,Degrees C.,"Bavoh, Cornelius B.; Yuha, Yasmine Binti Md; Tay, W. H.; Ofei, Titus Ntow; Lal, Bhajan; Mukhtar, Hilmi",Experimental and modelling of the impact of quaternary ammonium salts/ionic liquid on the rheological and hydrate inhibition properties of xanthan gum water-based muds for drilling gas hydrate-bearing rocks,Gas hydrate sediments; Rheology; Drilling mud; Quaternary ammonium salts/ionic liquid; Classical nucleation theory; Xanthan gum,DUAL FUNCTION INHIBITORS; IONIC LIQUIDS; COSMO-RS; METHANE; NUCLEATION; FLUIDS; GLYCOL,"In this study, quaternary ammonium salts (QAS) and ionic liquid (IL) were used as additives in xanthan gum water-based muds formulations to investigate their rheological and hydrate inhibitive potentials in drilling gas hydrate sediment. The QAS/IL used were TMABr, TP(r)ABr, TMACl, and EMIMCl. The mud rheological characterisation was performed at a controlled shear rate of 1 s(-1) to 200 s(-1) at -2 degrees C-40 degrees C. The hydrate test was conducted in a high-pressure reactor at 8 MPa and -2 degrees C. The hydrate nucleation onset time was predicted using the classical nucleation theory (CNT) model. The rheology and hydrate results confirmed the potential application of QAS/IL in drilling mud formulations for drilling hydrate sediments. The presence of QAS/IL in the base mud suitably reduced the mud viscosity and yield stress, which are desired properties for generating turbulent flow to enhance cuttings transport, especially in high angle wellbores. The rheological properties of water-based mud were found to be significantly controlled or affected by the cation, anion, and alkyl chain length type of QAS/IL. However, the anion effect is more dominant and exhibit a critical concentration depending on its respective ionic strength. Further FTIR analysis confirmed the presence of N-O stretching which supports the performance of TMA(+) over EMIM+ to reduce the mud yield stress. In addition, the thermal degradation of the base mud was significantly reduced in the presence of QAS/IL. Amongst the studied additives, TMACl and TP(r)ABr WBMs completely prevented hydrate plugs in the mud system. Furthermore, the CNT model accurately predicted the hydrate onset time with APE < 2%. The QAS/IL in the WBM systems exhibited minimal to negligible disturbance (< 0.5 K shift) on the methane hydrate phase boundary compared with commercial hydrate additives at 3 wt%. This study provides guidelines to design efficient QAS/IL WBMs for drilling gas hydrate rocks.",14,14,5
Drilling Fluid,Degrees C.,"Oseh, Jeffrey O.; Norddin, M. N. A. Mohd; Ismail, Issham; Ismail, Abdul R.; Gbadamosi, Afeez O.; Agi, Augustine; Ogiriki, Shadrach O.",Investigating almond seed oil as potential biodiesel-based drilling mud,Biodegradation; Biodiesel; Diesel; Sweet almond seed oil; Rheology; Shale swelling,VEGETABLE-OIL; PALM OIL; PERFORMANCE; FLUID; TRANSESTERIFICATION; ENHANCEMENT; STABILITY; VISCOSITY; DESIGN,"With increasing strict environmental laws, there is a need for operators to design a benign oil-based muds (OBMs). In this study, oil extracted from non-edible sweet almond seed (SASO) was used as the continuous phase to formulate biodiesel-based drilling mud (BBDM). Different properties of the BBDM including the economic viability were evaluated and compared with those of the diesel OBM to determine the applicability of these properties for drilling fluids and their level of toxicity to the environment. The results indicate that the rheology, filtration properties, electrical stability, thermal stability and shale swelling inhibition performance of the BBDM are comparable with those of the diesel OBM. The biodiesel has a significantly higher flash point of 169 degrees C than the diesel with 78 degrees C; demonstrating that it can supply better fire safety than the diesel. The data of the toxicity test indicate SASO to be safer and less harmful compared to diesel #2 type used. After the 28-day period of biodegradation tests, the BBDM and the diesel OBM showed 83% and 25.2% aerobic biodegradation with Penicillium sp., respectively. The low branching degree and absence of aromatic compounds in the BBDM contributes for its higher biodegradation. The economic evaluation of the BBDM indicates low cost of formulation and waste management. The general outcome of the tests illustrates that SASO has the potentials of being one of the technically and environmentally feasible substitutes for the diesel OBM.",14,15,1
Drilling Fluid,Degrees C.,"Ahdaya, Mohamed; Imqam, Abdulmohsin",Investigating geopolymer cement performance in presence of water based drilling fluid,Geopolymer cement; Water based drilling fluid; Rheological and mechanical performance,,"Oil well cementing is one of the most important steps in drilling and completion processes and providing a full zonal isolation which is the most important features in the oil cementing. Traditionally, Portland cement is used for oil cementing operations, however, a few years ago, a new cost-effective material came to light called geopolymer. In this research, a fly ash class C based geopolymer was used. This research investigates the effect of drilling fluid contamination with geopolymer cement to understand its impact on geopolymer rheological and mechanical performance. Initially, the optimized geopolymer was prepared and mixed with different drilling fluid ratios, including 0%, 5%, and 10% by weight of cement at atmospheric pressure and ambient temperature (24 degrees C). Same percentages were added to Portland cement to compare it with the geopolymer. Four tests were conducted to determine the effects of drilling fluids including: rheology, density, fluid-loss, and compressive strength for different curing time (1 day, 3 days, and 7 days). Results showed that drilling fluids enhanced the geopolymer rheological behavior by improving geopolymer viscosity and reducing the fluid loss. Drilling fluids reduced the geopolymer viscosity which facilitates the pumping operation during the cementing. In contrast, mixing the drilling fluid with Portland cement had a negative effect on rheological behavior as well as fluid loss. Mixing the drilling fluid with Portland cement increased the fluid loss significantly. In term of compressive strength, as the amount of drilling fluids increased, the compressive strength of geopolymer was not significantly affected. After 3 days curing time, geopolymer lost about 8.5% of its strength when 5% of drilling fluids weight percent was added. Whereas, Portland cement has lost 38.4% of its strength when 5% of drilling fluids weight percent was added. After 7 days curing time, geopolymer lost about 23% of its strength when 5% of drilling fluid by weight of cement was added. However, Portland cement lost 49% of compressive strength in the same conditions. These obtained results indicates that geopolymer has the ability to withstand the drilling fluids contamination.",13,13,5
Drilling Fluid,Damage,"Zhao, Xin; Qiu, Zhengsong; Sun, Baojiang; Liu, Shujie; Xing, Xijin; Wang, Mingliang",Formation damage mechanisms associated with drilling and completion fluids for deepwater reservoirs,Formation damage; Deepwater reservoir; Drilling and completion fluids; Sensitivity damage; Invasion of solid and filtrate; Rock-fluid incompatibilities,INVASION; FILTRATE; QUALITY; SHALE; MODEL; BASIN,"Immense oil and gas reserves exist in the deepwater of the South China Sea, and the first priority for implementing successful drilling and completion operations without reservoir damage is to understand the damaging mechanisms to the reservoir formation. With the use of deepwater reservoir cores from the western South China Sea, the mineral composition, microstructure, porosity, and permeability characteristics of the reservoir formation were analyzed. With the use of core flow tests, potential fluid sensitivity was analyzed to determine how and which fluids can damage the reservoir formation during drilling and completion. The results show that the reservoir formation is composed of unconsolidated siltstone with a clay mineral content of 6-19%, and has high porosity and permeability with large pore throats. Sensitivity damage due to the increasing flow rate is strong, and an unusual salinity sensitivity exists with a critical salinity at 40,000-45,000 mg/L. Moderate alkali fluids sensitivity damage exists, with water sensitivity being weak. The main mechanisms of formation damage by drilling and completion fluids were analyzed as following: plugging of pore throats by solid invasion occurs because the sizes of the solid materials in the drilling fluids are just ideal for the formation of an external filter. Rock-fluid incompatibilities occur due to the increasing flow rate and salinity of the fluids because the formation rock is unconsolidated and the fines will easily detach and migrate, plugging the pore throats. Therefore, effective temporary plugging of the pore throats with a large diameter is important for protecting the reservoir. This study provides basic data for the design and implementation of reservoir protection measures in deepwater oil and gas exploration.",73,75,6
Drilling Fluid,Damage,"Dong, Bingqiang; Meng, Meng; Qiu, Zhengsong; Lu, Zhaohui; Zhang, Ye; Zhong, Hanyi",Formation damage prevention using microemulsion in tight sandstone gas reservoir,Damage mechanism; Water blocking; Sensitivity damages; Protective drilling fluid,STRESS SENSITIVITY; LOW-PERMEABILITY; DRILLING-FLUID; OIL; REMOVAL; MODEL; SAND; FLOW,"Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production.",43,45,1
Drilling Fluid,Damage,Zhang Lufeng; Zhou Fujian; Zhang Shicheng; Li Zhu; Wang Ji; Wang Yuechun,Evaluation of permeability damage caused by drilling and fracturing fluids in tight low permeability sandstone reservoirs,Permeability damage; Pressure transmission test; Fracturing fluids; Drilling fluids; Tight sandstone reservoir,PULSE-DECAY METHOD; TRANSIENT LABORATORY METHOD; HYDRAULIC-PROPERTIES; GAS-PERMEABILITY; MECHANISM; METHODOLOGY; PERFORMANCE; RELAXATION; ROCKS; FLOW,"Tight sandstone reservoirs with low porosity and permeability are always vulnerable to damage due to drilling and fracturing fluids, which significantly impedes hydrocarbon production. Therefore, exploring damage evaluation methods has been an undeniable demand of formation protection and efficient development. However, the common steady-state core flow method is time-consuming and inaccurate for evaluating permeability damage in tight low permeability reservoirs. Aiming at this problem, this paper introduced pressure transmission test (PIT), a time-saving and accurate method, to quantitatively evaluate the core permeability damage degree from macroscopic perspective. Furthermore, nuclear magnetic resonance (NMR) was also used to analyze the damage mechanisms of fracturing fluids from microscopic perspective. In the fracturing fluids damage experiments, the results of PTT show that the ultimate damage degree of fracturing fluids is approximately 40%, of which water-sensitivity, water-block, and solid-phase are approximately 10%, 12% and 16%, respectively. With the technique of NMR, the damage mechanisms due to fracturing fluids are also investigated. In the drilling and fracturing fluids damage experiments, the results of PIT show that the drilling fluids cause the major damage. In the experiments of acidizing treatment, the chelating acid shows excellent properties in reliving core permeability damage caused by drilling and fracturing fluids. This study provides a new idea for evaluating permeability damage in low permeability reservoirs, such as shale, tight sandstone reservoirs, bedrock reservoirs, and so on.",37,38,12
Drilling Fluid,Damage,"Li, Tianjiao; Li, Lianchong; Tang, Chun'an; Zhang, Zilin; Li, Ming; Zhang, Liaoyuan; Li, Aishan",A coupled hydraulic-mechanical-damage geotechnical model for simulation of fracture propagation in geological media during hydraulic fracturing,HMD; Numerical simulation; Unsteady flow; Hydraulic fracturing; Stress shadow effect,FINITE-ELEMENT-METHOD; NUMERICAL MANIFOLD METHOD; FLUID-FLOW; CUBIC LAW; POROUS-MEDIA; ROCK; STRESS; DISCONTINUITY; COALESCENCE; CONTINUUM,"This paper proposed a coupled hydraulic-mechanical-damage (HMD) geotechnical model for simulating the entire failure process in geological media. In this model, elastic damage mechanics describes the damage process of elements. Darcy's Law and unsteady seepage flow equation describe fluid flow in elements, where compression of fluid and rock are considered. The coupled process is fulfilled by Biot's consolidation theory describing how pore-pressure affects the stress field and the stress/aperture/mesh-dependent permeability that represents the influence of stress on seepage field. The HMD model is implemented in the calculation module of Rock-Failure-Process-Analysis on Petroleum-problems (RFPA-Petrol) codes. The RFPA suite of software codes is based on the idea that the heterogeneity leads to non-linearity and causes progressive failure behavior observed in brittle rock. The capability of RFPA-Petrol simulator is demonstrated by a typical coupled problem related to double fractures propagation during hydraulic fracturing. This simulation successfully reproduces the asynchronous initiation, asymmetric growth and non-equal deflection of fractures in the numerical model. Then this simulator was used to investigate how fracture spacing and horizontal stress ratio influence propagation and reorientation of three hydraulic fractures from a horizontal well. At last, a horizontal well drilled by SHENGLI oilfield is simulated to certificate RFPA-Petrol's ability on field-scale models. It is found that larger fracture spacing and higher initial fracture height will form longer and wider fractured zones. HMD-based RFPA-Petrol is suitable for simulation of laboratory scale and field scale fracture propagation problems.",26,27,5
Drilling Fluid,Damage,"Bageri, Badr S.; Adebayo, Abdulrauf Rasheed; Barri, Assad; Al Jaberi, Jaber; Patil, Shirish; Hussaini, Syed Rizwanullah; Babu, Rahul S.",Evaluation of secondary formation damage caused by the interaction of chelated barite with formation rocks during filter cake removal,Drilling fluid; Barite; Chelating agent; NMR; CT scan; Filtration loss,LOW-FIELD NMR,"Filter cake formed by barite-based drilling fluid are often removed using chelating agents such as Diethylenetriaminepentaaceticacid (DTPA) in combination with other catalysts. During the removal process, the filter cake is soaked with the chelating agent for approximately 24 h, after which they absorb barite from the filter cake to form a barite chelate (BaDTPA). The filter cake thickness may not be homogenous along the wellbore surface, especially in directional wells. As a result, the chelating agent will dissolve the thinner filter cake faster and earlier than the thicker filter cake. Thus, for a given treatment period, the thin filter case is quickly dissolved and the resulting barite chelate will have more time to invade the formation. This paper investigates the interaction between the barite chelate and the rock formation after filter cake dissolution. A suite of lab scale experiments was conducted to simulate filter cake formation on the face of four rock samples (limestone and sandstone) using a High-Pressure High Temperature (HPHT) filter loss apparatus. DTPA (20 wt %) was then used to dissolve the filter cake. A core flooding apparatus was used to inject the effluent barite chelate into the rock samples to simulate its invasion and interaction with the rock. NMR spectroscopy and x-ray micro CT images of the samples revealed interesting changes in the pore size distributions of the samples. Barite chelate released barite precipitates into the pores of the rock and then absorbs cations from the rock minerals. In sandstones, the barite chelates released barites into the small - intermediate pores and absorbed cations ions from the large pores. In carbonates, the barite chelates released barites into the big pores and absorbed cations from small - intermediate pores. Micro-CT scan and spatial T-2 NMR analysis also showed that no wormholes were generated during filter cake dissolution. A detailed explanation of the observed results is presented with supporting results.",21,21,0
Drilling Fluid,Damage,"Zhang, Dujie; Kang, Yili; Selvadurai, A. P. S.; You, Lijun; Tian, Jian",The role of phase trapping on permeability reduction in an ultra-deep tight sandstone gas reservoirs,Ultra-deep tight gas reservoirs; Phase trapping damage; Drill-in fluids; Invasion depth; Permeability damage ratio; Numerical simulation model,MERCURY INTRUSION POROSIMETRY; PORE-SIZE DISTRIBUTIONS; SPONTANEOUS IMBIBITION; RELATIVE PERMEABILITY; WATER IMBIBITION; TARIM BASIN; PRESSURE; HYSTERESIS; ADSORPTION; IMPACT,"As the first external liquids that are introduced into a reservoir rock, suitable drill-in fluids not only prevent phase trapping-induced permeability reduction (also referred to as phase trapping damage) caused by the drill-in fluid itself but also minimize any phase trapping damage caused by the invasion of subsequent working fluids. An ultra-deep tight sandstone reservoir in the Tarim Basin, NW China is considered as a case study, and this paper presents the results of an extensive series of phase trapping damage investigations that were carried out to determine the permeability reduction in the reservoir rock that comes into contact with different working fluids during the processes of drilling, drill stem tests, completion and well tests. Both the pore microstructure and surface properties were also investigated. The experimental results showed that the integrated phase trapping damage ratio (PDR) of water-based drill-in fluids (WBDF)-organic salt completion fluids (PDR = 0.99) was greater than that of oil-based drill-in fluids (OBDF)-organic salt completion fluids (PDR = 0.88). The analysis suggests that the OBDF is more effectively in inhibiting the absorption of the filtrate of the completion fluids compared with WBDF. A procedure for reducing phase trapping damage by OBDF is presented, and a numerical simulation model is developed to validate the procedure. The results could be useful in understanding and selecting the best drill-in fluids and completion fluids to minimize phase trapping damage in ultra-deep tight gas reservoirs.",18,20,1
Drilling Fluid,Damage,"Hajiabadi, Seyed Hasan; Aghaei, Hamed; Kalateh-Aghamohammadi, Mina; Sanati, Ali; Kazemi-Beydokhti, Amin; Esmaeilzadeh, Feridun","A comprehensive empirical, analytical and tomographic investigation on rheology and formation damage behavior of a novel nano-modified invert emulsion drilling fluid",Rheological behavior; Invert emulsion drilling fluid; PEGylated oxidized carbon NanoTube; Formation damage; Computed tomography (CT) scanning,NANOPARTICLES; PERFORMANCE; STABILITY,"The present study aims to investigate the rheological behaviors of one the most common drilling fluids in oil and gas industry known as the invert oil emulsions (W/O), specially, in addition of the carbon-based nanomaterials. The W/O fluid samples and a range of modified Multi-Walled carbon NanoTube (MWNT) additives were prepared and analyzed based on well-known rheological models, such as, the Carreau model in several temperatures. The subsequent formation damage was studied on selected core samples using the Computed Tomography (CT) and Scanning Electron Microscopy (SEM) imaging techniques. In summary, the drilling fluid sample behaviors are well-matched with the Carreau model and it has been shown that the nanomaterial additives are highly efficient in significant improvement of the critical rheological properties. The latest was well verified and supported through comparison of the fluid sample's pre- and post-damaged CT and SEM images.",18,18,1
Drilling Fluid,Damage,"Lyu, Shuaifeng; Wang, Shengwei; Chen, Xiaojun; Shah, S. M.; Li, Rui; Xiao, Yuhang; Dong, Qingxiang; Gu, Yuanyuan",Experimental study of a degradable polymer drilling fluid system for coalbed methane well,Degradable polymer drilling fluid; Bio-enzymes; Permeability recovery; Polymer removal; Coal cuttings carrying; South Qinshui Basin,WATER; NANOPARTICLES; PERFORMANCE; PRESSURE; BENTONITE; SEAM,"Drilling along the coal seam is an effective way to improve gas recovery. Due to complex coal body structure and natural fractures, there are many difficulties, including a low abilities of cutting carrying, leakage while crossing the fracture zone and reservoir damage. In this work, a low density degradable polymer drilling fluid system is developed to solve these difficulties to enhance coalbed methane (CBM) production. In the laboratory, the properties of the polymer drilling fluid were evaluated using the coal cuttings suspension experiment, borehole stability simulation test, viscosity attenuation method, laser particle size analysis, polymer removal and core permeability recovery method. The experimental result indicates that the developed drilling fluid has good rheology and filtration, a high yield point and a strong inhibition, thereby meeting conventional drilling requirements and carrying coal cuttings effectively. Under the bio-enzymes, the viscosity of degradable drilling fluid can be initially reduced to 16%. The optimum temperature and pH for the enzyme activity is obtained, and enzymes with small weight fraction of 0.01% can dramatically alter rheological properties of drilling fluid and thereby the high biological activity. After degradation, the particle size in drilling fluid decreases greatly. During immersion test, the polymer film on the surface of the lump coal and thin sections is almost removed by enzyme solution. The reservoir's permeability damage rate may be reduced from 50% to 25% via the functionality of the enzymes, and it is noticeable that the relationships between effective stress and gas permeability treated by the drilling fluid and enzyme still obey the exponential function. Field applications show that the drilling fluid has a good coal fines resistance and compatibility with conventional plugging materials, which ensures the long horizontal footage of 901 m with the short construction period. The later decreased viscosity of the drilling fluid by the enzymes is conducive to reduce the damage to the coal reservoirs.",16,16,7
Drilling Fluid,Damage,"Sharifipour, M.; Nakhaee, A.; Pourafshary, P.",Model development of permeability impairment due to clay swelling in porous media using micromodels,LSW flooding; Clay swelling; Permeability impairment; Micromodel; Image processing,OIL-RECOVERY FACTOR; CAPILLARY-PRESSURE; WATER; GAS; MONTMORILLONITE; WETTABILITY; SURFACE,"Swelling and displacement of clay minerals during drilling and production of oil and gas reservoirs are among the main mechanisms of formation damage. Most reservoirs contain clay minerals, either originally deposited during sedimentation phase, or precipitated from fluids flowing through matrix. Owing to the large specific surface area of clay particles, their swelling, detachment, and migrationmay lead to permeability impairment in porous media. Therefore, an accurate interpretation of the behaviour of clay particles in the porous media may enable us to prevent and possibly reverse the respective damage mechanisms. In this work, the pore-scale swelling behaviour of clays are studied using glass micro models as porous medium and Sodium bentonite as swelling clay. By image processing technique, effective porosity of model during low salinity water (LSW) flooding are estimated. The effect of different parameters such as porous medium aspect ratio and clay concentration on permeability impairment is studied. According to this study, besides higher clay concentrations, the permeability is also affected adversely by larger aspect ratio of pore bodies. Based on our experiments, a model is developed to estimate permeability impairment by clay swelling as a function of pore geometry and clay concentration.",14,14,2
Drilling Fluid,Pores,"Zhao, Xin; Qiu, Zhengsong; Sun, Baojiang; Liu, Shujie; Xing, Xijin; Wang, Mingliang",Formation damage mechanisms associated with drilling and completion fluids for deepwater reservoirs,Formation damage; Deepwater reservoir; Drilling and completion fluids; Sensitivity damage; Invasion of solid and filtrate; Rock-fluid incompatibilities,INVASION; FILTRATE; QUALITY; SHALE; MODEL; BASIN,"Immense oil and gas reserves exist in the deepwater of the South China Sea, and the first priority for implementing successful drilling and completion operations without reservoir damage is to understand the damaging mechanisms to the reservoir formation. With the use of deepwater reservoir cores from the western South China Sea, the mineral composition, microstructure, porosity, and permeability characteristics of the reservoir formation were analyzed. With the use of core flow tests, potential fluid sensitivity was analyzed to determine how and which fluids can damage the reservoir formation during drilling and completion. The results show that the reservoir formation is composed of unconsolidated siltstone with a clay mineral content of 6-19%, and has high porosity and permeability with large pore throats. Sensitivity damage due to the increasing flow rate is strong, and an unusual salinity sensitivity exists with a critical salinity at 40,000-45,000 mg/L. Moderate alkali fluids sensitivity damage exists, with water sensitivity being weak. The main mechanisms of formation damage by drilling and completion fluids were analyzed as following: plugging of pore throats by solid invasion occurs because the sizes of the solid materials in the drilling fluids are just ideal for the formation of an external filter. Rock-fluid incompatibilities occur due to the increasing flow rate and salinity of the fluids because the formation rock is unconsolidated and the fines will easily detach and migrate, plugging the pore throats. Therefore, effective temporary plugging of the pore throats with a large diameter is important for protecting the reservoir. This study provides basic data for the design and implementation of reservoir protection measures in deepwater oil and gas exploration.",73,75,6
Drilling Fluid,Pores,"Meng, M.; Baldino, S.; Miska, S. Z.; Takach, N.",Wellbore stability in naturally fractured formations featuring dual-porosity/single-permeability and finite radial fluid discharge,Wellbore stability; Fractures; Dual-porosity/single-permeability; Hemisphere plot,MECHANICAL-PROPERTIES; CONSOLIDATION; SHALE; BOREHOLE; MEDIA,"This work presents an analytical solution for an inclined wellbore drilled in a fractured formation displaying a high contrast between the diffusion rates in the fractures and in the porous matrix, with the latter treated as a storage phase and thus not participating in the fluid transport. This scenario may result from different mud cake building rates, and/or adverse wettability of the rock matrix with respect to the drilling fluid being used. Different from the models available in the literature, the fractures are characterized by a more realistic finite radial fluid discharge (namely, the fractures network hydraulically connected to the wellbore is of limited extent). The models output in terms of pore pressures, total stresses and effective stresses response has been compared with the results of a widely accepted dual-porosity/dual-permeability model. Major differences and asymptotic behaviors have been analyzed. Subsequently, the results of the model have been used to perform a comprehensive wellbore stability analysis. The effect of time dependency, fractures network length and rock properties on the instability of the borehole have been investigated, and upper and lower mud weight bounds have been determined using several failure criteria. This investigation shows that under the specified conditions where dual-porosity/single-permeability conditions arise, the proposed model provides with theoretically more conservative mud weights predictions.",48,50,6
Drilling Fluid,Pores,"Dong, Bingqiang; Meng, Meng; Qiu, Zhengsong; Lu, Zhaohui; Zhang, Ye; Zhong, Hanyi",Formation damage prevention using microemulsion in tight sandstone gas reservoir,Damage mechanism; Water blocking; Sensitivity damages; Protective drilling fluid,STRESS SENSITIVITY; LOW-PERMEABILITY; DRILLING-FLUID; OIL; REMOVAL; MODEL; SAND; FLOW,"Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production.",43,45,1
Drilling Fluid,Pores,"Bageri, Badr S.; Adebayo, Abdulrauf Rasheed; Barri, Assad; Al Jaberi, Jaber; Patil, Shirish; Hussaini, Syed Rizwanullah; Babu, Rahul S.",Evaluation of secondary formation damage caused by the interaction of chelated barite with formation rocks during filter cake removal,Drilling fluid; Barite; Chelating agent; NMR; CT scan; Filtration loss,LOW-FIELD NMR,"Filter cake formed by barite-based drilling fluid are often removed using chelating agents such as Diethylenetriaminepentaaceticacid (DTPA) in combination with other catalysts. During the removal process, the filter cake is soaked with the chelating agent for approximately 24 h, after which they absorb barite from the filter cake to form a barite chelate (BaDTPA). The filter cake thickness may not be homogenous along the wellbore surface, especially in directional wells. As a result, the chelating agent will dissolve the thinner filter cake faster and earlier than the thicker filter cake. Thus, for a given treatment period, the thin filter case is quickly dissolved and the resulting barite chelate will have more time to invade the formation. This paper investigates the interaction between the barite chelate and the rock formation after filter cake dissolution. A suite of lab scale experiments was conducted to simulate filter cake formation on the face of four rock samples (limestone and sandstone) using a High-Pressure High Temperature (HPHT) filter loss apparatus. DTPA (20 wt %) was then used to dissolve the filter cake. A core flooding apparatus was used to inject the effluent barite chelate into the rock samples to simulate its invasion and interaction with the rock. NMR spectroscopy and x-ray micro CT images of the samples revealed interesting changes in the pore size distributions of the samples. Barite chelate released barite precipitates into the pores of the rock and then absorbs cations from the rock minerals. In sandstones, the barite chelates released barites into the small - intermediate pores and absorbed cations ions from the large pores. In carbonates, the barite chelates released barites into the big pores and absorbed cations from small - intermediate pores. Micro-CT scan and spatial T-2 NMR analysis also showed that no wormholes were generated during filter cake dissolution. A detailed explanation of the observed results is presented with supporting results.",21,21,0
Drilling Fluid,Pores,"Zhang, Dujie; Kang, Yili; Selvadurai, A. P. S.; You, Lijun; Tian, Jian",The role of phase trapping on permeability reduction in an ultra-deep tight sandstone gas reservoirs,Ultra-deep tight gas reservoirs; Phase trapping damage; Drill-in fluids; Invasion depth; Permeability damage ratio; Numerical simulation model,MERCURY INTRUSION POROSIMETRY; PORE-SIZE DISTRIBUTIONS; SPONTANEOUS IMBIBITION; RELATIVE PERMEABILITY; WATER IMBIBITION; TARIM BASIN; PRESSURE; HYSTERESIS; ADSORPTION; IMPACT,"As the first external liquids that are introduced into a reservoir rock, suitable drill-in fluids not only prevent phase trapping-induced permeability reduction (also referred to as phase trapping damage) caused by the drill-in fluid itself but also minimize any phase trapping damage caused by the invasion of subsequent working fluids. An ultra-deep tight sandstone reservoir in the Tarim Basin, NW China is considered as a case study, and this paper presents the results of an extensive series of phase trapping damage investigations that were carried out to determine the permeability reduction in the reservoir rock that comes into contact with different working fluids during the processes of drilling, drill stem tests, completion and well tests. Both the pore microstructure and surface properties were also investigated. The experimental results showed that the integrated phase trapping damage ratio (PDR) of water-based drill-in fluids (WBDF)-organic salt completion fluids (PDR = 0.99) was greater than that of oil-based drill-in fluids (OBDF)-organic salt completion fluids (PDR = 0.88). The analysis suggests that the OBDF is more effectively in inhibiting the absorption of the filtrate of the completion fluids compared with WBDF. A procedure for reducing phase trapping damage by OBDF is presented, and a numerical simulation model is developed to validate the procedure. The results could be useful in understanding and selecting the best drill-in fluids and completion fluids to minimize phase trapping damage in ultra-deep tight gas reservoirs.",18,20,1
Drilling Fluid,Pores,"Yu, Fuwei; Jiang, Hanqiao; Xu, Fei; Zhen, Fan; Wang, Jitao; Cheng, Baoyang; Su, Hang; Li, Junjian",A multi-scale experimental study of hydrophobically-modified polyacrylamide flood and surfactant-polymer flood on enhanced heavy oil recovery,Heavy oil; Surfactant-polymer flood; Hydrophobically-modified polyacrylamide flood; Multi-scale experiments,IN-WATER EMULSIONS; INTERFACIAL-TENSION; CONFORMANCE CONTROL; POROUS-MEDIA; PORE-SCALE; INJECTION; SALINITY; RESERVOIR; METHODOLOGY; IMBIBITION,"A large amount of residual oil remained in heavy oil reservoirs after water flood due to its viscosity nature. And it has been validated that chemical flood, if applied appropriately, is an efficient and economical EOR method for deeply buried or thin heavy oil reservoirs. A multi-scale experimental evaluation workflow was designed to explore the mechanisms behind the production of residual oil in heavy oil reservoirs by chemical flood. And we conducted three multi-scale experiments to evaluate the performance of hydrophobically-modified polyacrylamide (HMHPAM) flood, surfactant-polymer (SP) flood and their combination. Based on the results of corefloods and medical CT scans, we demonstrated the EOR potential of HMHPAM flood (HPF) synergy with SP flood (SPF). After each coreflood, two samples were drilled from the heterogenous core used in the macro-scale experiment. And the micro-CT scan results of these samples visualized the distribution of oil phase and aqueous phase in each coreflood at the pore scale, and further quantified the decrease of continuous oil clusters caused by the HMHPAM solution and following injected fluids. Besides, we also observed the linear relationship between the volume of each oil cluster against its surface area and the logarithmic relationship between the volume of discontinuous oil cluster and its cumulative contribution to total oil volume. Moreover, a simple method to calculate the oil-water proportion in pores was developed to correlate the relationship between the displacement efficiency of each pore and its pore size. Results showed that the relationship between oil saturation in each pore and its pore size followed the power law correlation. Moreover, the pore-scale analysis also validated that the residual oil in most pores after water flood was effectively mobilized by the synergy of HPF and SPF.",15,18,5
Drilling Fluid,Pores,"Sharifipour, M.; Nakhaee, A.; Pourafshary, P.",Model development of permeability impairment due to clay swelling in porous media using micromodels,LSW flooding; Clay swelling; Permeability impairment; Micromodel; Image processing,OIL-RECOVERY FACTOR; CAPILLARY-PRESSURE; WATER; GAS; MONTMORILLONITE; WETTABILITY; SURFACE,"Swelling and displacement of clay minerals during drilling and production of oil and gas reservoirs are among the main mechanisms of formation damage. Most reservoirs contain clay minerals, either originally deposited during sedimentation phase, or precipitated from fluids flowing through matrix. Owing to the large specific surface area of clay particles, their swelling, detachment, and migrationmay lead to permeability impairment in porous media. Therefore, an accurate interpretation of the behaviour of clay particles in the porous media may enable us to prevent and possibly reverse the respective damage mechanisms. In this work, the pore-scale swelling behaviour of clays are studied using glass micro models as porous medium and Sodium bentonite as swelling clay. By image processing technique, effective porosity of model during low salinity water (LSW) flooding are estimated. The effect of different parameters such as porous medium aspect ratio and clay concentration on permeability impairment is studied. According to this study, besides higher clay concentrations, the permeability is also affected adversely by larger aspect ratio of pore bodies. Based on our experiments, a model is developed to estimate permeability impairment by clay swelling as a function of pore geometry and clay concentration.",14,14,2
Drilling Fluid,Gas Production,"Dong, Bingqiang; Meng, Meng; Qiu, Zhengsong; Lu, Zhaohui; Zhang, Ye; Zhong, Hanyi",Formation damage prevention using microemulsion in tight sandstone gas reservoir,Damage mechanism; Water blocking; Sensitivity damages; Protective drilling fluid,STRESS SENSITIVITY; LOW-PERMEABILITY; DRILLING-FLUID; OIL; REMOVAL; MODEL; SAND; FLOW,"Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production.",43,45,1
Drilling Fluid,Gas Production,"Wang, Shuhua; Chen, Zan; Chen, Shengnan",Applicability of deep neural networks on production forecasting in Bakken shale reservoirs,Production forecasting; Bakken formation; Deep neural networks; Hyperparameter optimization; Global sensitivity analysis,NEWTON OPTIMIZATION METHOD; TIGHT-OIL; GAS-PRODUCTION; MODEL; PREDICTION; DESIGN; STEAM,"The unconventional shale and tight formations, such as the Bakken in Williston Basin, are becoming an important hydrocarbon sources since the development of advanced horizontal drilling and multi-stage stimulation techniques. The appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery. Although reservoir simulations are commonly used for production analysis, the modeling of hydraulic fractures and intrinsic complexity of shale have restricted an understanding of the fluid flow behavior. Owing to the available of a large amount of data in unconventional tight and shale reservoirs, data-driven approaches, such as deep neural networks (DNNs), provide an alternative approach for production analysis in these formations. In this study, a total of 2919 wells including 2780 multi-stage hydraulic fractured horizontal wells and 139 vertical wells in Bakken Formation were collected and analyzed using a deep learning method and Sobol's global sensitivity analysis. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, and batch normalization were evaluated to develop a reliable deep neural network model. Moreover, k -fold cross validation was used to evaluate the prediction ability and robustness of models. Prior to the performance evaluation of DNN algorithms, an optimum DNN model was achieved by optimizing the dropout layer, activation function, and hyperparameters of DNN models. It is found that the number of hidden layers and neurons in each layer have significant effects on the performance of models. The optimized DNN model has 3 hidden layers and 200 neurons for each layer. The prediction performance of DNN models is acceptable with the low mean squared errors for both 6- and 18-months cumulative oil productions. Furthermore, the importance of each parameter was studied using the Sobol's analysis. Results show that the average proppant placed per stage is the most important parameter, which accounts for more than 35% of variability in both 6- and 18-months cumulative oil productions. These data-driven models can be readily updated when the new well information becomes available. It is worth mentioning that the proposed DNN models can be directly integrated into existing hydraulic fracturing design routines.",35,37,5
Drilling Fluid,Gas Production,"Ghasemi, Mehdi; Moslemizadeh, Aghil; Shahbazi, Khalil; Mohammadzadeh, Omid; Zendehboudi, Sohrab; Jafari, Sina",Primary evaluation of a natural surfactant for inhibiting clay swelling,Ginsenosides; Biosurfactant; Clay swelling inhibitor; Wettability; Compatibility,WELLBORE STABILITY; SHALE HYDRATION; REDUCING ADSORPTION; ANIONIC SURFACTANT; MODIFIED BENTONITE; IONIC LIQUID; WATER; GINSENG; COPOLYMER; MONTMORILLONITE,"Water-based drilling muds, a more environment-friendly candidate than oil-based drilling muds, are wildly used for drilling oil and gas wells. When water-based drilling mud is used for drilling formations with shale containing active clay constituents, it is challenging to preserve stability of the borehole due to clay swelling unless proper inhibition mechanisms are foreseen. In the current study, the feasibility of using Korean red Ginseng root extract was assessed as a clay swelling inhibitor. This root extract is rich in non-ionic surfactants such as Ginsenosides Rg3, Rg5, and RK1, and is referred to as ""biosurfactant"" throughout this manuscript. After preparation of mud systems containing problematic clay particles, the clay-swelling inhibition performance of the biosurfactant was systematically investigated through a series of tests, including mud formation, filtration, immersion, sedimentation assisted with optical microscopy, wettability by sessile drop technique, use of thermal gravimetric analysis (TGA), scanning electron microscopy (SEM) and Fourier-transform infrared spectroscopy (FTIR), and shale cuttings recovery. The clay-swelling inhibition performance of the biosurfactant was then compared against two clay swelling inhibitors namely CTAB (Cetrimonium bromide, a known cationic surfactant) and potassium chloride. There are some properties associated with the mud systems prepared with biosurfactant solution which makes this product unique. These properties include: remarkable loading capacity of sodium montmorillonite (Mt) which in turn resulted in low rheological profile, poor fluid loss control, creation of stable Mt pellets, creation of larger size and aggregated Mt particles with less hydrophilicity, creation of fully unstable dispersed Mt particles that resulted in good sedimentation over time, less mass loss, and higher shale cuttings recovery, all compared to the baseline fluid made without the presence of biosurfactant. The results of this study indicate that the biosurfactant provides excellent clay swelling inhibition properties, comparable to known inhibitors. The biosurfactant's compatibility with other drilling mud components was also checked, and it was found that the fluid properties are independent of the biosurfactant. The wettability and FTIR analyses were also performed to investigate the mechanisms involved in clay swelling inhibition of the biosurfactant, which are believed to be as a result of coating the clay active surfaces with a hydrophobic layer, hence repelling the water phase. This hydrophobic layer is probably formed by interactions of the hydrophilic group of the Ginsenosides and the oxygen atoms available on the Mt surfaces, when the hydrophobic tail is oriented toward the aqueous phase.",30,30,0
Drilling Fluid,Gas Production,"Lyu, Shuaifeng; Wang, Shengwei; Chen, Xiaojun; Shah, S. M.; Li, Rui; Xiao, Yuhang; Dong, Qingxiang; Gu, Yuanyuan",Experimental study of a degradable polymer drilling fluid system for coalbed methane well,Degradable polymer drilling fluid; Bio-enzymes; Permeability recovery; Polymer removal; Coal cuttings carrying; South Qinshui Basin,WATER; NANOPARTICLES; PERFORMANCE; PRESSURE; BENTONITE; SEAM,"Drilling along the coal seam is an effective way to improve gas recovery. Due to complex coal body structure and natural fractures, there are many difficulties, including a low abilities of cutting carrying, leakage while crossing the fracture zone and reservoir damage. In this work, a low density degradable polymer drilling fluid system is developed to solve these difficulties to enhance coalbed methane (CBM) production. In the laboratory, the properties of the polymer drilling fluid were evaluated using the coal cuttings suspension experiment, borehole stability simulation test, viscosity attenuation method, laser particle size analysis, polymer removal and core permeability recovery method. The experimental result indicates that the developed drilling fluid has good rheology and filtration, a high yield point and a strong inhibition, thereby meeting conventional drilling requirements and carrying coal cuttings effectively. Under the bio-enzymes, the viscosity of degradable drilling fluid can be initially reduced to 16%. The optimum temperature and pH for the enzyme activity is obtained, and enzymes with small weight fraction of 0.01% can dramatically alter rheological properties of drilling fluid and thereby the high biological activity. After degradation, the particle size in drilling fluid decreases greatly. During immersion test, the polymer film on the surface of the lump coal and thin sections is almost removed by enzyme solution. The reservoir's permeability damage rate may be reduced from 50% to 25% via the functionality of the enzymes, and it is noticeable that the relationships between effective stress and gas permeability treated by the drilling fluid and enzyme still obey the exponential function. Field applications show that the drilling fluid has a good coal fines resistance and compatibility with conventional plugging materials, which ensures the long horizontal footage of 901 m with the short construction period. The later decreased viscosity of the drilling fluid by the enzymes is conducive to reduce the damage to the coal reservoirs.",16,16,7
Drilling Fluid,Gas Production,"Bhattacharya, Shuvajit; Ghahfarokhi, Payam Kavousi; Carr, Timothy R.; Pantaleone, Scott","Application of predictive data analytics to model daily hydrocarbon production using petrophysical, geomechanical, fiber-optic, completions, and surface data: A case study from the Marcellus Shale, North America",Marcellus Shale; Fiber optic; Data analytics; Machine learning; Predicting gas production,APPALACHIAN BASIN; LITHOFACIES,"Predicting gas production from stimulated unconventional reservoirs has always been a challenge to oil and gas companies because the physics of fluid flow through such reservoirs is not well understood. On the other hand, modeling gas production from shale reservoirs is a complex multi-variate problem that requires proper integration of data from multiple disciplines, such as geology, petrophysics, geomechanics, completions, and surface-based measurements, etc. This study demonstrates the application of data-driven machine learning algorithms, integrating geoscientific, distributed acoustic sensing (DAS), distributed temperature sensing (DTS) fiber-optic, completions, flow scanner production log, and surface data to model daily gas production from a 28-stage stimulated horizontal well drilled in the Marcellus Shale of the Appalachian basin in North America. In addition, this study aims to utilize the data from a fiber-optic monitoring system, such as DAS and DTS to evaluate the well performance. We build supervised data-driven machine learning models using Random Forest (RF), Artificial Neural Network (ANN), and Support Vector Machine (SVM) algorithms to understand the well performance and forecast the daily gas production. The study compares the forecasted results, tests the level of accuracy, and addresses different issues with these machine learning algorithms. A spatio-temporal database is constructed and used to perform sensitivity analyses to identify the key drivers for gas production. The results show that RF and ANN algorithms can be used to predict daily gas production with significantly high accuracy; however, RF algorithm is the best predictor in terms of highest accuracy (96%), less computational time and cost. Based on sensitivity analysis, it appears that Poisson's ratio, minimum horizontal stress, DAS, casing pressure, gamma log are the most important parameters to predict gas production.",14,15,4
Drilling Fluid,Gas Production,"Sharifipour, M.; Nakhaee, A.; Pourafshary, P.",Model development of permeability impairment due to clay swelling in porous media using micromodels,LSW flooding; Clay swelling; Permeability impairment; Micromodel; Image processing,OIL-RECOVERY FACTOR; CAPILLARY-PRESSURE; WATER; GAS; MONTMORILLONITE; WETTABILITY; SURFACE,"Swelling and displacement of clay minerals during drilling and production of oil and gas reservoirs are among the main mechanisms of formation damage. Most reservoirs contain clay minerals, either originally deposited during sedimentation phase, or precipitated from fluids flowing through matrix. Owing to the large specific surface area of clay particles, their swelling, detachment, and migrationmay lead to permeability impairment in porous media. Therefore, an accurate interpretation of the behaviour of clay particles in the porous media may enable us to prevent and possibly reverse the respective damage mechanisms. In this work, the pore-scale swelling behaviour of clays are studied using glass micro models as porous medium and Sodium bentonite as swelling clay. By image processing technique, effective porosity of model during low salinity water (LSW) flooding are estimated. The effect of different parameters such as porous medium aspect ratio and clay concentration on permeability impairment is studied. According to this study, besides higher clay concentrations, the permeability is also affected adversely by larger aspect ratio of pore bodies. Based on our experiments, a model is developed to estimate permeability impairment by clay swelling as a function of pore geometry and clay concentration.",14,14,2
Drilling Fluid,Filter Cake,"Zhong, Hanyi; Shen, Guangcheng; Qiu, Zhengsong; Lin, Yongxue; Fan, Lijun; Xing, Xiaodong; Li, Jia",Minimizing the HTHP filtration loss of oil-based drilling fluid with swellable polymer microspheres,Oil-based drilling fluid; Filtration; Swellable polymer; High temperature; Microsphere,PERFORMANCE; ADDITIVES,"Filtration control of drilling fluid plays an important role in the process of well-bore construction and ensures the success of drilling operation. A swellable polymer microsphere (SPM) of methylmethacrylate (MMA), butyl acrylate (BA), and lauryl methacrylate (LMA) was synthesized with suspension polymerization. Its swelling property was characterized by oil adsorption capacity measurement. First, the effect of SPM on the filtration and rheological properties of virgin organic clay dispersion was investigated. Then the filtration and rheological properties of mineral oil-based drilling fluid in the presence of SPM were elucidated under the respective conditions of hot aging temperature, oil to water ratio and density. Furthermore, the filtration control properties between SPM and two traditional filtration loss additives including modified lignite and asphaltic additive was compared. Addition of SPM exhibited obvious influence on the viscosity of oil-based drilling fluid especially at high concentration of 3 w/v%, therefore, a concentration of lower than 1.5 w/v% was recommended. After hot aging at 200 degrees C, the oil-based drilling fluid containing 1 w/v% SPM exhibited an API filtration loss decrease of 85%, and HTHP filtration loss decrease of 79% in comparison with the base fluid. After hot rolling at 180 degrees C, the API filtration loss decreased by 2%, 24% and 53%, and the HTHP filtration loss decreased by 42%, 54% and 65% respectively when 1 w/v% asphaltic additive, modified lignite and SPM are in the presence of the base fluid. Besides decreasing the filtration loss volume under high temperatures, incorporation of SPM also improves the filter cake quality of oil-based drilling fluid. SPM is capable of adsorbing considerable base oil and become swellable. The swellable polymer microspheres with favorably deformable and compressible properties can effectively fill the voids of filter cake and reduce the permeability, which leads to low filtration loss and minimization of solids invasion.",44,44,7
Drilling Fluid,Filter Cake,"Aramendiz, Jose; Imqam, Abdulmohsin",Water-based drilling fluid formulation using silica and graphene nanoparticles for unconventional shale applications,,DESIGN; MUD,"The development of unconventional shales started a new era in the oil and gas industry. These reservoirs represent a challenge to conventional drilling fluids since the fluid invasion, cutting dispersion, or shale swelling can lead to wellbore instability problems. Although oil-based drilling fluids (OBM) are capable to control these issues, environmental and economic concerns limit its application. Recently, nanoparticles (NPs) have introduced a new perspective in drilling fluid technology, offering a unique alternative to improve the performance of water-based drilling fluids (WBM) for shale applications. This research evaluates the potential of using silica nanoparticles (SiO2-NPs) and graphene nanoplatelets (GNPs) to formulate a nanoparticle water-based drilling fluid (NP-WBM). The study considers a bottom-up approach, selecting the NPs based on the Woodford Shale's characterization and focuses its primary objective in finding the most suitable NP combination to enhance the rheological, filtration and inhibition properties of the customized NP-WBM. The shale characterization included X-ray diffraction (XRD), cation exchange capacity (CEC), and scanning electron microscopy (SEM). The zeta-potential technique was used to assess the stability of the NPs. The NP-WBM was evaluated by means of API filtration test (LTLP), high-temperature/high-pressure (HTHP) filtration test and rheological measurements using a conventional viscometer. Finally, the inhibition capability of the NP-WBM was tested against the Woodford shale through immersion and cutting dispersion tests. NPs' characterization revealed that both additives can provide stable suspensions with zeta-potential values < - 30 mV. A total NP concentration of 0.75 wt% (0.5 wt% of SiO2-NPs and 0.25 wt% of GNPs) yielded to the maximum reduction in filtrate volume at both, LTLP and HTHP conditions. The less permeable filter cake resulted in no spurt-losses, supporting the NPs' plugging effect. A strong cross-linked network created between the NPs and the conventional additives increased the cutting carrying capacity of the NP-WBM with slight effects on its plastic viscosity (PV). The immersion test carried out in water revealed that illitic shales might experience micro-fractures along the bedding planes in the absence of bridging materials. Contrarily, the NP-WBM provided an adequate plugging network between grain boundaries, resulting in no micro-fractures, and the reduction of the cutting erosion by 35.61%. Overall, this study highlights the capability of nanomaterials to extend the reliability of WBM to harsher environments while seeking an eco-friendlier alternative.",38,38,3
Drilling Fluid,Filter Cake,"Bageri, Badr S.; Adebayo, Abdulrauf Rasheed; Barri, Assad; Al Jaberi, Jaber; Patil, Shirish; Hussaini, Syed Rizwanullah; Babu, Rahul S.",Evaluation of secondary formation damage caused by the interaction of chelated barite with formation rocks during filter cake removal,Drilling fluid; Barite; Chelating agent; NMR; CT scan; Filtration loss,LOW-FIELD NMR,"Filter cake formed by barite-based drilling fluid are often removed using chelating agents such as Diethylenetriaminepentaaceticacid (DTPA) in combination with other catalysts. During the removal process, the filter cake is soaked with the chelating agent for approximately 24 h, after which they absorb barite from the filter cake to form a barite chelate (BaDTPA). The filter cake thickness may not be homogenous along the wellbore surface, especially in directional wells. As a result, the chelating agent will dissolve the thinner filter cake faster and earlier than the thicker filter cake. Thus, for a given treatment period, the thin filter case is quickly dissolved and the resulting barite chelate will have more time to invade the formation. This paper investigates the interaction between the barite chelate and the rock formation after filter cake dissolution. A suite of lab scale experiments was conducted to simulate filter cake formation on the face of four rock samples (limestone and sandstone) using a High-Pressure High Temperature (HPHT) filter loss apparatus. DTPA (20 wt %) was then used to dissolve the filter cake. A core flooding apparatus was used to inject the effluent barite chelate into the rock samples to simulate its invasion and interaction with the rock. NMR spectroscopy and x-ray micro CT images of the samples revealed interesting changes in the pore size distributions of the samples. Barite chelate released barite precipitates into the pores of the rock and then absorbs cations from the rock minerals. In sandstones, the barite chelates released barites into the small - intermediate pores and absorbed cations ions from the large pores. In carbonates, the barite chelates released barites into the big pores and absorbed cations from small - intermediate pores. Micro-CT scan and spatial T-2 NMR analysis also showed that no wormholes were generated during filter cake dissolution. A detailed explanation of the observed results is presented with supporting results.",21,21,0
Drilling Fluid,Filter Cake,"Huang, Sheng; Guo, Xiaoyang; Duan, Wenhui; Cheng, Xiaowei; Zhang, Xingguo; Li, Zaoyuan",Degradation of high molecular weight polyacrylamide by alkali-activated persulfate: Reactivity and potential application in filter cake removal before cementing,Oil and gas well; Polyacrylamide; Persulfate; Filter cake; Free radical; Cementing,PHOTOCATALYTIC DEGRADATION; AQUEOUS-SOLUTION; OXIDATION; MECHANISM; WATER; BASE; POLYETHYLENE; KINETICS; OXIDE; IONS,"The interface between annular cement to wellbore rock is crucial for ensuring the oil and gas well integrity and the environmental protection. Poor bonding quality may lead to gas influx into the annulus or even ground and cause health, safety and environment (HSE) hazards including contamination of freshwater-bearing zones, corruption of the cement and casing, sustained casing pressure (SCP) and formation fluid spill to the ground surface. This bonding interface between annular cement and wellbore is given by a filter cake, which is commonly consisted of a bentonite, barite and high molecular weight polymer such as polyacrylamide (PAM) from the drilling process. Therefore, finding an efficient and environment-friendly method to degrade PAM to remove the filter cake before the cementing is highly desired. In this study, a fast and effective method for high molecular weight PAM (Mw = 3 x 107 Da) degradation by an oxidizing OH-/persulfate (PS) system is presented. By optimizing the PS concentration, alkali-to-PS ratio and temperature of the oxidizing solution, it is demonstrated that a high PAM degradation efficiency (nearly 90%) can be obtained within 20 minutes and maintain a pH range suitable for cement casting. The degradation reactions conformed to pseudo-first-order kinetics with an activation energy of 59.87 kJ mol-1. Dominant radicals were analyzed by EPR that both SO4 center dot- and HO center dot were found in the reaction system, but the HO center dot played the dominant role in the degradation process. Structure transformation of PAM was studied via GPC, SEM and FTIR. The backbone cleavage and detachment of side groups caused structural failure of polymer-bentonite and make possible removing filter cake. Filter cake removal test demonstrated at least 81% filter cake could be removed under the optimized condition. It's more effective than ordinary preflush with only 24wt% on average. The results obtained in this work exhibit that polymer degradation by OH-/PS oxidizing system highly helps to filter cake removal and the OH-/PS system is a promising method for filter cake removal before the cementing process.",17,18,12
Drilling Fluid,Filter Cake,"Zhao, Xin; Qiu, Zhengsong; Wang, Mingliang; Xu, Jiangen; Huang, Weian",Experimental investigation of the effect of drilling fluid on wellbore stability in shallow unconsolidated formations in deep water,Deepwater unconsolidated formation; Wellbore stability; Experimental method; Drilling fluid; Wellbore stabilizer; Silicate; Aluminum complex,COMPOSITE; MECHANISM; SURFACE; SHALES; MODEL,"Wellbore instability in shallow unconsolidated formations is a great challenge to deepwater oil and gas drilling operations. Traditional experimental methods for evaluating wellbore stability cannot effectively simulate the cementation and consolidation effects of the drilling fluid on unconsolidated formations. To overcome this problem, this paper proposes an experimental device and method for evaluating the effect of drilling fluids on wellbore stability in deepwater shallow unconsolidated formations. The effects of some typical drilling fluid wellbore stabilizers on wellbore stability in such formations were examined using the needle penetration, permeability, and compressive strength as the evaluation indexes. The results exhibited favorable repeatability with the proposed method. The deepwater formation was simulated by using quartz sand with a particle size range of 450 mu m-300 mu m (40-60 mesh) and a sand-to-clay ratio of 7:3. The compressive strength and needle penetration of the rock sample cannot be effectively improved with conventional shale inhibitors such as KCl and polyamine, as they are unable to cement and consolidate the wellbore. By contrast, the use of silicates and aluminum complex can effectively reduce the needle penetration and permeability of the rock sample, and can simultaneously enhance its compressive strength by approximately 18%, thus significantly enhancing wellbore stability in unconsolidated formations in deep water. When encountering formation water with a low pH value and Mg2+/Ca2+ ions in the formation, aluminum complex can produce Al(OH)(3) and humic acid precipitates, which can cement the wellbore and enhance the compactness of the filter cake, thus improving wellbore stability.",13,13,6
Drilling Fluid,Flow Rate,"Zhao, Xin; Qiu, Zhengsong; Sun, Baojiang; Liu, Shujie; Xing, Xijin; Wang, Mingliang",Formation damage mechanisms associated with drilling and completion fluids for deepwater reservoirs,Formation damage; Deepwater reservoir; Drilling and completion fluids; Sensitivity damage; Invasion of solid and filtrate; Rock-fluid incompatibilities,INVASION; FILTRATE; QUALITY; SHALE; MODEL; BASIN,"Immense oil and gas reserves exist in the deepwater of the South China Sea, and the first priority for implementing successful drilling and completion operations without reservoir damage is to understand the damaging mechanisms to the reservoir formation. With the use of deepwater reservoir cores from the western South China Sea, the mineral composition, microstructure, porosity, and permeability characteristics of the reservoir formation were analyzed. With the use of core flow tests, potential fluid sensitivity was analyzed to determine how and which fluids can damage the reservoir formation during drilling and completion. The results show that the reservoir formation is composed of unconsolidated siltstone with a clay mineral content of 6-19%, and has high porosity and permeability with large pore throats. Sensitivity damage due to the increasing flow rate is strong, and an unusual salinity sensitivity exists with a critical salinity at 40,000-45,000 mg/L. Moderate alkali fluids sensitivity damage exists, with water sensitivity being weak. The main mechanisms of formation damage by drilling and completion fluids were analyzed as following: plugging of pore throats by solid invasion occurs because the sizes of the solid materials in the drilling fluids are just ideal for the formation of an external filter. Rock-fluid incompatibilities occur due to the increasing flow rate and salinity of the fluids because the formation rock is unconsolidated and the fines will easily detach and migrate, plugging the pore throats. Therefore, effective temporary plugging of the pore throats with a large diameter is important for protecting the reservoir. This study provides basic data for the design and implementation of reservoir protection measures in deepwater oil and gas exploration.",73,75,6
Drilling Fluid,Flow Rate,"Boyou, Natalie Vanessa; Ismail, Issham; Sulaiman, Wan Rosli Wan; Haddad, Amin Sharifi; Husein, Norhafizuddin; Hui, Heah Thin; Nadaraja, Kathigesu",Experimental investigation of hole cleaning in directional drilling by using nano-enhanced water-based drilling fluids,Directional drilling; Hole cleaning; Cuttings transport efficiency; Nano-enhanced drilling fluids,CUTTINGS-TRANSPORT; NANOPARTICLES; PERFORMANCE; MUD,"Inadequate hole cleaning often leads to challenges in drilling and well completion operations such as low rates of penetration, pipe sucking, losing tools, difficulties in liner/casing placements, etc. Designing a drilling fluid with improved rheological properties would be a solution to increase cuttings transportation efficiency. This study investigates the performance of nanosilica water-based drilling fluids for the hole cleaning process in directional drilling operations. Different inclination angles have been considered in a flow loop system with different rotational speeds (0 and 150 rpm) to simulate the drilling conditions in a wellbore. The performance of nano-enhanced drilling fluids in the cuttings removal process was compared with conventional water-based drilling fluids, and it was found that silica nanoparticles increased the cuttings transport efficiency in all experiments. The results indicated that the presence of nanosilica in the mud increased the colloidal interactions with cuttings and contributed to the improvements in cuttings transportation efficiency by 30.8-44% for different nano-enhanced water-based drilling fluids used in this study. The implementation of nanosilica in water-based drilling fluids showed promising results in the hole cleaning process which demonstrates the feasibility of using them in extended reach drilling operations.",71,71,15
Drilling Fluid,Flow Rate,"Soares, Cesar; Gray, Kenneth",Real-time predictive capabilities of analytical and machine learning rate of penetration (ROP) models,Rate of penetration; ROP modeling; Real-time retraining; Machine learning; PDC bit,PRESSURE; BOURGOYNE,"Real-time drilling optimization consists of selecting operational parameters that maximize a desirable measure of drilling performance. Drilling optimization efforts often aspire to improve drilling speed, commonly referred to as rate of penetration (ROP). Three operational drilling parameters may be constantly adjusted at surface to influence ROP: weight on bit (WOB), drillstring rotational speed (RPM), and drilling fluid (mud) flow rate. In the traditional, analytical approach to ROP modeling, inflexible equations relate WOB, RPM, flow rate and/or other measurable drilling parameters to ROP and empirical model coefficients are computed for each rock formation to best fit field data. Over the last decade, enhanced data acquisition technology and widespread cheap computational power have driven a surge in applications of machine learning (ML) techniques to ROP prediction. Machine learning algorithms leverage statistics to uncover relations between any prescribed inputs (features/predictors) and the quantity of interest (response). The biggest advantage of ML algorithms over analytical models is their flexibility in model form. With no set equation, ML models permit segmentation of the drilling operational parameter space. However, the increased model complexity diminishes interpretability of how an adjustment to the inputs will affect the output. There is no single ROP model applicable in every situation. This study investigates real-time predictive capabilities of analytical and ML ROP models in a continuous learning setting. Data are constantly recorded as a well is drilled, and it is postulated that ROP models can learn and adapt in real-time to become more accurate. Novel learning metrics demonstrate that machine learning models reduce test error much more effectively than analytical models with incremental training data availability. Both analytical and ML model performance improves with shortened retraining intervals, defined either by length or number of data points. Cross-validation is investigated as a methodology to select the best performing ROP model in real-time.",42,42,8
Drilling Fluid,Flow Rate,"Gbadamosi, Afeez O.; Junin, Radzuan; Abdalla, Yassir; Agi, Augustine; Oseh, Jeffrey O.",Experimental investigation of the effects of silica nanoparticle on hole cleaning efficiency of water-based drilling mud,Water-based mud; Drilling fluid; Cuttings transports; Nanotechnology; Cuttings sizes; Nanosilica,ENHANCED OIL-RECOVERY; FILTRATION PROPERTIES; OXIDE NANOPARTICLES; CUTTINGS TRANSPORT; FLUIDS; PERFORMANCE; NANOSILICA; BEADS,"Effective cuttings transports and hole cleaning is crucial for obtaining an efficient drilling operation. Recently, the use of nanotechnology have been exploited to improve rheological and filtration properties of water-based mud. Herein, water-based mud (WBM) was formulated with nanosilica to enhance cuttings and solid particles transports from the wellbore to the surface. Different weight percent concentrations of nanosilica (0.001-1.5 wt %) at three different flow rates in litres/seconds (0.4, 0.6 and 1.0) and cuttings sizes (small, medium and large) were used to investigate the formulated water-based mud lifting capacity of the drilled cuttings. Experimental results show that addition of the nanosilica concentrations to the WBM enhances the viscosity, thereby increasing the muds carrying and circulating capacity. Moreover, nanosilica water-based mud (n-WBM) displays improved mud stability with high propensity to prevent intrusion of formation fluids. The effect of cuttings size on the wellbore cleaning is minimal. The large cuttings size shows a lower degree of cuttings transportation compared with the small and medium cutting size. Accordingly, the small cuttings size has higher cuttings recovery to the surface. Finally, though increase in flow rate leads to more cuttings recovery, there is every tendency that much fluid flow rate will cause an increase in frictional pressure losses and equivalent circulating density, high pump pressure requirement and potential hole erosion.",33,33,1
Drilling Fluid,Flow Rate,"Renteria, A.; Maleki, A.; Frigaard, I. A.; Lund, B.; Taghipour, A.; Ytrehus, J. D.",Effects of irregularity on displacement flows in primary cementing of highly deviated wells,Well integrity; Cementing; Fluid-fluid displacement; Experiment; Simulation,NON-NEWTONIAN FLUID; WELLBORE COMPLETION FLUIDS; NARROW ECCENTRIC ANNULI; CASING MOVEMENT; EXPANSIONS; MODEL; OIL,"Anywhere between 0% and 80% of primary cemented wells have integrity failures. Strong local variability suggests both geological and operational factors. One way geology affects cementing is via irregular wellbores, e.g. washouts. Here we study the effects of washouts on mud removal in strongly inclined wellbores, experimentally and via 2-D computational simulations, with the aim of identifying key control parameters. Experiments were performed with 2 fluids with properties representative of drilling mud and cement (or spacer), displaced at constant flow rate through a 10 m long annular flow loop. One downstream section of annulus had an enlarged outer diameter to mimic a wellbore with a washout. In the uniform horizontal sections, the density difference promotes slumping towards the bottom, while eccentricity promotes flow along the wide side of the annulus. At inclinations less than horizontal the slumping tendency is reduced. This competition between slumping and eccentricity is affected by the washout. In most of the experiments the mud was removed from the washout, but the simulations showed this is not true for higher yield stress muds than those tested experimentally: residual fluid was left in the washout section. The simulations also provide detailed information on the evolution of the fluid-fluid interfaces as they pass through the annulus and washout.",16,16,2
Drilling Fluid,Flow Rate,"Bavoh, Cornelius B.; Yuha, Yasmine Binti Md; Tay, W. H.; Ofei, Titus Ntow; Lal, Bhajan; Mukhtar, Hilmi",Experimental and modelling of the impact of quaternary ammonium salts/ionic liquid on the rheological and hydrate inhibition properties of xanthan gum water-based muds for drilling gas hydrate-bearing rocks,Gas hydrate sediments; Rheology; Drilling mud; Quaternary ammonium salts/ionic liquid; Classical nucleation theory; Xanthan gum,DUAL FUNCTION INHIBITORS; IONIC LIQUIDS; COSMO-RS; METHANE; NUCLEATION; FLUIDS; GLYCOL,"In this study, quaternary ammonium salts (QAS) and ionic liquid (IL) were used as additives in xanthan gum water-based muds formulations to investigate their rheological and hydrate inhibitive potentials in drilling gas hydrate sediment. The QAS/IL used were TMABr, TP(r)ABr, TMACl, and EMIMCl. The mud rheological characterisation was performed at a controlled shear rate of 1 s(-1) to 200 s(-1) at -2 degrees C-40 degrees C. The hydrate test was conducted in a high-pressure reactor at 8 MPa and -2 degrees C. The hydrate nucleation onset time was predicted using the classical nucleation theory (CNT) model. The rheology and hydrate results confirmed the potential application of QAS/IL in drilling mud formulations for drilling hydrate sediments. The presence of QAS/IL in the base mud suitably reduced the mud viscosity and yield stress, which are desired properties for generating turbulent flow to enhance cuttings transport, especially in high angle wellbores. The rheological properties of water-based mud were found to be significantly controlled or affected by the cation, anion, and alkyl chain length type of QAS/IL. However, the anion effect is more dominant and exhibit a critical concentration depending on its respective ionic strength. Further FTIR analysis confirmed the presence of N-O stretching which supports the performance of TMA(+) over EMIM+ to reduce the mud yield stress. In addition, the thermal degradation of the base mud was significantly reduced in the presence of QAS/IL. Amongst the studied additives, TMACl and TP(r)ABr WBMs completely prevented hydrate plugs in the mud system. Furthermore, the CNT model accurately predicted the hydrate onset time with APE < 2%. The QAS/IL in the WBM systems exhibited minimal to negligible disturbance (< 0.5 K shift) on the methane hydrate phase boundary compared with commercial hydrate additives at 3 wt%. This study provides guidelines to design efficient QAS/IL WBMs for drilling gas hydrate rocks.",14,14,5
Drilling Fluid,Drill Pipe,"Boyou, Natalie Vanessa; Ismail, Issham; Sulaiman, Wan Rosli Wan; Haddad, Amin Sharifi; Husein, Norhafizuddin; Hui, Heah Thin; Nadaraja, Kathigesu",Experimental investigation of hole cleaning in directional drilling by using nano-enhanced water-based drilling fluids,Directional drilling; Hole cleaning; Cuttings transport efficiency; Nano-enhanced drilling fluids,CUTTINGS-TRANSPORT; NANOPARTICLES; PERFORMANCE; MUD,"Inadequate hole cleaning often leads to challenges in drilling and well completion operations such as low rates of penetration, pipe sucking, losing tools, difficulties in liner/casing placements, etc. Designing a drilling fluid with improved rheological properties would be a solution to increase cuttings transportation efficiency. This study investigates the performance of nanosilica water-based drilling fluids for the hole cleaning process in directional drilling operations. Different inclination angles have been considered in a flow loop system with different rotational speeds (0 and 150 rpm) to simulate the drilling conditions in a wellbore. The performance of nano-enhanced drilling fluids in the cuttings removal process was compared with conventional water-based drilling fluids, and it was found that silica nanoparticles increased the cuttings transport efficiency in all experiments. The results indicated that the presence of nanosilica in the mud increased the colloidal interactions with cuttings and contributed to the improvements in cuttings transportation efficiency by 30.8-44% for different nano-enhanced water-based drilling fluids used in this study. The implementation of nanosilica in water-based drilling fluids showed promising results in the hole cleaning process which demonstrates the feasibility of using them in extended reach drilling operations.",71,71,15
Drilling Fluid,Drill Pipe,"Skadsem, Hans Joakim; Kragset, Steinar; Lund, Bjornar; Ytrehus, Jan David; Taghipour, Ali",Annular displacement in a highly inclined irregular wellbore: Experimental and three-dimensional numerical simulations,Displacement; Annulus; Viscoplastic fluids; Geometry; Washout,NARROW ECCENTRIC ANNULI; VISCOPLASTIC FLUID DISPLACEMENTS; TRAVELING-WAVE SOLUTIONS; NON-NEWTONIAN FLUID; CONCENTRIC ANNULUS; COMPLETION FLUIDS; CEMENT PLACEMENT; CASING MOVEMENT; INNER-CYLINDER; LAMINAR-FLOW,"Primary cementing of well casings is the operation where drilling fluid is displaced from the annulus between the casing and the drilled rock formation and replaced by a cement slurry. The annulus to be cemented is normally narrow and eccentric, and the formation wall may exhibit irregular geometric features such as local enlargements or washouts, originating from the drilling process and varying geological properties. Eccentricity and the presence of wellbore irregularities can lead to residual, non-displaced drilling fluid or mixing of the cement slurry with other wellbore fluids, causing contamination and failure to hydraulically isolate the annulus outside the casing. We study non-Newtonian fluid displacement in an irregular annulus experimentally and numerically for concentric and eccentric configurations of the inner pipe, and for horizontal and slanted orientations of the annulus. An overgauge section simulates a washed out zone in the wellbore. Eccentricity promotes fluid flow in the wide sector of the annulus, leading to an axial elongation of the interface between the two fluids. Depending on eccentricity and inclination, residual non-displaced fluid remains in different parts of the hole enlargement, while inclination from the horizontal is found to improve the fluid displacement in the enlarged section. The experiments and simulations agree well for the tests where the annulus is slanted, with simulations replicating displacement trends and arrival times measured in experiments. The quantitative difference between experiment and simulation is larger for the horizontal and concentric annulus tests. We discuss modelling assumptions and experiment uncertainties that can explain the observed differences.",27,27,0
Drilling Fluid,Drill Pipe,"Davoodi, Shadfar; Ramazani, Ahmad S. A.; Soleimanian, Alireza; Jahromi, Arash Fellah",Application of a novel acrylamide copolymer containing highly hydrophobic comonomer as filtration control and rheology modifier additive in water-based drilling mud,Drilling fluid; Acrylamide styrene copolymer; Starch; Filtration behavior; Rheological characteristics,FLUID-LOSS; POLYMER; NANOPARTICLES; REDUCER; SILICA,"Deep wells suffer from the instability and disintegration of natural polymers and other commonly used additives under high pressure and high temperature condition. As a result, serious problems such as hydraulic loss, stuck pipe, and high torque and drag are expected to take place which leads to a dramatic increase in cost and time. This study presents the functionality of a novel synthetic based acrylamide-styrene copolymer (SBASC) as a supersede additive for water-based drilling mud. First, the SBASC was synthesized using an emulsion polymerization process and its particle morphological and polymer chain structural properties were determined by Field Emission Scanning Electron Microscopy (FESEM) and Fourier-Transform Infrared Spectroscopy (FTIR), respectively. Then, the designated copolymer was added into a mud formulation which is applicable in oil and gas fields, and its performance in the mud was investigated with respect to filtration properties and rheological characteristics. In addition, the rheological characteristics and filtration behavior of drilling fluids containing SBASC were compared with those of a field applicable fluid that contained 9 g of HT starch which is a commercial natural polymer commonly used in drilling fluid industry. Furthermore, the thermal stability of SBASC was determined by conducting hot rolling and high pressure-high temperature (HP-HT) filtration tests. The obtained results confirmed that the addition of the copolymer enhances the rheological characteristics of the drilling fluid before and after aging at 121.1 degrees C. Moreover, the filtration behavior at both conditions was improved by introducing SBASC into the fluid, while the best performance was observed for the fluid containing 3 g of SBASC which shows 38.8% and 47.5% fluid loss reduction for HP-HT and LP-LT conditions, respectively. Furthermore, the solubility of SBASC in saline and fresh water is verified by demonstrating a promising solubility in high salinity water sample with different concentrations of a monovalent salt.",23,25,7
Drilling Fluid,Drill Pipe,"Heshamudin, Nursyafiqah S.; Katende, Allan; Rashid, Halimatun A.; Ismail, Issham; Sagala, Farad; Samsuri, Ariffin",Experimental investigation of the effect of drill pipe rotation on improving hole cleaning using water-based mud enriched with polypropylene beads in vertical and horizontal wellbores,Cuttings size; Cuttings transport ratio; Hole angles; Hole cleaning; Pipe rotation; Water-based mud,CUTTINGS TRANSPORT BEHAVIOR; FLUID; CFD; SIMULATION; OIL; POLYETHYLENE; PERFORMANCE; EFFICIENCY; VISCOSITY; IMPACT,"Field experience has shown that the inefficient transport of small cuttings is a main factor contributing to excessive drag and torque during the drilling of a deviated hole; however, very little is known about the transport behavior of small cuttings. This experimental study investigates the effect of different polypropylene bead concentrations in water-based mud (WBM) on hole cleaning, along with the effects of cutting size, drill pipe rotation, and hole inclination angle. A total of 160 runs were performed using an experimental rig consisting of a 13 ft (3.96 m) long casing with a 2 in (50.8 mm) Inner Diameter (ID) and a rotary inner pipe with a 0.8 in (20 mm) Outer Diameter (OD). Four cutting size ranges, namely, 0.5-1.0 mm, 1.0-1.4 mm, 1.4-1.7 mm, and 1.7-2.0 mm, with a density of 2400 kg/m(3) were tested in WBM with varying polypropylene bead concentrations ranging from 0 to 8 ppb. The concentric annulus flow test section was changed to vertical and horizontal angles with pipe rotation from 0 to 150 rpm. The mud density and viscosity were maintained at 10 ppg and 16 cp, respectively, under a flow velocity of 3.48 m/s (Reynolds number of 6620). The results indicate that smaller cuttings are easier to transport at all pipe rotations and polypropylene bead concentrations in both vertical and horizontal holes. The optimal pipe rotational speed was found to be 60 rpm. In this study, polypropylene beads undeniably enhanced the mud carrying capacity by significantly increasing the cutting transport ratio (CTR) by up to 16.57% in vertical holes and 15.73% in horizontal holes.",22,23,0
Drilling Fluid,Drill Pipe,"Pang, Boxue; Wang, Shuyan; Jiang, Xiaoxue; Lu, Huilin",Effect of orbital motion of drill pipe on the transport of non-Newtonian fluid-cuttings mixture in horizontal drilling annulus,Cuttings transport; Orbital motion; Non-Newtonian fluid; Drill pipe rotation; Secondary flow; Pressure drop,SOLID-LIQUID FLOW; KINETIC-THEORY; NUMERICAL PREDICTION; VIRTUAL MASS; SIMULATION; BEHAVIOR; CYLINDER; ROTATION; MODEL,"The effect of orbital motion of drill pipe on the transport of non-Newtonian fluid and cuttings is simulated by means of the two-fluid model in combination with the kinetic theory of granular flow in the horizontal wellbore annulus. The drill pipe self-rotates around its own axis while pursuing a circular orbit around the axis of the wellbore annulus, in which the orbital radius is the eccentric distance of the drill pipe from the axis of the wellbore. The embedded sliding mesh method is adopted to achieve the effect of the orbital movement of the drill pipe wall on the liquid-solid mixture. The cuttings transport ratio (CTR) which is defined as the ratio of the concentration of injected cuttings to the concentration of cuttings retained in the annulus is chosen as the measurement to evaluate hole cleaning. Cuttings transport behaviors in the annuli with the four motion states of drill pipe are investigated respectively. Simulations indicate that if the drill pipe is not concentric, there must be the fluid force that causes the lateral movement of drill pipe when it rotates. The orbital motion of drill pipe improves cuttings transport ratio in the annulus due to the periodical stirring and entrainment effect on cutting particles. The tangential flow within the annulus is dominated by the orbital motion of drill pipe rather than the self-rotation. The secondary flow appears especially when the self-rotation and orbital motion of drill pipe are in the opposite direction. With the increase of the orbital radius, the cuttings transport ratio is improved and the pressure drop is reduced because of the agitation of the drill string against the flow field. Increasing the rotating speed of the drill pipe contributes to a better wellbore cleaning, while an excessive rotating speed causes a higher pressure drop. Although the orbital motion of the drill pipe improves the hole cleaning, it also greatly increases the resistance and resultant moment exerted by the liquid-solid mixture, especially at high rotation speeds and eccentricity ratios.",21,22,9
Drilling Fluid,Hole Cleaning,"Boyou, Natalie Vanessa; Ismail, Issham; Sulaiman, Wan Rosli Wan; Haddad, Amin Sharifi; Husein, Norhafizuddin; Hui, Heah Thin; Nadaraja, Kathigesu",Experimental investigation of hole cleaning in directional drilling by using nano-enhanced water-based drilling fluids,Directional drilling; Hole cleaning; Cuttings transport efficiency; Nano-enhanced drilling fluids,CUTTINGS-TRANSPORT; NANOPARTICLES; PERFORMANCE; MUD,"Inadequate hole cleaning often leads to challenges in drilling and well completion operations such as low rates of penetration, pipe sucking, losing tools, difficulties in liner/casing placements, etc. Designing a drilling fluid with improved rheological properties would be a solution to increase cuttings transportation efficiency. This study investigates the performance of nanosilica water-based drilling fluids for the hole cleaning process in directional drilling operations. Different inclination angles have been considered in a flow loop system with different rotational speeds (0 and 150 rpm) to simulate the drilling conditions in a wellbore. The performance of nano-enhanced drilling fluids in the cuttings removal process was compared with conventional water-based drilling fluids, and it was found that silica nanoparticles increased the cuttings transport efficiency in all experiments. The results indicated that the presence of nanosilica in the mud increased the colloidal interactions with cuttings and contributed to the improvements in cuttings transportation efficiency by 30.8-44% for different nano-enhanced water-based drilling fluids used in this study. The implementation of nanosilica in water-based drilling fluids showed promising results in the hole cleaning process which demonstrates the feasibility of using them in extended reach drilling operations.",71,71,15
Drilling Fluid,Hole Cleaning,"Gbadamosi, Afeez O.; Junin, Radzuan; Abdalla, Yassir; Agi, Augustine; Oseh, Jeffrey O.",Experimental investigation of the effects of silica nanoparticle on hole cleaning efficiency of water-based drilling mud,Water-based mud; Drilling fluid; Cuttings transports; Nanotechnology; Cuttings sizes; Nanosilica,ENHANCED OIL-RECOVERY; FILTRATION PROPERTIES; OXIDE NANOPARTICLES; CUTTINGS TRANSPORT; FLUIDS; PERFORMANCE; NANOSILICA; BEADS,"Effective cuttings transports and hole cleaning is crucial for obtaining an efficient drilling operation. Recently, the use of nanotechnology have been exploited to improve rheological and filtration properties of water-based mud. Herein, water-based mud (WBM) was formulated with nanosilica to enhance cuttings and solid particles transports from the wellbore to the surface. Different weight percent concentrations of nanosilica (0.001-1.5 wt %) at three different flow rates in litres/seconds (0.4, 0.6 and 1.0) and cuttings sizes (small, medium and large) were used to investigate the formulated water-based mud lifting capacity of the drilled cuttings. Experimental results show that addition of the nanosilica concentrations to the WBM enhances the viscosity, thereby increasing the muds carrying and circulating capacity. Moreover, nanosilica water-based mud (n-WBM) displays improved mud stability with high propensity to prevent intrusion of formation fluids. The effect of cuttings size on the wellbore cleaning is minimal. The large cuttings size shows a lower degree of cuttings transportation compared with the small and medium cutting size. Accordingly, the small cuttings size has higher cuttings recovery to the surface. Finally, though increase in flow rate leads to more cuttings recovery, there is every tendency that much fluid flow rate will cause an increase in frictional pressure losses and equivalent circulating density, high pump pressure requirement and potential hole erosion.",33,33,1
Drilling Fluid,Hole Cleaning,"Al-yasiri, Mortatha; Awad, Afrah; Pervaiz, Shahid; Wen, Dongsheng",Influence of silica nanoparticles on the functionality of water-based drilling fluids,Biopolymer; Rheology; Filtration; Swelling; Hole cleaning,XANTHAN GUM; NANOCOMPOSITE; COMPOSITE; POLYACRYLAMIDE; PERFORMANCE; ADSORPTION; STABILITY,"Using nanoparticles into a drilling fluid (mud) is a promising technique that could solve a range of problems presently encountered during drilling operations. This paper reports the development of a novel drilling fluid using a biopolymer/nanoparticle mixture to improve the performance of a water-based mud (WBM) formulation, enhancing rheological, filtration and lubrication properties. The xanthan gum- SiO2 mixture developed is proposed as a solution to operating challenges in drilling operation, with the synergistic properties of nanoparticles and polymer offering desirable properties. The novel nanofluids characterised by scanning electron microscope, X-ray diffraction, Fourier transform infrared spectroscopy and thermal-gravimetric analysis. The modified drilling fluids were found to have higher yield point, beneficial for hole cleaning, showed less filtrate loss and more bit lubrication than conventional WBM formulations. Properly engineered, nanoparticles could improve the performance of presently deployed drilling fluids significantly.",26,26,2
Drilling Fluid,Hole Cleaning,"Heshamudin, Nursyafiqah S.; Katende, Allan; Rashid, Halimatun A.; Ismail, Issham; Sagala, Farad; Samsuri, Ariffin",Experimental investigation of the effect of drill pipe rotation on improving hole cleaning using water-based mud enriched with polypropylene beads in vertical and horizontal wellbores,Cuttings size; Cuttings transport ratio; Hole angles; Hole cleaning; Pipe rotation; Water-based mud,CUTTINGS TRANSPORT BEHAVIOR; FLUID; CFD; SIMULATION; OIL; POLYETHYLENE; PERFORMANCE; EFFICIENCY; VISCOSITY; IMPACT,"Field experience has shown that the inefficient transport of small cuttings is a main factor contributing to excessive drag and torque during the drilling of a deviated hole; however, very little is known about the transport behavior of small cuttings. This experimental study investigates the effect of different polypropylene bead concentrations in water-based mud (WBM) on hole cleaning, along with the effects of cutting size, drill pipe rotation, and hole inclination angle. A total of 160 runs were performed using an experimental rig consisting of a 13 ft (3.96 m) long casing with a 2 in (50.8 mm) Inner Diameter (ID) and a rotary inner pipe with a 0.8 in (20 mm) Outer Diameter (OD). Four cutting size ranges, namely, 0.5-1.0 mm, 1.0-1.4 mm, 1.4-1.7 mm, and 1.7-2.0 mm, with a density of 2400 kg/m(3) were tested in WBM with varying polypropylene bead concentrations ranging from 0 to 8 ppb. The concentric annulus flow test section was changed to vertical and horizontal angles with pipe rotation from 0 to 150 rpm. The mud density and viscosity were maintained at 10 ppg and 16 cp, respectively, under a flow velocity of 3.48 m/s (Reynolds number of 6620). The results indicate that smaller cuttings are easier to transport at all pipe rotations and polypropylene bead concentrations in both vertical and horizontal holes. The optimal pipe rotational speed was found to be 60 rpm. In this study, polypropylene beads undeniably enhanced the mud carrying capacity by significantly increasing the cutting transport ratio (CTR) by up to 16.57% in vertical holes and 15.73% in horizontal holes.",22,23,0
Drilling Fluid,Hole Cleaning,"Pang, Boxue; Wang, Shuyan; Jiang, Xiaoxue; Lu, Huilin",Effect of orbital motion of drill pipe on the transport of non-Newtonian fluid-cuttings mixture in horizontal drilling annulus,Cuttings transport; Orbital motion; Non-Newtonian fluid; Drill pipe rotation; Secondary flow; Pressure drop,SOLID-LIQUID FLOW; KINETIC-THEORY; NUMERICAL PREDICTION; VIRTUAL MASS; SIMULATION; BEHAVIOR; CYLINDER; ROTATION; MODEL,"The effect of orbital motion of drill pipe on the transport of non-Newtonian fluid and cuttings is simulated by means of the two-fluid model in combination with the kinetic theory of granular flow in the horizontal wellbore annulus. The drill pipe self-rotates around its own axis while pursuing a circular orbit around the axis of the wellbore annulus, in which the orbital radius is the eccentric distance of the drill pipe from the axis of the wellbore. The embedded sliding mesh method is adopted to achieve the effect of the orbital movement of the drill pipe wall on the liquid-solid mixture. The cuttings transport ratio (CTR) which is defined as the ratio of the concentration of injected cuttings to the concentration of cuttings retained in the annulus is chosen as the measurement to evaluate hole cleaning. Cuttings transport behaviors in the annuli with the four motion states of drill pipe are investigated respectively. Simulations indicate that if the drill pipe is not concentric, there must be the fluid force that causes the lateral movement of drill pipe when it rotates. The orbital motion of drill pipe improves cuttings transport ratio in the annulus due to the periodical stirring and entrainment effect on cutting particles. The tangential flow within the annulus is dominated by the orbital motion of drill pipe rather than the self-rotation. The secondary flow appears especially when the self-rotation and orbital motion of drill pipe are in the opposite direction. With the increase of the orbital radius, the cuttings transport ratio is improved and the pressure drop is reduced because of the agitation of the drill string against the flow field. Increasing the rotating speed of the drill pipe contributes to a better wellbore cleaning, while an excessive rotating speed causes a higher pressure drop. Although the orbital motion of the drill pipe improves the hole cleaning, it also greatly increases the resistance and resultant moment exerted by the liquid-solid mixture, especially at high rotation speeds and eccentricity ratios.",21,22,9
Drilling Fluid,Clay Swelling,"Zhong, Hanyi; Shen, Guangcheng; Qiu, Zhengsong; Lin, Yongxue; Fan, Lijun; Xing, Xiaodong; Li, Jia",Minimizing the HTHP filtration loss of oil-based drilling fluid with swellable polymer microspheres,Oil-based drilling fluid; Filtration; Swellable polymer; High temperature; Microsphere,PERFORMANCE; ADDITIVES,"Filtration control of drilling fluid plays an important role in the process of well-bore construction and ensures the success of drilling operation. A swellable polymer microsphere (SPM) of methylmethacrylate (MMA), butyl acrylate (BA), and lauryl methacrylate (LMA) was synthesized with suspension polymerization. Its swelling property was characterized by oil adsorption capacity measurement. First, the effect of SPM on the filtration and rheological properties of virgin organic clay dispersion was investigated. Then the filtration and rheological properties of mineral oil-based drilling fluid in the presence of SPM were elucidated under the respective conditions of hot aging temperature, oil to water ratio and density. Furthermore, the filtration control properties between SPM and two traditional filtration loss additives including modified lignite and asphaltic additive was compared. Addition of SPM exhibited obvious influence on the viscosity of oil-based drilling fluid especially at high concentration of 3 w/v%, therefore, a concentration of lower than 1.5 w/v% was recommended. After hot aging at 200 degrees C, the oil-based drilling fluid containing 1 w/v% SPM exhibited an API filtration loss decrease of 85%, and HTHP filtration loss decrease of 79% in comparison with the base fluid. After hot rolling at 180 degrees C, the API filtration loss decreased by 2%, 24% and 53%, and the HTHP filtration loss decreased by 42%, 54% and 65% respectively when 1 w/v% asphaltic additive, modified lignite and SPM are in the presence of the base fluid. Besides decreasing the filtration loss volume under high temperatures, incorporation of SPM also improves the filter cake quality of oil-based drilling fluid. SPM is capable of adsorbing considerable base oil and become swellable. The swellable polymer microspheres with favorably deformable and compressible properties can effectively fill the voids of filter cake and reduce the permeability, which leads to low filtration loss and minimization of solids invasion.",44,44,7
Drilling Fluid,Clay Swelling,"Ghasemi, Mehdi; Moslemizadeh, Aghil; Shahbazi, Khalil; Mohammadzadeh, Omid; Zendehboudi, Sohrab; Jafari, Sina",Primary evaluation of a natural surfactant for inhibiting clay swelling,Ginsenosides; Biosurfactant; Clay swelling inhibitor; Wettability; Compatibility,WELLBORE STABILITY; SHALE HYDRATION; REDUCING ADSORPTION; ANIONIC SURFACTANT; MODIFIED BENTONITE; IONIC LIQUID; WATER; GINSENG; COPOLYMER; MONTMORILLONITE,"Water-based drilling muds, a more environment-friendly candidate than oil-based drilling muds, are wildly used for drilling oil and gas wells. When water-based drilling mud is used for drilling formations with shale containing active clay constituents, it is challenging to preserve stability of the borehole due to clay swelling unless proper inhibition mechanisms are foreseen. In the current study, the feasibility of using Korean red Ginseng root extract was assessed as a clay swelling inhibitor. This root extract is rich in non-ionic surfactants such as Ginsenosides Rg3, Rg5, and RK1, and is referred to as ""biosurfactant"" throughout this manuscript. After preparation of mud systems containing problematic clay particles, the clay-swelling inhibition performance of the biosurfactant was systematically investigated through a series of tests, including mud formation, filtration, immersion, sedimentation assisted with optical microscopy, wettability by sessile drop technique, use of thermal gravimetric analysis (TGA), scanning electron microscopy (SEM) and Fourier-transform infrared spectroscopy (FTIR), and shale cuttings recovery. The clay-swelling inhibition performance of the biosurfactant was then compared against two clay swelling inhibitors namely CTAB (Cetrimonium bromide, a known cationic surfactant) and potassium chloride. There are some properties associated with the mud systems prepared with biosurfactant solution which makes this product unique. These properties include: remarkable loading capacity of sodium montmorillonite (Mt) which in turn resulted in low rheological profile, poor fluid loss control, creation of stable Mt pellets, creation of larger size and aggregated Mt particles with less hydrophilicity, creation of fully unstable dispersed Mt particles that resulted in good sedimentation over time, less mass loss, and higher shale cuttings recovery, all compared to the baseline fluid made without the presence of biosurfactant. The results of this study indicate that the biosurfactant provides excellent clay swelling inhibition properties, comparable to known inhibitors. The biosurfactant's compatibility with other drilling mud components was also checked, and it was found that the fluid properties are independent of the biosurfactant. The wettability and FTIR analyses were also performed to investigate the mechanisms involved in clay swelling inhibition of the biosurfactant, which are believed to be as a result of coating the clay active surfaces with a hydrophobic layer, hence repelling the water phase. This hydrophobic layer is probably formed by interactions of the hydrophilic group of the Ginsenosides and the oxygen atoms available on the Mt surfaces, when the hydrophobic tail is oriented toward the aqueous phase.",30,30,0
Drilling Fluid,Clay Swelling,"Chu, Qi; Lin, Ling; Zhao, Yukun",Hyperbranched polyethylenimine modified with silane coupling agent as shale inhibitor for water-based drilling fluids,Silane coupling agent; Hyperbranched polyethylenimine; Shale inhibitor; Adsorption; Water-based drilling fluid; Application,POLYETHER DIAMINE; ADSORPTION; BENTONITE; MECHANISM; HYDRATION; AMINE; CORE,"Hyperbranched polyethylenimine modified with a silane coupling agent (Si-HPEI) as a shale inhibitor was synthesized by the Michael addition reaction of hyperbranched polyethylenimine (HPEI) and methacryloxypropyltrimethoxysilane. The structure of Si-HPEI was characterized by Fourier transform infrared spectroscopy and proton nuclear magnetic resonance. The inhibitory properties of Si-HPEI in comparison with currently available inhibitors were evaluated using linear swelling tests, cuttings dispersion tests, and bentonite inhibition tests. The inhibitory mechanism was investigated via X-ray diffraction measurements, adsorption measurements, and atomic force microscopy observations. The results indicated that Si-HPEI effectively inhibited the hydration and expansion of shale and exhibited excellent temperature resistance in comparison with HPEI and traditional shale inhibitors. The shale cuttings recovery in the case of Si-HPEI remained above 68% up to a hot rolling aging temperature of 140 degrees C, which demonstrated an excellent ability to inhibit hydration and dispersion that was significantly less affected by the hot rolling aging temperature than in the cases of other inhibitors. In addition, Si-HPEI inhibited the formation of a bentonite slurry more effectively at high temperatures. A mechanistic analysis showed that the siloxane groups present in the molecular chains of Si-HPEI caused strong and stable chemical adsorption of Si-HPEI on water-sensitive clay minerals, which thus hindered the penetration of water molecules and ultimately inhibited the hydration expansion and dispersion of water-sensitive clay minerals. In field application, Si-HPEI was successfully applied on Su 4-4HF well.",16,17,6
Drilling Fluid,Clay Swelling,"Sharifipour, M.; Nakhaee, A.; Pourafshary, P.",Model development of permeability impairment due to clay swelling in porous media using micromodels,LSW flooding; Clay swelling; Permeability impairment; Micromodel; Image processing,OIL-RECOVERY FACTOR; CAPILLARY-PRESSURE; WATER; GAS; MONTMORILLONITE; WETTABILITY; SURFACE,"Swelling and displacement of clay minerals during drilling and production of oil and gas reservoirs are among the main mechanisms of formation damage. Most reservoirs contain clay minerals, either originally deposited during sedimentation phase, or precipitated from fluids flowing through matrix. Owing to the large specific surface area of clay particles, their swelling, detachment, and migrationmay lead to permeability impairment in porous media. Therefore, an accurate interpretation of the behaviour of clay particles in the porous media may enable us to prevent and possibly reverse the respective damage mechanisms. In this work, the pore-scale swelling behaviour of clays are studied using glass micro models as porous medium and Sodium bentonite as swelling clay. By image processing technique, effective porosity of model during low salinity water (LSW) flooding are estimated. The effect of different parameters such as porous medium aspect ratio and clay concentration on permeability impairment is studied. According to this study, besides higher clay concentrations, the permeability is also affected adversely by larger aspect ratio of pore bodies. Based on our experiments, a model is developed to estimate permeability impairment by clay swelling as a function of pore geometry and clay concentration.",14,14,2
Drilling Fluid,Hydraulic Fractures,"Meng, M.; Baldino, S.; Miska, S. Z.; Takach, N.",Wellbore stability in naturally fractured formations featuring dual-porosity/single-permeability and finite radial fluid discharge,Wellbore stability; Fractures; Dual-porosity/single-permeability; Hemisphere plot,MECHANICAL-PROPERTIES; CONSOLIDATION; SHALE; BOREHOLE; MEDIA,"This work presents an analytical solution for an inclined wellbore drilled in a fractured formation displaying a high contrast between the diffusion rates in the fractures and in the porous matrix, with the latter treated as a storage phase and thus not participating in the fluid transport. This scenario may result from different mud cake building rates, and/or adverse wettability of the rock matrix with respect to the drilling fluid being used. Different from the models available in the literature, the fractures are characterized by a more realistic finite radial fluid discharge (namely, the fractures network hydraulically connected to the wellbore is of limited extent). The models output in terms of pore pressures, total stresses and effective stresses response has been compared with the results of a widely accepted dual-porosity/dual-permeability model. Major differences and asymptotic behaviors have been analyzed. Subsequently, the results of the model have been used to perform a comprehensive wellbore stability analysis. The effect of time dependency, fractures network length and rock properties on the instability of the borehole have been investigated, and upper and lower mud weight bounds have been determined using several failure criteria. This investigation shows that under the specified conditions where dual-porosity/single-permeability conditions arise, the proposed model provides with theoretically more conservative mud weights predictions.",48,50,6
Drilling Fluid,Hydraulic Fractures,"Wang, Shuhua; Chen, Zan; Chen, Shengnan",Applicability of deep neural networks on production forecasting in Bakken shale reservoirs,Production forecasting; Bakken formation; Deep neural networks; Hyperparameter optimization; Global sensitivity analysis,NEWTON OPTIMIZATION METHOD; TIGHT-OIL; GAS-PRODUCTION; MODEL; PREDICTION; DESIGN; STEAM,"The unconventional shale and tight formations, such as the Bakken in Williston Basin, are becoming an important hydrocarbon sources since the development of advanced horizontal drilling and multi-stage stimulation techniques. The appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery. Although reservoir simulations are commonly used for production analysis, the modeling of hydraulic fractures and intrinsic complexity of shale have restricted an understanding of the fluid flow behavior. Owing to the available of a large amount of data in unconventional tight and shale reservoirs, data-driven approaches, such as deep neural networks (DNNs), provide an alternative approach for production analysis in these formations. In this study, a total of 2919 wells including 2780 multi-stage hydraulic fractured horizontal wells and 139 vertical wells in Bakken Formation were collected and analyzed using a deep learning method and Sobol's global sensitivity analysis. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, and batch normalization were evaluated to develop a reliable deep neural network model. Moreover, k -fold cross validation was used to evaluate the prediction ability and robustness of models. Prior to the performance evaluation of DNN algorithms, an optimum DNN model was achieved by optimizing the dropout layer, activation function, and hyperparameters of DNN models. It is found that the number of hidden layers and neurons in each layer have significant effects on the performance of models. The optimized DNN model has 3 hidden layers and 200 neurons for each layer. The prediction performance of DNN models is acceptable with the low mean squared errors for both 6- and 18-months cumulative oil productions. Furthermore, the importance of each parameter was studied using the Sobol's analysis. Results show that the average proppant placed per stage is the most important parameter, which accounts for more than 35% of variability in both 6- and 18-months cumulative oil productions. These data-driven models can be readily updated when the new well information becomes available. It is worth mentioning that the proposed DNN models can be directly integrated into existing hydraulic fracturing design routines.",35,37,5
Drilling Fluid,Hydraulic Fractures,"Li, Tianjiao; Li, Lianchong; Tang, Chun'an; Zhang, Zilin; Li, Ming; Zhang, Liaoyuan; Li, Aishan",A coupled hydraulic-mechanical-damage geotechnical model for simulation of fracture propagation in geological media during hydraulic fracturing,HMD; Numerical simulation; Unsteady flow; Hydraulic fracturing; Stress shadow effect,FINITE-ELEMENT-METHOD; NUMERICAL MANIFOLD METHOD; FLUID-FLOW; CUBIC LAW; POROUS-MEDIA; ROCK; STRESS; DISCONTINUITY; COALESCENCE; CONTINUUM,"This paper proposed a coupled hydraulic-mechanical-damage (HMD) geotechnical model for simulating the entire failure process in geological media. In this model, elastic damage mechanics describes the damage process of elements. Darcy's Law and unsteady seepage flow equation describe fluid flow in elements, where compression of fluid and rock are considered. The coupled process is fulfilled by Biot's consolidation theory describing how pore-pressure affects the stress field and the stress/aperture/mesh-dependent permeability that represents the influence of stress on seepage field. The HMD model is implemented in the calculation module of Rock-Failure-Process-Analysis on Petroleum-problems (RFPA-Petrol) codes. The RFPA suite of software codes is based on the idea that the heterogeneity leads to non-linearity and causes progressive failure behavior observed in brittle rock. The capability of RFPA-Petrol simulator is demonstrated by a typical coupled problem related to double fractures propagation during hydraulic fracturing. This simulation successfully reproduces the asynchronous initiation, asymmetric growth and non-equal deflection of fractures in the numerical model. Then this simulator was used to investigate how fracture spacing and horizontal stress ratio influence propagation and reorientation of three hydraulic fractures from a horizontal well. At last, a horizontal well drilled by SHENGLI oilfield is simulated to certificate RFPA-Petrol's ability on field-scale models. It is found that larger fracture spacing and higher initial fracture height will form longer and wider fractured zones. HMD-based RFPA-Petrol is suitable for simulation of laboratory scale and field scale fracture propagation problems.",26,27,5
Drilling Fluid,Hydraulic Fractures,"Khanal, Aadi; Weijermars, Ruud",Pressure depletion and drained rock volume near hydraulically fractured parent and child wells,Depth of investigation; Drained rock volume; Well interference; Eagle ford; Complex analysis methods; Velocity plots,FLOOD DISPLACEMENT FRONTS; EAGLE FORD SHALE; INTERFERENCE; RESERVOIRS; HISTORY; MULTIWELL; TEXAS; OIL,"Field development of unconventional reservoirs tends to downsize well spacing when commercial success of a shale play is proven. The earlier, so-called parent wells are joined by infill wells, commonly called child wells. Tighter well spacing improves the recovery factor but the risk of well interference increases. The flow interference and pressure communication of adjoining wells via the matrix and their hydraulic fractures was investigated using the depth of investigation and associated pressure depletion plots. A sensitivity analysis shows how the depth of investigation in an unconventional reservoir is impacted by matrix permeability, other fluid properties, and time lapse between drilling of parent and child wells. In all cases, the extent of the drained region of a reservoir with hydraulic fractures is controlled by the fluid particle paths guided by the depth of investigation and time-of-flight contours. Time-of-flight contours visualize the reservoir drainage by parent and child wells using complex analysis methods (CAM) in a case study of the Eagle Ford shale. Even after 30 years of production, the actual drained rock volume (DRV) remains small and lags the depth of investigation. A commercial numerical reservoir simulator provides history matched inputs for the CAM tool which then can model the flow near the discrete fractures in the reservoir at high resolution. The developed procedure provides a computationally efficient method to quantify and visualize the DRV for parent and child wells in hydraulically fractured reservoirs. Fluid particle tracking provides a practical method to determine fracture and well-interference in combination with depth of investigation and pressure depletion studies.",18,18,0
Drilling Fluid,Shale Inhibitor,"Ghasemi, Mehdi; Moslemizadeh, Aghil; Shahbazi, Khalil; Mohammadzadeh, Omid; Zendehboudi, Sohrab; Jafari, Sina",Primary evaluation of a natural surfactant for inhibiting clay swelling,Ginsenosides; Biosurfactant; Clay swelling inhibitor; Wettability; Compatibility,WELLBORE STABILITY; SHALE HYDRATION; REDUCING ADSORPTION; ANIONIC SURFACTANT; MODIFIED BENTONITE; IONIC LIQUID; WATER; GINSENG; COPOLYMER; MONTMORILLONITE,"Water-based drilling muds, a more environment-friendly candidate than oil-based drilling muds, are wildly used for drilling oil and gas wells. When water-based drilling mud is used for drilling formations with shale containing active clay constituents, it is challenging to preserve stability of the borehole due to clay swelling unless proper inhibition mechanisms are foreseen. In the current study, the feasibility of using Korean red Ginseng root extract was assessed as a clay swelling inhibitor. This root extract is rich in non-ionic surfactants such as Ginsenosides Rg3, Rg5, and RK1, and is referred to as ""biosurfactant"" throughout this manuscript. After preparation of mud systems containing problematic clay particles, the clay-swelling inhibition performance of the biosurfactant was systematically investigated through a series of tests, including mud formation, filtration, immersion, sedimentation assisted with optical microscopy, wettability by sessile drop technique, use of thermal gravimetric analysis (TGA), scanning electron microscopy (SEM) and Fourier-transform infrared spectroscopy (FTIR), and shale cuttings recovery. The clay-swelling inhibition performance of the biosurfactant was then compared against two clay swelling inhibitors namely CTAB (Cetrimonium bromide, a known cationic surfactant) and potassium chloride. There are some properties associated with the mud systems prepared with biosurfactant solution which makes this product unique. These properties include: remarkable loading capacity of sodium montmorillonite (Mt) which in turn resulted in low rheological profile, poor fluid loss control, creation of stable Mt pellets, creation of larger size and aggregated Mt particles with less hydrophilicity, creation of fully unstable dispersed Mt particles that resulted in good sedimentation over time, less mass loss, and higher shale cuttings recovery, all compared to the baseline fluid made without the presence of biosurfactant. The results of this study indicate that the biosurfactant provides excellent clay swelling inhibition properties, comparable to known inhibitors. The biosurfactant's compatibility with other drilling mud components was also checked, and it was found that the fluid properties are independent of the biosurfactant. The wettability and FTIR analyses were also performed to investigate the mechanisms involved in clay swelling inhibition of the biosurfactant, which are believed to be as a result of coating the clay active surfaces with a hydrophobic layer, hence repelling the water phase. This hydrophobic layer is probably formed by interactions of the hydrophilic group of the Ginsenosides and the oxygen atoms available on the Mt surfaces, when the hydrophobic tail is oriented toward the aqueous phase.",30,30,0
Drilling Fluid,Shale Inhibitor,"Xu, Jian-gen; Qiu, Zhengsong; Zhao, Xin; Zhong, Hanyi; Huang, Weian",Study of 1-Octyl-3-methylimidazolium bromide for inhibiting shale hydration and dispersion,Shale inhibitor; Ionic liquid; Adsorption; Inhibition mechanism; Hydrophobic,DRILLING-FLUIDS; IONIC LIQUID; WATER,"In recent years, developing high-performance shale inhibitors with excellent shale swelling and dispersion inhibition properties has attracted great interests in the drilling industry. 1-Octyl-3-methylimidazolium bromide (OMB), a common imidazolium-based ionic liquid, was introduced as a promising shale inhibitor. Shale hydration inhibition capacity was investigated via sodium bentonite (Na-BT) plate soaking test, linear swelling experiment and hot-rolling dispersion experiment. The inhibition mechanism was analyzed by Fourier transforms infrared spectroscopy (FT-IR) analysis, X-ray diffraction (XRD) analysis, thermogravimetric (TGA) analysis, contact angle test, zeta potential test and surface tension measurement. The results demonstrated the shale hydration inhibition property of OMB was obviously superior to other widely used shale inhibitors. OMB could be easily adsorbed onto sodium montmorillonite (MMT) through electrostatic interaction, and some interlayer water molecules were expelled due to its intercalation. Meanwhile, the surface of MMT became more hydrophobic after adsorbed by OMB, and an effective shield against water intrusion was formed. In addition, OMB could effectively reduce the surface tension even at low concentrations, and a lower capillary suction pressure could be beneficial for reducing fluid invasion. The results obtained from the work indicated that OMB had the potential to become a high-performance shale inhibitor for drilling shale formations.",20,21,3
Drilling Fluid,Shale Inhibitor,"Chu, Qi; Lin, Ling; Zhao, Yukun",Hyperbranched polyethylenimine modified with silane coupling agent as shale inhibitor for water-based drilling fluids,Silane coupling agent; Hyperbranched polyethylenimine; Shale inhibitor; Adsorption; Water-based drilling fluid; Application,POLYETHER DIAMINE; ADSORPTION; BENTONITE; MECHANISM; HYDRATION; AMINE; CORE,"Hyperbranched polyethylenimine modified with a silane coupling agent (Si-HPEI) as a shale inhibitor was synthesized by the Michael addition reaction of hyperbranched polyethylenimine (HPEI) and methacryloxypropyltrimethoxysilane. The structure of Si-HPEI was characterized by Fourier transform infrared spectroscopy and proton nuclear magnetic resonance. The inhibitory properties of Si-HPEI in comparison with currently available inhibitors were evaluated using linear swelling tests, cuttings dispersion tests, and bentonite inhibition tests. The inhibitory mechanism was investigated via X-ray diffraction measurements, adsorption measurements, and atomic force microscopy observations. The results indicated that Si-HPEI effectively inhibited the hydration and expansion of shale and exhibited excellent temperature resistance in comparison with HPEI and traditional shale inhibitors. The shale cuttings recovery in the case of Si-HPEI remained above 68% up to a hot rolling aging temperature of 140 degrees C, which demonstrated an excellent ability to inhibit hydration and dispersion that was significantly less affected by the hot rolling aging temperature than in the cases of other inhibitors. In addition, Si-HPEI inhibited the formation of a bentonite slurry more effectively at high temperatures. A mechanistic analysis showed that the siloxane groups present in the molecular chains of Si-HPEI caused strong and stable chemical adsorption of Si-HPEI on water-sensitive clay minerals, which thus hindered the penetration of water molecules and ultimately inhibited the hydration expansion and dispersion of water-sensitive clay minerals. In field application, Si-HPEI was successfully applied on Su 4-4HF well.",16,17,6
Drilling Fluid,Shale Inhibitor,"Zhao, Xin; Qiu, Zhengsong; Wang, Mingliang; Xu, Jiangen; Huang, Weian",Experimental investigation of the effect of drilling fluid on wellbore stability in shallow unconsolidated formations in deep water,Deepwater unconsolidated formation; Wellbore stability; Experimental method; Drilling fluid; Wellbore stabilizer; Silicate; Aluminum complex,COMPOSITE; MECHANISM; SURFACE; SHALES; MODEL,"Wellbore instability in shallow unconsolidated formations is a great challenge to deepwater oil and gas drilling operations. Traditional experimental methods for evaluating wellbore stability cannot effectively simulate the cementation and consolidation effects of the drilling fluid on unconsolidated formations. To overcome this problem, this paper proposes an experimental device and method for evaluating the effect of drilling fluids on wellbore stability in deepwater shallow unconsolidated formations. The effects of some typical drilling fluid wellbore stabilizers on wellbore stability in such formations were examined using the needle penetration, permeability, and compressive strength as the evaluation indexes. The results exhibited favorable repeatability with the proposed method. The deepwater formation was simulated by using quartz sand with a particle size range of 450 mu m-300 mu m (40-60 mesh) and a sand-to-clay ratio of 7:3. The compressive strength and needle penetration of the rock sample cannot be effectively improved with conventional shale inhibitors such as KCl and polyamine, as they are unable to cement and consolidate the wellbore. By contrast, the use of silicates and aluminum complex can effectively reduce the needle penetration and permeability of the rock sample, and can simultaneously enhance its compressive strength by approximately 18%, thus significantly enhancing wellbore stability in unconsolidated formations in deep water. When encountering formation water with a low pH value and Mg2+/Ca2+ ions in the formation, aluminum complex can produce Al(OH)(3) and humic acid precipitates, which can cement the wellbore and enhance the compactness of the filter cake, thus improving wellbore stability.",13,13,6
Machine Learning,Seismic Attributes,"Sun, Jian; Li, Qi; Chen, Mingqiang; Ren, Long; Huang, Guihua; Li, Chenyang; Zhang, Zixuan",Optimization of models for a rapid identification of lithology while drilling-A win-win strategy based on machine learning,Machine learning; Lithologic identification while drilling; Optimization; Correlation analysis,SUPPORT VECTOR MACHINE; RANDOM FORESTS; SEISMIC ATTRIBUTES; NEURAL-NETWORK; TRAINING DATA; CLASSIFICATION; ALGORITHMS; PERFORMANCE; INTEGRATION; PREDICTION,"The identification of lithology from well log data is an important task in petroleum exploration and development. However, due to the complexity of the sedimentary environment and reservoir heterogeneity, the traditional lithology identification methods can not meet the needs of real-time and accurate prediction and identification with logging while drilling (LWD) equipment. The basic data of this paper are derived from conventional wireline logging (CWL) data and the LWD data in Yan'an Gas Field. The main research goal is to compare and analyse three popular machine learning algorithms, which are one-versus-rest support vector machines (OVR SVMs), one-versus-one support vector machines (OVO SVMs) and random forest (RF), and to optimize a more practical method in the field for LWD systems. To reduce the dimensions of the input data, the characteristic parameters of the training data are obtained by a correlation analysis of the logging data. The optimal parameter values of each algorithm are determined by grid search method and 10-fold cross-validation method. On this basis, the lithology predictions of the actual LWD data are carried out by using three classifiers. Considering the time consumption of the model training and the lithology identification accuracy of the model, the best lithology identification model while drilling is selected. The results show that the characteristic parameters of the training data after the correlation analysis are AC, CAL, GR, K, RD and SP logs. The overall classification and recognition performance of the RF classifier is better than that of the other two classifiers, and its accuracy is even greater than 90%. The evaluation matrix shows that the OVR SVMs and RF classifiers yield lower prediction errors than the OVO SVMs classifier in each single lithology identification, but the RF classifier spends much less time in the training process. Based on the comprehensive comparative analysis, it is considered that the RF classifier has the characteristics of a short training time and high recognition accuracy in practical production applications, so it is an ideal optimization classifier for lithology identification while drilling. The research results provide not only a theoretical basis for the drilling geosteering of oilfield development but also valuable information for future basic research.",24,24,10
Machine Learning,Seismic Attributes,"Anifowose, Fatai; Abdulraheem, Abdulazeez; Al-Shuhail, Abdullatif",A parametric study of machine learning techniques in petroleum reservoir permeability prediction by integrating seismic attributes and wireline data,Computational intelligence; Reservoir characterization; Seismic attributes; Wireline log; Depth-matching; Global averaging,FUZZY-LOGIC; FUNCTIONAL NETWORKS; SYSTEMS,"One of the recipes for the big data and artificial intelligence paradigms is multi-dimensional data integration for improved decision making in petroleum reservoir characterization. Various machine learning (ML) techniques have been applied. However, there is still ample room for improvement. This paper carries out a rigorous parametric study to investigate the comparative performance of common and sophisticated ML techniques in the estimation of the permeability of a carbonate reservoir in the Middle East. The study integrates seismic attributes and wireline data for improved permeability prediction. The effects of tuning hyperparameters on the performance of the techniques are also studied. The techniques are evaluated on two versions of the seismic-log integrated data: globally-averaged and depth-matched. The results show that using the depth-matched dataset gives marginal improvement on the permeability prediction as reflected in the higher correlation coefficient and lower errors than the globally-averaged version. The outcome of this study will assist users of ML techniques to make informed choices on the appropriate ML techniques to use in petroleum reservoir characterization for more accurate predictions and better decision making especially when faced with limited and sparse data.",18,19,1
Machine Learning,Seismic Attributes,"Li, Wei; Yue, Dali; Wang, Wenfeng; Wang, Wurong; Wu, Shenghe; Li, Jian; Chen, Depo",Fusing multiple frequency-decomposed seismic attributes with machine learning for thickness prediction and sedimentary facies interpretation in fluvial reservoirs,Fluvial reservoirs; Spectral decomposition; Seismic attributes; Machine learning; RGB blending; Sand thickness,MANSURI OIL-FIELD; BOHAI BAY BASIN; PROSPECT IDENTIFICATION; 90-DEGREES-PHASE WAVELETS; SPECTRAL DECOMPOSITION; SEQUENCE STRATIGRAPHY; WELL LOGS; INVERSION; SHALE; CLASSIFICATION,"Defining the boundaries, thicknesses and sedimentary facies of fluvial reservoirs (sand bodies) is critical for predicting hydrocarbon volumes, designing schemes for petroleum exploration and development and improving oil recovery. Most reservoirs contain thick and thin sand bodies at the same intervals, while the amplitude values of seismic data usually highlight sand bodies near the 1/4 wavelength for the tuning phenomena. Hence, the application of spectral decomposition to seismic attributes and the combination of multiple frequency-decomposed (spectral-decomposed) seismic attributes have gained increasing attention for the readjustment of tuning thickness to predict sand bodies of various thicknesses. However, the popular method of red-green-blue blending is a simple linear combination of three frequency-decomposed seismic attributes that qualitatively analyzes the sand thickness without well-log interpretation. This research proposes machine learning fusion as a new nonlinear method for fusing high-, middle-, and low-frequency seismic attributes. This method uses machine learning to link well-log interpretation and multiple-frequency seismic attributes for the quantitative prediction of sand thickness, which is important for development work in a mature field. Test results of the conceptual model and the real case indicate that the predicted sand thickness after fusing multiple frequency-decomposed seismic attributes is approximately in line with the actual thickness (correlations between 80 and 90%). Combined with the coherence attribute and the red-green-blue blending results, the distributions and histories of sedimentary facies are analyzed based on the predicted sand thickness and well data. The results suggest that the proposed method can effectively readjust the tuning thickness and improve the resolution of seismic interpretation. This method is a potentially effective technique to characterize the sand thickness and sedimentary facies in other fields using a similar geological setting and dataset.",17,17,10
Machine Learning,Seismic Attributes,"Ao, Yile; Li, Hongqi; Zhu, Liping; Ali, Sikandar; Yang, Zhongguo",Identifying channel sand-body from multiple seismic attributes with an improved random forest algorithm,Machine learning; Random forest; Ensemble learning; Seismic interpretation; Channel identification,MARCELLUS SHALE LITHOFACIES; REMOTE-SENSING DATA; NEURAL-NETWORKS; RESERVOIR CHARACTERIZATION; MINERAL PROSPECTIVITY; PREDICTION; POROSITY; CLASSIFICATION; MODELS; IDENTIFICATION,"Machine learning provides numerous data-driven tools for automatic pattern recognition. Even though various algorithms such as neural networks and support vector machines have been widely applied, it is still necessary to explore new paradigms and algorithms to improve the machine learning assisted seismic interpretation. Random Forest (RF) is a widely used ensemble algorithm, however, only limited studies of random forest in the seismic application were published. In this article, the methodology of random forest is introduced systematically. Meanwhile, to solve the problem of hyper-parameter determination, we propose an improved algorithm named Pruning Random Forest (PRF). To reveal the advantages of PRF in terms of predictive performance, robustness, and feature selection compared with support vector machine, neural network, and decision tree, several well-designed experiments are executed based on the seismic data of the western Bohai Sea of China. The potential and advantages of random forest in the present case are confirmed by various experiments, which substantiates that the proposed pruning random forest algorithm provides a reliable alternative way for further machine learning assisted seismic interpretation.",14,16,7
Machine Learning,Seismic Attributes,"Geng, Zhi; Wang, Hanqing; Fan, Meng; Lu, Yunhu; Nie, Zhen; Ding, Yunhong; Chen, Mian",Predicting seismic-based risk of lost circulation using machine learning,Machine learning; Lost circulation; Seismic attribute; Mud loss; Seismic interpretation,CURVATURE,"Lost circulation during well drilling and completion wastes productive time, and even kills the well in severe cases. Timely identifying lost circulation events and taking countermeasures has been the focus of related study. However, a real prediction of lost circulation risk before drilling would be an active response to the challenge. In this paper, a technical solution is proposed to evaluate geological lost-circulation risk in the field using 3D seismic data attributes and machine learning technique. First, four seismic attributes (variance, attenuation, sweetness, RMS amplitude) that are the most correlated with lost circulation incidents are recommended. Then a prediction model is built by conducing supervised learning that involves a majority voting algorithm. The performance of the model is illustrated by six unseen drilled wells and shows the ability and potential to forecast lost circulation probability both along well trajectory and in the region far away from the drilled wells. The prediction resolution in the lateral and vertical direction is about 25 m and 6 m (2 ms), respectively, which are distinct advantages over the traditional description of geological structures using seismic data. It shows that the lost circulation risk can be hardly recognized by interpreting one specific seismic attribute, which is a common practice. Finally, the challenges in predicting lost circulation risk using seismic data are summarized. Overall, the study suggests that machine learning would be a practical solution to predict various construction risks that are related to seismic-based geological issues. Knowing in advance the risks, people could avoid or at least minimize the losses by optimizing well deployment in the field and taking preventive measures.",14,16,5
Machine Learning,Regression,"Ao, Yile; Li, Hongqi; Zhu, Liping; Ali, Sikandar; Yang, Zhongguo",The linear random forest algorithm and its advantages in machine learning assisted logging regression modeling,Machine learning; Logging interpretation; Logging regression modeling; Linear random forest; Algorithm comparison,SUPPORT-VECTOR-REGRESSION; PETROLEUM RESERVOIR CHARACTERIZATION; ARTIFICIAL NEURAL-NETWORKS; PERMEABILITY PREDICTION; GENETIC-ALGORITHM; WATER SATURATION; WIRELINE LOGS; FUZZY-LOGIC; POROSITY; INDUCTION,"Direct measurements of formation properties such as the shale volume, porosity, permeability, and fluid saturation are often accompanied by expensive cost and are time-consuming too. Well logging inversion provides an alternative way for the determination of formation properties. Compared to traditional theoretical models or formalized empirical fitted models, machine learning assisted logging regression modeling is more accurate and objective. Several machine learning regression algorithms such as neural networks, support vector regression, fuzzy logic, k nearest neighbors regression, multivariate adaptive regression spline, and random forest have already been applied. In this article, we present the Linear Random Forest algorithm and investigate its application in logging regression modeling. By systematic comparison with 8 other algorithms including least squared linear regression, neural networks, epsilon support vector regression, k nearest neighbors regression, regression tree, regression random forest, gradient descent boosted trees, and linear decision tree, the advantage of linear random forest in performance is confirmed by 24 real-world tasks from 7 different areas. Deeper discussions reveal that the advantages of linear random forest source from its strong learning ability, robustness, and feasibility of the hypothesis space. Through our study, the superiority of linear random forest for logging regression modeling is substantiated, which provides a more reasonable way for the further practices of logging regression modeling.",38,41,24
Machine Learning,Regression,"Ahmed, Omogbolahan S.; Adeniran, Ahmed A.; Samsuri, Ariffin",Computational intelligence based prediction of drilling rate of penetration: A comparative study,ROP prediction; Neural network; Least square support vector regression; Specific energy; Drilling efficiency; Extreme learning machine,EXTREME LEARNING-MACHINE; SUPPORT VECTOR MACHINES,"Application of artificial intelligence in the accurate prediction of the rate of penetration (ROP), an important measure of drilling performance, has lately gained significant interest in oil and gas well drilling operations. Consequently, several computational intelligence techniques (CITs) for the prediction of ROP have been explored in the literature. This study explores the predictive capabilities of four commonly used CITs in the pre- diction of ROP and experimentally compare their predictive performance. The CIT algorithm utilizes predictors which are easily accessible continuous drilling data that have physical but complex relationship with ROP based on hydro-mechanical specific energy ROP model. The four CITs compared are the artificial neural network (ANN), extreme learning machine, support vector Regression and least-square support vector regression (LSSVR). Two experiments were carried out; the first experiment investigates the comparative performance of the CITs while the second investigates the effect of reduced number of predictors on the performance of the models. The results show that all the CITs perform within acceptable accuracy with testing root mean square error range (RMSE) of 18.27-28.84 and testing correlation coefficient (CC) range of 0.71-0.94. LS-SVR has the best predictive performance in terms of accuracy with RMSE of 18.27 and CC of 0.94 while ANN has the best testing execution time at 0.03 s. Also utilizing the specific energy concept in chosen drilling parameters to be included among the predictors shows improved performance with five drilling parameters showing an improvement of 3%-9% in RMSE for LS-SVR in the two well studied. The utilization of the specific energy concept in the selection of the predictors in this study has demonstrated that the easily accessible drilling parameters have immense value to provide acceptable performance in the development of ROP model with CITs.",35,35,6
Machine Learning,Regression,"Anemangely, Mohammad; Ramezanzadeh, Ahmad; Amiri, Hamed; Hoseinpour, Seyed-Ahmad",Machine learning technique for the prediction of shear wave velocity using petrophysical logs,Shear wave velocity estimation; Machine learning; Outlier detection; Feature selection; Optimization algorithm,EMPIRICAL RELATIONS; RESERVOIR; ALGORITHM,"Compressional wave velocity (Vp) and shear wave velocity (Vs) are widely used as quick, easy to use, and cost-effective means of determining the mechanical properties of formations in the petroleum industry. However, shear wave logs are only available in a limited number of wells in an oil field due to the high cost of the log acquisition. For this reason, many attempts have been made to find a correlation between Vs and other petrophysical logs. In this study, a set of log data consisting of depth, neutron porosity (NPHI), density (RHOB), photoelectric (PEF), gamma ray (GR), caliper, true resistivity (RT), V-p, and Vs were used to develop a model for Vs estimation in a well drilled in Ahvaz field. For this purpose, Tukey's method was employed to preprocess the data and eliminate outliers. Then, using the Non-dominated Sorting Genetic Algorithm II (NSGA-II), the best features were selected among the inputs to estimate Vs. Results indicate that increasing the number of input parameters of the model leads to an increase in accuracy and determination coefficient; however, this increase was negligible for the models with more than five input parameters. These parameters, i.e., V-p, RT, GR, RHOB, and NPHI, were selected as the best features to estimate Vs adopting Least Square Support Vector Machine (LSSVM) combined with Particle Swarm Optimization (PSO), Genetic Algorithm (GA), and Cuckoo Optimization Algorithm (COA). Results obtained from modeling reveal that LSSVM-COA algorithm produces a more accurate estimate of V-s compared to LSSVM-PSO and LSSVM-COA in both training and testing steps. In addition, a very slight difference between the error in testing and training steps suggests a higher reliability of LSSVM-COA compared to two other hybrid algorithms. Comparing this model with empirical and regression ones clearly showed that the model error is considerably less than those models. Eventually, another set of data gathered in Ab-Teymour field was used to evaluate the model from the perspective of generalizability. Similarly, V-s estimation by LSSVM-COA model provided more reliable and accurate results compared to those of empirical and regression models, and also LSSVM-PSO and LSSVM-GA algorithms. Finally, it can be concluded that the method employed in this study could be used as an efficient means to accurately estimate Vs.",31,32,2
Machine Learning,Regression,"Wang, Pan; Peng, Suping",On a new method of estimating shear wave velocity from conventional well logs,Shear wave velocity; Extreme learning machine; Mean impact value; Artificial intelligence; Conventional well logs; Ordos basin,EXTREME LEARNING-MACHINE; EMPIRICAL RELATIONS; COMPRESSIONAL-WAVE; MIXED SELECTIVITY; NEURAL-NETWORKS; PREDICTION; RESERVOIR; APPROXIMATION; REGRESSION; ALGORITHM,"Shear wave velocity is a critical parameter for the characterization of hydrocarbon reservoirs. Compared with compressional wave velocity which almost exist in every well, shear wave velocity hasn't been recorded in those days for the older wells due to the lack of logging equipment or limited funds. Furthermore, measuring shear wave velocity is fairly time-and money-consuming as it can only be gained by the analysis of core samples conducted in the lab or from the dipole sonic imager (DSI). To cope with the above puzzles, a new methodology, by integrating extreme learning machines (ELM) and technique of mean impact value (MIV), is proposed in this paper with the support of log data collected from two wells located in unconventional shale gas reservoir in Ordos Basin, China. Based on mean impact value, a well-trained ELM model is taken to identify optimal well logs and five well logs are identified to provide the significant and valid information for the estimation of shear wave velocity. 3201 data points collected from well L4 are used in constructing the model. Compared with artificial neural network used in the former studies Levenberg-Marquardt algorithm (ANN-LM), the ELM model's prediction accuracy has been evaluated, the results indicates that the ELM model outperforms ANN-LM model with faster calculating speed and better performance. Additionally, the efficiency of the model proposed here is well investigated by using another well with 3201 data points. Through the comparison among ELM, support vector regression (SVR), convolutional neural network (CNN) and four widely known empirical formulas, what can be concluded is that ELM model is more efficient in fast calculation and high precision. From the result, it can be demonstrated that the use of ELM model, combined with the analysis of mean impact value (MIV), is a more efficient and promising method for shear wave velocity estimation process from conventional well log data, which can be recognized as a promising tool with an extended application. And this research can be applied into a software system for rapid acquisition of shear wave velocity logs.",17,17,4
Machine Learning,Regression,"Hegde, Chiranth; Millwater, Harry; Gra, Ken",Classification of drilling stick slip severity using machine learning,Vibrations; Logistic regression; Gaussian mixture models; Linear discriminant analysis; Machine learning,MODELS,"Rate of penetration (ROP) is a key metric used to monitor the success of drilling a well. It is directly affected by drilling vibrations since excessive vibrations result in a reduction of ROP. Vibration modeling and monitoring is a complex process often requiring many simplifying assumptions that may not always generalize to different BHAs, reservoirs, geology and formations. Therefore, it would be desirable to minimize drill string vibrations using data driven models using readily available drilling data. The hypothesis tested is the classification of stick slip severity due to drilling vibrations using open source machine learning algorithms. The stick slip index (SSI) - measuring the severity of stick slip due to drilling vibrations - is classified as low or high using machine learning classification algorithms such as logistic regression, support vector machines, random forests, gaussian mixture models and discriminant analysis. Each algorithm was evaluated based on classification accuracy, F-1 score and area under the receiver operating characteristic curve (AUC). The random forest algorithm outperforms other algorithms with an average accuracy of 90% (F-1 score of 0.91 and AUC score of 0.89). The classification model can then be used within a ROP optimization model (or framework) to determine optimal operation parameters which do not result in stick-slip conditions while drilling addressing a serious limitation of previously published ROP optimization papers.",14,15,4
Machine Learning,Gas Production,"Wang, Shuhua; Chen, Shengnan",Insights to fracture stimulation design in unconventional reservoirs based on machine learning modeling,Fracture stimulation design; Data mining; Feature selection; Machine learning; Montney tight reservoirs,ARTIFICIAL NEURAL-NETWORKS; GAS-PRODUCTION; NATURAL-GAS; TIGHT OIL; SHALE; OPTIMIZATION,"With rapid development of unconventional tight and shale reservoirs, considerable amounts of data sets are increasing rapidly. Data mining techniques are becoming attractive alternatives for well performance evaluation and optimization. This paper develops a comprehensive data mining process to evaluate well production performance in Montney Formations in western Canadian sedimentary basin. The general data visualization and statistical data evaluation are used to qualitatively and quantitatively evaluate the relationships between the stimulation parameters and first-year oil production. Then, the recursive feature elimination with cross validation (RFECV) is used to identify the most important factors on the first-year oil production in unconventional reservoirs. In addition, four commonly used supervised learning approaches including random forest (RF), adaptive boosting (AdaBoost), support vector machine (SVM), and neural network (NN) are compared to estimate the first-year well production. The results show that 6 features are the most important variables for constructing an accurate prediction model: well latitude, longitude, well true vertical depth (TVD), proppant pumped per well, well lateral length, and fluid injected per well. Compared to other algorithms, RF has the best prediction performance for the first-year oil production. Furthermore, such data-driven models are found to be very useful for reservoir engineers when designing hydraulic fracture treatments in Montney tight reservoirs.",45,46,5
Machine Learning,Gas Production,"Hajizadeh, Yasin",Machine learning in oil and gas; a SWOT analysis approach,Machine learning; Analytics; SWOT; IoT; Transfer learning; Technology,,"Digitalization of workflows using machine learning and advanced analytics is the new go-to strategy to add business value in the oil and gas industry. Enterprises strive to embrace these new technologies; but struggle to put their models in production, deliver tangible results and obtain favorable returns on investment. This paper reviews some of the recent developments and practices in this area and offers a SWOT analysis for strategic management and technology enablement. It is concluded that to reap the full benefits of ML in mission-critical tasks, oil and gas industry must leverage the latest technology developments, have a consistent strategic focus and build agile and collaborative teams of data scientists and domain experts.",29,29,2
Machine Learning,Gas Production,"Sun, Jian; Li, Qi; Chen, Mingqiang; Ren, Long; Huang, Guihua; Li, Chenyang; Zhang, Zixuan",Optimization of models for a rapid identification of lithology while drilling-A win-win strategy based on machine learning,Machine learning; Lithologic identification while drilling; Optimization; Correlation analysis,SUPPORT VECTOR MACHINE; RANDOM FORESTS; SEISMIC ATTRIBUTES; NEURAL-NETWORK; TRAINING DATA; CLASSIFICATION; ALGORITHMS; PERFORMANCE; INTEGRATION; PREDICTION,"The identification of lithology from well log data is an important task in petroleum exploration and development. However, due to the complexity of the sedimentary environment and reservoir heterogeneity, the traditional lithology identification methods can not meet the needs of real-time and accurate prediction and identification with logging while drilling (LWD) equipment. The basic data of this paper are derived from conventional wireline logging (CWL) data and the LWD data in Yan'an Gas Field. The main research goal is to compare and analyse three popular machine learning algorithms, which are one-versus-rest support vector machines (OVR SVMs), one-versus-one support vector machines (OVO SVMs) and random forest (RF), and to optimize a more practical method in the field for LWD systems. To reduce the dimensions of the input data, the characteristic parameters of the training data are obtained by a correlation analysis of the logging data. The optimal parameter values of each algorithm are determined by grid search method and 10-fold cross-validation method. On this basis, the lithology predictions of the actual LWD data are carried out by using three classifiers. Considering the time consumption of the model training and the lithology identification accuracy of the model, the best lithology identification model while drilling is selected. The results show that the characteristic parameters of the training data after the correlation analysis are AC, CAL, GR, K, RD and SP logs. The overall classification and recognition performance of the RF classifier is better than that of the other two classifiers, and its accuracy is even greater than 90%. The evaluation matrix shows that the OVR SVMs and RF classifiers yield lower prediction errors than the OVO SVMs classifier in each single lithology identification, but the RF classifier spends much less time in the training process. Based on the comprehensive comparative analysis, it is considered that the RF classifier has the characteristics of a short training time and high recognition accuracy in practical production applications, so it is an ideal optimization classifier for lithology identification while drilling. The research results provide not only a theoretical basis for the drilling geosteering of oilfield development but also valuable information for future basic research.",24,24,10
Machine Learning,Gas Production,"Bhattacharya, Shuvajit; Ghahfarokhi, Payam Kavousi; Carr, Timothy R.; Pantaleone, Scott","Application of predictive data analytics to model daily hydrocarbon production using petrophysical, geomechanical, fiber-optic, completions, and surface data: A case study from the Marcellus Shale, North America",Marcellus Shale; Fiber optic; Data analytics; Machine learning; Predicting gas production,APPALACHIAN BASIN; LITHOFACIES,"Predicting gas production from stimulated unconventional reservoirs has always been a challenge to oil and gas companies because the physics of fluid flow through such reservoirs is not well understood. On the other hand, modeling gas production from shale reservoirs is a complex multi-variate problem that requires proper integration of data from multiple disciplines, such as geology, petrophysics, geomechanics, completions, and surface-based measurements, etc. This study demonstrates the application of data-driven machine learning algorithms, integrating geoscientific, distributed acoustic sensing (DAS), distributed temperature sensing (DTS) fiber-optic, completions, flow scanner production log, and surface data to model daily gas production from a 28-stage stimulated horizontal well drilled in the Marcellus Shale of the Appalachian basin in North America. In addition, this study aims to utilize the data from a fiber-optic monitoring system, such as DAS and DTS to evaluate the well performance. We build supervised data-driven machine learning models using Random Forest (RF), Artificial Neural Network (ANN), and Support Vector Machine (SVM) algorithms to understand the well performance and forecast the daily gas production. The study compares the forecasted results, tests the level of accuracy, and addresses different issues with these machine learning algorithms. A spatio-temporal database is constructed and used to perform sensitivity analyses to identify the key drivers for gas production. The results show that RF and ANN algorithms can be used to predict daily gas production with significantly high accuracy; however, RF algorithm is the best predictor in terms of highest accuracy (96%), less computational time and cost. Based on sensitivity analysis, it appears that Poisson's ratio, minimum horizontal stress, DAS, casing pressure, gamma log are the most important parameters to predict gas production.",14,15,4
Machine Learning,Shale Lithofacies,"Rui, Jianwen; Zhang, Hongbing; Zhang, Dailu; Han, Feilong; Guo, Qiang",Total organic carbon content prediction based on support-vector-regression machine with particle swarm optimization,TOC content; Support vector regress; Delta logR; PSO algorithm,SHALE; LITHOFACIES; RICHNESS; BASIN; MODEL; TOC,"Total organic carbon (TOC) is a significant factor to evaluate the hydrocarbon potential of the unconventional reservoir, while it is difficult to obtain the continuous and accurate prediction result of TOC by traditional methods due to the non-linear relationship between TOC content and wireline log data. However, support vector regress machine is an efficient supervised learning artificial intelligence algorithm, and performs well to deal with non-linear relationship dataset. Therefore, in order to explore a more efficient way for TOC content prediction, the support vector regress machine was tried to predict TOC content through wireline log data. To further verify this, some data tests have been conducted on an offshore exploration prior well data in the northern of Beibu Gulf Basin. After analyzing various kernel functions and optimization methods by cross-validation and error analysis, it can be indicated that the Gaussian kernel function and the particle swarm optimization (PSO) algorithm which used the linear decreasing inertia coefficient and mutated particles are suitable for SVR model and model parameter selection, respectively. Finally, the prediction result of SVR with the best model and model parameters is compared with the results of an improved Delta logR method and multilayer perceptron method. The comparison results show that SVR has a higher correlation coefficient than other methods. In conclusion, the prediction result of SVR can be thought of as an efficient and reliable method for TOC content prediction. Through the continuous prediction of organic carbon content, the qualitative and quantitative evaluation of high-quality source rocks in this area can be realized, which is of great practical significance for determining the exploration field and the search for favorable target reservoirs.",30,32,3
Machine Learning,Shale Lithofacies,"Bhattacharya, Shuvajit; Carr, Timothy R.","Integrated data-driven 3D shale lithofacies modeling of the Bakken Formation in the Williston basin, North Dakota, United States",Bakken formation; Shale lithofacies; Petrophysics; Machine learning; 3D geocellular modeling,MISSISSIPPIAN BAKKEN; ORGANIC-CARBON; FACIES,"Integrated petrophysical analysis is used in conventional and unconventional reservoirs to visualize the distribution pattern of different lithofacies and interpret depositional environments. In this study, core data from 17 wells and well logs from 517 wells are used to construct 3D data-driven lithofacies models for the upper and lower shale members in the Bakken Formation of the Williston basin in North Dakota, United States. The principal objective of this multi-scale (core, well log, and regional) study is to use the petrophysical response of lithofacies defined in core from a very limited number of wells to identify different shale lithofacies in the Bakken Formation in the numerous and geographically extensive wells with wireline log suites. Shale lithofacies are defined in the core using quantitative mineralogy, Total Organic Carbon content, and petrophysical properties. These lithofacies are calibrated to advanced geochemical spectroscopy logs and conventional well logs at well scales. A machine learning algorithm, Support Vector Machine, is used to recognize the pattern of different shale lithofacies, associated with basic petrophysical parameters from ubiquitous conventional well log suites. Sequential Indicator Simulation is used to populate all lithofacies in a 3D grid, covering a large portion of the Williston basin in North Dakota. The results show that the Bakken shale members are vertically and laterally heterogeneous, but are successfully classified into five different lithofacies. Organic-rich shale lithofacies outweigh the proportion of organic-lean shale lithofacies. It appears several factors influenced the pattern of shale lithofacies distribution of the Bakken Formation.",16,17,2
Machine Learning,Shale Lithofacies,"Ao, Yile; Li, Hongqi; Zhu, Liping; Ali, Sikandar; Yang, Zhongguo",Identifying channel sand-body from multiple seismic attributes with an improved random forest algorithm,Machine learning; Random forest; Ensemble learning; Seismic interpretation; Channel identification,MARCELLUS SHALE LITHOFACIES; REMOTE-SENSING DATA; NEURAL-NETWORKS; RESERVOIR CHARACTERIZATION; MINERAL PROSPECTIVITY; PREDICTION; POROSITY; CLASSIFICATION; MODELS; IDENTIFICATION,"Machine learning provides numerous data-driven tools for automatic pattern recognition. Even though various algorithms such as neural networks and support vector machines have been widely applied, it is still necessary to explore new paradigms and algorithms to improve the machine learning assisted seismic interpretation. Random Forest (RF) is a widely used ensemble algorithm, however, only limited studies of random forest in the seismic application were published. In this article, the methodology of random forest is introduced systematically. Meanwhile, to solve the problem of hyper-parameter determination, we propose an improved algorithm named Pruning Random Forest (PRF). To reveal the advantages of PRF in terms of predictive performance, robustness, and feature selection compared with support vector machine, neural network, and decision tree, several well-designed experiments are executed based on the seismic data of the western Bohai Sea of China. The potential and advantages of random forest in the present case are confirmed by various experiments, which substantiates that the proposed pruning random forest algorithm provides a reliable alternative way for further machine learning assisted seismic interpretation.",14,16,7
Machine Learning,Shale Lithofacies,"Bhattacharya, Shuvajit; Ghahfarokhi, Payam Kavousi; Carr, Timothy R.; Pantaleone, Scott","Application of predictive data analytics to model daily hydrocarbon production using petrophysical, geomechanical, fiber-optic, completions, and surface data: A case study from the Marcellus Shale, North America",Marcellus Shale; Fiber optic; Data analytics; Machine learning; Predicting gas production,APPALACHIAN BASIN; LITHOFACIES,"Predicting gas production from stimulated unconventional reservoirs has always been a challenge to oil and gas companies because the physics of fluid flow through such reservoirs is not well understood. On the other hand, modeling gas production from shale reservoirs is a complex multi-variate problem that requires proper integration of data from multiple disciplines, such as geology, petrophysics, geomechanics, completions, and surface-based measurements, etc. This study demonstrates the application of data-driven machine learning algorithms, integrating geoscientific, distributed acoustic sensing (DAS), distributed temperature sensing (DTS) fiber-optic, completions, flow scanner production log, and surface data to model daily gas production from a 28-stage stimulated horizontal well drilled in the Marcellus Shale of the Appalachian basin in North America. In addition, this study aims to utilize the data from a fiber-optic monitoring system, such as DAS and DTS to evaluate the well performance. We build supervised data-driven machine learning models using Random Forest (RF), Artificial Neural Network (ANN), and Support Vector Machine (SVM) algorithms to understand the well performance and forecast the daily gas production. The study compares the forecasted results, tests the level of accuracy, and addresses different issues with these machine learning algorithms. A spatio-temporal database is constructed and used to perform sensitivity analyses to identify the key drivers for gas production. The results show that RF and ANN algorithms can be used to predict daily gas production with significantly high accuracy; however, RF algorithm is the best predictor in terms of highest accuracy (96%), less computational time and cost. Based on sensitivity analysis, it appears that Poisson's ratio, minimum horizontal stress, DAS, casing pressure, gamma log are the most important parameters to predict gas production.",14,15,4
Machine Learning,Lithology,"Imamverdiyev, Yadigar; Sukhostat, Lyudmila",Lithological facies classification using deep convolutional neural network,Well log data; Facies; Facies classification; Deep learning; Convolutional neural network,RESERVOIR; FIELD; ANN,"The aim of this paper is the development of an effective model based on deep learning for geological fades classification in wells. Fades classification is carried out by studying the lithological properties of rocks, which are characteristic of modern sediments, accumulating in certain physical and geographical conditions. In this study, a new 1D-CNN model, which is trained on various optimization algorithms, is proposed. The photoelectric effect, gamma ray, resistivity logging, neutron-density porosity difference, average neutron density porosity and geologic constraining variables are considered as input data of the model. Acceptable accuracy and the use of conventional well log data are the main advantages of the proposed intellectual model. The proposed model is compared with a recurrent neural network model, a long short-term memory model, a support vector machine model, and a k-nearest neighbor model and shows more accurate results in comparison with them. The model shows successful results in the study of well log data and can, therefore, be recommended as a suitable and effective approach for well log data processing required for lithological discrimination.",40,43,5
Machine Learning,Lithology,"Sun, Jian; Li, Qi; Chen, Mingqiang; Ren, Long; Huang, Guihua; Li, Chenyang; Zhang, Zixuan",Optimization of models for a rapid identification of lithology while drilling-A win-win strategy based on machine learning,Machine learning; Lithologic identification while drilling; Optimization; Correlation analysis,SUPPORT VECTOR MACHINE; RANDOM FORESTS; SEISMIC ATTRIBUTES; NEURAL-NETWORK; TRAINING DATA; CLASSIFICATION; ALGORITHMS; PERFORMANCE; INTEGRATION; PREDICTION,"The identification of lithology from well log data is an important task in petroleum exploration and development. However, due to the complexity of the sedimentary environment and reservoir heterogeneity, the traditional lithology identification methods can not meet the needs of real-time and accurate prediction and identification with logging while drilling (LWD) equipment. The basic data of this paper are derived from conventional wireline logging (CWL) data and the LWD data in Yan'an Gas Field. The main research goal is to compare and analyse three popular machine learning algorithms, which are one-versus-rest support vector machines (OVR SVMs), one-versus-one support vector machines (OVO SVMs) and random forest (RF), and to optimize a more practical method in the field for LWD systems. To reduce the dimensions of the input data, the characteristic parameters of the training data are obtained by a correlation analysis of the logging data. The optimal parameter values of each algorithm are determined by grid search method and 10-fold cross-validation method. On this basis, the lithology predictions of the actual LWD data are carried out by using three classifiers. Considering the time consumption of the model training and the lithology identification accuracy of the model, the best lithology identification model while drilling is selected. The results show that the characteristic parameters of the training data after the correlation analysis are AC, CAL, GR, K, RD and SP logs. The overall classification and recognition performance of the RF classifier is better than that of the other two classifiers, and its accuracy is even greater than 90%. The evaluation matrix shows that the OVR SVMs and RF classifiers yield lower prediction errors than the OVO SVMs classifier in each single lithology identification, but the RF classifier spends much less time in the training process. Based on the comprehensive comparative analysis, it is considered that the RF classifier has the characteristics of a short training time and high recognition accuracy in practical production applications, so it is an ideal optimization classifier for lithology identification while drilling. The research results provide not only a theoretical basis for the drilling geosteering of oilfield development but also valuable information for future basic research.",24,24,10
Machine Learning,Lithology,"Gu, Yufeng; Bao, Zhidong; Song, Xinmin; Patil, Shirish; Ling, Kegang",Complex lithology prediction using probabilistic neural network improved by continuous restricted Boltzmann machine and particle swarm optimization,Carbonate reservoirs; Lithology prediction; Probabilistic neural network; Continuous restricted Boltzmann machine; Particle swarm optimization,SUPPORT VECTOR MACHINE; SANTOS BASIN; DISCRIMINANT-ANALYSIS; PATTERN-RECOGNITION; INERTIA WEIGHT; RANDOM FOREST; CLASSIFICATION; ALGORITHM; MODELS; GAS,"Lithology prediction, especially for reservoirs consisting of complex lithologies, is universally considered as a critical underlying task for petroleum exploration, because lithological data is indispensable for the analysis of some geological work, such as stratigraphic correlation or sedimentation modeling. Hence, how to acquire the reliable lithological information gradually becomes a hot topic in the geoscience. Probabilistic neural network (PNN) is an excellent approach for lithology prediction since it can efficiently complete pattern recognition by determining characteristics of each kind of learning data. However, its computation performance is severely limited by two factors, which are quality of raw data and selection of parameter. High correlation of raw data could be an obstacle for the determination of data characteristics because partial probability density distributions established by PNN would be merged. As window length of each probability density distribution shows great impact on the accuracy of calculated results, the selection of this parameter must be addressed optimally before prediction. In order to improve the calculation capability of PNN, two techniques, continuous restricted Boltzmann machine (CRBM) and particle swarm optimization (PSO), are introduced. CRBM has the special function of extracting features from raw data and the features generally present with low correlation, thus can be viewed as an ideal preprocessing segment for PNN. PSO is one of the most efficient algorithms used for solving optimization problem, and the optimal parameter setting of PNN, therefore, can be revealed. Due to the advantages of CRBM and PSO for PNN, a new method for complex lithology prediction is proposed, which is referred as CRBM-PSO-PNN. Data for new method validation is recorded by two wells which are located in the IARA oilfield. Moreover, three experiments are well designed in order to verify the computing capability of new method comprehensively. Experiment results manifest that the prediction accuracies provided by new method in three experiments are highest, all of which are over 75%. High prediction accuracies fully demonstrate that the proposed method is effective to predict complex lithology, and the predicted results are reliable to serve other geological work.",17,18,2
Machine Learning,Source Rocks,"Rui, Jianwen; Zhang, Hongbing; Zhang, Dailu; Han, Feilong; Guo, Qiang",Total organic carbon content prediction based on support-vector-regression machine with particle swarm optimization,TOC content; Support vector regress; Delta logR; PSO algorithm,SHALE; LITHOFACIES; RICHNESS; BASIN; MODEL; TOC,"Total organic carbon (TOC) is a significant factor to evaluate the hydrocarbon potential of the unconventional reservoir, while it is difficult to obtain the continuous and accurate prediction result of TOC by traditional methods due to the non-linear relationship between TOC content and wireline log data. However, support vector regress machine is an efficient supervised learning artificial intelligence algorithm, and performs well to deal with non-linear relationship dataset. Therefore, in order to explore a more efficient way for TOC content prediction, the support vector regress machine was tried to predict TOC content through wireline log data. To further verify this, some data tests have been conducted on an offshore exploration prior well data in the northern of Beibu Gulf Basin. After analyzing various kernel functions and optimization methods by cross-validation and error analysis, it can be indicated that the Gaussian kernel function and the particle swarm optimization (PSO) algorithm which used the linear decreasing inertia coefficient and mutated particles are suitable for SVR model and model parameter selection, respectively. Finally, the prediction result of SVR with the best model and model parameters is compared with the results of an improved Delta logR method and multilayer perceptron method. The comparison results show that SVR has a higher correlation coefficient than other methods. In conclusion, the prediction result of SVR can be thought of as an efficient and reliable method for TOC content prediction. Through the continuous prediction of organic carbon content, the qualitative and quantitative evaluation of high-quality source rocks in this area can be realized, which is of great practical significance for determining the exploration field and the search for favorable target reservoirs.",30,32,3
Machine Learning,Source Rocks,"Shalaby, Mohamed R.; Jumat, Nurhazwana; Lai, Daphne; Malik, Owais","Integrated TOC prediction and source rock characterization using machine learning, well logs and geochemical analysis: Case study from the Jurassic source rocks in Shams Field, NW Desert, Egypt",Machine learning; Artificial neural network; Geochemical analysis; Well log data; Source rock; Jurassic; Egypt,NORTHERN WESTERN DESERT; ORGANIC-CARBON CONTENT; APPALACHIAN DEVONIAN SHALES; DEPOSITIONAL ENVIRONMENT; KAZHDUMI FORMATION; KHATATBA FORMATION; SHUSHAN BASIN; WIRELINE LOGS; GENERATION; RESERVOIR,"The machine learning methods and well log mathematical models have been used for predicting total organic carbon (TOC) in Jurassic source rock formations in Northwestern Desert, Egypt. Conventional well log data from two wells have been utilized for source rock study of Jurassic source rocks from Khatatba and Ras Qattara formations in the study area. The source rock is first studied based on geochemical parameters, which include assessments on the type and amount of kerogen present within the source rock samples. The Jurassic source rock samples have great generative potential and consist of mixed kerogen type III and kerogen type II-III. TOC content reaches up to 46.90% for Khatatba and 16.80% Ras Qattara. In the second part of this research, we attempt to characterize the Jurassic source rocks by using mathematical well log models and machine learning methods. GR, RHOB and NPHI well log data were used for TOC prediction using both methods. The quantified TOC results show that the R-2 values of well log models are above 0.9 for both formations, whereas the machine learning method using Artificial Neural Network showed R-2 value of 0.4. The results from the well log models suggest that they are applicable in the study area. This study has proven that well log data can be used with confidence to evaluate organic source quantity of Jurassic rocks in Northwestern Desert in the absence of geochemical data.",25,28,2
Machine Learning,ML Algorithms,"Soares, Cesar; Gray, Kenneth",Real-time predictive capabilities of analytical and machine learning rate of penetration (ROP) models,Rate of penetration; ROP modeling; Real-time retraining; Machine learning; PDC bit,PRESSURE; BOURGOYNE,"Real-time drilling optimization consists of selecting operational parameters that maximize a desirable measure of drilling performance. Drilling optimization efforts often aspire to improve drilling speed, commonly referred to as rate of penetration (ROP). Three operational drilling parameters may be constantly adjusted at surface to influence ROP: weight on bit (WOB), drillstring rotational speed (RPM), and drilling fluid (mud) flow rate. In the traditional, analytical approach to ROP modeling, inflexible equations relate WOB, RPM, flow rate and/or other measurable drilling parameters to ROP and empirical model coefficients are computed for each rock formation to best fit field data. Over the last decade, enhanced data acquisition technology and widespread cheap computational power have driven a surge in applications of machine learning (ML) techniques to ROP prediction. Machine learning algorithms leverage statistics to uncover relations between any prescribed inputs (features/predictors) and the quantity of interest (response). The biggest advantage of ML algorithms over analytical models is their flexibility in model form. With no set equation, ML models permit segmentation of the drilling operational parameter space. However, the increased model complexity diminishes interpretability of how an adjustment to the inputs will affect the output. There is no single ROP model applicable in every situation. This study investigates real-time predictive capabilities of analytical and ML ROP models in a continuous learning setting. Data are constantly recorded as a well is drilled, and it is postulated that ROP models can learn and adapt in real-time to become more accurate. Novel learning metrics demonstrate that machine learning models reduce test error much more effectively than analytical models with incremental training data availability. Both analytical and ML model performance improves with shortened retraining intervals, defined either by length or number of data points. Cross-validation is investigated as a methodology to select the best performing ROP model in real-time.",42,42,8
Machine Learning,ML Algorithms,"Kanin, E. A.; Osiptsov, A. A.; Vainshtein, A. L.; Burnaev, E., V",A predictive model for steady-state multiphase pipe flow: Machine learning on lab data,Multiphase flow; Machine learning; Surrogate modeling; Pressure gradient; Flow pattern; Liquid holdup,LIQUID HOLDUP; SLUG,"Engineering simulators used for steady-state multiphase flows in oil and gas wells and pipelines are commonly utilized to predict pressure drop and phase velocities. Such simulators are typically based on either empirical correlations (e.g., Beggs and Brill, Mukherjee and Brill, Duns and Ros) or first-principles mechanistic models (e.g., Ansari, Xiao, TUFFP Unified, Leda Flow Point model, OLGAS). The simulators allow one to evaluate the pressure drop in a multiphase pipe flow with acceptable accuracy. However, the only shortcoming of these correlations and mechanistic models is their applicability (besides steady-state versions of transient simulators such as Leda Flow and OLGA). Empirical correlations are commonly applicable in their respective ranges of data fitting; and mechanistic models are limited by the applicability of the empirically based closure relations that are a part of such models. In order to extend the applicability and the accuracy of the existing accessible methods, a method of pressure drop calculation in the pipeline is proposed. The method is based on well segmentation and calculation of the pressure gradient in each segment using three surrogate models based on Machine Learning (ML) algorithms trained on a representative lab data set from the open literature. The first model predicts the value of a liquid holdup in the segment, the second one determines the flow pattern, and the third one is used to estimate the pressure gradient. To build these models, several ML algorithms are trained such as Random Forest, Gradient Boosting Decision Trees, Support Vector Machine, and Artificial Neural Network, and their predictive abilities are cross-compared. The proposed method for pressure gradient calculation yields R-2 = 0.95 by using the Gradient Boosting algorithm as compared with R-2 = 0.92 in case of Mukherjee and Brill correlation and R-2 = 0.91 when a combination of Ansari and Xiao mechanistic models is utilized. The application of the above-mentioned ML algorithms and the larger database used for their training will allow extending the proposed methodology to a wider applicability range of input parameters as compared to standard accessible techniques. The method for pressure drop prediction based on ML algorithms trained on lab data is also validated on three real field cases. Validation indicates that the proposed model yields the following coefficients of determination: R-2 = 0.806, 0.815 and 0.99 as compared with the highest values obtained by commonly used techniques: R-2 = 0.82 (Beggs and Brill correlation), (Mukherjee and Brill correlation) and R-2 = 0.98 (Beggs and Brill correlation). Hence, the method for calculating the pressure distribution could give comparable or even higher scores on field data by contrast to correlations and mechanistic models. This fact is an indicator that the model can be scalable from the lab to the field conditions without any additional retraining of ML algorithms.",21,21,1
Tight Sandstone,Size Distribution,"Gao, Hui; Wang, Chen; Cao, Jie; He, Mengqing; Dou, Liangbin",Quantitative study on the stress sensitivity of pores in tight sandstone reservoirs of Ordos basin using NMR technique,Stress sensitivity of pores; NMR; Pore volume; Quantitative evaluation; Tight sandstone,NUCLEAR-MAGNETIC-RESONANCE; RESIDUAL OIL DISTRIBUTION; PERMEABILITY; GAS; POROSITY; SHALE; FLUID; ROCKS,"For tight sandstone reservoirs, the pore structure is sensitive to the stress variations during the production process. The alternation of pore structure influences the petrophysical properties and therefore the dynamic flow of tight sandstone reservoirs. In this research, Nuclear Magnetic Resonance (NMR) technique is employed to quantitatively study the pore volume variation under different confining pressures. Not only during the compression process, this research also investigated the sandstone pore sensitivity to stress during the recovery process of rock samples, which is equally important and happens during the production process when the formation pressure is building up due to the temporary well shut-in or water injection. The core samples selected from Ordos basin are first tested routinely for basic parameters like porosity, permeability and detrital components, and then through both compression and recovery processes where the pressure decreases and increases, respectively. It is found that the core samples with high permeability show stronger stress sensitivity of pores than those with low permeability due to the higher content of large pores. Besides permeability, detrital components and interstitial material can also affect the stress sensitivity of pores. During the recovery process, the low recovery degree of pore volume is related to the recoverable pore size (mainly smaller size pores) and the narrow distribution range of recovered pores. Furthermore, the power function relationship and the exponential relationship are suggested to evaluate the variation of pore volume in compression and recovery process, respectively. The results demonstrated that the compressibility of larger pores is bigger than that of smaller pores. During the compression process, the higher permeability rocks, containing a higher content of larger pores, are easier to be compressed, and has a greater decrease in permeability. Besides, the recoverability of the total pore volume after compression is mainly controlled by smaller pores, which results in the lower recoverability of the total pore volume and the permeability for the higher permeability core samples.",41,42,9
Tight Sandstone,Size Distribution,"Guo, Xiaobo; Huang, Zhilong; Zhao, Libin; Han, Wei; Ding, Chao; Sun, Xiongwei; Yan, Ruitao; Zhang, Tonghui; Yang, Xuejun; Wang, Ruomei","Pore structure and multi-fractal analysis of tight sandstone using MIP, NMR and NMRC methods: A case study from the Kuqa depression, China",Tight sandstone; Fractal dimension; Pore structure; Kuqa depression,ORDOS BASIN; TARIM BASIN; SIZE DISTRIBUTION; GAS SANDSTONE; OIL; POROSIMETRY; PARAMETERS; RESERVOIRS; DYNAMICS; ROCKS,"The pore structure and fractal characteristic of tight gas sandstone from Cretaceous Bashijiqike Formation in Kuqa depression were investigated, using thin section, scanning electronic microscope (SEM), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR) and NMR cryoporometry (NMRC) measurements. The pores of tight sandstone samples mainly contain residual primary intergranular pores, intergranular and intragranular dissolved pores, micropores related to clay aggregates and microfractures. The MIP, NMR and NMRC analyses show that the pore structure of tight sandstone is complex and heterogeneous at different pore scales, displaying as a multi-fractal feature. Fractal dimension Dg-s (with respect to small pore throats) from MIP and Dn-1 (long T-2 relaxation time, representing large pores and fractures or movable-fluid pores) are negatively correlated with porosity, permeability, median pore throat radius and skewness, and have inverse relationships with bound water saturation (S-bnd). Fractal dimension Dg-b ( > 3.0, with respect to larger pore throats) and Dn-s ( < 2.0, short T-2 relaxation time, representing small pores or bound-water pores) from NMR don't present clear relationships with most of pore structure parameters. Fractal dimension Dc-(1) and Dc-(2) from NMRC show more complex or inconspicuous relationships with pore structure parameters, in the pore diameter size < 500 nm. Hence, Dg-s from MIP and Dn-1 from NMR can be considered as effective parameters for pore structure and fluid properties characterization of tight sandstone. Fractal dimension Dg-b ( > 3.0) and Dn-s ( < 2.0) have no practical significance to characterize the pore structure of tight sandstone. The formation of residual primary intergranular pores and intergranular dissolution pores can reduce the fractal dimension which could be an important sign of effective reservoirs in the study area.",37,39,10
Tight Sandstone,Size Distribution,"Gao, Hui; Cao, Jie; Wang, Chen; He, Mengqing; Dou, Liangbin; Huang, Xing; Li, Tiantai","Comprehensive characterization of pore and throat system for tight sandstone reservoirs and associated permeability determination method using SEM, rate-controlled mercury and high pressure mercury",Tight sandstones; Micro pore-throat system; Permeability determination,TRIASSIC YANCHANG FORMATION; FORMATION CHANG 7; ORDOS BASIN; PETROPHYSICAL CHARACTERIZATION; OIL-RESERVOIRS; RELATIVE PERMEABILITY; SHALE; NMR; SIZES; LACUSTRINE,"Unconventional resource formations like tight sandstone reservoirs have complex pore and throat structure that are hard to characterize in micro scale. In this research, the pore and throat system of tight sandstones was characterized comprehensively, analysed qualitatively using scanning electron microscopy (SEM) techniques and quantitatively through combined high pressure mercury (HPM) and rate-controlled mercury (RCM) methods. First, the throat, distinguished from the pore, was divided in several types for tight sandstones and visualized through SEM imaging. Then, an integrated approach was proposed to combine the results from both HPM and RCM measurements, resulting in overall size distributions of the pore and the throat with scales from nanometer to micrometer. Both overall size distribution using the new combining method represented the pore and the throat more accurately in wider ranges. The results also showed that for tight sandstone core samples with different permeability, the difference of pore size distribution was less obvious than that of the throat. Therefore, the quantitative characterization of the throat size distribution was ultimately employed in developing a new permeability model together with physical considerations. The results demonstrated that the permeability of tight sandstones was in general depend on the size distribution of relatively larger throat, denoted as the macrothroat. However, for extreme low permeability (<0.1mD) formation, the small throats like microthroats and mesothroats mainly contributed to the permeability since the contents of macrothroats are really low.",34,36,5
Tight Sandstone,Size Distribution,"Wang, Fuyong; Zhao, Jiuyu",A mathematical model for co-current spontaneous water imbibition into oil-saturated tight sandstone: Upscaling from pore-scale to core-scale with fractal approach,Spontaneous imbibition; Co-current; Tight oil; Fractal; Porous media; Capillary tube,2-PHASE FLOW; RECOVERY; WETTABILITY; DYNAMICS,Spontaneous Imbibition (SI) is an important mechanism of enhancing oil recovery in tight oil reservoirs. Predicting core-scale oil flow rate by water imbibition from the pore-scale SI modelling is challenging due to the wide distributions of nano- and micro-pores in tight sandstone and huge amount of calculation of upscaling pore-scale modelling results for core-scale prediction. A semi-analytical mathematical model of characterizing co-current SI of water into oil-saturated tight sandstone has been proposed in this paper based on the capillary tube model and fractal theory. The non-uniform of water imbibition front due to the different imbibition rate in different sizes of pores can be dynamically characterized. Connate water and residual oil are considered and treated as immovable boundary-layers and coupled into the tortuous capillary tube model. The proposed model has been validated with the experiments results of core imbibition tests from literature. The key parameters of pore structures and fluid properties influencing imbibition flow rate have been quantitatively analyzed and identified.,19,23,6
Tight Sandstone,Size Distribution,"Ghanbarian, Behzad; Torres-Verdin, Carlos; Lake, Larry W.; Marder, Michael",Gas permeability in unconventional tight sandstones: Scaling up from pore to core,Effective-medium approximation; Effective pore size; Electrical conductivity; Gas permeability; Pore-throat size distribution; Tight-gas sandstone,ELECTRICAL-CONDUCTIVITY; HYDRAULIC CONDUCTIVITY; APPARENT PERMEABILITY; TOMOGRAPHIC-IMAGES; EFFECTIVE STRESS; PARTICLE-SIZE; POROUS-MEDIA; MODEL; PRESSURE; FLOW,"Upscaling Klinkenberg-corrected gas permeability, k, in unconventional tight sandstones has numerous practical applications, particularly in gas exploration and production. In this study, we adapt the effective-medium approximation (EMA) model of Doyen - proposed first to estimate bulk electrical conductivity, sigma(b), and permeability in sandstones from rock images - to scale up sigma(b) and k in tight-gas sandstones from pore to core. For this purpose, we calculate two characteristic pore sizes: an effective hydraulic and an effective electrical pore size from porethroat size distributions - determined from mercury intrusion capillary pressure (MICP) curves - and pore-throat connectivity. The latter is estimated from critical volume fraction (or percolation threshold) for macroscopic flow. Electrical conductivity and permeability are then scaled up from the two characteristic pore sizes, tortuosity, and porosity by assuming two different pore geometries: cylindrical and slit-shaped. Comparison of results obtained for eighteen tight-gas sandstones indicates that the EMA estimates sigma(b) and k more accurately when pores are assumed to be cylindrical. We also estimate k from the pore-throat size distributions and the measured electrical conductivity using the EMA and critical path analysis (CPA), another upscaling technique borrowed from statistical physics. Theoretically, the former is valid in relatively heterogeneous porous media with narrow pore-throat size distribution, while the latter is valid in heterogeneous media with broad pore-throat size distribution. Results show that the EMA estimates k more accurately than CPA and arrives within a factor of two of the measurements on average.",13,13,5
Tight Sandstone,Scanning Electron Microscopy,"Ren, Dazhong; Zhou, Desheng; Liu, Dengke; Dong, Fengjuan; Ma, Shuwei; Huang, Hai",Formation mechanism of the Upper Triassic Yanchang Formation tight sandstone reservoir in Ordos Basin-Take Chang 6 reservoir in Jiyuan oil field as an example,Diagenesis; Porosity evolution; Geological effect; Chang 6 member; Ordos bain,KRISHNA-GODAVARI BASIN; POROSITY EVOLUTION; DIAGENESIS; QUALITY; PERMEABILITY; CEMENTATION; AREA,"The Upper Triassic Yanchang Formation Chang 6 Member (C6 Member) in the Ordos Basin is the typical crude oil-rich sandstone in China, and its density restrict the exploration and development potential of hydrocarbon as well as their evaluation accuracy. Reservoir characteristics was studied using thin section (TS) associated with particle and pore size image analysis, X-ray diffractions, scanning electron microscopy (SEM) and mercury intrusion porosimetry (MIP). Time was taken as the main axle combined with diagenetic history, burial history, thermal history and structure. Thus, formation mechanism of tight reservoir was discussed by building the porosity evolution model and calculation method using ""diagenesis simulation"" and ""geological effect simulation"". Results show that after strong evolution and reconstruction, micro-nano pore throat system has developed and ultralow-low porosity-super low permeability tight sandstone reservoir has formed. Porosity evolution of Well H53 of C6 Member has revealed the correlations between the hydrocarbon charging and the porosity. Tight sandstone reservoir quality is affected by the maximum intergranular point-counted porosity, maximum compaction rate, maximum cementation rate, pore evolution of sample and the oil saturation, reasons for the formation of tight sandstone reservoir as well as its quality have been found out.",65,65,8
Tight Sandstone,Scanning Electron Microscopy,"Shi, Bingbing; Chang, Xiangchun; Yin, Wei; Li, Yang; Mao, Lixin","Quantitative evaluation model for tight sandstone reservoirs based on statistical methods - A case study of the Triassic Chang 8 tight sandstones, Zhenjing area, Ordos Basin, China",Tight sandstone; Comprehensive quantitative evaluation; Statistical methods; Reservoir quality; Ordos basin,YANCHANG FORMATION; QUALITY; HETEROGENEITY; DIAGENESIS; SEQUENCE; POROSITY; IMPACT; MEMBER; FIELD,"Petroleum exploration for tight sandstone reservoirs in the Ordos Basin has attracted much attention in recent years. However, the effective evaluation of the quality of tight sandstones is challenging due to their low porosity, low permeability, non-Darcy flow, continuously or quasi-continuously distribution and strong heterogeneity. Using constant velocity mercury injection, cathodoluminescence micrography, energy spectrum analysis, scanning electron microscopy and casting thin sections, a set of parameters, including the clay mineral index, Lorentz coefficient, compositional maturity, and plane porosity are tentatively proposed to evaluate the quality of tight reservoir rocks. Coupled with statistical methods, i.e., Principal Component Analysis, Grey Correlation Analysis, Analytic Hierarchy Process and Hierarchical Cluster Analysis, a comprehensive quantitative reservoir evaluation model is established. Then, the evaluation index (REI) is calculated, and the thresholds of various types of reservoirs are determined. The case study based on the above evaluation model shows that most of the type I reservoirs are petroleum-enriched, which are favourable targets for exploration and development. By contrast with sedimentary microfacies, the sandbodies in favourable targets were deposited in ancient subaqueous distributary channels, and they show a large herringbone-like distribution. Whereas the poor type-III reservoirs and non-prospective layers are mainly located in the southeastern part of the study area. The case evaluation based on the statistical methods is consistent with the results of previous multi-parameter evaluations, which has important implications for further exploration in the study area as well as other tight sandstone reservoirs.",64,69,6
Tight Sandstone,Scanning Electron Microscopy,"Dong, Bingqiang; Meng, Meng; Qiu, Zhengsong; Lu, Zhaohui; Zhang, Ye; Zhong, Hanyi",Formation damage prevention using microemulsion in tight sandstone gas reservoir,Damage mechanism; Water blocking; Sensitivity damages; Protective drilling fluid,STRESS SENSITIVITY; LOW-PERMEABILITY; DRILLING-FLUID; OIL; REMOVAL; MODEL; SAND; FLOW,"Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production.",43,45,1
Tight Sandstone,Scanning Electron Microscopy,"Gao, Hui; Cao, Jie; Wang, Chen; He, Mengqing; Dou, Liangbin; Huang, Xing; Li, Tiantai","Comprehensive characterization of pore and throat system for tight sandstone reservoirs and associated permeability determination method using SEM, rate-controlled mercury and high pressure mercury",Tight sandstones; Micro pore-throat system; Permeability determination,TRIASSIC YANCHANG FORMATION; FORMATION CHANG 7; ORDOS BASIN; PETROPHYSICAL CHARACTERIZATION; OIL-RESERVOIRS; RELATIVE PERMEABILITY; SHALE; NMR; SIZES; LACUSTRINE,"Unconventional resource formations like tight sandstone reservoirs have complex pore and throat structure that are hard to characterize in micro scale. In this research, the pore and throat system of tight sandstones was characterized comprehensively, analysed qualitatively using scanning electron microscopy (SEM) techniques and quantitatively through combined high pressure mercury (HPM) and rate-controlled mercury (RCM) methods. First, the throat, distinguished from the pore, was divided in several types for tight sandstones and visualized through SEM imaging. Then, an integrated approach was proposed to combine the results from both HPM and RCM measurements, resulting in overall size distributions of the pore and the throat with scales from nanometer to micrometer. Both overall size distribution using the new combining method represented the pore and the throat more accurately in wider ranges. The results also showed that for tight sandstone core samples with different permeability, the difference of pore size distribution was less obvious than that of the throat. Therefore, the quantitative characterization of the throat size distribution was ultimately employed in developing a new permeability model together with physical considerations. The results demonstrated that the permeability of tight sandstones was in general depend on the size distribution of relatively larger throat, denoted as the macrothroat. However, for extreme low permeability (<0.1mD) formation, the small throats like microthroats and mesothroats mainly contributed to the permeability since the contents of macrothroats are really low.",34,36,5
Tight Sandstone,Scanning Electron Microscopy,Zhao Zhongxiang; Dong Chunmei; Zhang Xianguo; Lin Chengyan; Huang Xin; Duan Dongping; Lin Jianli; Zeng Fang; Li Dan,"Reservoir controlling factors of the Paleogene Oligocene Huagang Formation in the north central part of the Xihu Depression, East China Sea Basin, China",East China Sea Basin; Xihu depression; Huagang formation; Reservoir controlling factors; Low permeability - tight reservoir,DEPOSITIONAL FACIES; SANDSTONES; POROSITY; COMPACTION; DIAGENESIS; FIELD; CEMENTATION; PROPAGATION; PREDICTION; KAOLINITE,"Huagang Formation is a typical offshore, deep, low-permeability, tight sandstone reservoir with a low level of exploration and development and unclear control factors in the North Central area of the Xihu Depression in the East China Sea Basin. In this paper, we begin with the analysis of basic data, such as cores, casting thin sections, cathode luminescence, scanning electron microscopy, physical property statistics, grain size analysis, mercury penetration and magnetic resonance imaging, combined with field logging data from conventional logging, imaging logging and three-dimensional seismic imagery. The reservoir's physical properties were comprehensively discussed in terms of provenance, deposition, diagenesis and fractures. The results showed that the reservoir physical properties of the Huagang Formation were mainly affected by compaction, and the porosity and permeability decreased with the depth of burial. When the depth exceeds 4000 m, the porosity is basically < 10% and the permeability is nearly < 1 mD. The compaction above 4000 m was mainly controlled by provenance and depositional microfacies. The reservoir physical properties in the northern provenance is better than that of the east provenance. A high-energy braided channel is the best physical depositional microfacies. The reservoir formed by event sedimentation, such as from storms and floods, due to poor sorting, often containing mud and so on, with poor physical properties. Carbonate cementation only had a great influence on the local reservoir. Illite, illite/smectite and pore-filling chlorite were important factors affecting physical property deterioration. Pore-lining chlorite can promote the retention of primary pores. Below 4000 m, favorable reservoirs were mainly controlled by dissolution, resulting in dissolution pores being the main reservoir space. Microfractures played an important role in the properties of low-permeability and tight reservoirs. Microfractures themselves were easily dissolved into dissolution pores while being an important seepage channel for low-permeability and tight reservoirs. The denser the reservoir is, the more important the microfracture seepage is.",13,14,4
Tight Sandstone,Core Samples,"Gao, Hui; Wang, Chen; Cao, Jie; He, Mengqing; Dou, Liangbin",Quantitative study on the stress sensitivity of pores in tight sandstone reservoirs of Ordos basin using NMR technique,Stress sensitivity of pores; NMR; Pore volume; Quantitative evaluation; Tight sandstone,NUCLEAR-MAGNETIC-RESONANCE; RESIDUAL OIL DISTRIBUTION; PERMEABILITY; GAS; POROSITY; SHALE; FLUID; ROCKS,"For tight sandstone reservoirs, the pore structure is sensitive to the stress variations during the production process. The alternation of pore structure influences the petrophysical properties and therefore the dynamic flow of tight sandstone reservoirs. In this research, Nuclear Magnetic Resonance (NMR) technique is employed to quantitatively study the pore volume variation under different confining pressures. Not only during the compression process, this research also investigated the sandstone pore sensitivity to stress during the recovery process of rock samples, which is equally important and happens during the production process when the formation pressure is building up due to the temporary well shut-in or water injection. The core samples selected from Ordos basin are first tested routinely for basic parameters like porosity, permeability and detrital components, and then through both compression and recovery processes where the pressure decreases and increases, respectively. It is found that the core samples with high permeability show stronger stress sensitivity of pores than those with low permeability due to the higher content of large pores. Besides permeability, detrital components and interstitial material can also affect the stress sensitivity of pores. During the recovery process, the low recovery degree of pore volume is related to the recoverable pore size (mainly smaller size pores) and the narrow distribution range of recovered pores. Furthermore, the power function relationship and the exponential relationship are suggested to evaluate the variation of pore volume in compression and recovery process, respectively. The results demonstrated that the compressibility of larger pores is bigger than that of smaller pores. During the compression process, the higher permeability rocks, containing a higher content of larger pores, are easier to be compressed, and has a greater decrease in permeability. Besides, the recoverability of the total pore volume after compression is mainly controlled by smaller pores, which results in the lower recoverability of the total pore volume and the permeability for the higher permeability core samples.",41,42,9
Tight Sandstone,Core Samples,"Gao, Hui; Cao, Jie; Wang, Chen; He, Mengqing; Dou, Liangbin; Huang, Xing; Li, Tiantai","Comprehensive characterization of pore and throat system for tight sandstone reservoirs and associated permeability determination method using SEM, rate-controlled mercury and high pressure mercury",Tight sandstones; Micro pore-throat system; Permeability determination,TRIASSIC YANCHANG FORMATION; FORMATION CHANG 7; ORDOS BASIN; PETROPHYSICAL CHARACTERIZATION; OIL-RESERVOIRS; RELATIVE PERMEABILITY; SHALE; NMR; SIZES; LACUSTRINE,"Unconventional resource formations like tight sandstone reservoirs have complex pore and throat structure that are hard to characterize in micro scale. In this research, the pore and throat system of tight sandstones was characterized comprehensively, analysed qualitatively using scanning electron microscopy (SEM) techniques and quantitatively through combined high pressure mercury (HPM) and rate-controlled mercury (RCM) methods. First, the throat, distinguished from the pore, was divided in several types for tight sandstones and visualized through SEM imaging. Then, an integrated approach was proposed to combine the results from both HPM and RCM measurements, resulting in overall size distributions of the pore and the throat with scales from nanometer to micrometer. Both overall size distribution using the new combining method represented the pore and the throat more accurately in wider ranges. The results also showed that for tight sandstone core samples with different permeability, the difference of pore size distribution was less obvious than that of the throat. Therefore, the quantitative characterization of the throat size distribution was ultimately employed in developing a new permeability model together with physical considerations. The results demonstrated that the permeability of tight sandstones was in general depend on the size distribution of relatively larger throat, denoted as the macrothroat. However, for extreme low permeability (<0.1mD) formation, the small throats like microthroats and mesothroats mainly contributed to the permeability since the contents of macrothroats are really low.",34,36,5
Tight Sandstone,Core Samples,"Cheng, Zhilin; Ning, Zhengfu; Ye, Xiongfei; Wang, Qing; Zhang, Wentong",New insights into spontaneous imbibition in tight oil sandstones with NMR,Spontaneous imbibition; Tight oil sandstones; Gravity effect; Anisotropic pore structure; Viscosity effect,PORE STRUCTURE; UNDERSTANDING WETTABILITY; BOUNDARY-CONDITIONS; SHAPE FACTOR; RECOVERY; SHALE; WATER; RESERVOIRS; PRESSURE; FLUID,"Previous research has confirmed that substantial yield has been recovered in the soaking period after hydraulic fracturing. Spontaneous imbibition (SI) is the primary mechanism responsible for the enhanced oil production and has become an effective oil recovery method with regards to unconventional reservoirs. Despite the importance of SI, an in-depth understanding of the features of SI in tight reservoirs is still inadequate. In this article, nuclear magnetic resonance (NMR) T-2 was employed to study the dynamic behavior of imbibition in tight sandstone samples from Yanchang formation, Ordos Basin. Additionally, high-pressure mercury intrusion (HPMI) and the initial T-2 of a core sample were combined to characterize pore structures of tight rocks and oil distributions in various pores at different imbibition stages. Then, the effects of gravity, anisotropic pore structure, and non-wetting phase (NWP) viscosity on imbibition recovery were determined via the variations in T-2 spectra for each sample. The results show that the tight cores feature a multiscale pore structure. Sub-micropores is the dominant type providing the major contribution to oil recovery, while nanopores have largest imbibition efficiency due to the larger capillary force. Gravity of fluids has a non-trivial effect on SI and cannot be neglected in tight samples under two-ends-open (TEO) or one-end-open (OEO) conditions; this seemingly counterintuitive finding is because the capillary force is weakened by the resistance force caused by the intricate flow paths and other possible surface forces at the nanoscale. Imbibition performance in a tight medium is strongly related to its pore structure. The variations in directional permeabilities, relative permeabilities and capillary pressure functions resulting from highly anisotropic samples greatly affect both the ultimate oil recovery and imbibition rate for tight samples under TEO condition, but only impact imbibition rate under allfaces-open (AFO) condition. Furthermore, because tight oil has a narrow range of viscosity, the imbibition behavior in tight samples may not be sensitive to the oil viscosity. It would be hoped that the insights gained from this study can help to improve our understanding of imbibition characteristics in tight reservoirs and develop new scaling models for the predication of oil recovery.",32,34,10
Tight Sandstone,Core Samples,"Hassan, Amjed M.; Mahmoud, Mohamed A.; Al-Majed, Abdulaziz A.; Al-Nakhli, Ayman R.; Bataweel, Mohammed A.",Water blockage removal and productivity index enhancement by injecting thermochemical fluids in tight sandstone formations,Water blockage; Thermochemical fluids; Tight sandstone; Micro fractures; Capillary forces,FORMATION DAMAGE; LOW PERMEABILITY; GAS-RESERVOIRS; BLOCKING; PREVENTION; BASIN; FLOW; OIL,"Several challenges are associated with hydrocarbon production from tight reservoirs. Tight reservoirs are characterized with low permeability which reduces the hydrocarbon flow into the wellbore. Water blockage is considered one of the main damaging mechanisms in tight reservoirs due to the increase of water saturation around the wellbore region and eventually decrease in the relative permeability of hydrocarbons. Acid fracturing or hydraulic fracturing are required to remove the damage and enhance the formation conductivity. This paper presents a new technique to remove the water blockage from tight formations and improve the formation productivity using thermochemical treatment. Chemicals that generate pressure and heat at reservoir conditions are used to remove the water bank from tight core samples to enhance the flow conditions. Coreflooding experiments, capillary pressure, and NMR measurements were conducted as well as routine core analysis. The impact of thermochemical treatment on improving the formation productivity was quantified. The productivity index for core samples were determined before and after the thermochemical flooding. The effect of thermochemical injection on reducing the capillary forces was analyzed by measuring the capillary pressure before and after the chemical treatment. The alteration in pore geometry due to the thermochemical flooding was evaluated using NMR measurements. The results of this study show that water blockage is a potential damage in tight gas reservoirs. Injecting thermochemical fluids into tight samples reduced the capillary forces and removed the water banking. Flooding tight core samples with thermochemical resulted in generating tiny fractures in the treated samples, which reduces the capillary forces by 55.6% after the chemical treatment. The in-situ generated heat and nitrogen gas during thermochemical treatment can result in removing the water blockage from tight formations utilizing the desiccation effect. Also, thermochemical treatment showed a significant improvement in the core conductivity. The productivity index of core samples increased by 94.3% due to the chemical flooding. This study introduces a new chemical treatment for removing the water blockage from tight formations using environmentally friendly fluids. Thermochemical treatment improved the productivity index by a factor of 1.94 and decreased the drawdown pressure by more than 80%. Consequently, the trapped water was removed, and the total hydrocarbon production significantly improved.",16,16,4
Tight Sandstone,Spontaneous Imbibition,"Cheng, Zhilin; Ning, Zhengfu; Ye, Xiongfei; Wang, Qing; Zhang, Wentong",New insights into spontaneous imbibition in tight oil sandstones with NMR,Spontaneous imbibition; Tight oil sandstones; Gravity effect; Anisotropic pore structure; Viscosity effect,PORE STRUCTURE; UNDERSTANDING WETTABILITY; BOUNDARY-CONDITIONS; SHAPE FACTOR; RECOVERY; SHALE; WATER; RESERVOIRS; PRESSURE; FLUID,"Previous research has confirmed that substantial yield has been recovered in the soaking period after hydraulic fracturing. Spontaneous imbibition (SI) is the primary mechanism responsible for the enhanced oil production and has become an effective oil recovery method with regards to unconventional reservoirs. Despite the importance of SI, an in-depth understanding of the features of SI in tight reservoirs is still inadequate. In this article, nuclear magnetic resonance (NMR) T-2 was employed to study the dynamic behavior of imbibition in tight sandstone samples from Yanchang formation, Ordos Basin. Additionally, high-pressure mercury intrusion (HPMI) and the initial T-2 of a core sample were combined to characterize pore structures of tight rocks and oil distributions in various pores at different imbibition stages. Then, the effects of gravity, anisotropic pore structure, and non-wetting phase (NWP) viscosity on imbibition recovery were determined via the variations in T-2 spectra for each sample. The results show that the tight cores feature a multiscale pore structure. Sub-micropores is the dominant type providing the major contribution to oil recovery, while nanopores have largest imbibition efficiency due to the larger capillary force. Gravity of fluids has a non-trivial effect on SI and cannot be neglected in tight samples under two-ends-open (TEO) or one-end-open (OEO) conditions; this seemingly counterintuitive finding is because the capillary force is weakened by the resistance force caused by the intricate flow paths and other possible surface forces at the nanoscale. Imbibition performance in a tight medium is strongly related to its pore structure. The variations in directional permeabilities, relative permeabilities and capillary pressure functions resulting from highly anisotropic samples greatly affect both the ultimate oil recovery and imbibition rate for tight samples under TEO condition, but only impact imbibition rate under allfaces-open (AFO) condition. Furthermore, because tight oil has a narrow range of viscosity, the imbibition behavior in tight samples may not be sensitive to the oil viscosity. It would be hoped that the insights gained from this study can help to improve our understanding of imbibition characteristics in tight reservoirs and develop new scaling models for the predication of oil recovery.",32,34,10
Tight Sandstone,Spontaneous Imbibition,"Wang, Fuyong; Zhao, Jiuyu",A mathematical model for co-current spontaneous water imbibition into oil-saturated tight sandstone: Upscaling from pore-scale to core-scale with fractal approach,Spontaneous imbibition; Co-current; Tight oil; Fractal; Porous media; Capillary tube,2-PHASE FLOW; RECOVERY; WETTABILITY; DYNAMICS,Spontaneous Imbibition (SI) is an important mechanism of enhancing oil recovery in tight oil reservoirs. Predicting core-scale oil flow rate by water imbibition from the pore-scale SI modelling is challenging due to the wide distributions of nano- and micro-pores in tight sandstone and huge amount of calculation of upscaling pore-scale modelling results for core-scale prediction. A semi-analytical mathematical model of characterizing co-current SI of water into oil-saturated tight sandstone has been proposed in this paper based on the capillary tube model and fractal theory. The non-uniform of water imbibition front due to the different imbibition rate in different sizes of pores can be dynamically characterized. Connate water and residual oil are considered and treated as immovable boundary-layers and coupled into the tortuous capillary tube model. The proposed model has been validated with the experiments results of core imbibition tests from literature. The key parameters of pore structures and fluid properties influencing imbibition flow rate have been quantitatively analyzed and identified.,19,23,6
Tight Sandstone,Spontaneous Imbibition,"Lai, Fengpeng; Li, Zhiping; Zhang, Tiantian; Zhou, Anqi; Gong, Bao","Characteristics of microscopic pore structure and its influence on spontaneous imbibition of tight gas reservoir in the Ordos Basin, China",Tight gas reservoir; Microscopic pore structure; Spontaneous imbibition; Experiments; Grey relational analysis,SANDSTONE RESERVOIRS; FLOW; PERMEABILITY; SHALE; MODEL,"Spontaneous imbibition is an important mechanism governing the tight reservoir production performance, especially in the early stage of production after hydraulic fracturing. The microscopic pore structure of reservoirs is an important factor affecting imbibition. In this study, high-pressure mercury injection (HPMI), rate-controlled mercury injection, and low-temperature nitrogen adsorption (LP-N(2)GA) were preformed to study pore structure characteristics and fluid distribution in samples from the Ordos Basin, China. Nuclear magnetic resonance (NMR) and imbibition experiments were used to investigate the fluid distribution in porous media during imbibition. The porosity of samples ranges from 11.378% to 12.356%, with an average of 12.034%. The permeability of samples ranges from 0.034 mD to 0.056 mD, with an average of 0.048 mD. Results show that the recovery ranges from 68% to 94.81%, with an average of 81.09%. The reservoir is dominated by open flat slit micropores and mesopores. Sample pore volume ranges from 0.0155 ml/g to 0.0193 ml/g, with an average of 0.01687 ml/g. Micropores and mesopores less than 50 nm provide most of the pore volume. Pore radius and pore-throat ratio were obtained from experiments. Imbibition occurs primarily in pores ranging from 0.1 mu m to 1 mu m in radius, followed by pores ranging from 1 mu m to 10 mu m. The effects of porosity, permeability, average pore radius, average throat radius, average pore-throat ratio, specific surface area, and pore volume on imbibition recovery were statistically analyzed. Grey relational analysis was applied to sequence the imbibition influencing factors and determine the most influential factor. Results demonstrate that imbibition recovery is the most affected by average pore radius, followed by permeability, porosity, average pore-throat ratio, median radius, average throat radius, and specific surface area.",19,18,4
Tight Sandstone,Spontaneous Imbibition,"Zhang, Dujie; Kang, Yili; Selvadurai, A. P. S.; You, Lijun; Tian, Jian",The role of phase trapping on permeability reduction in an ultra-deep tight sandstone gas reservoirs,Ultra-deep tight gas reservoirs; Phase trapping damage; Drill-in fluids; Invasion depth; Permeability damage ratio; Numerical simulation model,MERCURY INTRUSION POROSIMETRY; PORE-SIZE DISTRIBUTIONS; SPONTANEOUS IMBIBITION; RELATIVE PERMEABILITY; WATER IMBIBITION; TARIM BASIN; PRESSURE; HYSTERESIS; ADSORPTION; IMPACT,"As the first external liquids that are introduced into a reservoir rock, suitable drill-in fluids not only prevent phase trapping-induced permeability reduction (also referred to as phase trapping damage) caused by the drill-in fluid itself but also minimize any phase trapping damage caused by the invasion of subsequent working fluids. An ultra-deep tight sandstone reservoir in the Tarim Basin, NW China is considered as a case study, and this paper presents the results of an extensive series of phase trapping damage investigations that were carried out to determine the permeability reduction in the reservoir rock that comes into contact with different working fluids during the processes of drilling, drill stem tests, completion and well tests. Both the pore microstructure and surface properties were also investigated. The experimental results showed that the integrated phase trapping damage ratio (PDR) of water-based drill-in fluids (WBDF)-organic salt completion fluids (PDR = 0.99) was greater than that of oil-based drill-in fluids (OBDF)-organic salt completion fluids (PDR = 0.88). The analysis suggests that the OBDF is more effectively in inhibiting the absorption of the filtrate of the completion fluids compared with WBDF. A procedure for reducing phase trapping damage by OBDF is presented, and a numerical simulation model is developed to validate the procedure. The results could be useful in understanding and selecting the best drill-in fluids and completion fluids to minimize phase trapping damage in ultra-deep tight gas reservoirs.",18,20,1
Tight Sandstone,Damage,"Dong, Bingqiang; Meng, Meng; Qiu, Zhengsong; Lu, Zhaohui; Zhang, Ye; Zhong, Hanyi",Formation damage prevention using microemulsion in tight sandstone gas reservoir,Damage mechanism; Water blocking; Sensitivity damages; Protective drilling fluid,STRESS SENSITIVITY; LOW-PERMEABILITY; DRILLING-FLUID; OIL; REMOVAL; MODEL; SAND; FLOW,"Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production.",43,45,1
Tight Sandstone,Damage,Zhang Lufeng; Zhou Fujian; Zhang Shicheng; Li Zhu; Wang Ji; Wang Yuechun,Evaluation of permeability damage caused by drilling and fracturing fluids in tight low permeability sandstone reservoirs,Permeability damage; Pressure transmission test; Fracturing fluids; Drilling fluids; Tight sandstone reservoir,PULSE-DECAY METHOD; TRANSIENT LABORATORY METHOD; HYDRAULIC-PROPERTIES; GAS-PERMEABILITY; MECHANISM; METHODOLOGY; PERFORMANCE; RELAXATION; ROCKS; FLOW,"Tight sandstone reservoirs with low porosity and permeability are always vulnerable to damage due to drilling and fracturing fluids, which significantly impedes hydrocarbon production. Therefore, exploring damage evaluation methods has been an undeniable demand of formation protection and efficient development. However, the common steady-state core flow method is time-consuming and inaccurate for evaluating permeability damage in tight low permeability reservoirs. Aiming at this problem, this paper introduced pressure transmission test (PIT), a time-saving and accurate method, to quantitatively evaluate the core permeability damage degree from macroscopic perspective. Furthermore, nuclear magnetic resonance (NMR) was also used to analyze the damage mechanisms of fracturing fluids from microscopic perspective. In the fracturing fluids damage experiments, the results of PTT show that the ultimate damage degree of fracturing fluids is approximately 40%, of which water-sensitivity, water-block, and solid-phase are approximately 10%, 12% and 16%, respectively. With the technique of NMR, the damage mechanisms due to fracturing fluids are also investigated. In the drilling and fracturing fluids damage experiments, the results of PIT show that the drilling fluids cause the major damage. In the experiments of acidizing treatment, the chelating acid shows excellent properties in reliving core permeability damage caused by drilling and fracturing fluids. This study provides a new idea for evaluating permeability damage in low permeability reservoirs, such as shale, tight sandstone reservoirs, bedrock reservoirs, and so on.",37,38,12
Tight Sandstone,Damage,"Zhang, Dujie; Kang, Yili; Selvadurai, A. P. S.; You, Lijun; Tian, Jian",The role of phase trapping on permeability reduction in an ultra-deep tight sandstone gas reservoirs,Ultra-deep tight gas reservoirs; Phase trapping damage; Drill-in fluids; Invasion depth; Permeability damage ratio; Numerical simulation model,MERCURY INTRUSION POROSIMETRY; PORE-SIZE DISTRIBUTIONS; SPONTANEOUS IMBIBITION; RELATIVE PERMEABILITY; WATER IMBIBITION; TARIM BASIN; PRESSURE; HYSTERESIS; ADSORPTION; IMPACT,"As the first external liquids that are introduced into a reservoir rock, suitable drill-in fluids not only prevent phase trapping-induced permeability reduction (also referred to as phase trapping damage) caused by the drill-in fluid itself but also minimize any phase trapping damage caused by the invasion of subsequent working fluids. An ultra-deep tight sandstone reservoir in the Tarim Basin, NW China is considered as a case study, and this paper presents the results of an extensive series of phase trapping damage investigations that were carried out to determine the permeability reduction in the reservoir rock that comes into contact with different working fluids during the processes of drilling, drill stem tests, completion and well tests. Both the pore microstructure and surface properties were also investigated. The experimental results showed that the integrated phase trapping damage ratio (PDR) of water-based drill-in fluids (WBDF)-organic salt completion fluids (PDR = 0.99) was greater than that of oil-based drill-in fluids (OBDF)-organic salt completion fluids (PDR = 0.88). The analysis suggests that the OBDF is more effectively in inhibiting the absorption of the filtrate of the completion fluids compared with WBDF. A procedure for reducing phase trapping damage by OBDF is presented, and a numerical simulation model is developed to validate the procedure. The results could be useful in understanding and selecting the best drill-in fluids and completion fluids to minimize phase trapping damage in ultra-deep tight gas reservoirs.",18,20,1
Tight Sandstone,Damage,"Hassan, Amjed M.; Mahmoud, Mohamed A.; Al-Majed, Abdulaziz A.; Al-Nakhli, Ayman R.; Bataweel, Mohammed A.",Water blockage removal and productivity index enhancement by injecting thermochemical fluids in tight sandstone formations,Water blockage; Thermochemical fluids; Tight sandstone; Micro fractures; Capillary forces,FORMATION DAMAGE; LOW PERMEABILITY; GAS-RESERVOIRS; BLOCKING; PREVENTION; BASIN; FLOW; OIL,"Several challenges are associated with hydrocarbon production from tight reservoirs. Tight reservoirs are characterized with low permeability which reduces the hydrocarbon flow into the wellbore. Water blockage is considered one of the main damaging mechanisms in tight reservoirs due to the increase of water saturation around the wellbore region and eventually decrease in the relative permeability of hydrocarbons. Acid fracturing or hydraulic fracturing are required to remove the damage and enhance the formation conductivity. This paper presents a new technique to remove the water blockage from tight formations and improve the formation productivity using thermochemical treatment. Chemicals that generate pressure and heat at reservoir conditions are used to remove the water bank from tight core samples to enhance the flow conditions. Coreflooding experiments, capillary pressure, and NMR measurements were conducted as well as routine core analysis. The impact of thermochemical treatment on improving the formation productivity was quantified. The productivity index for core samples were determined before and after the thermochemical flooding. The effect of thermochemical injection on reducing the capillary forces was analyzed by measuring the capillary pressure before and after the chemical treatment. The alteration in pore geometry due to the thermochemical flooding was evaluated using NMR measurements. The results of this study show that water blockage is a potential damage in tight gas reservoirs. Injecting thermochemical fluids into tight samples reduced the capillary forces and removed the water banking. Flooding tight core samples with thermochemical resulted in generating tiny fractures in the treated samples, which reduces the capillary forces by 55.6% after the chemical treatment. The in-situ generated heat and nitrogen gas during thermochemical treatment can result in removing the water blockage from tight formations utilizing the desiccation effect. Also, thermochemical treatment showed a significant improvement in the core conductivity. The productivity index of core samples increased by 94.3% due to the chemical flooding. This study introduces a new chemical treatment for removing the water blockage from tight formations using environmentally friendly fluids. Thermochemical treatment improved the productivity index by a factor of 1.94 and decreased the drawdown pressure by more than 80%. Consequently, the trapped water was removed, and the total hydrocarbon production significantly improved.",16,16,4
Tight Sandstone,Carbonate,"Ba, Jing; Ma, Rupeng; Carcione, Jose M.; Picotti, Stefano",Ultrasonic wave attenuation dependence on saturation in tight oil siltstones,Elasticity and anelasticity; Microstructure; Permeability and porosity; Acoustic properties; Seismic attenuation; Wave propagation,SEISMIC ATTENUATION; WATER SATURATION; PORE-STRUCTURE; ROCKS; DISPERSION; VELOCITY; FLUIDS; DRY; SANDSTONES; STRESS,"Ultrasonic P-wave attenuation was measured in tight oil siltstones, carbonates and a tight sandstone with two independent estimation methods. The dependence on saturation in gas-water partially-saturated siltstones at in-situ conditions shows a different behavior compared to the other rocks. The siltstones in our experiments exhibit a behavior characterized by a gradual decrease of attenuation with increasing water saturation in the presence of gas, and full-gas saturation shows more attenuation than full-oil and full-water saturations. However, previous theoretical and experimental studies show that gas-water saturated carbonates and sandstones have the highest attenuation at high water saturations, and generally, a liquid-saturated rock shows more attenuation than a gas-saturated one. Poroelasticity theory shows that the two dominant loss mechanisms (due to fabric heterogeneity and patchy saturation) have peaks at different frequencies for siltstones, resulting in a gradual decrease of attenuation with water saturation, while these mechanisms overlap at ultrasonic frequencies for carbonates and sandstones, leading to an attenuation peak at high water saturations. The predicted attenuation dependence on fluid type agrees with the measurement for most samples. Regarding the tight oil siltstones, although the model fails to explain the experimental results for oil-water saturation, it can be concluded that for gas-water saturation the squirt flow caused by fabric heterogeneity dominates the attenuation, which differs from carbonates and sandstones. Experimental studies show that the attenuation dependence on saturation in tight oil reservoirs can be associated with fabric texture. The theory describes these behaviors, which can potentially improve the practices of detecting and monitoring multi-phase fluids in the reservoirs.",33,33,5
Tight Sandstone,Carbonate,"Cheng, Wei; Ba, Jing; Fu, Li-Yun; Lebedev, Maxim",Wave-velocity dispersion and rock microstructure,Wave propagation; P-Wave velocity dispersion; Ultrasonic measurement; Gassmann equation; Carbonates; Sandstones; Volcanic rocks; Porosity; Microcracks; Poroelasticity,P-WAVE; CLAY CONTENT; SQUIRT-FLOW; POROSITY; ATTENUATION; SANDSTONES; MODEL; PERMEABILITY; FREQUENCIES; RESERVOIRS,"Porosity, fluid type and rock texture significantly affect acoustic wave propagation, since velocity dispersion and attenuation in fluid saturated rocks are mainly caused by wave-induced local fluid flow between microcracks and intergranular pores. We analyze P-wave velocity dispersion as a function of porosity to obtain information about the rock microstructure. The P-wave velocities in water-saturated rocks are predicted from measurements in gas-saturated rocks, using the Gassmann fluid substitution equation (the relaxed state). The dispersion is estimated from the difference between this predicted velocity and the measured one, where the latter corresponds to the unrelaxed state. We evaluate the wave dispersion as a function of porosity for 112 carbonates, 128 sandstones and 56 volcanic rocks, including our measurements for 86 tight rocks, showing that dispersion increases with porosity in the low porosity range, but decreases in the high porosity range. The dispersion peak occurs at a porosity of approximately 15%. Double-porosity poroelasticity modeling based on the local fluid-flow mechanism confirms this behavior. The microcrack radius has a peak in the porosity range 15-19% for all the lithologies from our collection, while the behavior of microcrack porosity is less evident. The dispersion peak may reveal the characteristics of lithological units, in particular porosity, fluid type and rock microstructure.",23,24,6
Tight Sandstone,Carbonate,"Li, Guozhang; Qin, Yong; Shen, Jian; Wu, Meng; Li, Chao; Wei, Kaihua; Zhu, Chao","Geochemical characteristics of tight sandstone gas and hydrocarbon charging history of Linxing area in Ordos Basin, China",Linxing area; Gas genetic type; Stable isotopes; Fluid inclusion; Secondary biogenic gas,NATURAL-GAS; FLUID INCLUSION; COALBED GASES; SICHUAN BASIN; VELENJE BASIN; SAND GAS; ORIGIN; CARBON; GENERATION; ACCUMULATION,"Genetic type, source, charging history and reasons for secondary biogenic transformation of tight sandstone gas in the Linxing area in China's Ordos Basin have been studied through a combined analysis of gas compositions, isotopes of alkane and carbon dioxide, fluid inclusions and basin simulation. Tight sandstone gas in this area is predominated by methane, and the dryness coefficient is between 0.864 and 0.997 (average = 0.969). The delta C-13(1) values of methane and ethane in this area range from -44.5 parts per thousand to -33.2 parts per thousand (average = -39.4 parts per thousand) and from -27.5 parts per thousand to -24.4 parts per thousand (average = -25.9 parts per thousand), respectively. The non-hydrocarbon gases are nitrogen, followed by carbon dioxide and argon, and delta C-13 of carbon dioxide ranges from -14.6 parts per thousand to 8.6 parts per thousand. The homogenization temperatures of gas and gas-liquid inclusions in P(2)s and C(3)t in Linxing range from 80 degrees C to 170 degrees C, which are concentrated at 120-130 degrees C. The identification of gas origin indicates that tight sandstone gas is coal-type gas, which is mainly due to thermal evolution, followed by the mixing of secondary biogenic gas. Geological conditions and gas geochemical characteristics suggest that tight sandstone gas was produced by coal seam and carbonaceous shale in Upper Paleozoic in the Linxing area. The homogenization temperature of inclusion reflects the continuous accumulation process of tight sandstone gas, and the Cretaceous was the main period for gas charging. The monoclinal structure, maturity of source rocks and activity of underground water in this area are the important factors for secondary biogenic gas formation.",17,17,8
Tight Sandstone,Carbonate,Zhao Zhongxiang; Dong Chunmei; Zhang Xianguo; Lin Chengyan; Huang Xin; Duan Dongping; Lin Jianli; Zeng Fang; Li Dan,"Reservoir controlling factors of the Paleogene Oligocene Huagang Formation in the north central part of the Xihu Depression, East China Sea Basin, China",East China Sea Basin; Xihu depression; Huagang formation; Reservoir controlling factors; Low permeability - tight reservoir,DEPOSITIONAL FACIES; SANDSTONES; POROSITY; COMPACTION; DIAGENESIS; FIELD; CEMENTATION; PROPAGATION; PREDICTION; KAOLINITE,"Huagang Formation is a typical offshore, deep, low-permeability, tight sandstone reservoir with a low level of exploration and development and unclear control factors in the North Central area of the Xihu Depression in the East China Sea Basin. In this paper, we begin with the analysis of basic data, such as cores, casting thin sections, cathode luminescence, scanning electron microscopy, physical property statistics, grain size analysis, mercury penetration and magnetic resonance imaging, combined with field logging data from conventional logging, imaging logging and three-dimensional seismic imagery. The reservoir's physical properties were comprehensively discussed in terms of provenance, deposition, diagenesis and fractures. The results showed that the reservoir physical properties of the Huagang Formation were mainly affected by compaction, and the porosity and permeability decreased with the depth of burial. When the depth exceeds 4000 m, the porosity is basically < 10% and the permeability is nearly < 1 mD. The compaction above 4000 m was mainly controlled by provenance and depositional microfacies. The reservoir physical properties in the northern provenance is better than that of the east provenance. A high-energy braided channel is the best physical depositional microfacies. The reservoir formed by event sedimentation, such as from storms and floods, due to poor sorting, often containing mud and so on, with poor physical properties. Carbonate cementation only had a great influence on the local reservoir. Illite, illite/smectite and pore-filling chlorite were important factors affecting physical property deterioration. Pore-lining chlorite can promote the retention of primary pores. Below 4000 m, favorable reservoirs were mainly controlled by dissolution, resulting in dissolution pores being the main reservoir space. Microfractures played an important role in the properties of low-permeability and tight reservoirs. Microfractures themselves were easily dissolved into dissolution pores while being an important seepage channel for low-permeability and tight reservoirs. The denser the reservoir is, the more important the microfracture seepage is.",13,14,4
Tight Sandstone,Degrees C.,"Li, Hu; Tang, Hongming; Qin, Qirong; Zhou, Jiling; Qin, Zhangjin; Fan, Cunhui; Su, Peidong; Wang, Qin; Zhong, Cheng","Characteristics, formation periods and genetic mechanisms of tectonic fractures in the tight gas sandstones reservoir: A case study of Xujiahe Formation in YB area, Sichuan Basin, China",Tight gas sandstone; Tectonic fractures; Characteristics; Formation periods; Xujiahe formation; YB area Sichuan; Basin,PERMIAN LUCAOGOU FORMATION; SLIP-FAULT ZONE; QUANTITATIVE PREDICTION; STRESS-FIELD; ORDOS BASIN; ACOUSTIC-EMISSION; JUNGGAR BASIN; ZHENJING AREA; SHALE; ROCK,"The main target for hydrocarbon exploration of terrestrial strata in Sichuan Basin is the tight gas sandstone reservoir of the Upper Triassic Xujiahe Formation. Xujiahe Formation in YB area is a major discovery of hydrocarbon exploration in recent years, which is characterized as tight with ultralow porosity, ultralow permeability, and intensive heterogeneity. The tectonic fractures have important influence on accumulation and productivity of gas in the area. In the paper, analysis data of outcrop, core, imaging logging and other experiments were used to determine the characteristics, formation periods and genetic mechanisms of tectonic fractures. There are mainly high-angle and low-angle shear fractures in the area, which caused by tectonic stress. The length of the fractures is mainly 0-4 m from the outcrop and 10-20 cm from the cores and fracture frequencies (number per meter) is mostly 2-7 m(-1), 2-4 m(-1) respectively. The fracture fillings are mainly calcite, argillaceous and carbonaceous, about 60% of the fractures is unfilled or incompletely filled. Without considering the diagenetic fractures, there are three periods of the fractures: the middle-late Yanshanian tectonic movement, the early-middle Himalaya tectonic movement and the late Himalaya tectonic movement. The first period of the fractures are mainly filled with fine calcite, homogenization temperature of inclusion is 75-85 degrees C and the maximum effective principal stress of paleostress is 71.64 Mpa. The second period of the fractures are half-filled (or unfilled) with coarse calcite, homogenization temperature of inclusion is 150-175 degrees C and the maximum effective principal stress of paleostress is 74.91 Mpa. The third period of the fractures are low filling degree and cuts formed fractures clearly, the maximum effective principal stress of paleostress is 86.52 Mpa. For these tectonic movement, there are four sets of the plane ""X"" shear fractures in the area: NE strike fractures, NW strike fractures, NEE strike fractures, S-N strike fractures. There are one set of the profile shear fractures of NWW strike. Finally, the complex fault system of nearly N-S, NW and NE strike are formed in YB area.",31,32,8
Tight Sandstone,Degrees C.,"Liu, Dengke; Sun, Wei; Ren, Dazhong; Li, Changzheng","Quartz cement origins and impact on storage performance in Permian Upper Shihezi Formation tight sandstone reservoirs in the northern Ordos Basin, China",Quartz cement; Sources of silica; Storage performance; Upper Shihezi formation; Ordos basin,NUCLEAR-MAGNETIC-RESONANCE; PORE-THROAT STRUCTURE; LOW PERMEABILITY; BURIAL HISTORY; SONGLIAO BASIN; DIAGENESIS; POROSITY; SMECTITE; QUALITY; CLAY,"Authigenic quartz is an important cementing material that can degrade storage capacity, whereas the effect of quartz cement on microscale pores and throats in tight sandstone is controversial. Therefore, it is crucial to verify the sources of quartz cement as well as the controls on microscopic storage. Toward this end, a variety of tests were performed on Permian Upper Shihezi Formation sandstones, and they are the vital exploration and development interval for gas in the northern Ordos basin. We found that quartz cement is the most abundant interstitial mineral in the Upper Shihezi Formation tight sandstones, which forms at approximately 55 degrees C to 188 degrees C with a continuous process. All the samples can be divided into pore dominated and throat dominated types, and there is an increase in micropores and a decrease in macropores as the quartz cement content decreases. Chemical compaction and transformation of clay minerals were the main sources of silica. This work shows that although quartz cement would occupy the void space and lead to a loss of porosity, it could retard the compaction and preserve the pores, which is attributed to the limited compressibility of quartz cement supported rocks. Thus, the difference in the pore radius and throat radius is diminished, resulting in the decrease in pore-throat size heterogeneity in tight sandstones.",20,23,3
Tight Sandstone,Degrees C.,"Li, Guozhang; Qin, Yong; Shen, Jian; Wu, Meng; Li, Chao; Wei, Kaihua; Zhu, Chao","Geochemical characteristics of tight sandstone gas and hydrocarbon charging history of Linxing area in Ordos Basin, China",Linxing area; Gas genetic type; Stable isotopes; Fluid inclusion; Secondary biogenic gas,NATURAL-GAS; FLUID INCLUSION; COALBED GASES; SICHUAN BASIN; VELENJE BASIN; SAND GAS; ORIGIN; CARBON; GENERATION; ACCUMULATION,"Genetic type, source, charging history and reasons for secondary biogenic transformation of tight sandstone gas in the Linxing area in China's Ordos Basin have been studied through a combined analysis of gas compositions, isotopes of alkane and carbon dioxide, fluid inclusions and basin simulation. Tight sandstone gas in this area is predominated by methane, and the dryness coefficient is between 0.864 and 0.997 (average = 0.969). The delta C-13(1) values of methane and ethane in this area range from -44.5 parts per thousand to -33.2 parts per thousand (average = -39.4 parts per thousand) and from -27.5 parts per thousand to -24.4 parts per thousand (average = -25.9 parts per thousand), respectively. The non-hydrocarbon gases are nitrogen, followed by carbon dioxide and argon, and delta C-13 of carbon dioxide ranges from -14.6 parts per thousand to 8.6 parts per thousand. The homogenization temperatures of gas and gas-liquid inclusions in P(2)s and C(3)t in Linxing range from 80 degrees C to 170 degrees C, which are concentrated at 120-130 degrees C. The identification of gas origin indicates that tight sandstone gas is coal-type gas, which is mainly due to thermal evolution, followed by the mixing of secondary biogenic gas. Geological conditions and gas geochemical characteristics suggest that tight sandstone gas was produced by coal seam and carbonaceous shale in Upper Paleozoic in the Linxing area. The homogenization temperature of inclusion reflects the continuous accumulation process of tight sandstone gas, and the Cretaceous was the main period for gas charging. The monoclinal structure, maturity of source rocks and activity of underground water in this area are the important factors for secondary biogenic gas formation.",17,17,8
Tight Sandstone,Water Saturation,"Guo, Xiaobo; Huang, Zhilong; Zhao, Libin; Han, Wei; Ding, Chao; Sun, Xiongwei; Yan, Ruitao; Zhang, Tonghui; Yang, Xuejun; Wang, Ruomei","Pore structure and multi-fractal analysis of tight sandstone using MIP, NMR and NMRC methods: A case study from the Kuqa depression, China",Tight sandstone; Fractal dimension; Pore structure; Kuqa depression,ORDOS BASIN; TARIM BASIN; SIZE DISTRIBUTION; GAS SANDSTONE; OIL; POROSIMETRY; PARAMETERS; RESERVOIRS; DYNAMICS; ROCKS,"The pore structure and fractal characteristic of tight gas sandstone from Cretaceous Bashijiqike Formation in Kuqa depression were investigated, using thin section, scanning electronic microscope (SEM), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR) and NMR cryoporometry (NMRC) measurements. The pores of tight sandstone samples mainly contain residual primary intergranular pores, intergranular and intragranular dissolved pores, micropores related to clay aggregates and microfractures. The MIP, NMR and NMRC analyses show that the pore structure of tight sandstone is complex and heterogeneous at different pore scales, displaying as a multi-fractal feature. Fractal dimension Dg-s (with respect to small pore throats) from MIP and Dn-1 (long T-2 relaxation time, representing large pores and fractures or movable-fluid pores) are negatively correlated with porosity, permeability, median pore throat radius and skewness, and have inverse relationships with bound water saturation (S-bnd). Fractal dimension Dg-b ( > 3.0, with respect to larger pore throats) and Dn-s ( < 2.0, short T-2 relaxation time, representing small pores or bound-water pores) from NMR don't present clear relationships with most of pore structure parameters. Fractal dimension Dc-(1) and Dc-(2) from NMRC show more complex or inconspicuous relationships with pore structure parameters, in the pore diameter size < 500 nm. Hence, Dg-s from MIP and Dn-1 from NMR can be considered as effective parameters for pore structure and fluid properties characterization of tight sandstone. Fractal dimension Dg-b ( > 3.0) and Dn-s ( < 2.0) have no practical significance to characterize the pore structure of tight sandstone. The formation of residual primary intergranular pores and intergranular dissolution pores can reduce the fractal dimension which could be an important sign of effective reservoirs in the study area.",37,39,10
Tight Sandstone,Water Saturation,"Ba, Jing; Ma, Rupeng; Carcione, Jose M.; Picotti, Stefano",Ultrasonic wave attenuation dependence on saturation in tight oil siltstones,Elasticity and anelasticity; Microstructure; Permeability and porosity; Acoustic properties; Seismic attenuation; Wave propagation,SEISMIC ATTENUATION; WATER SATURATION; PORE-STRUCTURE; ROCKS; DISPERSION; VELOCITY; FLUIDS; DRY; SANDSTONES; STRESS,"Ultrasonic P-wave attenuation was measured in tight oil siltstones, carbonates and a tight sandstone with two independent estimation methods. The dependence on saturation in gas-water partially-saturated siltstones at in-situ conditions shows a different behavior compared to the other rocks. The siltstones in our experiments exhibit a behavior characterized by a gradual decrease of attenuation with increasing water saturation in the presence of gas, and full-gas saturation shows more attenuation than full-oil and full-water saturations. However, previous theoretical and experimental studies show that gas-water saturated carbonates and sandstones have the highest attenuation at high water saturations, and generally, a liquid-saturated rock shows more attenuation than a gas-saturated one. Poroelasticity theory shows that the two dominant loss mechanisms (due to fabric heterogeneity and patchy saturation) have peaks at different frequencies for siltstones, resulting in a gradual decrease of attenuation with water saturation, while these mechanisms overlap at ultrasonic frequencies for carbonates and sandstones, leading to an attenuation peak at high water saturations. The predicted attenuation dependence on fluid type agrees with the measurement for most samples. Regarding the tight oil siltstones, although the model fails to explain the experimental results for oil-water saturation, it can be concluded that for gas-water saturation the squirt flow caused by fabric heterogeneity dominates the attenuation, which differs from carbonates and sandstones. Experimental studies show that the attenuation dependence on saturation in tight oil reservoirs can be associated with fabric texture. The theory describes these behaviors, which can potentially improve the practices of detecting and monitoring multi-phase fluids in the reservoirs.",33,33,5
Tight Sandstone,Water Saturation,"Hassan, Amjed M.; Mahmoud, Mohamed A.; Al-Majed, Abdulaziz A.; Al-Nakhli, Ayman R.; Bataweel, Mohammed A.",Water blockage removal and productivity index enhancement by injecting thermochemical fluids in tight sandstone formations,Water blockage; Thermochemical fluids; Tight sandstone; Micro fractures; Capillary forces,FORMATION DAMAGE; LOW PERMEABILITY; GAS-RESERVOIRS; BLOCKING; PREVENTION; BASIN; FLOW; OIL,"Several challenges are associated with hydrocarbon production from tight reservoirs. Tight reservoirs are characterized with low permeability which reduces the hydrocarbon flow into the wellbore. Water blockage is considered one of the main damaging mechanisms in tight reservoirs due to the increase of water saturation around the wellbore region and eventually decrease in the relative permeability of hydrocarbons. Acid fracturing or hydraulic fracturing are required to remove the damage and enhance the formation conductivity. This paper presents a new technique to remove the water blockage from tight formations and improve the formation productivity using thermochemical treatment. Chemicals that generate pressure and heat at reservoir conditions are used to remove the water bank from tight core samples to enhance the flow conditions. Coreflooding experiments, capillary pressure, and NMR measurements were conducted as well as routine core analysis. The impact of thermochemical treatment on improving the formation productivity was quantified. The productivity index for core samples were determined before and after the thermochemical flooding. The effect of thermochemical injection on reducing the capillary forces was analyzed by measuring the capillary pressure before and after the chemical treatment. The alteration in pore geometry due to the thermochemical flooding was evaluated using NMR measurements. The results of this study show that water blockage is a potential damage in tight gas reservoirs. Injecting thermochemical fluids into tight samples reduced the capillary forces and removed the water banking. Flooding tight core samples with thermochemical resulted in generating tiny fractures in the treated samples, which reduces the capillary forces by 55.6% after the chemical treatment. The in-situ generated heat and nitrogen gas during thermochemical treatment can result in removing the water blockage from tight formations utilizing the desiccation effect. Also, thermochemical treatment showed a significant improvement in the core conductivity. The productivity index of core samples increased by 94.3% due to the chemical flooding. This study introduces a new chemical treatment for removing the water blockage from tight formations using environmentally friendly fluids. Thermochemical treatment improved the productivity index by a factor of 1.94 and decreased the drawdown pressure by more than 80%. Consequently, the trapped water was removed, and the total hydrocarbon production significantly improved.",16,16,4
Tight Sandstone,Cement,"Ren, Dazhong; Zhou, Desheng; Liu, Dengke; Dong, Fengjuan; Ma, Shuwei; Huang, Hai",Formation mechanism of the Upper Triassic Yanchang Formation tight sandstone reservoir in Ordos Basin-Take Chang 6 reservoir in Jiyuan oil field as an example,Diagenesis; Porosity evolution; Geological effect; Chang 6 member; Ordos bain,KRISHNA-GODAVARI BASIN; POROSITY EVOLUTION; DIAGENESIS; QUALITY; PERMEABILITY; CEMENTATION; AREA,"The Upper Triassic Yanchang Formation Chang 6 Member (C6 Member) in the Ordos Basin is the typical crude oil-rich sandstone in China, and its density restrict the exploration and development potential of hydrocarbon as well as their evaluation accuracy. Reservoir characteristics was studied using thin section (TS) associated with particle and pore size image analysis, X-ray diffractions, scanning electron microscopy (SEM) and mercury intrusion porosimetry (MIP). Time was taken as the main axle combined with diagenetic history, burial history, thermal history and structure. Thus, formation mechanism of tight reservoir was discussed by building the porosity evolution model and calculation method using ""diagenesis simulation"" and ""geological effect simulation"". Results show that after strong evolution and reconstruction, micro-nano pore throat system has developed and ultralow-low porosity-super low permeability tight sandstone reservoir has formed. Porosity evolution of Well H53 of C6 Member has revealed the correlations between the hydrocarbon charging and the porosity. Tight sandstone reservoir quality is affected by the maximum intergranular point-counted porosity, maximum compaction rate, maximum cementation rate, pore evolution of sample and the oil saturation, reasons for the formation of tight sandstone reservoir as well as its quality have been found out.",65,65,8
Tight Sandstone,Cement,"Liu, Dengke; Sun, Wei; Ren, Dazhong; Li, Changzheng","Quartz cement origins and impact on storage performance in Permian Upper Shihezi Formation tight sandstone reservoirs in the northern Ordos Basin, China",Quartz cement; Sources of silica; Storage performance; Upper Shihezi formation; Ordos basin,NUCLEAR-MAGNETIC-RESONANCE; PORE-THROAT STRUCTURE; LOW PERMEABILITY; BURIAL HISTORY; SONGLIAO BASIN; DIAGENESIS; POROSITY; SMECTITE; QUALITY; CLAY,"Authigenic quartz is an important cementing material that can degrade storage capacity, whereas the effect of quartz cement on microscale pores and throats in tight sandstone is controversial. Therefore, it is crucial to verify the sources of quartz cement as well as the controls on microscopic storage. Toward this end, a variety of tests were performed on Permian Upper Shihezi Formation sandstones, and they are the vital exploration and development interval for gas in the northern Ordos basin. We found that quartz cement is the most abundant interstitial mineral in the Upper Shihezi Formation tight sandstones, which forms at approximately 55 degrees C to 188 degrees C with a continuous process. All the samples can be divided into pore dominated and throat dominated types, and there is an increase in micropores and a decrease in macropores as the quartz cement content decreases. Chemical compaction and transformation of clay minerals were the main sources of silica. This work shows that although quartz cement would occupy the void space and lead to a loss of porosity, it could retard the compaction and preserve the pores, which is attributed to the limited compressibility of quartz cement supported rocks. Thus, the difference in the pore radius and throat radius is diminished, resulting in the decrease in pore-throat size heterogeneity in tight sandstones.",20,23,3
Tight Sandstone,Cement,Zhao Zhongxiang; Dong Chunmei; Zhang Xianguo; Lin Chengyan; Huang Xin; Duan Dongping; Lin Jianli; Zeng Fang; Li Dan,"Reservoir controlling factors of the Paleogene Oligocene Huagang Formation in the north central part of the Xihu Depression, East China Sea Basin, China",East China Sea Basin; Xihu depression; Huagang formation; Reservoir controlling factors; Low permeability - tight reservoir,DEPOSITIONAL FACIES; SANDSTONES; POROSITY; COMPACTION; DIAGENESIS; FIELD; CEMENTATION; PROPAGATION; PREDICTION; KAOLINITE,"Huagang Formation is a typical offshore, deep, low-permeability, tight sandstone reservoir with a low level of exploration and development and unclear control factors in the North Central area of the Xihu Depression in the East China Sea Basin. In this paper, we begin with the analysis of basic data, such as cores, casting thin sections, cathode luminescence, scanning electron microscopy, physical property statistics, grain size analysis, mercury penetration and magnetic resonance imaging, combined with field logging data from conventional logging, imaging logging and three-dimensional seismic imagery. The reservoir's physical properties were comprehensively discussed in terms of provenance, deposition, diagenesis and fractures. The results showed that the reservoir physical properties of the Huagang Formation were mainly affected by compaction, and the porosity and permeability decreased with the depth of burial. When the depth exceeds 4000 m, the porosity is basically < 10% and the permeability is nearly < 1 mD. The compaction above 4000 m was mainly controlled by provenance and depositional microfacies. The reservoir physical properties in the northern provenance is better than that of the east provenance. A high-energy braided channel is the best physical depositional microfacies. The reservoir formed by event sedimentation, such as from storms and floods, due to poor sorting, often containing mud and so on, with poor physical properties. Carbonate cementation only had a great influence on the local reservoir. Illite, illite/smectite and pore-filling chlorite were important factors affecting physical property deterioration. Pore-lining chlorite can promote the retention of primary pores. Below 4000 m, favorable reservoirs were mainly controlled by dissolution, resulting in dissolution pores being the main reservoir space. Microfractures played an important role in the properties of low-permeability and tight reservoirs. Microfractures themselves were easily dissolved into dissolution pores while being an important seepage channel for low-permeability and tight reservoirs. The denser the reservoir is, the more important the microfracture seepage is.",13,14,4
Tight Sandstone,Tectonic Fractures,"Li, Hu; Tang, Hongming; Qin, Qirong; Zhou, Jiling; Qin, Zhangjin; Fan, Cunhui; Su, Peidong; Wang, Qin; Zhong, Cheng","Characteristics, formation periods and genetic mechanisms of tectonic fractures in the tight gas sandstones reservoir: A case study of Xujiahe Formation in YB area, Sichuan Basin, China",Tight gas sandstone; Tectonic fractures; Characteristics; Formation periods; Xujiahe formation; YB area Sichuan; Basin,PERMIAN LUCAOGOU FORMATION; SLIP-FAULT ZONE; QUANTITATIVE PREDICTION; STRESS-FIELD; ORDOS BASIN; ACOUSTIC-EMISSION; JUNGGAR BASIN; ZHENJING AREA; SHALE; ROCK,"The main target for hydrocarbon exploration of terrestrial strata in Sichuan Basin is the tight gas sandstone reservoir of the Upper Triassic Xujiahe Formation. Xujiahe Formation in YB area is a major discovery of hydrocarbon exploration in recent years, which is characterized as tight with ultralow porosity, ultralow permeability, and intensive heterogeneity. The tectonic fractures have important influence on accumulation and productivity of gas in the area. In the paper, analysis data of outcrop, core, imaging logging and other experiments were used to determine the characteristics, formation periods and genetic mechanisms of tectonic fractures. There are mainly high-angle and low-angle shear fractures in the area, which caused by tectonic stress. The length of the fractures is mainly 0-4 m from the outcrop and 10-20 cm from the cores and fracture frequencies (number per meter) is mostly 2-7 m(-1), 2-4 m(-1) respectively. The fracture fillings are mainly calcite, argillaceous and carbonaceous, about 60% of the fractures is unfilled or incompletely filled. Without considering the diagenetic fractures, there are three periods of the fractures: the middle-late Yanshanian tectonic movement, the early-middle Himalaya tectonic movement and the late Himalaya tectonic movement. The first period of the fractures are mainly filled with fine calcite, homogenization temperature of inclusion is 75-85 degrees C and the maximum effective principal stress of paleostress is 71.64 Mpa. The second period of the fractures are half-filled (or unfilled) with coarse calcite, homogenization temperature of inclusion is 150-175 degrees C and the maximum effective principal stress of paleostress is 74.91 Mpa. The third period of the fractures are low filling degree and cuts formed fractures clearly, the maximum effective principal stress of paleostress is 86.52 Mpa. For these tectonic movement, there are four sets of the plane ""X"" shear fractures in the area: NE strike fractures, NW strike fractures, NEE strike fractures, S-N strike fractures. There are one set of the profile shear fractures of NWW strike. Finally, the complex fault system of nearly N-S, NW and NE strike are formed in YB area.",31,32,8
Tight Sandstone,Tectonic Fractures,"Gong, Lei; Su, Xiaocen; Gao, Shuai; Fu, Xiaofei; Jabbari, Hadi; Wang, Xixin; Liu, Bo; Yue, Wenting; Wang, Zhaosheng; Gao, Ang","Characteristics and formation mechanism of natural fractures in the tight gas sandstones of Jiulongshan gas field, China",Tight gas sandstone; Natural fractures; Fracture characteristics; Formation mechanism; Jiulongshan gas field,SICHUAN BASIN; STRATIGRAPHY; RESERVOIRS; POROSITY,"Natural fractures control the migration and accumulation of oil and gas in the tight sandstones. Understanding the characteristics and formation mechanism of natural fractures has important guiding significance to the comprehensive prediction and evaluation of the fracture distribution. Focusing on the tight sandstones of the Xujiahe Formation (T(3)x) of Jiulongshan gas field, northwest Sichuan Basin, China, the characteristics of natural fractures were characterized quantificationally, and a comprehensive evaluation method of fracture formation mechanism is proposed. Two types of natural fractures were identified in the T(3)x, namely tectonic fractures and diagenetic fractures. Most of the natural fractures are tectonic shear fractures, which can be subdivided into steep fractures and nearly horizontal fractures according to their dip angles. Three sets of tectonic fractures were identified in the study area, namely: NW-SE trending, NNE-SSW trending and NEE-SWW trending fractures. According to the characteristics of fracture sets, crosscutting relationships, acoustic emission tests and fluid inclusion analysis, and combined with the tectonic evolution history of the study area, the natural fractures were formed in four periods. Among them, the diagenetic fractures formed at the process of diagenesis are the first period fractures. The second to fourth periods are tectonic fractures formed at the end of the Triassic to the Early Jurassic, the Late Cretaceous and the end of Pliocene to the early of Pleistocene, respectively. Horizontal tectonic compression, uplift denudation and overpressure were the main force sources for the formation of the steep tectonic fractures. The formation of nearly horizontal fractures is related with the thrusting or inter-formational sliding caused by tectonic compression.",17,19,2
Tight Sandstone,Attenuation,"Ba, Jing; Ma, Rupeng; Carcione, Jose M.; Picotti, Stefano",Ultrasonic wave attenuation dependence on saturation in tight oil siltstones,Elasticity and anelasticity; Microstructure; Permeability and porosity; Acoustic properties; Seismic attenuation; Wave propagation,SEISMIC ATTENUATION; WATER SATURATION; PORE-STRUCTURE; ROCKS; DISPERSION; VELOCITY; FLUIDS; DRY; SANDSTONES; STRESS,"Ultrasonic P-wave attenuation was measured in tight oil siltstones, carbonates and a tight sandstone with two independent estimation methods. The dependence on saturation in gas-water partially-saturated siltstones at in-situ conditions shows a different behavior compared to the other rocks. The siltstones in our experiments exhibit a behavior characterized by a gradual decrease of attenuation with increasing water saturation in the presence of gas, and full-gas saturation shows more attenuation than full-oil and full-water saturations. However, previous theoretical and experimental studies show that gas-water saturated carbonates and sandstones have the highest attenuation at high water saturations, and generally, a liquid-saturated rock shows more attenuation than a gas-saturated one. Poroelasticity theory shows that the two dominant loss mechanisms (due to fabric heterogeneity and patchy saturation) have peaks at different frequencies for siltstones, resulting in a gradual decrease of attenuation with water saturation, while these mechanisms overlap at ultrasonic frequencies for carbonates and sandstones, leading to an attenuation peak at high water saturations. The predicted attenuation dependence on fluid type agrees with the measurement for most samples. Regarding the tight oil siltstones, although the model fails to explain the experimental results for oil-water saturation, it can be concluded that for gas-water saturation the squirt flow caused by fabric heterogeneity dominates the attenuation, which differs from carbonates and sandstones. Experimental studies show that the attenuation dependence on saturation in tight oil reservoirs can be associated with fabric texture. The theory describes these behaviors, which can potentially improve the practices of detecting and monitoring multi-phase fluids in the reservoirs.",33,33,5
Tight Sandstone,Attenuation,"Cheng, Wei; Ba, Jing; Fu, Li-Yun; Lebedev, Maxim",Wave-velocity dispersion and rock microstructure,Wave propagation; P-Wave velocity dispersion; Ultrasonic measurement; Gassmann equation; Carbonates; Sandstones; Volcanic rocks; Porosity; Microcracks; Poroelasticity,P-WAVE; CLAY CONTENT; SQUIRT-FLOW; POROSITY; ATTENUATION; SANDSTONES; MODEL; PERMEABILITY; FREQUENCIES; RESERVOIRS,"Porosity, fluid type and rock texture significantly affect acoustic wave propagation, since velocity dispersion and attenuation in fluid saturated rocks are mainly caused by wave-induced local fluid flow between microcracks and intergranular pores. We analyze P-wave velocity dispersion as a function of porosity to obtain information about the rock microstructure. The P-wave velocities in water-saturated rocks are predicted from measurements in gas-saturated rocks, using the Gassmann fluid substitution equation (the relaxed state). The dispersion is estimated from the difference between this predicted velocity and the measured one, where the latter corresponds to the unrelaxed state. We evaluate the wave dispersion as a function of porosity for 112 carbonates, 128 sandstones and 56 volcanic rocks, including our measurements for 86 tight rocks, showing that dispersion increases with porosity in the low porosity range, but decreases in the high porosity range. The dispersion peak occurs at a porosity of approximately 15%. Double-porosity poroelasticity modeling based on the local fluid-flow mechanism confirms this behavior. The microcrack radius has a peak in the porosity range 15-19% for all the lithologies from our collection, while the behavior of microcrack porosity is less evident. The dispersion peak may reveal the characteristics of lithological units, in particular porosity, fluid type and rock microstructure.",23,24,6
Tight Sandstone,MIP,"Ren, Dazhong; Zhou, Desheng; Liu, Dengke; Dong, Fengjuan; Ma, Shuwei; Huang, Hai",Formation mechanism of the Upper Triassic Yanchang Formation tight sandstone reservoir in Ordos Basin-Take Chang 6 reservoir in Jiyuan oil field as an example,Diagenesis; Porosity evolution; Geological effect; Chang 6 member; Ordos bain,KRISHNA-GODAVARI BASIN; POROSITY EVOLUTION; DIAGENESIS; QUALITY; PERMEABILITY; CEMENTATION; AREA,"The Upper Triassic Yanchang Formation Chang 6 Member (C6 Member) in the Ordos Basin is the typical crude oil-rich sandstone in China, and its density restrict the exploration and development potential of hydrocarbon as well as their evaluation accuracy. Reservoir characteristics was studied using thin section (TS) associated with particle and pore size image analysis, X-ray diffractions, scanning electron microscopy (SEM) and mercury intrusion porosimetry (MIP). Time was taken as the main axle combined with diagenetic history, burial history, thermal history and structure. Thus, formation mechanism of tight reservoir was discussed by building the porosity evolution model and calculation method using ""diagenesis simulation"" and ""geological effect simulation"". Results show that after strong evolution and reconstruction, micro-nano pore throat system has developed and ultralow-low porosity-super low permeability tight sandstone reservoir has formed. Porosity evolution of Well H53 of C6 Member has revealed the correlations between the hydrocarbon charging and the porosity. Tight sandstone reservoir quality is affected by the maximum intergranular point-counted porosity, maximum compaction rate, maximum cementation rate, pore evolution of sample and the oil saturation, reasons for the formation of tight sandstone reservoir as well as its quality have been found out.",65,65,8
Tight Sandstone,MIP,"Guo, Xiaobo; Huang, Zhilong; Zhao, Libin; Han, Wei; Ding, Chao; Sun, Xiongwei; Yan, Ruitao; Zhang, Tonghui; Yang, Xuejun; Wang, Ruomei","Pore structure and multi-fractal analysis of tight sandstone using MIP, NMR and NMRC methods: A case study from the Kuqa depression, China",Tight sandstone; Fractal dimension; Pore structure; Kuqa depression,ORDOS BASIN; TARIM BASIN; SIZE DISTRIBUTION; GAS SANDSTONE; OIL; POROSIMETRY; PARAMETERS; RESERVOIRS; DYNAMICS; ROCKS,"The pore structure and fractal characteristic of tight gas sandstone from Cretaceous Bashijiqike Formation in Kuqa depression were investigated, using thin section, scanning electronic microscope (SEM), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR) and NMR cryoporometry (NMRC) measurements. The pores of tight sandstone samples mainly contain residual primary intergranular pores, intergranular and intragranular dissolved pores, micropores related to clay aggregates and microfractures. The MIP, NMR and NMRC analyses show that the pore structure of tight sandstone is complex and heterogeneous at different pore scales, displaying as a multi-fractal feature. Fractal dimension Dg-s (with respect to small pore throats) from MIP and Dn-1 (long T-2 relaxation time, representing large pores and fractures or movable-fluid pores) are negatively correlated with porosity, permeability, median pore throat radius and skewness, and have inverse relationships with bound water saturation (S-bnd). Fractal dimension Dg-b ( > 3.0, with respect to larger pore throats) and Dn-s ( < 2.0, short T-2 relaxation time, representing small pores or bound-water pores) from NMR don't present clear relationships with most of pore structure parameters. Fractal dimension Dc-(1) and Dc-(2) from NMRC show more complex or inconspicuous relationships with pore structure parameters, in the pore diameter size < 500 nm. Hence, Dg-s from MIP and Dn-1 from NMR can be considered as effective parameters for pore structure and fluid properties characterization of tight sandstone. Fractal dimension Dg-b ( > 3.0) and Dn-s ( < 2.0) have no practical significance to characterize the pore structure of tight sandstone. The formation of residual primary intergranular pores and intergranular dissolution pores can reduce the fractal dimension which could be an important sign of effective reservoirs in the study area.",37,39,10
Tight Sandstone,Upper Triassic,"Ren, Dazhong; Zhou, Desheng; Liu, Dengke; Dong, Fengjuan; Ma, Shuwei; Huang, Hai",Formation mechanism of the Upper Triassic Yanchang Formation tight sandstone reservoir in Ordos Basin-Take Chang 6 reservoir in Jiyuan oil field as an example,Diagenesis; Porosity evolution; Geological effect; Chang 6 member; Ordos bain,KRISHNA-GODAVARI BASIN; POROSITY EVOLUTION; DIAGENESIS; QUALITY; PERMEABILITY; CEMENTATION; AREA,"The Upper Triassic Yanchang Formation Chang 6 Member (C6 Member) in the Ordos Basin is the typical crude oil-rich sandstone in China, and its density restrict the exploration and development potential of hydrocarbon as well as their evaluation accuracy. Reservoir characteristics was studied using thin section (TS) associated with particle and pore size image analysis, X-ray diffractions, scanning electron microscopy (SEM) and mercury intrusion porosimetry (MIP). Time was taken as the main axle combined with diagenetic history, burial history, thermal history and structure. Thus, formation mechanism of tight reservoir was discussed by building the porosity evolution model and calculation method using ""diagenesis simulation"" and ""geological effect simulation"". Results show that after strong evolution and reconstruction, micro-nano pore throat system has developed and ultralow-low porosity-super low permeability tight sandstone reservoir has formed. Porosity evolution of Well H53 of C6 Member has revealed the correlations between the hydrocarbon charging and the porosity. Tight sandstone reservoir quality is affected by the maximum intergranular point-counted porosity, maximum compaction rate, maximum cementation rate, pore evolution of sample and the oil saturation, reasons for the formation of tight sandstone reservoir as well as its quality have been found out.",65,65,8
Tight Sandstone,Upper Triassic,"Li, Hu; Tang, Hongming; Qin, Qirong; Zhou, Jiling; Qin, Zhangjin; Fan, Cunhui; Su, Peidong; Wang, Qin; Zhong, Cheng","Characteristics, formation periods and genetic mechanisms of tectonic fractures in the tight gas sandstones reservoir: A case study of Xujiahe Formation in YB area, Sichuan Basin, China",Tight gas sandstone; Tectonic fractures; Characteristics; Formation periods; Xujiahe formation; YB area Sichuan; Basin,PERMIAN LUCAOGOU FORMATION; SLIP-FAULT ZONE; QUANTITATIVE PREDICTION; STRESS-FIELD; ORDOS BASIN; ACOUSTIC-EMISSION; JUNGGAR BASIN; ZHENJING AREA; SHALE; ROCK,"The main target for hydrocarbon exploration of terrestrial strata in Sichuan Basin is the tight gas sandstone reservoir of the Upper Triassic Xujiahe Formation. Xujiahe Formation in YB area is a major discovery of hydrocarbon exploration in recent years, which is characterized as tight with ultralow porosity, ultralow permeability, and intensive heterogeneity. The tectonic fractures have important influence on accumulation and productivity of gas in the area. In the paper, analysis data of outcrop, core, imaging logging and other experiments were used to determine the characteristics, formation periods and genetic mechanisms of tectonic fractures. There are mainly high-angle and low-angle shear fractures in the area, which caused by tectonic stress. The length of the fractures is mainly 0-4 m from the outcrop and 10-20 cm from the cores and fracture frequencies (number per meter) is mostly 2-7 m(-1), 2-4 m(-1) respectively. The fracture fillings are mainly calcite, argillaceous and carbonaceous, about 60% of the fractures is unfilled or incompletely filled. Without considering the diagenetic fractures, there are three periods of the fractures: the middle-late Yanshanian tectonic movement, the early-middle Himalaya tectonic movement and the late Himalaya tectonic movement. The first period of the fractures are mainly filled with fine calcite, homogenization temperature of inclusion is 75-85 degrees C and the maximum effective principal stress of paleostress is 71.64 Mpa. The second period of the fractures are half-filled (or unfilled) with coarse calcite, homogenization temperature of inclusion is 150-175 degrees C and the maximum effective principal stress of paleostress is 74.91 Mpa. The third period of the fractures are low filling degree and cuts formed fractures clearly, the maximum effective principal stress of paleostress is 86.52 Mpa. For these tectonic movement, there are four sets of the plane ""X"" shear fractures in the area: NE strike fractures, NW strike fractures, NEE strike fractures, S-N strike fractures. There are one set of the profile shear fractures of NWW strike. Finally, the complex fault system of nearly N-S, NW and NE strike are formed in YB area.",31,32,8
Neural Network,Random Forest,"Wang, Shuhua; Chen, Shengnan",Insights to fracture stimulation design in unconventional reservoirs based on machine learning modeling,Fracture stimulation design; Data mining; Feature selection; Machine learning; Montney tight reservoirs,ARTIFICIAL NEURAL-NETWORKS; GAS-PRODUCTION; NATURAL-GAS; TIGHT OIL; SHALE; OPTIMIZATION,"With rapid development of unconventional tight and shale reservoirs, considerable amounts of data sets are increasing rapidly. Data mining techniques are becoming attractive alternatives for well performance evaluation and optimization. This paper develops a comprehensive data mining process to evaluate well production performance in Montney Formations in western Canadian sedimentary basin. The general data visualization and statistical data evaluation are used to qualitatively and quantitatively evaluate the relationships between the stimulation parameters and first-year oil production. Then, the recursive feature elimination with cross validation (RFECV) is used to identify the most important factors on the first-year oil production in unconventional reservoirs. In addition, four commonly used supervised learning approaches including random forest (RF), adaptive boosting (AdaBoost), support vector machine (SVM), and neural network (NN) are compared to estimate the first-year well production. The results show that 6 features are the most important variables for constructing an accurate prediction model: well latitude, longitude, well true vertical depth (TVD), proppant pumped per well, well lateral length, and fluid injected per well. Compared to other algorithms, RF has the best prediction performance for the first-year oil production. Furthermore, such data-driven models are found to be very useful for reservoir engineers when designing hydraulic fracture treatments in Montney tight reservoirs.",45,46,5
Neural Network,Random Forest,"Ao, Yile; Li, Hongqi; Zhu, Liping; Ali, Sikandar; Yang, Zhongguo",The linear random forest algorithm and its advantages in machine learning assisted logging regression modeling,Machine learning; Logging interpretation; Logging regression modeling; Linear random forest; Algorithm comparison,SUPPORT-VECTOR-REGRESSION; PETROLEUM RESERVOIR CHARACTERIZATION; ARTIFICIAL NEURAL-NETWORKS; PERMEABILITY PREDICTION; GENETIC-ALGORITHM; WATER SATURATION; WIRELINE LOGS; FUZZY-LOGIC; POROSITY; INDUCTION,"Direct measurements of formation properties such as the shale volume, porosity, permeability, and fluid saturation are often accompanied by expensive cost and are time-consuming too. Well logging inversion provides an alternative way for the determination of formation properties. Compared to traditional theoretical models or formalized empirical fitted models, machine learning assisted logging regression modeling is more accurate and objective. Several machine learning regression algorithms such as neural networks, support vector regression, fuzzy logic, k nearest neighbors regression, multivariate adaptive regression spline, and random forest have already been applied. In this article, we present the Linear Random Forest algorithm and investigate its application in logging regression modeling. By systematic comparison with 8 other algorithms including least squared linear regression, neural networks, epsilon support vector regression, k nearest neighbors regression, regression tree, regression random forest, gradient descent boosted trees, and linear decision tree, the advantage of linear random forest in performance is confirmed by 24 real-world tasks from 7 different areas. Deeper discussions reveal that the advantages of linear random forest source from its strong learning ability, robustness, and feasibility of the hypothesis space. Through our study, the superiority of linear random forest for logging regression modeling is substantiated, which provides a more reasonable way for the further practices of logging regression modeling.",38,41,24
Neural Network,Random Forest,"Kanin, E. A.; Osiptsov, A. A.; Vainshtein, A. L.; Burnaev, E., V",A predictive model for steady-state multiphase pipe flow: Machine learning on lab data,Multiphase flow; Machine learning; Surrogate modeling; Pressure gradient; Flow pattern; Liquid holdup,LIQUID HOLDUP; SLUG,"Engineering simulators used for steady-state multiphase flows in oil and gas wells and pipelines are commonly utilized to predict pressure drop and phase velocities. Such simulators are typically based on either empirical correlations (e.g., Beggs and Brill, Mukherjee and Brill, Duns and Ros) or first-principles mechanistic models (e.g., Ansari, Xiao, TUFFP Unified, Leda Flow Point model, OLGAS). The simulators allow one to evaluate the pressure drop in a multiphase pipe flow with acceptable accuracy. However, the only shortcoming of these correlations and mechanistic models is their applicability (besides steady-state versions of transient simulators such as Leda Flow and OLGA). Empirical correlations are commonly applicable in their respective ranges of data fitting; and mechanistic models are limited by the applicability of the empirically based closure relations that are a part of such models. In order to extend the applicability and the accuracy of the existing accessible methods, a method of pressure drop calculation in the pipeline is proposed. The method is based on well segmentation and calculation of the pressure gradient in each segment using three surrogate models based on Machine Learning (ML) algorithms trained on a representative lab data set from the open literature. The first model predicts the value of a liquid holdup in the segment, the second one determines the flow pattern, and the third one is used to estimate the pressure gradient. To build these models, several ML algorithms are trained such as Random Forest, Gradient Boosting Decision Trees, Support Vector Machine, and Artificial Neural Network, and their predictive abilities are cross-compared. The proposed method for pressure gradient calculation yields R-2 = 0.95 by using the Gradient Boosting algorithm as compared with R-2 = 0.92 in case of Mukherjee and Brill correlation and R-2 = 0.91 when a combination of Ansari and Xiao mechanistic models is utilized. The application of the above-mentioned ML algorithms and the larger database used for their training will allow extending the proposed methodology to a wider applicability range of input parameters as compared to standard accessible techniques. The method for pressure drop prediction based on ML algorithms trained on lab data is also validated on three real field cases. Validation indicates that the proposed model yields the following coefficients of determination: R-2 = 0.806, 0.815 and 0.99 as compared with the highest values obtained by commonly used techniques: R-2 = 0.82 (Beggs and Brill correlation), (Mukherjee and Brill correlation) and R-2 = 0.98 (Beggs and Brill correlation). Hence, the method for calculating the pressure distribution could give comparable or even higher scores on field data by contrast to correlations and mechanistic models. This fact is an indicator that the model can be scalable from the lab to the field conditions without any additional retraining of ML algorithms.",21,21,1
Neural Network,Random Forest,"Gu, Yufeng; Bao, Zhidong; Song, Xinmin; Patil, Shirish; Ling, Kegang",Complex lithology prediction using probabilistic neural network improved by continuous restricted Boltzmann machine and particle swarm optimization,Carbonate reservoirs; Lithology prediction; Probabilistic neural network; Continuous restricted Boltzmann machine; Particle swarm optimization,SUPPORT VECTOR MACHINE; SANTOS BASIN; DISCRIMINANT-ANALYSIS; PATTERN-RECOGNITION; INERTIA WEIGHT; RANDOM FOREST; CLASSIFICATION; ALGORITHM; MODELS; GAS,"Lithology prediction, especially for reservoirs consisting of complex lithologies, is universally considered as a critical underlying task for petroleum exploration, because lithological data is indispensable for the analysis of some geological work, such as stratigraphic correlation or sedimentation modeling. Hence, how to acquire the reliable lithological information gradually becomes a hot topic in the geoscience. Probabilistic neural network (PNN) is an excellent approach for lithology prediction since it can efficiently complete pattern recognition by determining characteristics of each kind of learning data. However, its computation performance is severely limited by two factors, which are quality of raw data and selection of parameter. High correlation of raw data could be an obstacle for the determination of data characteristics because partial probability density distributions established by PNN would be merged. As window length of each probability density distribution shows great impact on the accuracy of calculated results, the selection of this parameter must be addressed optimally before prediction. In order to improve the calculation capability of PNN, two techniques, continuous restricted Boltzmann machine (CRBM) and particle swarm optimization (PSO), are introduced. CRBM has the special function of extracting features from raw data and the features generally present with low correlation, thus can be viewed as an ideal preprocessing segment for PNN. PSO is one of the most efficient algorithms used for solving optimization problem, and the optimal parameter setting of PNN, therefore, can be revealed. Due to the advantages of CRBM and PSO for PNN, a new method for complex lithology prediction is proposed, which is referred as CRBM-PSO-PNN. Data for new method validation is recorded by two wells which are located in the IARA oilfield. Moreover, three experiments are well designed in order to verify the computing capability of new method comprehensively. Experiment results manifest that the prediction accuracies provided by new method in three experiments are highest, all of which are over 75%. High prediction accuracies fully demonstrate that the proposed method is effective to predict complex lithology, and the predicted results are reliable to serve other geological work.",17,18,2
Neural Network,Random Forest,"Ao, Yile; Li, Hongqi; Zhu, Liping; Ali, Sikandar; Yang, Zhongguo",Identifying channel sand-body from multiple seismic attributes with an improved random forest algorithm,Machine learning; Random forest; Ensemble learning; Seismic interpretation; Channel identification,MARCELLUS SHALE LITHOFACIES; REMOTE-SENSING DATA; NEURAL-NETWORKS; RESERVOIR CHARACTERIZATION; MINERAL PROSPECTIVITY; PREDICTION; POROSITY; CLASSIFICATION; MODELS; IDENTIFICATION,"Machine learning provides numerous data-driven tools for automatic pattern recognition. Even though various algorithms such as neural networks and support vector machines have been widely applied, it is still necessary to explore new paradigms and algorithms to improve the machine learning assisted seismic interpretation. Random Forest (RF) is a widely used ensemble algorithm, however, only limited studies of random forest in the seismic application were published. In this article, the methodology of random forest is introduced systematically. Meanwhile, to solve the problem of hyper-parameter determination, we propose an improved algorithm named Pruning Random Forest (PRF). To reveal the advantages of PRF in terms of predictive performance, robustness, and feature selection compared with support vector machine, neural network, and decision tree, several well-designed experiments are executed based on the seismic data of the western Bohai Sea of China. The potential and advantages of random forest in the present case are confirmed by various experiments, which substantiates that the proposed pruning random forest algorithm provides a reliable alternative way for further machine learning assisted seismic interpretation.",14,16,7
Neural Network,Random Forest,"Bhattacharya, Shuvajit; Ghahfarokhi, Payam Kavousi; Carr, Timothy R.; Pantaleone, Scott","Application of predictive data analytics to model daily hydrocarbon production using petrophysical, geomechanical, fiber-optic, completions, and surface data: A case study from the Marcellus Shale, North America",Marcellus Shale; Fiber optic; Data analytics; Machine learning; Predicting gas production,APPALACHIAN BASIN; LITHOFACIES,"Predicting gas production from stimulated unconventional reservoirs has always been a challenge to oil and gas companies because the physics of fluid flow through such reservoirs is not well understood. On the other hand, modeling gas production from shale reservoirs is a complex multi-variate problem that requires proper integration of data from multiple disciplines, such as geology, petrophysics, geomechanics, completions, and surface-based measurements, etc. This study demonstrates the application of data-driven machine learning algorithms, integrating geoscientific, distributed acoustic sensing (DAS), distributed temperature sensing (DTS) fiber-optic, completions, flow scanner production log, and surface data to model daily gas production from a 28-stage stimulated horizontal well drilled in the Marcellus Shale of the Appalachian basin in North America. In addition, this study aims to utilize the data from a fiber-optic monitoring system, such as DAS and DTS to evaluate the well performance. We build supervised data-driven machine learning models using Random Forest (RF), Artificial Neural Network (ANN), and Support Vector Machine (SVM) algorithms to understand the well performance and forecast the daily gas production. The study compares the forecasted results, tests the level of accuracy, and addresses different issues with these machine learning algorithms. A spatio-temporal database is constructed and used to perform sensitivity analyses to identify the key drivers for gas production. The results show that RF and ANN algorithms can be used to predict daily gas production with significantly high accuracy; however, RF algorithm is the best predictor in terms of highest accuracy (96%), less computational time and cost. Based on sensitivity analysis, it appears that Poisson's ratio, minimum horizontal stress, DAS, casing pressure, gamma log are the most important parameters to predict gas production.",14,15,4
Neural Network,Regression,"Ashrafi, Seyed Babak; Anemangely, Mohammad; Sabah, Mohammad; Ameri, Mohammad Javad",Application of hybrid artificial neural networks for predicting rate of penetration (ROP): A case study from Marun oil field,Rate of penetration; Artificial neural network; Feature selection; Evolutionary algorithms,SUPPORT VECTOR REGRESSION; KRILL HERD ALGORITHM; DRILLING RATE; FEATURE-SELECTION; MODELS; ROCKS; OPTIMIZATION; RESERVOIRS; VISCOSITY; IDENTIFICATION,"Rate of Penetration (ROP) can be considered as a crucial factor in optimization and cost minimization of drilling operations. In order to predict ROP with satisfactory precision, some hybrid artificial intelligence models were developed in the present research. To achieve this, dataset including petrophysical logs and drilling data was collected from a vertical well drilled in Marun oil field where is in southwest corner of Iran. Then, overall noise of the collected data was reduced with implementing Savitzky-Golay (SG) smoothing filter. In the next stage, a feature selection method with application of genetic algorithm was employed for choosing the unrivaled features and lessening the input vectors. Regarding results of the feature selection method, eight parameters including weight on bit, bit rotational speed, pump flow rate, pump pressure, pore pressure, gamma ray, density log and shear wave velocity were identified as the most influential parameters in drilling rate. After that, eight hybrid artificial neural networks (ANN) were developed and trained by four evolutionary algorithms. These algorithms are genetic algorithm (GA), particle swarm optimization (PSO), biogeography-based optimizer (BBO) and imperialist competitive algorithm (ICA). After model developments, to provide an objective assessment of performances of the proposed hybrid models, their results were compared with results of conventional ANN models and two multiple regression methods (NLMR and LMR) using different performance indices such as root mean square error (RMSE), variance account for (VAF), and performance index (PI). Results showed that PSO-multilayer perception (PSO-MLP) and PSO-radial basis function (PSO-RBF) neural networks with RMSE of 1.12 and 1.4, respectively yielded the highest performance in prediction comparing to results of other developed models. Concluding remark is that hybrid ANNs exhibit much more efficiency and reliability than conventional ANNs and regression methods in terms of ROP prediction, indicating superiority of evolutionary algorithms over back propagation (BP) methods in the ANNs training.",44,44,7
Neural Network,Regression,"Ao, Yile; Li, Hongqi; Zhu, Liping; Ali, Sikandar; Yang, Zhongguo",The linear random forest algorithm and its advantages in machine learning assisted logging regression modeling,Machine learning; Logging interpretation; Logging regression modeling; Linear random forest; Algorithm comparison,SUPPORT-VECTOR-REGRESSION; PETROLEUM RESERVOIR CHARACTERIZATION; ARTIFICIAL NEURAL-NETWORKS; PERMEABILITY PREDICTION; GENETIC-ALGORITHM; WATER SATURATION; WIRELINE LOGS; FUZZY-LOGIC; POROSITY; INDUCTION,"Direct measurements of formation properties such as the shale volume, porosity, permeability, and fluid saturation are often accompanied by expensive cost and are time-consuming too. Well logging inversion provides an alternative way for the determination of formation properties. Compared to traditional theoretical models or formalized empirical fitted models, machine learning assisted logging regression modeling is more accurate and objective. Several machine learning regression algorithms such as neural networks, support vector regression, fuzzy logic, k nearest neighbors regression, multivariate adaptive regression spline, and random forest have already been applied. In this article, we present the Linear Random Forest algorithm and investigate its application in logging regression modeling. By systematic comparison with 8 other algorithms including least squared linear regression, neural networks, epsilon support vector regression, k nearest neighbors regression, regression tree, regression random forest, gradient descent boosted trees, and linear decision tree, the advantage of linear random forest in performance is confirmed by 24 real-world tasks from 7 different areas. Deeper discussions reveal that the advantages of linear random forest source from its strong learning ability, robustness, and feasibility of the hypothesis space. Through our study, the superiority of linear random forest for logging regression modeling is substantiated, which provides a more reasonable way for the further practices of logging regression modeling.",38,41,24
Neural Network,Regression,"Ahmed, Omogbolahan S.; Adeniran, Ahmed A.; Samsuri, Ariffin",Computational intelligence based prediction of drilling rate of penetration: A comparative study,ROP prediction; Neural network; Least square support vector regression; Specific energy; Drilling efficiency; Extreme learning machine,EXTREME LEARNING-MACHINE; SUPPORT VECTOR MACHINES,"Application of artificial intelligence in the accurate prediction of the rate of penetration (ROP), an important measure of drilling performance, has lately gained significant interest in oil and gas well drilling operations. Consequently, several computational intelligence techniques (CITs) for the prediction of ROP have been explored in the literature. This study explores the predictive capabilities of four commonly used CITs in the pre- diction of ROP and experimentally compare their predictive performance. The CIT algorithm utilizes predictors which are easily accessible continuous drilling data that have physical but complex relationship with ROP based on hydro-mechanical specific energy ROP model. The four CITs compared are the artificial neural network (ANN), extreme learning machine, support vector Regression and least-square support vector regression (LSSVR). Two experiments were carried out; the first experiment investigates the comparative performance of the CITs while the second investigates the effect of reduced number of predictors on the performance of the models. The results show that all the CITs perform within acceptable accuracy with testing root mean square error range (RMSE) of 18.27-28.84 and testing correlation coefficient (CC) range of 0.71-0.94. LS-SVR has the best predictive performance in terms of accuracy with RMSE of 18.27 and CC of 0.94 while ANN has the best testing execution time at 0.03 s. Also utilizing the specific energy concept in chosen drilling parameters to be included among the predictors shows improved performance with five drilling parameters showing an improvement of 3%-9% in RMSE for LS-SVR in the two well studied. The utilization of the specific energy concept in the selection of the predictors in this study has demonstrated that the easily accessible drilling parameters have immense value to provide acceptable performance in the development of ROP model with CITs.",35,35,6
Neural Network,Regression,"Wang, Pan; Peng, Suping",On a new method of estimating shear wave velocity from conventional well logs,Shear wave velocity; Extreme learning machine; Mean impact value; Artificial intelligence; Conventional well logs; Ordos basin,EXTREME LEARNING-MACHINE; EMPIRICAL RELATIONS; COMPRESSIONAL-WAVE; MIXED SELECTIVITY; NEURAL-NETWORKS; PREDICTION; RESERVOIR; APPROXIMATION; REGRESSION; ALGORITHM,"Shear wave velocity is a critical parameter for the characterization of hydrocarbon reservoirs. Compared with compressional wave velocity which almost exist in every well, shear wave velocity hasn't been recorded in those days for the older wells due to the lack of logging equipment or limited funds. Furthermore, measuring shear wave velocity is fairly time-and money-consuming as it can only be gained by the analysis of core samples conducted in the lab or from the dipole sonic imager (DSI). To cope with the above puzzles, a new methodology, by integrating extreme learning machines (ELM) and technique of mean impact value (MIV), is proposed in this paper with the support of log data collected from two wells located in unconventional shale gas reservoir in Ordos Basin, China. Based on mean impact value, a well-trained ELM model is taken to identify optimal well logs and five well logs are identified to provide the significant and valid information for the estimation of shear wave velocity. 3201 data points collected from well L4 are used in constructing the model. Compared with artificial neural network used in the former studies Levenberg-Marquardt algorithm (ANN-LM), the ELM model's prediction accuracy has been evaluated, the results indicates that the ELM model outperforms ANN-LM model with faster calculating speed and better performance. Additionally, the efficiency of the model proposed here is well investigated by using another well with 3201 data points. Through the comparison among ELM, support vector regression (SVR), convolutional neural network (CNN) and four widely known empirical formulas, what can be concluded is that ELM model is more efficient in fast calculation and high precision. From the result, it can be demonstrated that the use of ELM model, combined with the analysis of mean impact value (MIV), is a more efficient and promising method for shear wave velocity estimation process from conventional well log data, which can be recognized as a promising tool with an extended application. And this research can be applied into a software system for rapid acquisition of shear wave velocity logs.",17,17,4
Neural Network,Regression,"Anemangely, Mohammad; Ramezanzadeh, Ahmad; Behboud, Mohammad Mohammadi",Geomechanical parameter estimation from mechanical specific energy using artificial intelligence,Mechanical specific energy; Geomechanical parameters prediction; Artificial intelligence; Outlier detection,KRISHNA-GODAVARI BASIN; MUD WEIGHT; PREDICTION; OIL,"A comprehensive knowledge of geomechanical characteristics of the formations above a reservoir (cap rock, in particular) can prevent a large spectrum of problems during drilling operation. Furthermore, access to such information during drilling operation greatly contributes to proper adjustment of controllable parameters and enhanced rate of penetration (ROP). Unfortunately, due to the high costs associated with the acquisition of petrophysical logs, these sets of data are commonly acquired within the reservoir interval only, i.e. at most 20% of total drilled length. As such, the present contribution is an attempt to use the concept of mechanical specific energy (MSE) to estimate geomechanical parameters of rock. For this purpose, data was collected from two vertical wells drilled into an oilfield in southwest of Iran. Firstly, based upon available drilling reports and Tukey method, outlier data points were detected and omitted. Then, MSE was evaluated using different models proposed for this purpose previously. The evaluation results indicated that, the results obtained from Dupriest and Koederitz (2005) model were in good agreement with actual conditions at the considered wells. Therefore, the obtained MSE from this model along with flow rate (FR), bit tooth wear (CT), and Depth logs were used as input for multivariate nonlinear regression (MNLR) method as well as multi-layer perceptron neural network combined with cuckoo optimization algorithm (MLP-COA) and also with particle swarm optimization (MLP-PSO) to estimate confined compressive strength (CCS), uniaxial compressive strength (UCS), internal friction angle (phi), and Poisson's ratio (nu). Models were trained on data from one well and then validation-tested on the other well's data. Results of adopting these models indicated that, as far as the estimation of geomechanical parameters was concerned, intelligent models were of higher accuracy and reliability than the regression model. A comparison between the results of MLP-COA and MLP-PSO models showed that, COA outperforms PSO algorithm in achieving a model of higher accuracy and reliability. Results of the three models indicated that, the presented method in this research possesses large potentials for estimating CCS, UCS, and phi parameters, and it can be stipulated with certainty that, the proposed method can be used to estimate the parameters at other wells across the field under study provided further data is available from more wells and even the formations overlying the reservoir. However, application of this method for estimating nu shall be practiced with care.",15,15,3
Neural Network,Regression,"Du, Qizhen; Yasin, Qamar; Ismail, Atif; Sohail, Ghulam Mohyuddin",Combining classification and regression for improving shear wave velocity estimation from well logs data,Shear wave velocity; Clustering and classification; Multivariate regression; Rock physics modeling; Neural network,SAWAN GAS-FIELD; PRACTICAL APPLICATION; CARBONATE RESERVOIR; PETROPHYSICAL DATA; COMMITTEE MACHINE; FLOW UNITS; PREDICTION; PERMEABILITY; POROSITY; ELECTROFACIES,"A shear wave is a critical property that helps to constrain rock properties such as lithology, pore fluid, and pore pressure. Nevertheless, valid and reliable estimation of shear wave velocity in highly heterogeneous reservoirs is still considered a challenge to be faced. In this paper, we propose a strategy for improving shear wave velocity estimation based on the combination of clustering and classification plus regression using conventional logs. The approach includes two steps. In step one, data clustering algorithms are applied to build a classifier model for identifying the distinct electrofacies (EF) based on similarity of well log responses. In step two, a distinct and specialized regression model is selected from more sophisticated methods (empirical models, statistical regression, virtual intelligence, and rock physics modeling) for determining the final shear wave velocity profile. The effectiveness of this proposed strategy is validated over a dataset from offset wells and their respective measured shear wave velocity data. The final results revealed that the proposed strategy that combines data mining task of clustering and classification plus regression, led to more uniform and better predictive performance of shear wave velocity (R-2 = 0.97) in comparison with the use of stand-alone rock physics model (R-2 = 0.70), virtual intelligence (R-2 = 0.82), and statistical regression (R-2 = 0.91). The silent features of this proposed strategy is that field-specific regression models are built based on log derived EF and geological information.",14,14,1
Neural Network,Lithology,"Imamverdiyev, Yadigar; Sukhostat, Lyudmila",Lithological facies classification using deep convolutional neural network,Well log data; Facies; Facies classification; Deep learning; Convolutional neural network,RESERVOIR; FIELD; ANN,"The aim of this paper is the development of an effective model based on deep learning for geological fades classification in wells. Fades classification is carried out by studying the lithological properties of rocks, which are characteristic of modern sediments, accumulating in certain physical and geographical conditions. In this study, a new 1D-CNN model, which is trained on various optimization algorithms, is proposed. The photoelectric effect, gamma ray, resistivity logging, neutron-density porosity difference, average neutron density porosity and geologic constraining variables are considered as input data of the model. Acceptable accuracy and the use of conventional well log data are the main advantages of the proposed intellectual model. The proposed model is compared with a recurrent neural network model, a long short-term memory model, a support vector machine model, and a k-nearest neighbor model and shows more accurate results in comparison with them. The model shows successful results in the study of well log data and can, therefore, be recommended as a suitable and effective approach for well log data processing required for lithological discrimination.",40,43,5
Neural Network,Lithology,"Ren, Xiaoxu; Hou, Jiagen; Song, Suihong; Liu, Yuming; Chen, Depo; Wang, Xixin; Dou, Luxing",Lithology identification using well logs: A method by integrating artificial neural networks and sedimentary patterns,Combination pattern; Geological pattern; Probability combination scheme; Statistical method; Log interpretation; ANN,LITHOFACIES IDENTIFICATION; CLASSIFICATION; BASIN,"Effective identification of lithology using well logs is one of the most important steps for reservoir characterization. A lot of methods have been developed to identify lithology automatically by analyzing the value or patterns of well logs. However, the response characteristics of log curves for some different lithologies are similar and indistinguishable. As a result, we may obtain results which do not follow the general geologic rules if we only use values or patterns of well logs as the criteria to identify lithology. In this paper, we propose an alternative automatic method to identify lithology by integrating both well logs and sedimentary patterns. First, we obtain the probability of lithology by applying the artificial neural networks (ANN) to the well logs. Then, we obtain the vertical combination patterns of different lithologies by applying a probabilistic statistical method to the cores. Finally, we produce an integrated lithology probability by combining the lithology probabilities calculated using ANN and lithology probabilities computed using sedimentary pattern. We validated our method by applying it to a real case study from China. The results indicate that the accuracy of lithology identification using the proposed method is much higher (91%) than that using neural networks method (83%).",20,20,16
Neural Network,Lithology,"Valentin, Manuel Blanco; Bom, Clecio R.; Coelho, Juliana M.; Correia, Maury Duarte; de Albuquerque, Marcio P.; de Albuquerque, Marcelo P.; Faria, Elisangela L.",A deep residual convolutional neural network for automatic lithological facies identification in Brazilian pre-salt oilfield wellbore image logs,Borehole; Image; Logs; Deep; Residual; Network; Lithofacies; Classification,BOREHOLE IMAGES; CLASSIFICATION; POROSITY,"Field characterization in oil industry is a challenging task which aims to determine or estimate some of the petrophysical properties of a reservoir. These properties are expected to be later used in a non-deterministic workflow (which might depend on subjective interpretations carried out by each petrophysicist) whose aim is to answer questions such as whether exploiting the reservoir is feasible or not, how much hydrocarbon can be extracted from it and whether the geology of the reservoir will stand the stresses of exploitation without collapsing. Three properties stand-out amongst all the rest, as they are closely correlated to the amount of hydrocarbon present in the reservoir and also to the feasibility of its exploitation: permeability, porosity, and lithology. Obtaining reliable and robust measurements of these properties requires extracting core samples from the reservoir, which is, however, a very resource-consuming task. Hence, it is common to use other tools (such as wirelogging tools or borehole imagers) to extract several other properties from the reservoir, in an attempt to obtain information that might help experts to estimate these properties on those intervals at which no core sample could be extracted. In this context, estimating lithofacies helps petrophysicists to automatize the process of identifying the lithology of the reservoir. Previous work (Basu et al., 2002; Chai et al., 2009; Linek et al., 2007; Newberry et al., 2004; Hall et al., 1996) used a considerable amount of wirelog data and borehole image logs to induce the lithology of the reservoir. In the work presented in this paper, we introduce a new methodology for automatic reservoir lithofacies identification. Our model relies only on ultrasonic and microresistivity borehole image logs as inputs, which are characterized by a deep residual convolutional network which then infers the probability of each sample to be classified as each type of previously defined lithofacies classes. The method presented in this work was tested on a carbonate well from the Brazilian pre-salt oilfields, and it allowed us to obtain an average classification accuracy of 81.45% and an average area under the ROC curve of 92.70% for all classes, for the blind test sample.",18,20,3
Neural Network,Lithology,"Gu, Yufeng; Bao, Zhidong; Song, Xinmin; Patil, Shirish; Ling, Kegang",Complex lithology prediction using probabilistic neural network improved by continuous restricted Boltzmann machine and particle swarm optimization,Carbonate reservoirs; Lithology prediction; Probabilistic neural network; Continuous restricted Boltzmann machine; Particle swarm optimization,SUPPORT VECTOR MACHINE; SANTOS BASIN; DISCRIMINANT-ANALYSIS; PATTERN-RECOGNITION; INERTIA WEIGHT; RANDOM FOREST; CLASSIFICATION; ALGORITHM; MODELS; GAS,"Lithology prediction, especially for reservoirs consisting of complex lithologies, is universally considered as a critical underlying task for petroleum exploration, because lithological data is indispensable for the analysis of some geological work, such as stratigraphic correlation or sedimentation modeling. Hence, how to acquire the reliable lithological information gradually becomes a hot topic in the geoscience. Probabilistic neural network (PNN) is an excellent approach for lithology prediction since it can efficiently complete pattern recognition by determining characteristics of each kind of learning data. However, its computation performance is severely limited by two factors, which are quality of raw data and selection of parameter. High correlation of raw data could be an obstacle for the determination of data characteristics because partial probability density distributions established by PNN would be merged. As window length of each probability density distribution shows great impact on the accuracy of calculated results, the selection of this parameter must be addressed optimally before prediction. In order to improve the calculation capability of PNN, two techniques, continuous restricted Boltzmann machine (CRBM) and particle swarm optimization (PSO), are introduced. CRBM has the special function of extracting features from raw data and the features generally present with low correlation, thus can be viewed as an ideal preprocessing segment for PNN. PSO is one of the most efficient algorithms used for solving optimization problem, and the optimal parameter setting of PNN, therefore, can be revealed. Due to the advantages of CRBM and PSO for PNN, a new method for complex lithology prediction is proposed, which is referred as CRBM-PSO-PNN. Data for new method validation is recorded by two wells which are located in the IARA oilfield. Moreover, three experiments are well designed in order to verify the computing capability of new method comprehensively. Experiment results manifest that the prediction accuracies provided by new method in three experiments are highest, all of which are over 75%. High prediction accuracies fully demonstrate that the proposed method is effective to predict complex lithology, and the predicted results are reliable to serve other geological work.",17,18,2
Neural Network,Lithology,"Du, Qizhen; Yasin, Qamar; Ismail, Atif; Sohail, Ghulam Mohyuddin",Combining classification and regression for improving shear wave velocity estimation from well logs data,Shear wave velocity; Clustering and classification; Multivariate regression; Rock physics modeling; Neural network,SAWAN GAS-FIELD; PRACTICAL APPLICATION; CARBONATE RESERVOIR; PETROPHYSICAL DATA; COMMITTEE MACHINE; FLOW UNITS; PREDICTION; PERMEABILITY; POROSITY; ELECTROFACIES,"A shear wave is a critical property that helps to constrain rock properties such as lithology, pore fluid, and pore pressure. Nevertheless, valid and reliable estimation of shear wave velocity in highly heterogeneous reservoirs is still considered a challenge to be faced. In this paper, we propose a strategy for improving shear wave velocity estimation based on the combination of clustering and classification plus regression using conventional logs. The approach includes two steps. In step one, data clustering algorithms are applied to build a classifier model for identifying the distinct electrofacies (EF) based on similarity of well log responses. In step two, a distinct and specialized regression model is selected from more sophisticated methods (empirical models, statistical regression, virtual intelligence, and rock physics modeling) for determining the final shear wave velocity profile. The effectiveness of this proposed strategy is validated over a dataset from offset wells and their respective measured shear wave velocity data. The final results revealed that the proposed strategy that combines data mining task of clustering and classification plus regression, led to more uniform and better predictive performance of shear wave velocity (R-2 = 0.97) in comparison with the use of stand-alone rock physics model (R-2 = 0.70), virtual intelligence (R-2 = 0.82), and statistical regression (R-2 = 0.91). The silent features of this proposed strategy is that field-specific regression models are built based on log derived EF and geological information.",14,14,1
Neural Network,Gas Production,"Wang, Shuhua; Chen, Shengnan",Insights to fracture stimulation design in unconventional reservoirs based on machine learning modeling,Fracture stimulation design; Data mining; Feature selection; Machine learning; Montney tight reservoirs,ARTIFICIAL NEURAL-NETWORKS; GAS-PRODUCTION; NATURAL-GAS; TIGHT OIL; SHALE; OPTIMIZATION,"With rapid development of unconventional tight and shale reservoirs, considerable amounts of data sets are increasing rapidly. Data mining techniques are becoming attractive alternatives for well performance evaluation and optimization. This paper develops a comprehensive data mining process to evaluate well production performance in Montney Formations in western Canadian sedimentary basin. The general data visualization and statistical data evaluation are used to qualitatively and quantitatively evaluate the relationships between the stimulation parameters and first-year oil production. Then, the recursive feature elimination with cross validation (RFECV) is used to identify the most important factors on the first-year oil production in unconventional reservoirs. In addition, four commonly used supervised learning approaches including random forest (RF), adaptive boosting (AdaBoost), support vector machine (SVM), and neural network (NN) are compared to estimate the first-year well production. The results show that 6 features are the most important variables for constructing an accurate prediction model: well latitude, longitude, well true vertical depth (TVD), proppant pumped per well, well lateral length, and fluid injected per well. Compared to other algorithms, RF has the best prediction performance for the first-year oil production. Furthermore, such data-driven models are found to be very useful for reservoir engineers when designing hydraulic fracture treatments in Montney tight reservoirs.",45,46,5
Neural Network,Gas Production,"Wang, Shuhua; Chen, Zan; Chen, Shengnan",Applicability of deep neural networks on production forecasting in Bakken shale reservoirs,Production forecasting; Bakken formation; Deep neural networks; Hyperparameter optimization; Global sensitivity analysis,NEWTON OPTIMIZATION METHOD; TIGHT-OIL; GAS-PRODUCTION; MODEL; PREDICTION; DESIGN; STEAM,"The unconventional shale and tight formations, such as the Bakken in Williston Basin, are becoming an important hydrocarbon sources since the development of advanced horizontal drilling and multi-stage stimulation techniques. The appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery. Although reservoir simulations are commonly used for production analysis, the modeling of hydraulic fractures and intrinsic complexity of shale have restricted an understanding of the fluid flow behavior. Owing to the available of a large amount of data in unconventional tight and shale reservoirs, data-driven approaches, such as deep neural networks (DNNs), provide an alternative approach for production analysis in these formations. In this study, a total of 2919 wells including 2780 multi-stage hydraulic fractured horizontal wells and 139 vertical wells in Bakken Formation were collected and analyzed using a deep learning method and Sobol's global sensitivity analysis. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, and batch normalization were evaluated to develop a reliable deep neural network model. Moreover, k -fold cross validation was used to evaluate the prediction ability and robustness of models. Prior to the performance evaluation of DNN algorithms, an optimum DNN model was achieved by optimizing the dropout layer, activation function, and hyperparameters of DNN models. It is found that the number of hidden layers and neurons in each layer have significant effects on the performance of models. The optimized DNN model has 3 hidden layers and 200 neurons for each layer. The prediction performance of DNN models is acceptable with the low mean squared errors for both 6- and 18-months cumulative oil productions. Furthermore, the importance of each parameter was studied using the Sobol's analysis. Results show that the average proppant placed per stage is the most important parameter, which accounts for more than 35% of variability in both 6- and 18-months cumulative oil productions. These data-driven models can be readily updated when the new well information becomes available. It is worth mentioning that the proposed DNN models can be directly integrated into existing hydraulic fracturing design routines.",35,37,5
Neural Network,Gas Production,"Naderi, Meysam; Khamehchi, Ehsan; Karimi, Behrooz","Novel statistical forecasting models for crude oil price, gas price, and interest rate based on meta-heuristic bat algorithm",Artificial neural network; Auto-regressive integrated moving average; Forecasting oil and gas price and interest rate; Genetic programming; Least square support vector machine; Meta-heuristic bat algorithm,SUPPORT VECTOR MACHINE; OPTIMIZATION; PREDICTION; PRESSURE,"Investment in the petroleum industry is usually faced with a high degree of risk due to uncertainty associated with economic factors. Typical factors include oil and gas price, interest rate, operational and capital expenditure. In addition, the investment risk increases as offshore exploration, drilling and production activities increase. Therefore, accurate prediction of economic factors is crucial in an upstream oil and gas sector in order to make better strategic decisions with minimized risk. In the present study, four methods of the least square support vector machine (LSSVM), genetic programming (GP), artificial neural network (ANN), and auto-regressive integrated moving average (ARIMA) were initially used to forecast monthly oil price (MOP), daily gas price (DGP), and annual interest rate (AIR). Next, the meta-heuristic bat algorithm (BA) was applied in order to optimally combine the four mentioned forecasting methods in an integrated equation as a novel approach. All required historical data to forecast oil price, gas price and interest rate were collected from the Central Bank of the Islamic Republic of Iran. Error analysis in terms of coefficient of determination (R-2), average absolute relative error percentage (AAREP), root-mean square error (RMSE), and cumulative probability distribution versus absolute relative error percentage were used to compare the prediction performance of forecasting methods. Error analysis proves that the BA optimized method is superior over all other forecasting methods in terms of highest R-2 and lowest RMSE. After the BA optimized method, construction of LSSVM, ARIMA, ANN, and GP has better prediction ability, respectively. The results indicate that the BA optimized method reduces RMSE at least by 6.61% in MOP forecast; by 18.33% in DGP forecast; and by 23.13% in AIR forecast over all other forecasting methods.",21,22,0
Neural Network,Gas Production,"Bhattacharya, Shuvajit; Ghahfarokhi, Payam Kavousi; Carr, Timothy R.; Pantaleone, Scott","Application of predictive data analytics to model daily hydrocarbon production using petrophysical, geomechanical, fiber-optic, completions, and surface data: A case study from the Marcellus Shale, North America",Marcellus Shale; Fiber optic; Data analytics; Machine learning; Predicting gas production,APPALACHIAN BASIN; LITHOFACIES,"Predicting gas production from stimulated unconventional reservoirs has always been a challenge to oil and gas companies because the physics of fluid flow through such reservoirs is not well understood. On the other hand, modeling gas production from shale reservoirs is a complex multi-variate problem that requires proper integration of data from multiple disciplines, such as geology, petrophysics, geomechanics, completions, and surface-based measurements, etc. This study demonstrates the application of data-driven machine learning algorithms, integrating geoscientific, distributed acoustic sensing (DAS), distributed temperature sensing (DTS) fiber-optic, completions, flow scanner production log, and surface data to model daily gas production from a 28-stage stimulated horizontal well drilled in the Marcellus Shale of the Appalachian basin in North America. In addition, this study aims to utilize the data from a fiber-optic monitoring system, such as DAS and DTS to evaluate the well performance. We build supervised data-driven machine learning models using Random Forest (RF), Artificial Neural Network (ANN), and Support Vector Machine (SVM) algorithms to understand the well performance and forecast the daily gas production. The study compares the forecasted results, tests the level of accuracy, and addresses different issues with these machine learning algorithms. A spatio-temporal database is constructed and used to perform sensitivity analyses to identify the key drivers for gas production. The results show that RF and ANN algorithms can be used to predict daily gas production with significantly high accuracy; however, RF algorithm is the best predictor in terms of highest accuracy (96%), less computational time and cost. Based on sensitivity analysis, it appears that Poisson's ratio, minimum horizontal stress, DAS, casing pressure, gamma log are the most important parameters to predict gas production.",14,15,4
Neural Network,Source Rocks,"Wang, Huijun; Wu, Wei; Chen, Tao; Dong, Xinjun; Wang, Guangxu","An improved neural network for TOC, S-1 and S-2 estimation based on conventional well logs",Deep learning; Convolutional neural network (CNN); Total organic carbon (TOC); Volatile hydrocarbon (S-1); Remaining hydrocarbon (S-2); Well logging,BOHAI BAY BASIN; CARBON CONTENT PREDICTION; PARS GAS-FIELD; APPALACHIAN DEVONIAN SHALES; NIUZHUANG SOUTH SLOPE; ORGANIC-CARBON; PETROLEUM SYSTEMS; SOURCE ROCKS; SHAHEJIE FORMATION; WIRELINE LOGS,"Total organic carbon (TOC), volatile hydrocarbon (S-1) and remaining hydrocarbon (S-2) are significant factors for shale oil and gas exploration and development. However, the TOC, S-1 and S-2 estimations are considered as challenges for the geological engineers because the direct laboratory method is time consuming and costly. Passey method and back propagation artificial neural network (BPANN) based on well logs have been extensively employed to determine organic richness. However, the prediction accuracy of Passey method is low, and BP neural network is easily trapped into local optimum. Hence, in this paper, for the first time, we propose a six-layer convolutional neural network (CNN) model in the field of deep learning to address these challenges. CNN is characterized by local connections, weight sharing and convolution kernels. These merits enable CNN to mitigate overfitting and provide higher prediction accuracy and better generalization ability than the traditional neural network. Specifically, 125 core shale samples and well logging data of Shahejie Formation from Dongying Depression, Bohai Bay, China were split into 100 training samples and 25 validating samples to evaluate the proposed CNN for predicting TOC, S-1 and S-2. Moreover, we made a correlation between TOC S-1, S-2 and well logs to choose the suitable input. All logging attributes and selected logging attributes were used as inputs respectively for comparison. The experimental results demonstrate that the new technique CNN model outperforms the available methods in calculating the TOC, S-1 and S-2, which indicates the feasibility of this method. Besides, the prediction accuracy with selected logs as input is higher than that of with all logs as input, which illustrates that making a correlation between well logs and TOC, S-1, S-2 to choose appropriate logs is helpful for improving prediction accuracy. The proposed CNN model allows organic richness (TOC, S-1 and S-2) to be precisely calculated based on conventional well logs.",34,34,9
Neural Network,Source Rocks,"Shalaby, Mohamed R.; Jumat, Nurhazwana; Lai, Daphne; Malik, Owais","Integrated TOC prediction and source rock characterization using machine learning, well logs and geochemical analysis: Case study from the Jurassic source rocks in Shams Field, NW Desert, Egypt",Machine learning; Artificial neural network; Geochemical analysis; Well log data; Source rock; Jurassic; Egypt,NORTHERN WESTERN DESERT; ORGANIC-CARBON CONTENT; APPALACHIAN DEVONIAN SHALES; DEPOSITIONAL ENVIRONMENT; KAZHDUMI FORMATION; KHATATBA FORMATION; SHUSHAN BASIN; WIRELINE LOGS; GENERATION; RESERVOIR,"The machine learning methods and well log mathematical models have been used for predicting total organic carbon (TOC) in Jurassic source rock formations in Northwestern Desert, Egypt. Conventional well log data from two wells have been utilized for source rock study of Jurassic source rocks from Khatatba and Ras Qattara formations in the study area. The source rock is first studied based on geochemical parameters, which include assessments on the type and amount of kerogen present within the source rock samples. The Jurassic source rock samples have great generative potential and consist of mixed kerogen type III and kerogen type II-III. TOC content reaches up to 46.90% for Khatatba and 16.80% Ras Qattara. In the second part of this research, we attempt to characterize the Jurassic source rocks by using mathematical well log models and machine learning methods. GR, RHOB and NPHI well log data were used for TOC prediction using both methods. The quantified TOC results show that the R-2 values of well log models are above 0.9 for both formations, whereas the machine learning method using Artificial Neural Network showed R-2 value of 0.4. The results from the well log models suggest that they are applicable in the study area. This study has proven that well log data can be used with confidence to evaluate organic source quantity of Jurassic rocks in Northwestern Desert in the absence of geochemical data.",25,28,2
Neural Network,Image,"Wang, Ying Da; Armstrong, Ryan T.; Mostaghimi, Peyman",Enhancing Resolution of Digital Rock Images with Super Resolution Convolutional Neural Networks,Digital rock; Super resolution; Neural networks; Micro-CT imaging,X-RAY MICROTOMOGRAPHY,"Single Image Super Resolution (SISR) techniques based on Super Resolution Convolutional Neural Networks (SRCNN) are applied to micro-computed tomography (micro-CT) images of sandstone and carbonate rocks. Digital rock imaging is limited by the capability of the scanning device resulting in a trade-off between resolution and field of view, and super resolution methods tested in this study aim to compensate for this limitation. SRCNN models SR-Resnet, Enhanced Deep SR (EDSR), and Wide-Activation Deep SR (WDSR) are used on the Digital Rock Super Resolution 1 (DRSRD1) Dataset of 4x downsampled images, comprising of 2000 high resolution (800 x 800) raw micro-CT images of Bentheimer sandstone and Estaillades carbonate. The trained models are applied to the validation and test data within the dataset and show a 3-5 dB rise (50%-70% reduction in relative error) in image quality compared to bicubic interpolation, with all tested models performing within a 0.1 dB range. Difference maps indicate that edge sharpness is completely recovered in images within the scope of the trained model, with only high frequency noise related detail loss. We find that aside from generation of high-resolution images, a beneficial side effect of super resolution methods applied to synthetically downgraded images is the removal of image noise while recovering edgewise sharpness which is important for the segmentation process. The model is also tested against low-resolution images of Bentheimer rock with image augmentation to account for natural noise and blur. The SRCNN method is shown to act as a preconditioner for image segmentation under these circumstances which naturally leads to further future development and training of models that segment an image directly. Image restoration by SRCNN on the rock images is of significantly higher quality than traditional methods and suggests SRCNN methods are a viable processing step in a digital rock workflow.",25,25,7
Neural Network,Image,"Valentin, Manuel Blanco; Bom, Clecio R.; Coelho, Juliana M.; Correia, Maury Duarte; de Albuquerque, Marcio P.; de Albuquerque, Marcelo P.; Faria, Elisangela L.",A deep residual convolutional neural network for automatic lithological facies identification in Brazilian pre-salt oilfield wellbore image logs,Borehole; Image; Logs; Deep; Residual; Network; Lithofacies; Classification,BOREHOLE IMAGES; CLASSIFICATION; POROSITY,"Field characterization in oil industry is a challenging task which aims to determine or estimate some of the petrophysical properties of a reservoir. These properties are expected to be later used in a non-deterministic workflow (which might depend on subjective interpretations carried out by each petrophysicist) whose aim is to answer questions such as whether exploiting the reservoir is feasible or not, how much hydrocarbon can be extracted from it and whether the geology of the reservoir will stand the stresses of exploitation without collapsing. Three properties stand-out amongst all the rest, as they are closely correlated to the amount of hydrocarbon present in the reservoir and also to the feasibility of its exploitation: permeability, porosity, and lithology. Obtaining reliable and robust measurements of these properties requires extracting core samples from the reservoir, which is, however, a very resource-consuming task. Hence, it is common to use other tools (such as wirelogging tools or borehole imagers) to extract several other properties from the reservoir, in an attempt to obtain information that might help experts to estimate these properties on those intervals at which no core sample could be extracted. In this context, estimating lithofacies helps petrophysicists to automatize the process of identifying the lithology of the reservoir. Previous work (Basu et al., 2002; Chai et al., 2009; Linek et al., 2007; Newberry et al., 2004; Hall et al., 1996) used a considerable amount of wirelog data and borehole image logs to induce the lithology of the reservoir. In the work presented in this paper, we introduce a new methodology for automatic reservoir lithofacies identification. Our model relies only on ultrasonic and microresistivity borehole image logs as inputs, which are characterized by a deep residual convolutional network which then infers the probability of each sample to be classified as each type of previously defined lithofacies classes. The method presented in this work was tested on a carbonate well from the Brazilian pre-salt oilfields, and it allowed us to obtain an average classification accuracy of 81.45% and an average area under the ROC curve of 92.70% for all classes, for the blind test sample.",18,20,3
Hydrate,Numerical Simulation,"Mahabadi, Nariman; Dai, Sheng; Seol, Yongkoo; Jang, Jaewon",Impact of hydrate saturation on water permeability in hydrate-bearing sediments,Water permeability; Hydrate-bearing sediments; Hydrate saturation; Wave velocity; Pore network model; Pore habit,GAS-PRODUCTION; RELATIVE PERMEABILITY; POROUS-MEDIA; ELASTIC PROPERTIES; THF-HYDRATE; TOMOGRAPHY; PRESSURE,"Permeability of the hydrate-bearing sediments critically affects the hydrate dissociation process as well as the rate and efficiency of gas production. Reported permeability values are observed to be widely are very scattered owing to the dependence on multiple factors such as experimental conditions and test procedures. It is critical that the permeability is measured accurately to enable prediction of long-term gas production using numerical simulation for an economic development of hydrate-bearing reservoirs. In this study, the tetrahydrofuran (THF) hydrates that exhibit pore habits of the pore-filling pattern are formed in sediments, and the water permeability is quantified as a function of hydrate saturation. The results show that a decrease in the permeability for an increase in the hydrate saturation. Based on the measured values that are bounded by Kozeny grain-coating and pore-filling models, the fitting parameters of the empirical permeability models are suggested for use in numerical simulation of long-term hydrate dissociation. Wave velocity measurements reveal pore habits of pore-filling pattern of THF hydrates in the sediments with S-h < 0.5, and a gradual transition to patchy and load-bearing pore-habits when S-h > 0.6. The numerical simulation results obtained using the complementary pore-network model suggest that the THF hydrates in the sediments may form in small clusters with an average patch size of similar to 4 pores.",54,57,10
Hydrate,Numerical Simulation,"Sun, Xiang; Wang, Lei; Luo, Hao; Song, Yongchen; Li, Yanghui",Numerical modeling for the mechanical behavior of marine gas hydrate-bearing sediments during hydrate production by depressurization,Natural gas hydrate; Constitutive model; Fully coupled THMC model; Depressurization,METHANE-HYDRATE; CONSTITUTIVE MODEL; DISSOCIATION; STABILITY; STRENGTH; SAND; FLOW; SIMULATION; ENERGY,"Natural gas hydrate, which is called inflammable ice, has drawn global interest. Many countries have carried out the trial production of natural gas from marine gas hydrate formations. However, due to the failure of the bonded structure and the disappearance of the hydrate in the pores of formations, improper production might induce geological hazards such as submarine landslide, non-uniform subsidence and local large deformation of the formations. In this study, a constitutive model based on super-loading and sub-loading surface theory is proposed to investigate the mechanical behavior of gas hydrate-bearing sediments (GHBSs). The mechanical behavior of both GHBSs and the structured clay are modeled by introducing rotational hardening rule, sub-loading surface and super-loading surface. A fully coupled thermo-hydro-chemo-mechanical (THCM) model is applied to study the mutiphysical responses of GHBSs during hydrate production by depressurization. The simulation results of the two-layer model show that the mutiphysical responses are dependent on not only the different material properties of the two layers but also the difference between the hydrate dissociated and undissociated zones. Although depressurization is the driving factor of hydrate dissociation, the heat transfer from the clay layer is also a key factor in the hydrate dissociation. Hydrate dissociation results in the variation in the stiffness and strength of the GHBSs leading to stress and strain and strain redistribution. The yielding and structural failure of sediments mainly occur in the hydrate dissociated zone.",49,51,22
Hydrate,Numerical Simulation,"Sun, Youhong; Ma, Xiaolong; Guo, Wei; Jia, Rui; Li, Bing",Numerical simulation of the short- and long-term production behavior of the first offshore gas hydrate production test in the South China Sea,The Shenhu area; Gas hydrates; Production behavior; Hydrate reformation; Numerical simulation,METHANE HYDRATE; SHENHU AREA; THERMAL-STIMULATION; BEARING SEDIMENTS; POROUS-MEDIA; DEPRESSURIZATION; DEPOSITS; DISSOCIATION; SITE; RESERVOIR,"Gas hydrate-bearing sediments at the first offshore gas hydrate production test site in the Shenhu area, South China Sea, have the characteristics of high irreducible water saturation and low permeability. The stratum structure of this production test site is complex, its gas hydrate-bearing layer (GHBL), three-phase layer (TPL) and free gas layer (FGL) all contain methane gas or gas hydrates, that make the production more complicated. According to the available geological data at the first offshore gas hydrate production test site in the Shenhu area, a 2D numerical simulation model is built to study the short-and the long-term production behavior of the gas hydrates in the Shenhu area. In the short-term, the total gas production from hydrates, when the TPL gas saturation is 0.078, is determined to be 2.75 x 10(5) m(3), which is close to the actual total gas production of 3.09 x 10(5) m(3). When the irreducible water saturation varies from 0.40 to 0.63, the total gas production changes from 1.41 x 10(5) to 2.75 x 10(5) m(3), and the total water production decreases from 1.04 x 10(4) to 8.7 x 10(3) m(3), which indicates that irreducible water is a favorable factor for gas production from hydrates in clayey silt sediments. In the long-term gas production from hydrates, the gas production rate first decreases, then increases, and finally decreases again. Gas hydrate reformation occurs at the interface between the TPL and the FGL, which will adversely affect the gas production from hydrates.",26,32,15
Hydrate,Numerical Simulation,"Yu, Tao; Guan, Guoqing; Abudula, Abuliti; Yoshida, Akihiro; Wang, Dayong; Song, Yongchen","Heat-assisted production strategy for oceanic methane hydrate development in the Nankai Trough, Japan",Methane hydrate; Nankai Trough; Horizontal well; Thermal injection; Well placement,QILIAN MOUNTAIN PERMAFROST; SOUTH CHINA SEA; GAS-PRODUCTION; SHENHU AREA; NUMERICAL-SIMULATION; HORIZONTAL WELLS; POWER-GENERATION; PUFF METHOD; TEST-SITE; DEPOSITS,"The heat-assisted production strategy was considered to be an effective approach for the oceanic methane hydrate (MH) development. In this study, the combined method of depressurization and hot water injection was applied to the multilayered MH reservoir in the Nankai Trough, Japan, by using dual horizontal wells. Some possible well placements by placing the two wells in the same sublayer and different sublayers were designed in this study, and their effectiveness on the gas recovery enhancement was verified via long-term simulations of the oceanic MH production. It was found that when the two wells were placed in different sublayers, with some horizontal distance and the injection well locating above the production well, a favorable average gas production rate of 2.0 x 10(6) m(3)/day could be obtained, and was up to 100 times of that confirmed during the 2013 offshore MH production test in the Nankai Trough (2.0 x 10(4) m(3)/day), which indicated the high efficiency of the method proposed in this study. Furthermore, sensitivity analyses on the well locations suggested that the production well should be placed near the bottom of the hydrate reservoir, and a mild well spacing should be carefully determined, both to promote the heat transfer in the reservoir by making the maximum use of the injected hot water, and obtain a higher gas production rate.",18,18,4
Hydrate,Numerical Simulation,"Zhang, Jinming; Li, Xiaosen; Chen, Zhaoyang; Li, Qingping; Li, Gang; Lv, Tao",Numerical simulation of the improved gas production from low permeability hydrate reservoirs by using an enlarged highly permeable well wall,Methane hydrates; Depressurization; Low permeability; Enlarged permeable well wall; Liwan 3 area,EASTERN NANKAI TROUGH; SOUTH CHINA SEA; METHANE-HYDRATE; SHENHU AREA; PRODUCTION BEHAVIOR; ENERGY RECOVERY; ULLEUNG BASIN; POROUS-MEDIA; PUFF METHOD; DEPRESSURIZATION,"Gas production from low-permeability hydrate reservoirs is characterized by very low efficiency. In this work, the enlarged well wall with good permeability was first proposed to improve the gas production performance from low-permeability hydrate reservoir in Liwan 3 area of the South China Sea. The gas-water production behaviors, the spatial distributions and evolutions of hydrate reservoir parameters and gas-water flow characteristics, induced by constant-depressurization, were investigated and evaluated by numerical simulations under different radius of permeable well wall. Results show that the enlarged well wall provides a high-permeability channel around the production interval and increases the contact area between the production interval and hydrate layer, so the pressure drop propagation speed and distance, i.e. the depressurization efficiency in the hydrate-bearing sediments is increased. Both gas and water production performances are significantly improved, and the gas and water production rates, cumulates and gas to water ratio increase with the increase in permeable well wall radius. The cumulative CH4 and water produced increase by ca. 4 and 3 times, respectively, when the permeable well wall radius increases from 0 to 5 m. However, the heat supply by heat convection of geothermal water is still limited.",14,16,4
Hydrate,Numerical Simulation,"Sondermann, Carina Nogueira; Baptista, Renan Martins; de Freitas Rachid, Felipe Bastos; Rachid Bodstein, Gustavo Cesar",Numerical simulation of non-isothermal two-phase flow in pipelines using a two-fluid model,Two-phase flow; Two-fluid model; Flux-corrected transport method; Numerical simulation; Gas pipelines; Hyperbolicity analysis,FLUX-CORRECTED TRANSPORT; SLUG FLOW; EQUATIONS; PIPES,"The analysis of two-phase flows through numerical simulations is a very useful tool to design and operate long pipelines. It is also important for monitoring the flow during adverse situations, such as the formation of hydrates and wax deposition that may occur due to temperature variations in the fluids along the pipe. The present work aims to validate a model along with a numerical technique for analyzing non-isothermal stratified-pattern two-phase flows that occur in typical gas-gathering offshore pipelines. The mathematical model is one-dimensional and based on a two-fluid model that comprises two mass and two momentum conservation equations, one for each phase, along with one energy conservation equation for the mixture. The system of equations is discretized in a conservative form within a finite-difference framework and is solved by the flux-corrected transport (FCT) numerical method. Because an ill-posed mathematical problem is obtained if the system of equations is not hyperbolic, a hyperbolicity analysis is performed for all cases simulated in this work, which also indicates how to impose the boundary conditions adequately and avoids the production of non-physical output. The results obtained for the distribution of pressure, fluid velocities, holdup and temperature along the pipeline demonstrated that even relatively small temperature differences between the fluids and the external environment at the pipe inlet cause significant thermal effects on the entire flow. The simulations also predicted results in good agreement with those of a commercial software used for comparison, for steady-state regime, and significantly different results from those produced by an isothermal-flow model, which emphasizes the importance of considering the heat transfer in the problem. In summary, the results showed that the mathematical model and the numerical method form together a reliable tool of second-order accuracy in space that perform accurate numerical simulations of two-phase flows in long pipelines that are subject to non-isothermal conditions.",14,14,1
Hydrate,Natural Gas,"Sun, Xiang; Wang, Lei; Luo, Hao; Song, Yongchen; Li, Yanghui",Numerical modeling for the mechanical behavior of marine gas hydrate-bearing sediments during hydrate production by depressurization,Natural gas hydrate; Constitutive model; Fully coupled THMC model; Depressurization,METHANE-HYDRATE; CONSTITUTIVE MODEL; DISSOCIATION; STABILITY; STRENGTH; SAND; FLOW; SIMULATION; ENERGY,"Natural gas hydrate, which is called inflammable ice, has drawn global interest. Many countries have carried out the trial production of natural gas from marine gas hydrate formations. However, due to the failure of the bonded structure and the disappearance of the hydrate in the pores of formations, improper production might induce geological hazards such as submarine landslide, non-uniform subsidence and local large deformation of the formations. In this study, a constitutive model based on super-loading and sub-loading surface theory is proposed to investigate the mechanical behavior of gas hydrate-bearing sediments (GHBSs). The mechanical behavior of both GHBSs and the structured clay are modeled by introducing rotational hardening rule, sub-loading surface and super-loading surface. A fully coupled thermo-hydro-chemo-mechanical (THCM) model is applied to study the mutiphysical responses of GHBSs during hydrate production by depressurization. The simulation results of the two-layer model show that the mutiphysical responses are dependent on not only the different material properties of the two layers but also the difference between the hydrate dissociated and undissociated zones. Although depressurization is the driving factor of hydrate dissociation, the heat transfer from the clay layer is also a key factor in the hydrate dissociation. Hydrate dissociation results in the variation in the stiffness and strength of the GHBSs leading to stress and strain and strain redistribution. The yielding and structural failure of sediments mainly occur in the hydrate dissociated zone.",49,51,22
Hydrate,Natural Gas,"Ghasemi, Mehdi; Moslemizadeh, Aghil; Shahbazi, Khalil; Mohammadzadeh, Omid; Zendehboudi, Sohrab; Jafari, Sina",Primary evaluation of a natural surfactant for inhibiting clay swelling,Ginsenosides; Biosurfactant; Clay swelling inhibitor; Wettability; Compatibility,WELLBORE STABILITY; SHALE HYDRATION; REDUCING ADSORPTION; ANIONIC SURFACTANT; MODIFIED BENTONITE; IONIC LIQUID; WATER; GINSENG; COPOLYMER; MONTMORILLONITE,"Water-based drilling muds, a more environment-friendly candidate than oil-based drilling muds, are wildly used for drilling oil and gas wells. When water-based drilling mud is used for drilling formations with shale containing active clay constituents, it is challenging to preserve stability of the borehole due to clay swelling unless proper inhibition mechanisms are foreseen. In the current study, the feasibility of using Korean red Ginseng root extract was assessed as a clay swelling inhibitor. This root extract is rich in non-ionic surfactants such as Ginsenosides Rg3, Rg5, and RK1, and is referred to as ""biosurfactant"" throughout this manuscript. After preparation of mud systems containing problematic clay particles, the clay-swelling inhibition performance of the biosurfactant was systematically investigated through a series of tests, including mud formation, filtration, immersion, sedimentation assisted with optical microscopy, wettability by sessile drop technique, use of thermal gravimetric analysis (TGA), scanning electron microscopy (SEM) and Fourier-transform infrared spectroscopy (FTIR), and shale cuttings recovery. The clay-swelling inhibition performance of the biosurfactant was then compared against two clay swelling inhibitors namely CTAB (Cetrimonium bromide, a known cationic surfactant) and potassium chloride. There are some properties associated with the mud systems prepared with biosurfactant solution which makes this product unique. These properties include: remarkable loading capacity of sodium montmorillonite (Mt) which in turn resulted in low rheological profile, poor fluid loss control, creation of stable Mt pellets, creation of larger size and aggregated Mt particles with less hydrophilicity, creation of fully unstable dispersed Mt particles that resulted in good sedimentation over time, less mass loss, and higher shale cuttings recovery, all compared to the baseline fluid made without the presence of biosurfactant. The results of this study indicate that the biosurfactant provides excellent clay swelling inhibition properties, comparable to known inhibitors. The biosurfactant's compatibility with other drilling mud components was also checked, and it was found that the fluid properties are independent of the biosurfactant. The wettability and FTIR analyses were also performed to investigate the mechanisms involved in clay swelling inhibition of the biosurfactant, which are believed to be as a result of coating the clay active surfaces with a hydrophobic layer, hence repelling the water phase. This hydrophobic layer is probably formed by interactions of the hydrophilic group of the Ginsenosides and the oxygen atoms available on the Mt surfaces, when the hydrophobic tail is oriented toward the aqueous phase.",30,30,0
Hydrate,Natural Gas,"Gambelli, Alberto Maria; Castellani, Beatrice; Nicolini, Andrea; Rossi, Federico","Experimental study on natural gas hydrate exploitation: Optimization of methane recovery, carbon dioxide storage and deposit structure preservation",Natural gas hydrate; CO2 replacement; Lab-scale reactor; CO2 storage; Environment preservation,INJECTION; DISSOCIATION; DECOMPOSITION; ACCUMULATIONS; SATURATION; RESERVOIRS; SEDIMENT,"Aim of this work is locating how CO2 replacement into methane hydrate deposits may be performed, in order to increase both methane recovered and carbon dioxide stored quantities. The experimental section deals with the study of natural gas hydrate formation process and replacement of methane, contained into water cages, with carbon dioxide. In particular, the formation of methane hydrate is analyzed to understand the parameters that most influence the replacement process. A total of 10 tests were carried out in a laboratory scale reactor. Test 1-8 were performed adopting thermal stimulation as replacement technique, while in Test 9 and Test 10 depressurization was used. Results obtained have led to the conclusion that the rate of methane hydrate formation positively influences the percentage of CO2 stored, while the initial saturation of the sand pores has a negative effect. The presence of hydrate agglomerates hinders the gas transition preventing the replacement process. Finally, a greater quantity of CO2 hydrate, both via replacement process and via new hydrate formation, is related to a higher deposit structure preservation. As emerges from the experimental tests, the adopted replacement strategy influences the experimental relationships.",24,24,8
Hydrate,Natural Gas,"Stoporev, Andrey S.; Semenov, Anton P.; Medvedev, Vladimir I.; Mendgaziev, Rais I.; Istomin, Vladimir A.; Sergeeva, Daria V.; Manakov, Andrey Yu.; Vinokurov, Vladimir A.",Formation and agglomeration of gas hydrates in gas - organic liquid - water systems in a stirred reactor: Role of resins/asphaltenes/surfactants,Gas hydrate; Crude oil; Surfactants; Resins; Asphaltenes; Nucleation,ALCOHOL COSURFACTANTS; METHANE HYDRATE; FLOW ASSURANCE; INHIBITION; SURFACTANT; PREDICTION; CHEMISTRY,"In the present work, the nucleation and growth of methane hydrate and C-1-C-3 mixed hydrate in the systems with organic liquids (n-decane, toluene, crude oils) have been studied. The experiments were carried out in an autoclave at a stirring rate in a range of 100-600 rpm and at a constant cooling rate of 8.4 degrees C/h under isochoric conditions. In the case of n-decane, the experiments were conducted both with the addition of 0.5 wt % of nonionic surfactants (Span 80 or Surfynol 420) and without them; in the case of toluene the experiments were performed with addition of natural resins and asphaltenes. It was shown that Surfynol 420 had the lowest anti-agglomeration activity with respect to hydrate particles in comparison with Span 80 and oils used. Gas hydrate nucleation occurred at a lower degree of supercooling in the case of oils with a higher content of resins and asphaltenes. The change of resistance to flow in the obtained disperse systems had a reverse trend. Based on the obtained data it can be concluded that the unambiguous effect of the stirring rate on the hydrate nucleation in systems with different composition is not observed. At the same time, an increase in the stirring rate leads to an increase in the amount of gas hydrate formed in a system.",23,23,4
Hydrate,Natural Gas,"Aminnaji, Morteza; Anderson, Ross; Tohidi, Bahman",Anomalous KHI-Induced dissociation of gas hydrates inside the hydrate stability zone: Experimental observations & potential mechanisms,Hydrate dissociation; KHIs; PVCap; Luvicap bio,METHANE; TRANSFORMATIONS; PRESSURE,"In the past decade, the low dosage hydrate inhibitors (LDHIs) - which include kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs) - have seen increasing use for gas hydrate prevention in hydrocarbon production operations, offering significant CAPEX/OPEX advantages over traditional thermodynamic inhibitors (e.g. methanol, glycols). Typically dosed at < 2.5% in produced water, KHIs were historically considered primarily as hydrate nucleation inhibitors, although in recent years focus has shifted towards their powerful crystal growth inhibition properties. Beginning at low aqueous concentrations, KHI polymers induce a number of highly repeatable, well-defined, hydrate crystal growth inhibition (CGI) regions as a function of subcooling, varying from complete inhibition, through long induction times and reduced growth rates, to final failure/uninhibited growth. This behaviour can be used to robustly assess KHIs for field use, as we have previously demonstrated through development of the KHI CGI evaluation method, which is now used as standard by a number of laboratories. During CGI testing, it is not uncommon to observe anomalous (should be stable thermodynamically) hydrate dissociation in the presence of KHIs, although very little is understood regarding this phenomenon. In this work, we present the initial findings of experimental studies aimed at investigating this anomalous dissociation for different commercial base polymers. Results demonstrate that, in addition to inhibiting hydrate growth/nucleation, low dosages (e.g. 0.5% and 0.25%) of KHI polymers can induce partial or complete hydrate dissociation, with this process largely generic to different KHIs. However, some KHI polymers cause catastrophic hydrate growth after nucleation begins and these polymers show no ability to dissociate hydrates, so this hydrate dissociation ability is not universal to all KHI Polymers. The cause of this dissociation is unclear, although it is postulated to result from interactions between the KHI and inherent hydrate morphological and/or structural changes. In addition to improving confidence in KHI field use, findings potentially have novel applications with respect to hydrate plug remediation and gas production from naturally occurring hydrates in oceanic/permafrost sediments.",17,15,8
Hydrate,Shenhu Area,"Sun, Youhong; Ma, Xiaolong; Guo, Wei; Jia, Rui; Li, Bing",Numerical simulation of the short- and long-term production behavior of the first offshore gas hydrate production test in the South China Sea,The Shenhu area; Gas hydrates; Production behavior; Hydrate reformation; Numerical simulation,METHANE HYDRATE; SHENHU AREA; THERMAL-STIMULATION; BEARING SEDIMENTS; POROUS-MEDIA; DEPRESSURIZATION; DEPOSITS; DISSOCIATION; SITE; RESERVOIR,"Gas hydrate-bearing sediments at the first offshore gas hydrate production test site in the Shenhu area, South China Sea, have the characteristics of high irreducible water saturation and low permeability. The stratum structure of this production test site is complex, its gas hydrate-bearing layer (GHBL), three-phase layer (TPL) and free gas layer (FGL) all contain methane gas or gas hydrates, that make the production more complicated. According to the available geological data at the first offshore gas hydrate production test site in the Shenhu area, a 2D numerical simulation model is built to study the short-and the long-term production behavior of the gas hydrates in the Shenhu area. In the short-term, the total gas production from hydrates, when the TPL gas saturation is 0.078, is determined to be 2.75 x 10(5) m(3), which is close to the actual total gas production of 3.09 x 10(5) m(3). When the irreducible water saturation varies from 0.40 to 0.63, the total gas production changes from 1.41 x 10(5) to 2.75 x 10(5) m(3), and the total water production decreases from 1.04 x 10(4) to 8.7 x 10(3) m(3), which indicates that irreducible water is a favorable factor for gas production from hydrates in clayey silt sediments. In the long-term gas production from hydrates, the gas production rate first decreases, then increases, and finally decreases again. Gas hydrate reformation occurs at the interface between the TPL and the FGL, which will adversely affect the gas production from hydrates.",26,32,15
Hydrate,Shenhu Area,"Kuang, Yangmin; Yang, Lei; Li, Qingping; Lv, Xin; Li, Yuanping; Yu, Bin; Leng, Shudong; Song, Yongchen; Zhao, Jiafei",Physical characteristic analysis of unconsolidated sediments containing gas hydrate recovered from the Shenhu Area of the South China sea,Physical properties; Hydrate-bearing sediments; Shenhu area; South China sea,STRATIGRAPHIC TEST WELL; METHANE HYDRATE; BEARING SEDIMENTS; POROUS-MEDIA; GEOTECHNICAL PROPERTIES; MECHANICAL-PROPERTIES; ULLEUNG BASIN; CORE SAMPLES; EAST SEA; PERMEABILITY,"Laboratory research based on the physical characteristics of unconsolidated sediments containing gas hydrate was carried out on hydrate-bearing sediment samples recovered from China National Offshore Oil Corporation (CNOOC) drilling expeditions in 2015 and 2017 at the station of LW3 in the northern part of the South China Sea. We herein have measured the gas composition, index properties, surface characteristics, thermal properties, and mechanical properties of these sediment cores drilled at different seafloor depths. Based on the measurement results, more than 99% of the gas composition is methane gas. The hydrate-bearing sediments recovered from Shenhu Area are non-diagenetic rock, the fraction of grain size which less than 40 mu m was more than 90%. The results could provide useful guidance for potential sand-control system operations. Such small and consolidated particles indicated that the application of a novel solid fluidization mining method is viable and promising. The fine-grained layers were found to be mostly self-filtering and internally stable for the seepage flow during production. Gas hydrate mostly occurs in vein-type, and bioclastics consisting of marine planktonic diatoms and foraminifera were also found. The mineral components of the sediments were mostly quartz, clay minerals like illite and some feldspar like albite. The thermal conductivities changed from 1.4 to 1.77 W/(mK), which suggests that the isolated depressurization methods could exacerbate the problem of gas hydrate reformation or ice generation; thus, heat injection in wellbores should be combined for gas hydrate production strategies. The low liquid limit (38%) and plastic limit (24%) imply that stability of the production platform should be taken into account for avoiding submarine landslide impacts. The results of mechanical property analyses indicated that hydrate-bearing sediments at deeper sites have a relatively higher strength at hydrate layer of 120-133 mbsf in the Shenhu Area of the South China Sea.",22,23,16
Hydrate,Shenhu Area,"Yu, Tao; Guan, Guoqing; Abudula, Abuliti; Yoshida, Akihiro; Wang, Dayong; Song, Yongchen","Heat-assisted production strategy for oceanic methane hydrate development in the Nankai Trough, Japan",Methane hydrate; Nankai Trough; Horizontal well; Thermal injection; Well placement,QILIAN MOUNTAIN PERMAFROST; SOUTH CHINA SEA; GAS-PRODUCTION; SHENHU AREA; NUMERICAL-SIMULATION; HORIZONTAL WELLS; POWER-GENERATION; PUFF METHOD; TEST-SITE; DEPOSITS,"The heat-assisted production strategy was considered to be an effective approach for the oceanic methane hydrate (MH) development. In this study, the combined method of depressurization and hot water injection was applied to the multilayered MH reservoir in the Nankai Trough, Japan, by using dual horizontal wells. Some possible well placements by placing the two wells in the same sublayer and different sublayers were designed in this study, and their effectiveness on the gas recovery enhancement was verified via long-term simulations of the oceanic MH production. It was found that when the two wells were placed in different sublayers, with some horizontal distance and the injection well locating above the production well, a favorable average gas production rate of 2.0 x 10(6) m(3)/day could be obtained, and was up to 100 times of that confirmed during the 2013 offshore MH production test in the Nankai Trough (2.0 x 10(4) m(3)/day), which indicated the high efficiency of the method proposed in this study. Furthermore, sensitivity analyses on the well locations suggested that the production well should be placed near the bottom of the hydrate reservoir, and a mild well spacing should be carefully determined, both to promote the heat transfer in the reservoir by making the maximum use of the injected hot water, and obtain a higher gas production rate.",18,18,4
Hydrate,Shenhu Area,"Zhang, Jinming; Li, Xiaosen; Chen, Zhaoyang; Li, Qingping; Li, Gang; Lv, Tao",Numerical simulation of the improved gas production from low permeability hydrate reservoirs by using an enlarged highly permeable well wall,Methane hydrates; Depressurization; Low permeability; Enlarged permeable well wall; Liwan 3 area,EASTERN NANKAI TROUGH; SOUTH CHINA SEA; METHANE-HYDRATE; SHENHU AREA; PRODUCTION BEHAVIOR; ENERGY RECOVERY; ULLEUNG BASIN; POROUS-MEDIA; PUFF METHOD; DEPRESSURIZATION,"Gas production from low-permeability hydrate reservoirs is characterized by very low efficiency. In this work, the enlarged well wall with good permeability was first proposed to improve the gas production performance from low-permeability hydrate reservoir in Liwan 3 area of the South China Sea. The gas-water production behaviors, the spatial distributions and evolutions of hydrate reservoir parameters and gas-water flow characteristics, induced by constant-depressurization, were investigated and evaluated by numerical simulations under different radius of permeable well wall. Results show that the enlarged well wall provides a high-permeability channel around the production interval and increases the contact area between the production interval and hydrate layer, so the pressure drop propagation speed and distance, i.e. the depressurization efficiency in the hydrate-bearing sediments is increased. Both gas and water production performances are significantly improved, and the gas and water production rates, cumulates and gas to water ratio increase with the increase in permeable well wall radius. The cumulative CH4 and water produced increase by ca. 4 and 3 times, respectively, when the permeable well wall radius increases from 0 to 5 m. However, the heat supply by heat convection of geothermal water is still limited.",14,16,4
Hydrate,Hydrate Nucleation,"Stoporev, Andrey S.; Semenov, Anton P.; Medvedev, Vladimir I.; Mendgaziev, Rais I.; Istomin, Vladimir A.; Sergeeva, Daria V.; Manakov, Andrey Yu.; Vinokurov, Vladimir A.",Formation and agglomeration of gas hydrates in gas - organic liquid - water systems in a stirred reactor: Role of resins/asphaltenes/surfactants,Gas hydrate; Crude oil; Surfactants; Resins; Asphaltenes; Nucleation,ALCOHOL COSURFACTANTS; METHANE HYDRATE; FLOW ASSURANCE; INHIBITION; SURFACTANT; PREDICTION; CHEMISTRY,"In the present work, the nucleation and growth of methane hydrate and C-1-C-3 mixed hydrate in the systems with organic liquids (n-decane, toluene, crude oils) have been studied. The experiments were carried out in an autoclave at a stirring rate in a range of 100-600 rpm and at a constant cooling rate of 8.4 degrees C/h under isochoric conditions. In the case of n-decane, the experiments were conducted both with the addition of 0.5 wt % of nonionic surfactants (Span 80 or Surfynol 420) and without them; in the case of toluene the experiments were performed with addition of natural resins and asphaltenes. It was shown that Surfynol 420 had the lowest anti-agglomeration activity with respect to hydrate particles in comparison with Span 80 and oils used. Gas hydrate nucleation occurred at a lower degree of supercooling in the case of oils with a higher content of resins and asphaltenes. The change of resistance to flow in the obtained disperse systems had a reverse trend. Based on the obtained data it can be concluded that the unambiguous effect of the stirring rate on the hydrate nucleation in systems with different composition is not observed. At the same time, an increase in the stirring rate leads to an increase in the amount of gas hydrate formed in a system.",23,23,4
Hydrate,Hydrate Nucleation,"Abedi-Farizhendi, Saeid; Rahmati-Abkenar, Mahboubeh; Manteghian, Mehrdad; Yekshaveh, Jamal Salehzadeh; Zahmatkeshan, Vahid",Kinetic study of propane hydrate in the presence of carbon nanostructures and SDS,Propane hydrate; Carbon nanostructures; SDS; Kinetic,GAS HYDRATE; SILVER NANOPARTICLES; GRAPHENE OXIDE; GRAPHITE NANOPARTICLES; STORAGE CAPACITY; METHANE; DISSOCIATION,"In this work, the effect of reduced graphene oxide (RGO), graphene oxide (GO), carbon nanotube (CNT) and sodium dodecyl sulfate (SDS) on the kinetic of propane hydrate at the temperature of 274.15 K and the initial pressure of 0.45 MPa have been studied. The results show that these additives improve the hydrate nucleation and growth rate, however, have no significant effect on the storage capacity and the water to hydrate conversion.",23,23,1
Hydrate,Hydrate Nucleation,"Aminnaji, Morteza; Anderson, Ross; Tohidi, Bahman",Anomalous KHI-Induced dissociation of gas hydrates inside the hydrate stability zone: Experimental observations & potential mechanisms,Hydrate dissociation; KHIs; PVCap; Luvicap bio,METHANE; TRANSFORMATIONS; PRESSURE,"In the past decade, the low dosage hydrate inhibitors (LDHIs) - which include kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs) - have seen increasing use for gas hydrate prevention in hydrocarbon production operations, offering significant CAPEX/OPEX advantages over traditional thermodynamic inhibitors (e.g. methanol, glycols). Typically dosed at < 2.5% in produced water, KHIs were historically considered primarily as hydrate nucleation inhibitors, although in recent years focus has shifted towards their powerful crystal growth inhibition properties. Beginning at low aqueous concentrations, KHI polymers induce a number of highly repeatable, well-defined, hydrate crystal growth inhibition (CGI) regions as a function of subcooling, varying from complete inhibition, through long induction times and reduced growth rates, to final failure/uninhibited growth. This behaviour can be used to robustly assess KHIs for field use, as we have previously demonstrated through development of the KHI CGI evaluation method, which is now used as standard by a number of laboratories. During CGI testing, it is not uncommon to observe anomalous (should be stable thermodynamically) hydrate dissociation in the presence of KHIs, although very little is understood regarding this phenomenon. In this work, we present the initial findings of experimental studies aimed at investigating this anomalous dissociation for different commercial base polymers. Results demonstrate that, in addition to inhibiting hydrate growth/nucleation, low dosages (e.g. 0.5% and 0.25%) of KHI polymers can induce partial or complete hydrate dissociation, with this process largely generic to different KHIs. However, some KHI polymers cause catastrophic hydrate growth after nucleation begins and these polymers show no ability to dissociate hydrates, so this hydrate dissociation ability is not universal to all KHI Polymers. The cause of this dissociation is unclear, although it is postulated to result from interactions between the KHI and inherent hydrate morphological and/or structural changes. In addition to improving confidence in KHI field use, findings potentially have novel applications with respect to hydrate plug remediation and gas production from naturally occurring hydrates in oceanic/permafrost sediments.",17,15,8
Hydrate,Hydrate Nucleation,"Bavoh, Cornelius B.; Yuha, Yasmine Binti Md; Tay, W. H.; Ofei, Titus Ntow; Lal, Bhajan; Mukhtar, Hilmi",Experimental and modelling of the impact of quaternary ammonium salts/ionic liquid on the rheological and hydrate inhibition properties of xanthan gum water-based muds for drilling gas hydrate-bearing rocks,Gas hydrate sediments; Rheology; Drilling mud; Quaternary ammonium salts/ionic liquid; Classical nucleation theory; Xanthan gum,DUAL FUNCTION INHIBITORS; IONIC LIQUIDS; COSMO-RS; METHANE; NUCLEATION; FLUIDS; GLYCOL,"In this study, quaternary ammonium salts (QAS) and ionic liquid (IL) were used as additives in xanthan gum water-based muds formulations to investigate their rheological and hydrate inhibitive potentials in drilling gas hydrate sediment. The QAS/IL used were TMABr, TP(r)ABr, TMACl, and EMIMCl. The mud rheological characterisation was performed at a controlled shear rate of 1 s(-1) to 200 s(-1) at -2 degrees C-40 degrees C. The hydrate test was conducted in a high-pressure reactor at 8 MPa and -2 degrees C. The hydrate nucleation onset time was predicted using the classical nucleation theory (CNT) model. The rheology and hydrate results confirmed the potential application of QAS/IL in drilling mud formulations for drilling hydrate sediments. The presence of QAS/IL in the base mud suitably reduced the mud viscosity and yield stress, which are desired properties for generating turbulent flow to enhance cuttings transport, especially in high angle wellbores. The rheological properties of water-based mud were found to be significantly controlled or affected by the cation, anion, and alkyl chain length type of QAS/IL. However, the anion effect is more dominant and exhibit a critical concentration depending on its respective ionic strength. Further FTIR analysis confirmed the presence of N-O stretching which supports the performance of TMA(+) over EMIM+ to reduce the mud yield stress. In addition, the thermal degradation of the base mud was significantly reduced in the presence of QAS/IL. Amongst the studied additives, TMACl and TP(r)ABr WBMs completely prevented hydrate plugs in the mud system. Furthermore, the CNT model accurately predicted the hydrate onset time with APE < 2%. The QAS/IL in the WBM systems exhibited minimal to negligible disturbance (< 0.5 K shift) on the methane hydrate phase boundary compared with commercial hydrate additives at 3 wt%. This study provides guidelines to design efficient QAS/IL WBMs for drilling gas hydrate rocks.",14,14,5
Hydrate,Shale Inhibitor,"Ghasemi, Mehdi; Moslemizadeh, Aghil; Shahbazi, Khalil; Mohammadzadeh, Omid; Zendehboudi, Sohrab; Jafari, Sina",Primary evaluation of a natural surfactant for inhibiting clay swelling,Ginsenosides; Biosurfactant; Clay swelling inhibitor; Wettability; Compatibility,WELLBORE STABILITY; SHALE HYDRATION; REDUCING ADSORPTION; ANIONIC SURFACTANT; MODIFIED BENTONITE; IONIC LIQUID; WATER; GINSENG; COPOLYMER; MONTMORILLONITE,"Water-based drilling muds, a more environment-friendly candidate than oil-based drilling muds, are wildly used for drilling oil and gas wells. When water-based drilling mud is used for drilling formations with shale containing active clay constituents, it is challenging to preserve stability of the borehole due to clay swelling unless proper inhibition mechanisms are foreseen. In the current study, the feasibility of using Korean red Ginseng root extract was assessed as a clay swelling inhibitor. This root extract is rich in non-ionic surfactants such as Ginsenosides Rg3, Rg5, and RK1, and is referred to as ""biosurfactant"" throughout this manuscript. After preparation of mud systems containing problematic clay particles, the clay-swelling inhibition performance of the biosurfactant was systematically investigated through a series of tests, including mud formation, filtration, immersion, sedimentation assisted with optical microscopy, wettability by sessile drop technique, use of thermal gravimetric analysis (TGA), scanning electron microscopy (SEM) and Fourier-transform infrared spectroscopy (FTIR), and shale cuttings recovery. The clay-swelling inhibition performance of the biosurfactant was then compared against two clay swelling inhibitors namely CTAB (Cetrimonium bromide, a known cationic surfactant) and potassium chloride. There are some properties associated with the mud systems prepared with biosurfactant solution which makes this product unique. These properties include: remarkable loading capacity of sodium montmorillonite (Mt) which in turn resulted in low rheological profile, poor fluid loss control, creation of stable Mt pellets, creation of larger size and aggregated Mt particles with less hydrophilicity, creation of fully unstable dispersed Mt particles that resulted in good sedimentation over time, less mass loss, and higher shale cuttings recovery, all compared to the baseline fluid made without the presence of biosurfactant. The results of this study indicate that the biosurfactant provides excellent clay swelling inhibition properties, comparable to known inhibitors. The biosurfactant's compatibility with other drilling mud components was also checked, and it was found that the fluid properties are independent of the biosurfactant. The wettability and FTIR analyses were also performed to investigate the mechanisms involved in clay swelling inhibition of the biosurfactant, which are believed to be as a result of coating the clay active surfaces with a hydrophobic layer, hence repelling the water phase. This hydrophobic layer is probably formed by interactions of the hydrophilic group of the Ginsenosides and the oxygen atoms available on the Mt surfaces, when the hydrophobic tail is oriented toward the aqueous phase.",30,30,0
Hydrate,Shale Inhibitor,"Xu, Jian-gen; Qiu, Zhengsong; Zhao, Xin; Zhong, Hanyi; Huang, Weian",Study of 1-Octyl-3-methylimidazolium bromide for inhibiting shale hydration and dispersion,Shale inhibitor; Ionic liquid; Adsorption; Inhibition mechanism; Hydrophobic,DRILLING-FLUIDS; IONIC LIQUID; WATER,"In recent years, developing high-performance shale inhibitors with excellent shale swelling and dispersion inhibition properties has attracted great interests in the drilling industry. 1-Octyl-3-methylimidazolium bromide (OMB), a common imidazolium-based ionic liquid, was introduced as a promising shale inhibitor. Shale hydration inhibition capacity was investigated via sodium bentonite (Na-BT) plate soaking test, linear swelling experiment and hot-rolling dispersion experiment. The inhibition mechanism was analyzed by Fourier transforms infrared spectroscopy (FT-IR) analysis, X-ray diffraction (XRD) analysis, thermogravimetric (TGA) analysis, contact angle test, zeta potential test and surface tension measurement. The results demonstrated the shale hydration inhibition property of OMB was obviously superior to other widely used shale inhibitors. OMB could be easily adsorbed onto sodium montmorillonite (MMT) through electrostatic interaction, and some interlayer water molecules were expelled due to its intercalation. Meanwhile, the surface of MMT became more hydrophobic after adsorbed by OMB, and an effective shield against water intrusion was formed. In addition, OMB could effectively reduce the surface tension even at low concentrations, and a lower capillary suction pressure could be beneficial for reducing fluid invasion. The results obtained from the work indicated that OMB had the potential to become a high-performance shale inhibitor for drilling shale formations.",20,21,3
Hydrate,Shale Inhibitor,"Chu, Qi; Lin, Ling; Zhao, Yukun",Hyperbranched polyethylenimine modified with silane coupling agent as shale inhibitor for water-based drilling fluids,Silane coupling agent; Hyperbranched polyethylenimine; Shale inhibitor; Adsorption; Water-based drilling fluid; Application,POLYETHER DIAMINE; ADSORPTION; BENTONITE; MECHANISM; HYDRATION; AMINE; CORE,"Hyperbranched polyethylenimine modified with a silane coupling agent (Si-HPEI) as a shale inhibitor was synthesized by the Michael addition reaction of hyperbranched polyethylenimine (HPEI) and methacryloxypropyltrimethoxysilane. The structure of Si-HPEI was characterized by Fourier transform infrared spectroscopy and proton nuclear magnetic resonance. The inhibitory properties of Si-HPEI in comparison with currently available inhibitors were evaluated using linear swelling tests, cuttings dispersion tests, and bentonite inhibition tests. The inhibitory mechanism was investigated via X-ray diffraction measurements, adsorption measurements, and atomic force microscopy observations. The results indicated that Si-HPEI effectively inhibited the hydration and expansion of shale and exhibited excellent temperature resistance in comparison with HPEI and traditional shale inhibitors. The shale cuttings recovery in the case of Si-HPEI remained above 68% up to a hot rolling aging temperature of 140 degrees C, which demonstrated an excellent ability to inhibit hydration and dispersion that was significantly less affected by the hot rolling aging temperature than in the cases of other inhibitors. In addition, Si-HPEI inhibited the formation of a bentonite slurry more effectively at high temperatures. A mechanistic analysis showed that the siloxane groups present in the molecular chains of Si-HPEI caused strong and stable chemical adsorption of Si-HPEI on water-sensitive clay minerals, which thus hindered the penetration of water molecules and ultimately inhibited the hydration expansion and dispersion of water-sensitive clay minerals. In field application, Si-HPEI was successfully applied on Su 4-4HF well.",16,17,6
Hydrate,Clay Swelling,"Ghasemi, Mehdi; Moslemizadeh, Aghil; Shahbazi, Khalil; Mohammadzadeh, Omid; Zendehboudi, Sohrab; Jafari, Sina",Primary evaluation of a natural surfactant for inhibiting clay swelling,Ginsenosides; Biosurfactant; Clay swelling inhibitor; Wettability; Compatibility,WELLBORE STABILITY; SHALE HYDRATION; REDUCING ADSORPTION; ANIONIC SURFACTANT; MODIFIED BENTONITE; IONIC LIQUID; WATER; GINSENG; COPOLYMER; MONTMORILLONITE,"Water-based drilling muds, a more environment-friendly candidate than oil-based drilling muds, are wildly used for drilling oil and gas wells. When water-based drilling mud is used for drilling formations with shale containing active clay constituents, it is challenging to preserve stability of the borehole due to clay swelling unless proper inhibition mechanisms are foreseen. In the current study, the feasibility of using Korean red Ginseng root extract was assessed as a clay swelling inhibitor. This root extract is rich in non-ionic surfactants such as Ginsenosides Rg3, Rg5, and RK1, and is referred to as ""biosurfactant"" throughout this manuscript. After preparation of mud systems containing problematic clay particles, the clay-swelling inhibition performance of the biosurfactant was systematically investigated through a series of tests, including mud formation, filtration, immersion, sedimentation assisted with optical microscopy, wettability by sessile drop technique, use of thermal gravimetric analysis (TGA), scanning electron microscopy (SEM) and Fourier-transform infrared spectroscopy (FTIR), and shale cuttings recovery. The clay-swelling inhibition performance of the biosurfactant was then compared against two clay swelling inhibitors namely CTAB (Cetrimonium bromide, a known cationic surfactant) and potassium chloride. There are some properties associated with the mud systems prepared with biosurfactant solution which makes this product unique. These properties include: remarkable loading capacity of sodium montmorillonite (Mt) which in turn resulted in low rheological profile, poor fluid loss control, creation of stable Mt pellets, creation of larger size and aggregated Mt particles with less hydrophilicity, creation of fully unstable dispersed Mt particles that resulted in good sedimentation over time, less mass loss, and higher shale cuttings recovery, all compared to the baseline fluid made without the presence of biosurfactant. The results of this study indicate that the biosurfactant provides excellent clay swelling inhibition properties, comparable to known inhibitors. The biosurfactant's compatibility with other drilling mud components was also checked, and it was found that the fluid properties are independent of the biosurfactant. The wettability and FTIR analyses were also performed to investigate the mechanisms involved in clay swelling inhibition of the biosurfactant, which are believed to be as a result of coating the clay active surfaces with a hydrophobic layer, hence repelling the water phase. This hydrophobic layer is probably formed by interactions of the hydrophilic group of the Ginsenosides and the oxygen atoms available on the Mt surfaces, when the hydrophobic tail is oriented toward the aqueous phase.",30,30,0
Hydrate,Clay Swelling,"Chu, Qi; Lin, Ling; Zhao, Yukun",Hyperbranched polyethylenimine modified with silane coupling agent as shale inhibitor for water-based drilling fluids,Silane coupling agent; Hyperbranched polyethylenimine; Shale inhibitor; Adsorption; Water-based drilling fluid; Application,POLYETHER DIAMINE; ADSORPTION; BENTONITE; MECHANISM; HYDRATION; AMINE; CORE,"Hyperbranched polyethylenimine modified with a silane coupling agent (Si-HPEI) as a shale inhibitor was synthesized by the Michael addition reaction of hyperbranched polyethylenimine (HPEI) and methacryloxypropyltrimethoxysilane. The structure of Si-HPEI was characterized by Fourier transform infrared spectroscopy and proton nuclear magnetic resonance. The inhibitory properties of Si-HPEI in comparison with currently available inhibitors were evaluated using linear swelling tests, cuttings dispersion tests, and bentonite inhibition tests. The inhibitory mechanism was investigated via X-ray diffraction measurements, adsorption measurements, and atomic force microscopy observations. The results indicated that Si-HPEI effectively inhibited the hydration and expansion of shale and exhibited excellent temperature resistance in comparison with HPEI and traditional shale inhibitors. The shale cuttings recovery in the case of Si-HPEI remained above 68% up to a hot rolling aging temperature of 140 degrees C, which demonstrated an excellent ability to inhibit hydration and dispersion that was significantly less affected by the hot rolling aging temperature than in the cases of other inhibitors. In addition, Si-HPEI inhibited the formation of a bentonite slurry more effectively at high temperatures. A mechanistic analysis showed that the siloxane groups present in the molecular chains of Si-HPEI caused strong and stable chemical adsorption of Si-HPEI on water-sensitive clay minerals, which thus hindered the penetration of water molecules and ultimately inhibited the hydration expansion and dispersion of water-sensitive clay minerals. In field application, Si-HPEI was successfully applied on Su 4-4HF well.",16,17,6
Hydrate,Clay Swelling,"Fu, Lipei; Liao, Kaili; Ge, Jijiang; Zhang, Guicai; He, Yanfeng; Wang, Xiang; Zhang, Shifeng; Deng, Song",Study of ethylenediammonium dichloride as a clay stabilizer used in the fracturing fluid,Clay stabilizer; Ethylenediammonium dichloride; Inhibition mechanism; Clay hydration; Fracturing fluid,OIL-RECOVERY; SHALE; NANOTECHNOLOGY; NANOPARTICLES; POLYMER,"Clay stabilizer is the topic of a great number of studies, particularly in petroleum engineering. The organic cationic polymer is a kind of clay stabilizer with excellent anti-swelling effect. However, for tight reservoirs, the organic cationic polymer type clay stabilizers tend to increase the permeability damage caused by retention and blockage of stabilizers. Therefore, stabilizers with low molecular weight are necessary for tight reservoirs. The inhibition properties and the mechanisms of ethylenediammonium dichloride (EDD) were studied in this paper. The clay inhibition properties were studied from three aspects: swelling inhibition, clay sedimentation, and particle size distribution. Results showed that the anti-swelling rate reaches 91.98%. Control experiments showed that EDD had better inhibition property than KCl, NH4Cl, and poly dimethyldiallyl ammonium chloride (PDMDAAC). The inhibition mechanisms, studied from the aspect of surface hydrophobicity, surface charge, interlayer water content, and crystal spacing, can be concluded as that EDD reduces clay electronegativity and enhances the hydrophobicity of the clay surface, thereby keeping clay in a stable state. Compatibility tests showed that EDD can be used in guar based fracturing fluid. This study provides an alternative clay stabilizer for hydraulic fracturing.",14,16,9
Hydrate,Core Samples,"Okwananke, Anthony; Hassanpouryouzband, Aliakbar; Farahani, Mehrdad Vasheghani; Yang, Jinhai; Tohidi, Bahman; Chuvilin, Evgeny; Istomin, Vladimir; Bukhanov, Boris",Methane recovery from gas hydrate-bearing sediments: An experimental study on the gas permeation characteristics under varying pressure,Methane recovery; Gas permeability; Methane hydrate; Breakthrough capillary pressure; Hydrate-forced heave and agglomeration; Klinkenberg effect,POROUS-MEDIA; RELATIVE PERMEABILITY; THERMAL-STIMULATION; CARBON-DIOXIDE; DEPRESSURIZATION; INJECTION; EXPLOITATION; DISSOCIATION; TOMOGRAPHY; COMBUSTION,"In this paper, characteristics of gas permeation through gas hydrate-bearing sediments were explored under varying differential pressure for three types of sedimentary core samples, including 100 wt % silica sand, 95 wt % silica sand + 5 wt % montmorillonite clay, and consolidated sandstone using a standard core-holder. Results of the experiments indicate that capillary breakthrough, hydrate-forced heave or agglomeration and also Klinkenberg effect play important roles in controlling the gas permeation through different porous sediments, depending on the sediment type and properties such as grain/pore size distribution and degree of consolidation. It was observed that due to the presence of large pores in unconsolidated silica sand core samples, the gas flow is dominated at both hydrate-free and hydrate-bearing cases by the capillary breakthrough mechanism rather than the gas slippage which resulted in direct relationship between the gas permeability and the differential pressure. This mechanism was also observed to be dominant while measuring the gas permeability for the hydrate-free sandstone core sample. For the unconsolidated sand-clay core samples, higher saturation of methane hydrate led to relatively higher gas permeability due to hydrate-forced heave phenomenon which pushed the sediment grains apart from each other or hydrate agglomeration that formed inter-grain pores. Klinkenberg effect became significant for the hydrate-free sand-clay and hydrate-bearing sandstone core samples; however, it was not observed to be dominant in the hydrate-bearing sand-clay core samples due to the hydrate-forced heave and agglomeration until the inlet pressure was sufficiently high.",24,24,10
Hydrate,Core Samples,"Kuang, Yangmin; Yang, Lei; Li, Qingping; Lv, Xin; Li, Yuanping; Yu, Bin; Leng, Shudong; Song, Yongchen; Zhao, Jiafei",Physical characteristic analysis of unconsolidated sediments containing gas hydrate recovered from the Shenhu Area of the South China sea,Physical properties; Hydrate-bearing sediments; Shenhu area; South China sea,STRATIGRAPHIC TEST WELL; METHANE HYDRATE; BEARING SEDIMENTS; POROUS-MEDIA; GEOTECHNICAL PROPERTIES; MECHANICAL-PROPERTIES; ULLEUNG BASIN; CORE SAMPLES; EAST SEA; PERMEABILITY,"Laboratory research based on the physical characteristics of unconsolidated sediments containing gas hydrate was carried out on hydrate-bearing sediment samples recovered from China National Offshore Oil Corporation (CNOOC) drilling expeditions in 2015 and 2017 at the station of LW3 in the northern part of the South China Sea. We herein have measured the gas composition, index properties, surface characteristics, thermal properties, and mechanical properties of these sediment cores drilled at different seafloor depths. Based on the measurement results, more than 99% of the gas composition is methane gas. The hydrate-bearing sediments recovered from Shenhu Area are non-diagenetic rock, the fraction of grain size which less than 40 mu m was more than 90%. The results could provide useful guidance for potential sand-control system operations. Such small and consolidated particles indicated that the application of a novel solid fluidization mining method is viable and promising. The fine-grained layers were found to be mostly self-filtering and internally stable for the seepage flow during production. Gas hydrate mostly occurs in vein-type, and bioclastics consisting of marine planktonic diatoms and foraminifera were also found. The mineral components of the sediments were mostly quartz, clay minerals like illite and some feldspar like albite. The thermal conductivities changed from 1.4 to 1.77 W/(mK), which suggests that the isolated depressurization methods could exacerbate the problem of gas hydrate reformation or ice generation; thus, heat injection in wellbores should be combined for gas hydrate production strategies. The low liquid limit (38%) and plastic limit (24%) imply that stability of the production platform should be taken into account for avoiding submarine landslide impacts. The results of mechanical property analyses indicated that hydrate-bearing sediments at deeper sites have a relatively higher strength at hydrate layer of 120-133 mbsf in the Shenhu Area of the South China Sea.",22,23,16
Hydrate,Water Sensitivity,"Wang, Boyang; Qin, Yong; Shen, Jian; Wang, Gang; Zhang, Qiusheng; Liu, Miao",Experimental study on water sensitivity and salt sensitivity of lignite reservoir under different pH,Lignite reservoirs; Water sensitivity; Salt sensitivity; pH,QUANTITATIVE-ANALYSIS; FUNCTIONAL-GROUPS; COAL FINES; FTIR; SPECTROSCOPY; TEMPERATURE; OXIDATION; MACERALS; FRACTURE; STRESS,"The water sensitivity and salt sensitivity of lignite reservoirs are important factors affecting the productivity of the coalbed methane (CBM) well. This paper took the lignite of Erlian Basin as the research object. The content and occurrence of mineral was analyzed by LTA + XRD combined with scanning electron microscopy (SEM), and distribution of each functional group of lignite was analyzed by infra-red spectrum. Based on the above analysis, standard salt water with different pH and salinity was used as the experimental injection fluid, and water sensitivity (salt sensitivity) experiments were performed under the condition of constant effective stress. The experimental results show that the sample contains a large number of water-sensitive minerals (kaolinite and illite/smectite mixed layer mineral), and the ratio of carbonyl, hydroxybenzene and carboxyl groups is 10:7:1. Hydrogen bonds are mainly OH center dot center dot center dot N hydrogen bonds. The lignite reservoirs with different pH have different degrees of water-sensitive damage, and the damage rates from high to low are partial alkalinity conditions (54.18%), partial acidity conditions (42.6%), and strong alkalinity conditions (23.67%). The dimensionless permeability changes with the decrease of salinity, which can be divided into three stages (no water sensitivity stage, particle migration water sensitivity stage, particle expansion water sensitivity stage) with 1250 mg/L and 10000 mg/L as the boundary. The displacement pressure and pH are the main controlling factors at different stages, and pH controls the wettability of pulverized coal and the hydration expansibility of clay minerals. The dimensionless permeability of lignite reservoir increases with the increase of salinity under the acidic condition. Under alkaline conditions, it is characterized by no-weak salt sensitivity. The greater the alkalinity, the stronger the salt sensitivity, which is mainly controlled by the change of the thickness of the water film under the influence of pH.",18,18,7
Hydrate,Water Sensitivity,"Yu, Tao; Guan, Guoqing; Abudula, Abuliti; Yoshida, Akihiro; Wang, Dayong; Song, Yongchen","Heat-assisted production strategy for oceanic methane hydrate development in the Nankai Trough, Japan",Methane hydrate; Nankai Trough; Horizontal well; Thermal injection; Well placement,QILIAN MOUNTAIN PERMAFROST; SOUTH CHINA SEA; GAS-PRODUCTION; SHENHU AREA; NUMERICAL-SIMULATION; HORIZONTAL WELLS; POWER-GENERATION; PUFF METHOD; TEST-SITE; DEPOSITS,"The heat-assisted production strategy was considered to be an effective approach for the oceanic methane hydrate (MH) development. In this study, the combined method of depressurization and hot water injection was applied to the multilayered MH reservoir in the Nankai Trough, Japan, by using dual horizontal wells. Some possible well placements by placing the two wells in the same sublayer and different sublayers were designed in this study, and their effectiveness on the gas recovery enhancement was verified via long-term simulations of the oceanic MH production. It was found that when the two wells were placed in different sublayers, with some horizontal distance and the injection well locating above the production well, a favorable average gas production rate of 2.0 x 10(6) m(3)/day could be obtained, and was up to 100 times of that confirmed during the 2013 offshore MH production test in the Nankai Trough (2.0 x 10(4) m(3)/day), which indicated the high efficiency of the method proposed in this study. Furthermore, sensitivity analyses on the well locations suggested that the production well should be placed near the bottom of the hydrate reservoir, and a mild well spacing should be carefully determined, both to promote the heat transfer in the reservoir by making the maximum use of the injected hot water, and obtain a higher gas production rate.",18,18,4
Hydrate,Mud,"Ghasemi, Mehdi; Moslemizadeh, Aghil; Shahbazi, Khalil; Mohammadzadeh, Omid; Zendehboudi, Sohrab; Jafari, Sina",Primary evaluation of a natural surfactant for inhibiting clay swelling,Ginsenosides; Biosurfactant; Clay swelling inhibitor; Wettability; Compatibility,WELLBORE STABILITY; SHALE HYDRATION; REDUCING ADSORPTION; ANIONIC SURFACTANT; MODIFIED BENTONITE; IONIC LIQUID; WATER; GINSENG; COPOLYMER; MONTMORILLONITE,"Water-based drilling muds, a more environment-friendly candidate than oil-based drilling muds, are wildly used for drilling oil and gas wells. When water-based drilling mud is used for drilling formations with shale containing active clay constituents, it is challenging to preserve stability of the borehole due to clay swelling unless proper inhibition mechanisms are foreseen. In the current study, the feasibility of using Korean red Ginseng root extract was assessed as a clay swelling inhibitor. This root extract is rich in non-ionic surfactants such as Ginsenosides Rg3, Rg5, and RK1, and is referred to as ""biosurfactant"" throughout this manuscript. After preparation of mud systems containing problematic clay particles, the clay-swelling inhibition performance of the biosurfactant was systematically investigated through a series of tests, including mud formation, filtration, immersion, sedimentation assisted with optical microscopy, wettability by sessile drop technique, use of thermal gravimetric analysis (TGA), scanning electron microscopy (SEM) and Fourier-transform infrared spectroscopy (FTIR), and shale cuttings recovery. The clay-swelling inhibition performance of the biosurfactant was then compared against two clay swelling inhibitors namely CTAB (Cetrimonium bromide, a known cationic surfactant) and potassium chloride. There are some properties associated with the mud systems prepared with biosurfactant solution which makes this product unique. These properties include: remarkable loading capacity of sodium montmorillonite (Mt) which in turn resulted in low rheological profile, poor fluid loss control, creation of stable Mt pellets, creation of larger size and aggregated Mt particles with less hydrophilicity, creation of fully unstable dispersed Mt particles that resulted in good sedimentation over time, less mass loss, and higher shale cuttings recovery, all compared to the baseline fluid made without the presence of biosurfactant. The results of this study indicate that the biosurfactant provides excellent clay swelling inhibition properties, comparable to known inhibitors. The biosurfactant's compatibility with other drilling mud components was also checked, and it was found that the fluid properties are independent of the biosurfactant. The wettability and FTIR analyses were also performed to investigate the mechanisms involved in clay swelling inhibition of the biosurfactant, which are believed to be as a result of coating the clay active surfaces with a hydrophobic layer, hence repelling the water phase. This hydrophobic layer is probably formed by interactions of the hydrophilic group of the Ginsenosides and the oxygen atoms available on the Mt surfaces, when the hydrophobic tail is oriented toward the aqueous phase.",30,30,0
Hydrate,Mud,"Bavoh, Cornelius B.; Yuha, Yasmine Binti Md; Tay, W. H.; Ofei, Titus Ntow; Lal, Bhajan; Mukhtar, Hilmi",Experimental and modelling of the impact of quaternary ammonium salts/ionic liquid on the rheological and hydrate inhibition properties of xanthan gum water-based muds for drilling gas hydrate-bearing rocks,Gas hydrate sediments; Rheology; Drilling mud; Quaternary ammonium salts/ionic liquid; Classical nucleation theory; Xanthan gum,DUAL FUNCTION INHIBITORS; IONIC LIQUIDS; COSMO-RS; METHANE; NUCLEATION; FLUIDS; GLYCOL,"In this study, quaternary ammonium salts (QAS) and ionic liquid (IL) were used as additives in xanthan gum water-based muds formulations to investigate their rheological and hydrate inhibitive potentials in drilling gas hydrate sediment. The QAS/IL used were TMABr, TP(r)ABr, TMACl, and EMIMCl. The mud rheological characterisation was performed at a controlled shear rate of 1 s(-1) to 200 s(-1) at -2 degrees C-40 degrees C. The hydrate test was conducted in a high-pressure reactor at 8 MPa and -2 degrees C. The hydrate nucleation onset time was predicted using the classical nucleation theory (CNT) model. The rheology and hydrate results confirmed the potential application of QAS/IL in drilling mud formulations for drilling hydrate sediments. The presence of QAS/IL in the base mud suitably reduced the mud viscosity and yield stress, which are desired properties for generating turbulent flow to enhance cuttings transport, especially in high angle wellbores. The rheological properties of water-based mud were found to be significantly controlled or affected by the cation, anion, and alkyl chain length type of QAS/IL. However, the anion effect is more dominant and exhibit a critical concentration depending on its respective ionic strength. Further FTIR analysis confirmed the presence of N-O stretching which supports the performance of TMA(+) over EMIM+ to reduce the mud yield stress. In addition, the thermal degradation of the base mud was significantly reduced in the presence of QAS/IL. Amongst the studied additives, TMACl and TP(r)ABr WBMs completely prevented hydrate plugs in the mud system. Furthermore, the CNT model accurately predicted the hydrate onset time with APE < 2%. The QAS/IL in the WBM systems exhibited minimal to negligible disturbance (< 0.5 K shift) on the methane hydrate phase boundary compared with commercial hydrate additives at 3 wt%. This study provides guidelines to design efficient QAS/IL WBMs for drilling gas hydrate rocks.",14,14,5
Hydrate,Carbon Dioxide,"Okwananke, Anthony; Hassanpouryouzband, Aliakbar; Farahani, Mehrdad Vasheghani; Yang, Jinhai; Tohidi, Bahman; Chuvilin, Evgeny; Istomin, Vladimir; Bukhanov, Boris",Methane recovery from gas hydrate-bearing sediments: An experimental study on the gas permeation characteristics under varying pressure,Methane recovery; Gas permeability; Methane hydrate; Breakthrough capillary pressure; Hydrate-forced heave and agglomeration; Klinkenberg effect,POROUS-MEDIA; RELATIVE PERMEABILITY; THERMAL-STIMULATION; CARBON-DIOXIDE; DEPRESSURIZATION; INJECTION; EXPLOITATION; DISSOCIATION; TOMOGRAPHY; COMBUSTION,"In this paper, characteristics of gas permeation through gas hydrate-bearing sediments were explored under varying differential pressure for three types of sedimentary core samples, including 100 wt % silica sand, 95 wt % silica sand + 5 wt % montmorillonite clay, and consolidated sandstone using a standard core-holder. Results of the experiments indicate that capillary breakthrough, hydrate-forced heave or agglomeration and also Klinkenberg effect play important roles in controlling the gas permeation through different porous sediments, depending on the sediment type and properties such as grain/pore size distribution and degree of consolidation. It was observed that due to the presence of large pores in unconsolidated silica sand core samples, the gas flow is dominated at both hydrate-free and hydrate-bearing cases by the capillary breakthrough mechanism rather than the gas slippage which resulted in direct relationship between the gas permeability and the differential pressure. This mechanism was also observed to be dominant while measuring the gas permeability for the hydrate-free sandstone core sample. For the unconsolidated sand-clay core samples, higher saturation of methane hydrate led to relatively higher gas permeability due to hydrate-forced heave phenomenon which pushed the sediment grains apart from each other or hydrate agglomeration that formed inter-grain pores. Klinkenberg effect became significant for the hydrate-free sand-clay and hydrate-bearing sandstone core samples; however, it was not observed to be dominant in the hydrate-bearing sand-clay core samples due to the hydrate-forced heave and agglomeration until the inlet pressure was sufficiently high.",24,24,10
Hydrate,Carbon Dioxide,"Gambelli, Alberto Maria; Castellani, Beatrice; Nicolini, Andrea; Rossi, Federico","Experimental study on natural gas hydrate exploitation: Optimization of methane recovery, carbon dioxide storage and deposit structure preservation",Natural gas hydrate; CO2 replacement; Lab-scale reactor; CO2 storage; Environment preservation,INJECTION; DISSOCIATION; DECOMPOSITION; ACCUMULATIONS; SATURATION; RESERVOIRS; SEDIMENT,"Aim of this work is locating how CO2 replacement into methane hydrate deposits may be performed, in order to increase both methane recovered and carbon dioxide stored quantities. The experimental section deals with the study of natural gas hydrate formation process and replacement of methane, contained into water cages, with carbon dioxide. In particular, the formation of methane hydrate is analyzed to understand the parameters that most influence the replacement process. A total of 10 tests were carried out in a laboratory scale reactor. Test 1-8 were performed adopting thermal stimulation as replacement technique, while in Test 9 and Test 10 depressurization was used. Results obtained have led to the conclusion that the rate of methane hydrate formation positively influences the percentage of CO2 stored, while the initial saturation of the sand pores has a negative effect. The presence of hydrate agglomerates hinders the gas transition preventing the replacement process. Finally, a greater quantity of CO2 hydrate, both via replacement process and via new hydrate formation, is related to a higher deposit structure preservation. As emerges from the experimental tests, the adopted replacement strategy influences the experimental relationships.",24,24,8
Hydrate,Polymer,"Aminnaji, Morteza; Anderson, Ross; Tohidi, Bahman",Anomalous KHI-Induced dissociation of gas hydrates inside the hydrate stability zone: Experimental observations & potential mechanisms,Hydrate dissociation; KHIs; PVCap; Luvicap bio,METHANE; TRANSFORMATIONS; PRESSURE,"In the past decade, the low dosage hydrate inhibitors (LDHIs) - which include kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs) - have seen increasing use for gas hydrate prevention in hydrocarbon production operations, offering significant CAPEX/OPEX advantages over traditional thermodynamic inhibitors (e.g. methanol, glycols). Typically dosed at < 2.5% in produced water, KHIs were historically considered primarily as hydrate nucleation inhibitors, although in recent years focus has shifted towards their powerful crystal growth inhibition properties. Beginning at low aqueous concentrations, KHI polymers induce a number of highly repeatable, well-defined, hydrate crystal growth inhibition (CGI) regions as a function of subcooling, varying from complete inhibition, through long induction times and reduced growth rates, to final failure/uninhibited growth. This behaviour can be used to robustly assess KHIs for field use, as we have previously demonstrated through development of the KHI CGI evaluation method, which is now used as standard by a number of laboratories. During CGI testing, it is not uncommon to observe anomalous (should be stable thermodynamically) hydrate dissociation in the presence of KHIs, although very little is understood regarding this phenomenon. In this work, we present the initial findings of experimental studies aimed at investigating this anomalous dissociation for different commercial base polymers. Results demonstrate that, in addition to inhibiting hydrate growth/nucleation, low dosages (e.g. 0.5% and 0.25%) of KHI polymers can induce partial or complete hydrate dissociation, with this process largely generic to different KHIs. However, some KHI polymers cause catastrophic hydrate growth after nucleation begins and these polymers show no ability to dissociate hydrates, so this hydrate dissociation ability is not universal to all KHI Polymers. The cause of this dissociation is unclear, although it is postulated to result from interactions between the KHI and inherent hydrate morphological and/or structural changes. In addition to improving confidence in KHI field use, findings potentially have novel applications with respect to hydrate plug remediation and gas production from naturally occurring hydrates in oceanic/permafrost sediments.",17,15,8
Hydrate,Polymer,"Fu, Lipei; Liao, Kaili; Ge, Jijiang; Zhang, Guicai; He, Yanfeng; Wang, Xiang; Zhang, Shifeng; Deng, Song",Study of ethylenediammonium dichloride as a clay stabilizer used in the fracturing fluid,Clay stabilizer; Ethylenediammonium dichloride; Inhibition mechanism; Clay hydration; Fracturing fluid,OIL-RECOVERY; SHALE; NANOTECHNOLOGY; NANOPARTICLES; POLYMER,"Clay stabilizer is the topic of a great number of studies, particularly in petroleum engineering. The organic cationic polymer is a kind of clay stabilizer with excellent anti-swelling effect. However, for tight reservoirs, the organic cationic polymer type clay stabilizers tend to increase the permeability damage caused by retention and blockage of stabilizers. Therefore, stabilizers with low molecular weight are necessary for tight reservoirs. The inhibition properties and the mechanisms of ethylenediammonium dichloride (EDD) were studied in this paper. The clay inhibition properties were studied from three aspects: swelling inhibition, clay sedimentation, and particle size distribution. Results showed that the anti-swelling rate reaches 91.98%. Control experiments showed that EDD had better inhibition property than KCl, NH4Cl, and poly dimethyldiallyl ammonium chloride (PDMDAAC). The inhibition mechanisms, studied from the aspect of surface hydrophobicity, surface charge, interlayer water content, and crystal spacing, can be concluded as that EDD reduces clay electronegativity and enhances the hydrophobicity of the clay surface, thereby keeping clay in a stable state. Compatibility tests showed that EDD can be used in guar based fracturing fluid. This study provides an alternative clay stabilizer for hydraulic fracturing.",14,16,9
Hydrate,Total Gas,"Sun, Youhong; Ma, Xiaolong; Guo, Wei; Jia, Rui; Li, Bing",Numerical simulation of the short- and long-term production behavior of the first offshore gas hydrate production test in the South China Sea,The Shenhu area; Gas hydrates; Production behavior; Hydrate reformation; Numerical simulation,METHANE HYDRATE; SHENHU AREA; THERMAL-STIMULATION; BEARING SEDIMENTS; POROUS-MEDIA; DEPRESSURIZATION; DEPOSITS; DISSOCIATION; SITE; RESERVOIR,"Gas hydrate-bearing sediments at the first offshore gas hydrate production test site in the Shenhu area, South China Sea, have the characteristics of high irreducible water saturation and low permeability. The stratum structure of this production test site is complex, its gas hydrate-bearing layer (GHBL), three-phase layer (TPL) and free gas layer (FGL) all contain methane gas or gas hydrates, that make the production more complicated. According to the available geological data at the first offshore gas hydrate production test site in the Shenhu area, a 2D numerical simulation model is built to study the short-and the long-term production behavior of the gas hydrates in the Shenhu area. In the short-term, the total gas production from hydrates, when the TPL gas saturation is 0.078, is determined to be 2.75 x 10(5) m(3), which is close to the actual total gas production of 3.09 x 10(5) m(3). When the irreducible water saturation varies from 0.40 to 0.63, the total gas production changes from 1.41 x 10(5) to 2.75 x 10(5) m(3), and the total water production decreases from 1.04 x 10(4) to 8.7 x 10(3) m(3), which indicates that irreducible water is a favorable factor for gas production from hydrates in clayey silt sediments. In the long-term gas production from hydrates, the gas production rate first decreases, then increases, and finally decreases again. Gas hydrate reformation occurs at the interface between the TPL and the FGL, which will adversely affect the gas production from hydrates.",26,32,15
Hydrate,Total Gas,"Gambelli, Alberto Maria; Castellani, Beatrice; Nicolini, Andrea; Rossi, Federico","Experimental study on natural gas hydrate exploitation: Optimization of methane recovery, carbon dioxide storage and deposit structure preservation",Natural gas hydrate; CO2 replacement; Lab-scale reactor; CO2 storage; Environment preservation,INJECTION; DISSOCIATION; DECOMPOSITION; ACCUMULATIONS; SATURATION; RESERVOIRS; SEDIMENT,"Aim of this work is locating how CO2 replacement into methane hydrate deposits may be performed, in order to increase both methane recovered and carbon dioxide stored quantities. The experimental section deals with the study of natural gas hydrate formation process and replacement of methane, contained into water cages, with carbon dioxide. In particular, the formation of methane hydrate is analyzed to understand the parameters that most influence the replacement process. A total of 10 tests were carried out in a laboratory scale reactor. Test 1-8 were performed adopting thermal stimulation as replacement technique, while in Test 9 and Test 10 depressurization was used. Results obtained have led to the conclusion that the rate of methane hydrate formation positively influences the percentage of CO2 stored, while the initial saturation of the sand pores has a negative effect. The presence of hydrate agglomerates hinders the gas transition preventing the replacement process. Finally, a greater quantity of CO2 hydrate, both via replacement process and via new hydrate formation, is related to a higher deposit structure preservation. As emerges from the experimental tests, the adopted replacement strategy influences the experimental relationships.",24,24,8
Organic Matter,Model,"Kong, Lingyun; Ostadhassan, Mehdi; Hou, Xiaodong; Mann, Michael; Li, Chunxiao",Microstructure characteristics and fractal analysis of 3D-printed sandstone using micro-CT and SEM-EDS,3D-printed rocks; Microstructures; Sandstone; Micro-computed tomography,RAY COMPUTED-TOMOGRAPHY; MECHANICAL-PROPERTIES; RESERVOIR ROCKS; ORGANIC-MATTER; PORE STRUCTURE; PERMEABILITY; PARTICLES; ALGORITHM; VOLUME; BASIN,"Replicating sedimentary rocks using three-dimensional (3D) printing can support routine reservoir rock analysis in petrophysical and geomechanical experiments, which is done limited in scope due to lack of suitable printing materials and achievable resolution. Following our previous studies on gypsum powder with binder, a new printing material, silica sand, is used and characterized in this study to demonstrate the microstructure and its similarity to Berea Sandstone. Binder jetting printing system was specifically utilized to bond silica sand particles to create intact cylindrical samples without digital porous model as input. Created samples were first scanned by Backscattered Scanning Electron Microscope (BS-SEM) and Energy Dispersive Spectroscopy (EDS) to identify the particles, the packing mode and cement (binder). Next, micro-computed tomography (CT) was used to determine the microstructure of the samples, including the size and the shape of both particles and pores, in the 3D space. In addition, anisotropy that was found to originate from the pore structures was quantified by comparing the characteristics of pores in different directions. Fractal dimensions from different sample sizes, 6 mm and 12 mm in diameter, were also calculated for pore structure analysis in order to illustrate the effect of sample size on pore heterogeneity in 3D printed samples with silica. The results demonstrated the feasibility of substituting 3D-printed sandstones for natural rocks regarding pore structures for experimental validation of petrophysical models.",24,26,10
Organic Matter,Model,"Cui, Ronghao; Feng, Qihong; Chen, Hongwei; Zhang, Wei; Wang, Sen",Multiscale random pore network modeling of oil-water two-phase slip flow in shale matrix,Pore network model; Shale oil; Two-phase flow; Slip effect; Computational fluid dynamics,FRACTURED HORIZONTAL WELL; FAST MASS-TRANSPORT; POROUS-MEDIA; RELATIVE PERMEABILITY; DYNAMIC PROPERTIES; CO2 SEQUESTRATION; ORGANIC-MATTER; GAS-FLOW; NANOPORES; RESERVOIR,"The large-scale hydraulic fracturing technology is commonly employed to significantly improve oil recovery in shale. An exceptional phenomenon from many field tests is worthy of attention that the majority of fracturing fluid (mainly water) does not return to the surface during hydraulic fracturing, but flows into shale matrix. As a consequence of this phenomenon, oil-water two-phase flow would happen. However, the fluid transportation in nano-pores is different from that of the conventional sandstone reservoirs. To understand oil-water two-phase flow in shale, an integrated pore network model (PNM) framework including network construction and flow simulation is developed. In the network construction, combined with a pore-size distribution (PSD) curve of shale system, a shale multiscale random pore network model is proposed, where organic pores and inorganic pores can be distinguished appropriately. In the flow simulation, considering that the traditional Hagen-Poiseuille equation may not be applicable in shale system, new bulk fluid and corner film flow models with slip length in various geometric pores (circular, square, equilateral triangle) are developed using the computational fluid dynamic (CFD) method. Through the quasi-static simulation technique, we estimate the flow properties in shale including capillary pressure and relative permeability. Simulation results confirm the slip effect would significantly affect oil-water two-phase flow in shale. And then, influences of shale pore structure on two-phase flow are further investigated. Through coupling network construction and two-phase flow simulation, we believe our work could shed light on the further research for multi-phase transportation in shale.",23,24,9
Organic Matter,Model,"Feng, Qihong; Xu, Shiqian; Wang, Sen; Li, Yuyao; Gao, Fangfang; Xu, Yajuan",Apparent permeability model for shale oil with multiple mechanisms,Shale oil; Apparent permeability; Natural fracture; Noncircular pore; Production prediction; Embedded discrete fracture model,PORE-SIZE DISTRIBUTION; FAST MASS-TRANSPORT; LIQUID PERMEABILITY; ORGANIC NANOPORES; POROUS-MEDIA; GAS-FLOW; NETWORK; SIMULATION; ROCK; ENHANCEMENT,"Accurate apparent permeability (AP) model for oil transport in shale must consider natural fractures and micro/nano-pores within organic matter and inorganic matrix. Furthermore, the effect of pore geometry, tortuosity, pore size distribution (PSD), the spatial distribution of different pores, total organic content (TOC), and liquid slip should also be taken into account. However, all of the aforementioned factors are not simultaneously considered in one AP model. In this work, we develop an AP model in 3D for shale oil to overcome this drawback. We first validate our model by comparing with the published data. Then sensitivity analysis for some parameters is investigated. After that, shale oil APs are used in a macro-scale reservoir simulation model. In this way, the effect of some micro-scale factors on production performance can be quantitatively evaluated. Notably, on the basis of embedded discrete fracture model (EDFM), our reservoir simulation model considers non-linear flow in shale matrix, complex hydraulic fracture geometry, and pressure-dependent permeability of hydraulic fractures. Results show that natural fractures contribute the most to AP, followed by organic pores and inorganic pores. In general, the AP in the horizontal direction is approximately twice that in the vertical direction in shale. Furthermore, the maximum error caused by the pore type on shale oil production is similar to 31%, followed by tortuosity (similar to 25%), pore shape (similar to 13%) and slip effect (similar to 4.8%). In conclusion, it is necessary to simultaneously incorporate the influences of the aforementioned factors. Our stochastic permeability model can serve as an efficient tool to determine shale oil AP.",17,19,3
Organic Matter,Model,"Sharma, Prashant; Prakash, Ravi; Abedi, Sara",Effect of temperature on nano- and microscale creep properties of organic-rich shales,Organic-rich shales; Short-duration nanoindentation; Creep nanoindentation; Creep rate magnitude; Clay-bound water; High temperature,MECHANICAL-PROPERTIES; NANOINDENTATION; INDENTATION; MATTER; DEFORMATION; MINERALS; BEHAVIOR; HARDNESS; MODULUS; STATE,"Understanding the creep properties of gas shales at elevated temperatures is critical for accurately predicting reservoir performance and assessing the effect of viscous behavior on closure rate, production rate, and conductivity loss. In order to better understand creep properties at in-situ conditions, a quantitative relationship between temperature, mechanical properties, and complex chemo-physical mechanisms that cause thermal alteration needs to be obtained. In this study, the elastic, strength, and creep properties of organic-rich shales are investigated by a combination of nanoindentation, energy dispersive x-ray spectroscopy, and micromechanical modeling over a range of temperatures (23-350 degrees C). Within the allotted temperature range, the elastic and strength properties of the porous clay/kerogen phase remain unchanged. A similar behavior is noticed in the creep modulus from temperatures 23-200 degrees C where it remains relatively unchanged and shows an isotropic characteristic. However, the creep modulus of the clay phase increases at 300 degrees C in both parallel and perpendicular directions to the bedding plane. While the analysis of creep data at lower temperatures shed light on the dictating role of organic matter and porosity on creep properties of organic-rich shales (Slim et al., 2018), at high temperature (above 200 degrees C) creep properties are affected by removal of clay-bound water. The results show that this small water content assists in mechanical compaction and grain sliding responsible for time-dependent deformation. We argue that the removal of clay-bound water at temperatures above 200 degrees C increases the frictional coefficient between clay particles and between clay particles and organic matter.",16,18,5
Organic Matter,Model,"Xiao, Hong; Wang, T. -G.; Li, Meijun; Lai, Hongfei; Liu, Jiguo; Mao, Fengjun; Tang, Youjun","Geochemical characteristics of Cretaceous Yogou Formation source rocks and oil-source correlation within a sequence stratigraphic framework in the Termit Basin, Niger",Source rock; Oil-source correlation; Sequence stratigraphic framework; Yogou Formation; Termit basin,MARINE SOURCE ROCKS; CRUDE OILS; DEPOSITIONAL ENVIRONMENT; ORGANIC FACIES; TARIM BASIN; TETRACYCLIC TERPANES; MATURITY PARAMETERS; RIFT BASINS; PETROLEUM; CHINA,"This study investigated the geochemical characteristics of source rocks in each sequence and studied on the oil-source correlation under a sequence stratigraphic framework of the Upper Cretaceous Yogou Formation. The Yogou Formation as the most primary and productive source bed in the Termit Basin (Niger), was further divided into three third-order sequences (i.e. YSQ1, YSQ2 and YSQ3, from bottom to top) in the study. On the basis of the geochemical analysis of a total of 35 rock samples from YSQ3, YSQ2 and YSQ1, the variation of the organic matter abundances, types and maturity of source rocks within different sequences were compared. The TOC content of YSQ2 and YSQ1 source rocks ranges from 0.76% to 1.69% with mature to high mature thermal evaluation stage (R-o: 0.63%-1.29%), while the TOC content of YSQ3 source rocks is much higher (1.11%-6.63%) with a relatively lower maturation levels (R-o: 0.59%-0.91%). All source rocks are dominated by Type II2-III kerogen. Moreover, in order to determine the oil-source correlation under a sequence stratigraphic framework, the composition of biomarkers in 35 source rocks and 25 crude oils were analyzed systematically. Various non-biomarker and biomarker parameters were applied involving source-related, maturity-related and environment-related parameters. The YSQ3 source rocks are typically characterized by relatively higher Pr/Ph ratio, higher concentration of dibenzofurans (DBFs) and lower gammacerane index indicating a suboxic transitional environment, and the relatively higher values of oleanane index and C24TeT/(C24TeT + C26TT) ratio reflecting a significant terrigenous organic matter input. Conversely, the YSQ2, YSQ1 source rocks and studied oils have relatively lower Pr/Ph ratios, higher content of gammacerane and dibenzothiophenes (DBTs) suggesting suboxic to anoxic conditions under shallow marine depositional environment, and low values of oleanane index and C24TeT/(C24TeT + C26TT) ratios indicating predominant algal aquatic organisms input. In addition, other molecular parameters in crude oils, including OEP, CPI, TAR, nC(21)-/nC(22) +, (nC(21) + nC(22))/(nC(28) + nC(29)), Pr/nC(17), Ph/nC(18) ratios and the distribution patterns and relevant parameters of tricyclic terpane series, also have the obviously similar characteristics to YSQ2 and YSQ1 source rocks, rather than YSQ3 source rocks. The result of oil-source correlation shows that the discovered oils are dominantly derived from YSQ2 and YSQ1 source rocks, with minor contribution of YSQ3 source rocks. Therefore, the oil-source correlation within a sequence stratigraphic framework can provide a practical model for source rock assessment and petroleum system study.",14,15,3
Organic Matter,Organic-rich Shale,"Zhang, Kun; Song, Yan; Jia, Chengzao; Jiang, Zhenxue; Jiang, Shu; Huang, Yizhou; Wen, Ming; Liu, Xiaoxue; Liu, Weiwei; Chen, Zhiyuan; Xie, Xuelian; Liu, Tianlin; Wang, Xin; Wang, Pengfei; Li, Xin; Shan, Chang'an","Vertical sealing mechanism of shale and its roof and floor and effect on shale gas accumulation, a case study of marine shale in Sichuan basin, the Upper Yangtze area",Physical sealing; Burial depth; Adsorption; Permeability; Evaluation method,SILURIAN LONGMAXI FORMATION; SOUTH CHINA EVIDENCE; ADSORPTION CAPACITY; ORGANIC-MATTER; PORE STRUCTURE; ENRICHMENT; PLATFORM; CHALLENGES; MATURITY; RODINIA,"Shale and its roof and floor are very important for shale gas preservation. How to clarify the mechanism of its vertical sealing and its effect on shale gas enrichment is a significant problem to be solved. In this paper, the objective layers are the Upper Ordovician Wufeng Formation, the first member of the Lower Silurian Longmaxi Formation and the Lower Cambrian Qiongzhusi Formation, which are all in the representative shale gas blocks in the Sichuan basin of the Yangtze region. Studied by statistical drilling data, the focus is on the detailed analyses of the JiaoYe-1, Ning-201 and Wei-201 well, and experiments were carried out such as the porosity test, the TOC content analysis and the experiment of overburden permeability, permeability experiments before and after adsorption of methane under different osmotic pressure, and isothermal adsorption experiments. The experiments results are applied on studying the effect of shale and its roof and floor on shale gas enrichment, combined with formula deduction. The results show that the roof and floor have a vertical sealing effect on the organic-rich shale by the difference of physical properties. In eastern Sichuan, the roof of the organic-rich shale of the Wufeng Formation and the first member of Longmaxi Formation is assemblage of argillaceous siltstone and siliceous shale, while in southern Sichuan it is assemblage of gray shale and siliceous shale. The floor is nodular limestone and limestone in both areas. The combination of roof and floor, with low porosity, can form a quality roof and floor sealing ability in the absence of fracture development. Its sealing ability is stronger than that in the upper part of the Qiongzhusi Formation, considering its roof and floor composed of argillaceous siltstone and siliceous shale. The floor of the organic-rich shale at the bottom of the Qiongzhusi Formation is a dolomite reservoir with good storage capacity, between which there is an unconformable contact causing the worst sealing ability among the three intervals. With the increase of burial depth, the overlying pressure of shale increases. With the increase of TOC content and thickness, the amount of adsorption gas of shale increases. These two aspects of factors can lead to the permeability decline and self-sealing enhancement of the organic-rich shale. In this study, focusing on the Upper Ordovician-Lower Silurian and the Lower Cambrian in the Sichuan basin, four patterns of organic-rich shale and its roof and floor were summed up, and the rapid evaluation method of sealing of shale and its roof and floor under the limited geological data was established.",20,21,2
Organic Matter,Organic-rich Shale,"Guo, Shaobin; Mao, Wenjing","Division of diagenesis and pore evolution of a Permian Shanxi shale in the Ordos Basin, China",Shale; Pore evolution; Diagenesis; Hydrocarbon production,MATURE POSIDONIA SHALE; ORGANIC-RICH SHALES; GAS-STORAGE; TRANSITIONAL SHALES; BIB-SEM; SIZE DISTRIBUTIONS; SPACE MORPHOLOGY; SURFACE-AREA; HILS AREA; SANDSTONES,"This research analyzed the pore evolution and diagenesis in a Permian Shanxi shale from the Ordos Basin. Thermal simulation method simulated the thermal evolution of organic matter in a sample from mature (R-o = 0.96%) to overmature (R-o = 3.05%). Gas adsorption and mercury intrusion capillary pressure techniques were used to analyze pore-size distribution across a maturation gradient. X-ray diffraction, Focused Ion Beam-Scanning Electron Microscopy and rock pyrolysis techniques were used to divide the stages of diagenesis and pore evolution. Results showed that mesopores and macropores dominate pore volume while micropores and mesopores dominate surface area. Pore volume and surface area initially decreased and then increased with maturity. Kaolinite is converted to illite and illite-smectite mixedlayer in the middle to late diagenesis stage. Pore evolution and diagenesis can be divided into four stages in a sample from mature to overmature. Factors influencing pore-size distribution are different in four stages.",17,17,3
Organic Matter,Organic-rich Shale,"Sharma, Prashant; Prakash, Ravi; Abedi, Sara",Effect of temperature on nano- and microscale creep properties of organic-rich shales,Organic-rich shales; Short-duration nanoindentation; Creep nanoindentation; Creep rate magnitude; Clay-bound water; High temperature,MECHANICAL-PROPERTIES; NANOINDENTATION; INDENTATION; MATTER; DEFORMATION; MINERALS; BEHAVIOR; HARDNESS; MODULUS; STATE,"Understanding the creep properties of gas shales at elevated temperatures is critical for accurately predicting reservoir performance and assessing the effect of viscous behavior on closure rate, production rate, and conductivity loss. In order to better understand creep properties at in-situ conditions, a quantitative relationship between temperature, mechanical properties, and complex chemo-physical mechanisms that cause thermal alteration needs to be obtained. In this study, the elastic, strength, and creep properties of organic-rich shales are investigated by a combination of nanoindentation, energy dispersive x-ray spectroscopy, and micromechanical modeling over a range of temperatures (23-350 degrees C). Within the allotted temperature range, the elastic and strength properties of the porous clay/kerogen phase remain unchanged. A similar behavior is noticed in the creep modulus from temperatures 23-200 degrees C where it remains relatively unchanged and shows an isotropic characteristic. However, the creep modulus of the clay phase increases at 300 degrees C in both parallel and perpendicular directions to the bedding plane. While the analysis of creep data at lower temperatures shed light on the dictating role of organic matter and porosity on creep properties of organic-rich shales (Slim et al., 2018), at high temperature (above 200 degrees C) creep properties are affected by removal of clay-bound water. The results show that this small water content assists in mechanical compaction and grain sliding responsible for time-dependent deformation. We argue that the removal of clay-bound water at temperatures above 200 degrees C increases the frictional coefficient between clay particles and between clay particles and organic matter.",16,18,5
Organic Matter,Organic-rich Shale,"Liu, Guoheng; Zhai, Gangyi; Huang, Zhilong; Zou, Caineng; Xia, Xianghua; Shi, Dishi; Zhou, Zhi; Zhang, Cong; Chen, Rong; Yu, Shufang; Chen, Lei; Zhang, Shaohua",The effect of tuffaceous material on characteristics of different lithofacies: A case study on Lucaogou Formation fine-grained sedimentary rocks in Santanghu Basin,Lithofacies characteristics; Tuffaceous material alteration; Oil generation; Shale oil; Lucaogou formation,FORT-WORTH BASIN; MISSISSIPPIAN BARNETT SHALE; PERMIAN TIAOHU FORMATION; WUFENG-LONGMAXI FORMATIONS; SOUTHERN JUNGGAR BASIN; BOHAI BAY BASIN; SICHUAN BASIN; CHINA IMPLICATIONS; ORGANIC-MATTER; TIGHT OIL,"Three types of lithofacies, which are organic-rich massive tuffaceous shale lithofacies (RMTSL), organic-rich laminated and cloddy diamictite lithofacies (RLCDL) and organic-lean massive dolomite lithofacies (LMDL), developed in Lucaogou Formation in this research area. Qualitative descriptions and quantitative analyses were implemented to figure out the reasons why only RMTSL can be considered as potential reservoir from the perspective of unconventional oil and gas resources. RMTSL shows the least development degree of the cracks, and displays the largest content of organic matter, which is mainly in the range of 5% similar to 9%. Organic matter in RMSTL is mainly composed of solid organic matter rather than residual bitumen. The kerogen in RMSTL is chiefly Type I and Type II1 organic matter. Lamalginite is the major component for macerals in RMSTL, which means a better oil generation potential than the other two lithofacies. LMDL interbedded with RMTSL displays a better oil generation potential than thick LMDL. Tuffaceous materials is the key for oil accumulation in Lucaogou Formation fine-grained sediments. The porosity of RMTSL is the highest because of tuffaceous materials alteration. Phytoplankton flourished at the intermittent periods of volcanic eruption because material from volcanic eruptions caused natural iron fertilization. These flourishing phytoplankton would deposit with tuffaceous matter and become sedimentary organic matter. The LMDL contained terrestrial organic matter, which cannot generate as much acid and hydrocarbon as phytoplankton during thermal maturity. Moreover, LMDL contains much less tuffaceous material. All these reasons led to low porosity and oil generating potential for LMDL. For RLCDL, the micro cracks caused by organic matter evolution and tuffaceous material alteration make it difficult to be cemented together tightly, which stop RLCDL from preserving much hydrocarbon.",14,16,1
Organic Matter,Quartz,"Zhang, Miao; Fu, Xuehai; Zhang, Qinghui; Cheng, Weiping","Research on the organic geochemical and mineral composition properties and its influence on pore structure of coal-measure shales in Yushe-Wuxiang Block, South Central Qinshui Basin, China",Transitional coal-measure shale; Gas adsorption methods; Pore structure; Controlling factors; Qinshui Basin,NORTHEASTERN BRITISH-COLUMBIA; SILURIAN LONGMAXI FORMATION; LOWER PERMIAN SHANXI; SICHUAN BASIN; GAS-ADSORPTION; FRACTAL CHARACTERISTICS; PALEOENVIRONMENT INTERPRETATION; TRANSITIONAL SHALE; LACUSTRINE SHALE; YUNNAN PROVINCE,"This paper uses coal-measure shales from Carboniferous-Permian in Yushe-Wuxiang Block as an example to study the physical properties of transitional coal measure shales, including geochemical properties (e.g. total organic carbon content (TOG), organic matter maturity and hydrocarbon generation potential); mineral composition determined by X-ray diffraction (XRD) and pore structure characteristics determined by gas adsorption methods. The results indicated that the transitional coal measure shales in Yushe-Wuxiang area mostly comprise type III kerogen and are mostly in the over-mature stage, with shales in the range of 1.86%-3.36%R-o. The TOC of transitional shales varied significantly, ranging from 0.10% to 34.37%. Clay minerals and quartz are major minerals in transitional shales, while the predominant clay minerals are illite-smectite mixed clay (IS) and kaolinite. The total pore volume (TPV) and pore specific surface area (SSA) of investigated mud shales varies from 0.0071 to 0.023 cm(3)/g and 8.4059-18.2888 m(2)/g, respectively. The transitional shales mostly provide mesopores and macropores, whereas the micropores provide the main SSA. The TOC content has a distinct effect on the porosity and micropores volume but contributes little to the TPV and volumes of macropores and mesopores. Clay minerals are positively correlated with porosity, TPV and volumes of each class of pores, while quartz has an opposite effect. In the over-maturity stage, the increase of organic matter maturity will inhibit the development level of pores in shale. For the coal measure shales, I/S and illite contribute most to the pore development.",24,24,3
Organic Matter,Quartz,"Chen, Kefei; Liu, Xiaoping; Liu, Jie; Zhang, Chen; Guan, Ming; Zhou, Shixin","Lithofacies and pore characterization of continental shale in the second Member of the Kongdian Formation in the Cangdong Sag, Bohai Bay Basin, China",Continental shale; Lithofacies; Pore structure; Controlling factors,FORT-WORTH BASIN; MISSISSIPPIAN BARNETT SHALE; GAS-STORAGE; CARBON-DIOXIDE; SICHUAN BASIN; POROSITY; ADSORPTION; PETROLEUM; EXPULSION; MARCELLUS,"The shale of the second Member of the Kongdian Formation (Ek(2)) in the Cangdong Sag is continental shale with vitrinite reflectance values (%, R-o) ranging from 0.45% to 0.84%. This study adopted systematic microscopic observation and experimental analysis to examine lithofacies and pore structure of the Ek(2) shale. Four primary lithofacies are identified based on mineral compositions and sedimentary structures, namely laminated siliceous shale, laminated argillaceous shale, laminated mixed shale and laminated calcareous shale. Scanning electronic microscopy (SEM) images reveal that organic matter pores are less abundant than inorganic mineral pores. Inorganic mineral pores are mostly developed between rigid minerals, such as quartz, feldspar, calcite and dolomite. Organic matter pores are mainly presented in high mature shales and some are under protection of mutual support from mineral grains. Results of low temperature N-2 adsorption analysis show that micropores are less developed than mesopores and macropores. For shales with R-o ranging from 0.45% to 0.60%, pore volumes decrease with increased R-o; while for shales with It o ranging from 0.60% to 0.84%, pore volumes increase with increased R-o. Total organic carbon (TOC), analcime, plagioclase and calcite contents all have positive correlations with pore volumes for shales with R-o ranging from 0.60% to 0.84%, and dissolved pores make greater contribution to pore volume and permeability than organic matter pores in Ek(2) shale. The geochemical analysis results show that laminated argillaceous shale has highest average TOC content of 5.20%, followed by laminated siliceous shale of 3.94%, laminated mixed shale of 3.04% and laminated calcareous shale of 1.27%. Considering study above, it is inferred that laminated siliceous shale and laminated mixed shale with higher thermal maturity are favorable for petroleum exploration in Ek(2) shale.",18,18,1
Organic Matter,Quartz,"Xi, Zhaodong; Tang, Shuheng; Zhang, Songhang; Yi, Yongxiang; Dang, Feng; Ye, Yapei","Characterization of quartz in the Wufeng Formation in northwest Hunan Province, south China and its implications for reservoir quality",Authigenic quartz; Silica source; Marine shale; Reservoir; Diagenesis; Pore structure,CAMBRIAN NIUTITANG FORMATION; CONTINENTAL TRANSITIONAL SHALE; MISSISSIPPIAN BARNETT SHALE; MARINE SHALE; PORE STRUCTURE; SILICA DIAGENESIS; AUTHIGENIC QUARTZ; SICHUAN BASIN; YANGTZE PLATFORM; NORTHERN GUIZHOU,"Quartz is one of the most important and common minerals in marine shales. This is especially true for the Wufeng-Longmaxi and Niutitang Formations in south China. However, the type, origin and formation mechanism of the quartz in these marine shales are as yet unclear. Thirteen samples of Ordovician shale from the Wufeng Formation in northwest Hunan Province were collected for this study. The quartz within the Wufeng shale was characterized through a series of experiments employing scanning electron microscopy with cathodoluminescence, nitrogen physisorption, X-ray diffraction, and geochemical analysis. The results were then used to assess the implications of the quartz component for reservoir quality. Three quartz types were identified based on scanning electron microscopy and cathodoluminescence imaging. Type I quartz has a relatively large grain size and exhibits bright luminescence, indicative of a terrigenous origin, whereas Type II and Type III quartz is authigenic and has dull or no luminescence. Type II quartz has small grain sizes and may be mainly biogenic in origin. This type of quartz may have formed during early diagenesis, with the silica being sourced from the dissolution of siliceous organisms. Type III quartz generally appears as dark rims on Type I quartz grains; the silica may have been derived from clay mineral alteration, with quartz-formation occurring during middle or late diagenesis. The authigenic quartz (Types II and III quartz) likely formed as a cement and would be expected to generate brittle behavior. The shale with a high content of authigenic quartz has a high Young's modulus and low Poisson's ratio. The biogenic authigenic quartz (Type II quartz) was pore-filling and formed during shallow burial. It would thus have been able to resist further compaction and provide a rigid framework within which the primary pores in the shale could be preserved, controlling the distribution of organic matter and the development of organic pores. The biogenic authigenic quartz has positive relationships with porosity and pore volume and specific surface area. Shale that was high in biogenic quartz had high porosity and adsorption capacity. The characterization of quartz in marine shales has significance for shale gas exploration and development and provides a new angle for evaluating the fracability and storage capacity of shale gas reservoirs.",15,20,2
Organic Matter,High Temperature,"Zou, Jie; Rezaee, Reza; Xie, Quan; You, Lijun",Characterization of the combined effect of high temperature and moisture on methane adsorption in shale gas reservoirs,Methane adsorption capacity; Moisture; High temperature; Combined effect; Shale gas reservoirs,NORTHEASTERN BRITISH-COLUMBIA; ORGANIC-MATTER; GEOLOGICAL CONTROLS; PORE CHARACTERIZATION; MOLECULAR SIMULATION; CARBON-DIOXIDE; CLAY-MINERALS; CAPACITY; SORPTION; BASIN,"With a significant amount of methane stored in shales in the form of adsorbed gas, it is important to understand the controlling factors of the methane adsorption capacity. Under actual reservoir conditions, the high temperature and moisture are always coexisting which can affect gas adsorption capacity. This paper studied the methane adsorption of shale at different temperatures in dry and wet conditions. The adsorption results indicated that the moisture and high temperature can reduce the adsorbed gas content in shales individually, and the two factors have a synergistic-negative effect on methane adsorption in shales. Thermodynamic parameters showed that the heat of adsorption shows a decreased tendency and the entropy of adsorption becomes less negative after moisturizing the samples. The combined effect of the two factors is sufficiently important in the evaluation of gas adsorption capacity in shale gas systems.",21,23,4
Organic Matter,High Temperature,"Chen, Kefei; Liu, Xiaoping; Liu, Jie; Zhang, Chen; Guan, Ming; Zhou, Shixin","Lithofacies and pore characterization of continental shale in the second Member of the Kongdian Formation in the Cangdong Sag, Bohai Bay Basin, China",Continental shale; Lithofacies; Pore structure; Controlling factors,FORT-WORTH BASIN; MISSISSIPPIAN BARNETT SHALE; GAS-STORAGE; CARBON-DIOXIDE; SICHUAN BASIN; POROSITY; ADSORPTION; PETROLEUM; EXPULSION; MARCELLUS,"The shale of the second Member of the Kongdian Formation (Ek(2)) in the Cangdong Sag is continental shale with vitrinite reflectance values (%, R-o) ranging from 0.45% to 0.84%. This study adopted systematic microscopic observation and experimental analysis to examine lithofacies and pore structure of the Ek(2) shale. Four primary lithofacies are identified based on mineral compositions and sedimentary structures, namely laminated siliceous shale, laminated argillaceous shale, laminated mixed shale and laminated calcareous shale. Scanning electronic microscopy (SEM) images reveal that organic matter pores are less abundant than inorganic mineral pores. Inorganic mineral pores are mostly developed between rigid minerals, such as quartz, feldspar, calcite and dolomite. Organic matter pores are mainly presented in high mature shales and some are under protection of mutual support from mineral grains. Results of low temperature N-2 adsorption analysis show that micropores are less developed than mesopores and macropores. For shales with R-o ranging from 0.45% to 0.60%, pore volumes decrease with increased R-o; while for shales with It o ranging from 0.60% to 0.84%, pore volumes increase with increased R-o. Total organic carbon (TOC), analcime, plagioclase and calcite contents all have positive correlations with pore volumes for shales with R-o ranging from 0.60% to 0.84%, and dissolved pores make greater contribution to pore volume and permeability than organic matter pores in Ek(2) shale. The geochemical analysis results show that laminated argillaceous shale has highest average TOC content of 5.20%, followed by laminated siliceous shale of 3.94%, laminated mixed shale of 3.04% and laminated calcareous shale of 1.27%. Considering study above, it is inferred that laminated siliceous shale and laminated mixed shale with higher thermal maturity are favorable for petroleum exploration in Ek(2) shale.",18,18,1
Organic Matter,High Temperature,"Sharma, Prashant; Prakash, Ravi; Abedi, Sara",Effect of temperature on nano- and microscale creep properties of organic-rich shales,Organic-rich shales; Short-duration nanoindentation; Creep nanoindentation; Creep rate magnitude; Clay-bound water; High temperature,MECHANICAL-PROPERTIES; NANOINDENTATION; INDENTATION; MATTER; DEFORMATION; MINERALS; BEHAVIOR; HARDNESS; MODULUS; STATE,"Understanding the creep properties of gas shales at elevated temperatures is critical for accurately predicting reservoir performance and assessing the effect of viscous behavior on closure rate, production rate, and conductivity loss. In order to better understand creep properties at in-situ conditions, a quantitative relationship between temperature, mechanical properties, and complex chemo-physical mechanisms that cause thermal alteration needs to be obtained. In this study, the elastic, strength, and creep properties of organic-rich shales are investigated by a combination of nanoindentation, energy dispersive x-ray spectroscopy, and micromechanical modeling over a range of temperatures (23-350 degrees C). Within the allotted temperature range, the elastic and strength properties of the porous clay/kerogen phase remain unchanged. A similar behavior is noticed in the creep modulus from temperatures 23-200 degrees C where it remains relatively unchanged and shows an isotropic characteristic. However, the creep modulus of the clay phase increases at 300 degrees C in both parallel and perpendicular directions to the bedding plane. While the analysis of creep data at lower temperatures shed light on the dictating role of organic matter and porosity on creep properties of organic-rich shales (Slim et al., 2018), at high temperature (above 200 degrees C) creep properties are affected by removal of clay-bound water. The results show that this small water content assists in mechanical compaction and grain sliding responsible for time-dependent deformation. We argue that the removal of clay-bound water at temperatures above 200 degrees C increases the frictional coefficient between clay particles and between clay particles and organic matter.",16,18,5
Organic Matter,Flow,"Cui, Ronghao; Feng, Qihong; Chen, Hongwei; Zhang, Wei; Wang, Sen",Multiscale random pore network modeling of oil-water two-phase slip flow in shale matrix,Pore network model; Shale oil; Two-phase flow; Slip effect; Computational fluid dynamics,FRACTURED HORIZONTAL WELL; FAST MASS-TRANSPORT; POROUS-MEDIA; RELATIVE PERMEABILITY; DYNAMIC PROPERTIES; CO2 SEQUESTRATION; ORGANIC-MATTER; GAS-FLOW; NANOPORES; RESERVOIR,"The large-scale hydraulic fracturing technology is commonly employed to significantly improve oil recovery in shale. An exceptional phenomenon from many field tests is worthy of attention that the majority of fracturing fluid (mainly water) does not return to the surface during hydraulic fracturing, but flows into shale matrix. As a consequence of this phenomenon, oil-water two-phase flow would happen. However, the fluid transportation in nano-pores is different from that of the conventional sandstone reservoirs. To understand oil-water two-phase flow in shale, an integrated pore network model (PNM) framework including network construction and flow simulation is developed. In the network construction, combined with a pore-size distribution (PSD) curve of shale system, a shale multiscale random pore network model is proposed, where organic pores and inorganic pores can be distinguished appropriately. In the flow simulation, considering that the traditional Hagen-Poiseuille equation may not be applicable in shale system, new bulk fluid and corner film flow models with slip length in various geometric pores (circular, square, equilateral triangle) are developed using the computational fluid dynamic (CFD) method. Through the quasi-static simulation technique, we estimate the flow properties in shale including capillary pressure and relative permeability. Simulation results confirm the slip effect would significantly affect oil-water two-phase flow in shale. And then, influences of shale pore structure on two-phase flow are further investigated. Through coupling network construction and two-phase flow simulation, we believe our work could shed light on the further research for multi-phase transportation in shale.",23,24,9
Organic Matter,Flow,"Feng, Qihong; Xu, Shiqian; Wang, Sen; Li, Yuyao; Gao, Fangfang; Xu, Yajuan",Apparent permeability model for shale oil with multiple mechanisms,Shale oil; Apparent permeability; Natural fracture; Noncircular pore; Production prediction; Embedded discrete fracture model,PORE-SIZE DISTRIBUTION; FAST MASS-TRANSPORT; LIQUID PERMEABILITY; ORGANIC NANOPORES; POROUS-MEDIA; GAS-FLOW; NETWORK; SIMULATION; ROCK; ENHANCEMENT,"Accurate apparent permeability (AP) model for oil transport in shale must consider natural fractures and micro/nano-pores within organic matter and inorganic matrix. Furthermore, the effect of pore geometry, tortuosity, pore size distribution (PSD), the spatial distribution of different pores, total organic content (TOC), and liquid slip should also be taken into account. However, all of the aforementioned factors are not simultaneously considered in one AP model. In this work, we develop an AP model in 3D for shale oil to overcome this drawback. We first validate our model by comparing with the published data. Then sensitivity analysis for some parameters is investigated. After that, shale oil APs are used in a macro-scale reservoir simulation model. In this way, the effect of some micro-scale factors on production performance can be quantitatively evaluated. Notably, on the basis of embedded discrete fracture model (EDFM), our reservoir simulation model considers non-linear flow in shale matrix, complex hydraulic fracture geometry, and pressure-dependent permeability of hydraulic fractures. Results show that natural fractures contribute the most to AP, followed by organic pores and inorganic pores. In general, the AP in the horizontal direction is approximately twice that in the vertical direction in shale. Furthermore, the maximum error caused by the pore type on shale oil production is similar to 31%, followed by tortuosity (similar to 25%), pore shape (similar to 13%) and slip effect (similar to 4.8%). In conclusion, it is necessary to simultaneously incorporate the influences of the aforementioned factors. Our stochastic permeability model can serve as an efficient tool to determine shale oil AP.",17,19,3
Organic Matter,Flow,"Josh, Matthew; Delle Piane, Claudio; Esteban, Lionel; Bourdet, Julien; Mayo, Sherry; Pejcic, Bobby; Burgar, Iko; Luzin, Vladimir; Clennell, Michael B.; Dewhurst, David N.","Advanced laboratory techniques characterising solids, fluids and pores in shales",Shale; Organic; Petrophysics; Geomechanics; Laboratory,DISPERSED ORGANIC-MATTER; WUFENG-LONGMAXI SHALE; X-RAY MICROTOMOGRAPHY; RAMAN-SPECTROSCOPY; THERMAL MATURITY; PREFERRED ORIENTATION; CARBONACEOUS MATERIAL; ELASTIC-ANISOTROPY; SICHUAN BASIN; PETROPHYSICAL CHARACTERIZATION,"Shales are of significant interest as reservoirs, seals and overburden in petroleum exploration and production, geological storage of CO2 and in the nuclear waste industry. Their properties and microstructure are difficult to measure and image and as such, there are still considerable gaps in our understanding of shale behaviour. The advent of more advanced and quantitative imaging methods along with novel sample preparation techniques including synchrotron imaging and K-edge subtraction with a contrast fluid, scanning (SEM) and transmission electron microscopy (TEM), have combined to allow the resolution of pores in the matrix and the organic matter in gas shales down to the nanometre scale. Textural quantification methods include neutron diffraction to quantify clay fabric alignment in siliciclastic shales as well as stress-dependent calcite c-axis orientation in carbonate-rich gas shales. The contents of the pores are also critical to the assessment of the preservation state of shales as well as the degree of water/gas saturation in resource shales. Combinations of dielectric analysis and 2 and 23 MHz nuclear magnetic resonance (NMR) measurements in siliciclastic and carbonate-rich gas shales can resolve not only the location of water, but also the interaction between water and mineral/organic surfaces in addition to the water and oil content. The organic content of shales is of particular interest in unconventional resources and this has driven application of Fourier transform infra-red (FTIR), to distinguish both mineral and organic maceral components in gas shales and Raman spectroscopy, which is increasingly used for organic matter characterisation in high maturity shales. Ultimately, shales are extremely complex nano-composite materials which require the application of multiple techniques to help determine their bulk physical and flow properties as well as factors controlling fabric and pore orientations and structure.",14,14,3
Organic Matter,Pore-size Distribution,"Cui, Ronghao; Feng, Qihong; Chen, Hongwei; Zhang, Wei; Wang, Sen",Multiscale random pore network modeling of oil-water two-phase slip flow in shale matrix,Pore network model; Shale oil; Two-phase flow; Slip effect; Computational fluid dynamics,FRACTURED HORIZONTAL WELL; FAST MASS-TRANSPORT; POROUS-MEDIA; RELATIVE PERMEABILITY; DYNAMIC PROPERTIES; CO2 SEQUESTRATION; ORGANIC-MATTER; GAS-FLOW; NANOPORES; RESERVOIR,"The large-scale hydraulic fracturing technology is commonly employed to significantly improve oil recovery in shale. An exceptional phenomenon from many field tests is worthy of attention that the majority of fracturing fluid (mainly water) does not return to the surface during hydraulic fracturing, but flows into shale matrix. As a consequence of this phenomenon, oil-water two-phase flow would happen. However, the fluid transportation in nano-pores is different from that of the conventional sandstone reservoirs. To understand oil-water two-phase flow in shale, an integrated pore network model (PNM) framework including network construction and flow simulation is developed. In the network construction, combined with a pore-size distribution (PSD) curve of shale system, a shale multiscale random pore network model is proposed, where organic pores and inorganic pores can be distinguished appropriately. In the flow simulation, considering that the traditional Hagen-Poiseuille equation may not be applicable in shale system, new bulk fluid and corner film flow models with slip length in various geometric pores (circular, square, equilateral triangle) are developed using the computational fluid dynamic (CFD) method. Through the quasi-static simulation technique, we estimate the flow properties in shale including capillary pressure and relative permeability. Simulation results confirm the slip effect would significantly affect oil-water two-phase flow in shale. And then, influences of shale pore structure on two-phase flow are further investigated. Through coupling network construction and two-phase flow simulation, we believe our work could shed light on the further research for multi-phase transportation in shale.",23,24,9
Organic Matter,Pore-size Distribution,"Feng, Qihong; Xu, Shiqian; Wang, Sen; Li, Yuyao; Gao, Fangfang; Xu, Yajuan",Apparent permeability model for shale oil with multiple mechanisms,Shale oil; Apparent permeability; Natural fracture; Noncircular pore; Production prediction; Embedded discrete fracture model,PORE-SIZE DISTRIBUTION; FAST MASS-TRANSPORT; LIQUID PERMEABILITY; ORGANIC NANOPORES; POROUS-MEDIA; GAS-FLOW; NETWORK; SIMULATION; ROCK; ENHANCEMENT,"Accurate apparent permeability (AP) model for oil transport in shale must consider natural fractures and micro/nano-pores within organic matter and inorganic matrix. Furthermore, the effect of pore geometry, tortuosity, pore size distribution (PSD), the spatial distribution of different pores, total organic content (TOC), and liquid slip should also be taken into account. However, all of the aforementioned factors are not simultaneously considered in one AP model. In this work, we develop an AP model in 3D for shale oil to overcome this drawback. We first validate our model by comparing with the published data. Then sensitivity analysis for some parameters is investigated. After that, shale oil APs are used in a macro-scale reservoir simulation model. In this way, the effect of some micro-scale factors on production performance can be quantitatively evaluated. Notably, on the basis of embedded discrete fracture model (EDFM), our reservoir simulation model considers non-linear flow in shale matrix, complex hydraulic fracture geometry, and pressure-dependent permeability of hydraulic fractures. Results show that natural fractures contribute the most to AP, followed by organic pores and inorganic pores. In general, the AP in the horizontal direction is approximately twice that in the vertical direction in shale. Furthermore, the maximum error caused by the pore type on shale oil production is similar to 31%, followed by tortuosity (similar to 25%), pore shape (similar to 13%) and slip effect (similar to 4.8%). In conclusion, it is necessary to simultaneously incorporate the influences of the aforementioned factors. Our stochastic permeability model can serve as an efficient tool to determine shale oil AP.",17,19,3
Organic Matter,Pore-size Distribution,"Guo, Shaobin; Mao, Wenjing","Division of diagenesis and pore evolution of a Permian Shanxi shale in the Ordos Basin, China",Shale; Pore evolution; Diagenesis; Hydrocarbon production,MATURE POSIDONIA SHALE; ORGANIC-RICH SHALES; GAS-STORAGE; TRANSITIONAL SHALES; BIB-SEM; SIZE DISTRIBUTIONS; SPACE MORPHOLOGY; SURFACE-AREA; HILS AREA; SANDSTONES,"This research analyzed the pore evolution and diagenesis in a Permian Shanxi shale from the Ordos Basin. Thermal simulation method simulated the thermal evolution of organic matter in a sample from mature (R-o = 0.96%) to overmature (R-o = 3.05%). Gas adsorption and mercury intrusion capillary pressure techniques were used to analyze pore-size distribution across a maturation gradient. X-ray diffraction, Focused Ion Beam-Scanning Electron Microscopy and rock pyrolysis techniques were used to divide the stages of diagenesis and pore evolution. Results showed that mesopores and macropores dominate pore volume while micropores and mesopores dominate surface area. Pore volume and surface area initially decreased and then increased with maturity. Kaolinite is converted to illite and illite-smectite mixedlayer in the middle to late diagenesis stage. Pore evolution and diagenesis can be divided into four stages in a sample from mature to overmature. Factors influencing pore-size distribution are different in four stages.",17,17,3
Organic Matter,Materials,"Kong, Lingyun; Ostadhassan, Mehdi; Hou, Xiaodong; Mann, Michael; Li, Chunxiao",Microstructure characteristics and fractal analysis of 3D-printed sandstone using micro-CT and SEM-EDS,3D-printed rocks; Microstructures; Sandstone; Micro-computed tomography,RAY COMPUTED-TOMOGRAPHY; MECHANICAL-PROPERTIES; RESERVOIR ROCKS; ORGANIC-MATTER; PORE STRUCTURE; PERMEABILITY; PARTICLES; ALGORITHM; VOLUME; BASIN,"Replicating sedimentary rocks using three-dimensional (3D) printing can support routine reservoir rock analysis in petrophysical and geomechanical experiments, which is done limited in scope due to lack of suitable printing materials and achievable resolution. Following our previous studies on gypsum powder with binder, a new printing material, silica sand, is used and characterized in this study to demonstrate the microstructure and its similarity to Berea Sandstone. Binder jetting printing system was specifically utilized to bond silica sand particles to create intact cylindrical samples without digital porous model as input. Created samples were first scanned by Backscattered Scanning Electron Microscope (BS-SEM) and Energy Dispersive Spectroscopy (EDS) to identify the particles, the packing mode and cement (binder). Next, micro-computed tomography (CT) was used to determine the microstructure of the samples, including the size and the shape of both particles and pores, in the 3D space. In addition, anisotropy that was found to originate from the pore structures was quantified by comparing the characteristics of pores in different directions. Fractal dimensions from different sample sizes, 6 mm and 12 mm in diameter, were also calculated for pore structure analysis in order to illustrate the effect of sample size on pore heterogeneity in 3D printed samples with silica. The results demonstrated the feasibility of substituting 3D-printed sandstones for natural rocks regarding pore structures for experimental validation of petrophysical models.",24,26,10
Organic Matter,Materials,"Josh, Matthew; Delle Piane, Claudio; Esteban, Lionel; Bourdet, Julien; Mayo, Sherry; Pejcic, Bobby; Burgar, Iko; Luzin, Vladimir; Clennell, Michael B.; Dewhurst, David N.","Advanced laboratory techniques characterising solids, fluids and pores in shales",Shale; Organic; Petrophysics; Geomechanics; Laboratory,DISPERSED ORGANIC-MATTER; WUFENG-LONGMAXI SHALE; X-RAY MICROTOMOGRAPHY; RAMAN-SPECTROSCOPY; THERMAL MATURITY; PREFERRED ORIENTATION; CARBONACEOUS MATERIAL; ELASTIC-ANISOTROPY; SICHUAN BASIN; PETROPHYSICAL CHARACTERIZATION,"Shales are of significant interest as reservoirs, seals and overburden in petroleum exploration and production, geological storage of CO2 and in the nuclear waste industry. Their properties and microstructure are difficult to measure and image and as such, there are still considerable gaps in our understanding of shale behaviour. The advent of more advanced and quantitative imaging methods along with novel sample preparation techniques including synchrotron imaging and K-edge subtraction with a contrast fluid, scanning (SEM) and transmission electron microscopy (TEM), have combined to allow the resolution of pores in the matrix and the organic matter in gas shales down to the nanometre scale. Textural quantification methods include neutron diffraction to quantify clay fabric alignment in siliciclastic shales as well as stress-dependent calcite c-axis orientation in carbonate-rich gas shales. The contents of the pores are also critical to the assessment of the preservation state of shales as well as the degree of water/gas saturation in resource shales. Combinations of dielectric analysis and 2 and 23 MHz nuclear magnetic resonance (NMR) measurements in siliciclastic and carbonate-rich gas shales can resolve not only the location of water, but also the interaction between water and mineral/organic surfaces in addition to the water and oil content. The organic content of shales is of particular interest in unconventional resources and this has driven application of Fourier transform infra-red (FTIR), to distinguish both mineral and organic maceral components in gas shales and Raman spectroscopy, which is increasingly used for organic matter characterisation in high maturity shales. Ultimately, shales are extremely complex nano-composite materials which require the application of multiple techniques to help determine their bulk physical and flow properties as well as factors controlling fabric and pore orientations and structure.",14,14,3
Organic Matter,Materials,"Liu, Guoheng; Zhai, Gangyi; Huang, Zhilong; Zou, Caineng; Xia, Xianghua; Shi, Dishi; Zhou, Zhi; Zhang, Cong; Chen, Rong; Yu, Shufang; Chen, Lei; Zhang, Shaohua",The effect of tuffaceous material on characteristics of different lithofacies: A case study on Lucaogou Formation fine-grained sedimentary rocks in Santanghu Basin,Lithofacies characteristics; Tuffaceous material alteration; Oil generation; Shale oil; Lucaogou formation,FORT-WORTH BASIN; MISSISSIPPIAN BARNETT SHALE; PERMIAN TIAOHU FORMATION; WUFENG-LONGMAXI FORMATIONS; SOUTHERN JUNGGAR BASIN; BOHAI BAY BASIN; SICHUAN BASIN; CHINA IMPLICATIONS; ORGANIC-MATTER; TIGHT OIL,"Three types of lithofacies, which are organic-rich massive tuffaceous shale lithofacies (RMTSL), organic-rich laminated and cloddy diamictite lithofacies (RLCDL) and organic-lean massive dolomite lithofacies (LMDL), developed in Lucaogou Formation in this research area. Qualitative descriptions and quantitative analyses were implemented to figure out the reasons why only RMTSL can be considered as potential reservoir from the perspective of unconventional oil and gas resources. RMTSL shows the least development degree of the cracks, and displays the largest content of organic matter, which is mainly in the range of 5% similar to 9%. Organic matter in RMSTL is mainly composed of solid organic matter rather than residual bitumen. The kerogen in RMSTL is chiefly Type I and Type II1 organic matter. Lamalginite is the major component for macerals in RMSTL, which means a better oil generation potential than the other two lithofacies. LMDL interbedded with RMTSL displays a better oil generation potential than thick LMDL. Tuffaceous materials is the key for oil accumulation in Lucaogou Formation fine-grained sediments. The porosity of RMTSL is the highest because of tuffaceous materials alteration. Phytoplankton flourished at the intermittent periods of volcanic eruption because material from volcanic eruptions caused natural iron fertilization. These flourishing phytoplankton would deposit with tuffaceous matter and become sedimentary organic matter. The LMDL contained terrestrial organic matter, which cannot generate as much acid and hydrocarbon as phytoplankton during thermal maturity. Moreover, LMDL contains much less tuffaceous material. All these reasons led to low porosity and oil generating potential for LMDL. For RLCDL, the micro cracks caused by organic matter evolution and tuffaceous material alteration make it difficult to be cemented together tightly, which stop RLCDL from preserving much hydrocarbon.",14,16,1
Organic Matter,N-2 Adsorption,"Zhao, Peiqiang; Wang, Xixin; Cai, Jianchao; Luo, Miao; Zhang, Jin; Liu, Yuming; Rabiei, Minou; Li, Chuncheng",Multifractal analysis of pore structure of Middle Bakken formation using low temperature N-2 adsorption and NMR measurements,Middle Bakken; Multifractal analysis; N-2 adsorption; Nuclear magnetic resonance (NMR),NUCLEAR-MAGNETIC-RESONANCE; RATE-CONTROLLED POROSIMETRY; FORD SHALE SAMPLES; SICHUAN BASIN; GAS-RESERVOIR; FRACTAL CHARACTERIZATION; ORGANIC-MATTER; OIL; SANDSTONE; DIMENSION,"Understanding the complexity and heterogeneity of pore structure can improve the comprehensive characterization for complex unconventional reservoirs and better exploit those resources. In this paper, multifractal analysis was conducted on low temperature N-2 adsorption and NMR T-2 distribution for the pore structure investigation in Middle Bakken formation in Williston Basin, USA. Results show that the averages of specific surface area, total pore volume, the average pore size of five N-2 adsorption samples are 3.31 m(2)/g, 0.008 cm(3)/g, and 19.57 nm, respectively. Six NMR T(2 )distributions are bimodal and the signals of left dominant peaks are mainly distributed between 0.3 ms and 10 ms. The T-2 logarithmic mean value ranges from 2.18 ms to 2.95 ms with an average value of 2.57 ms. Both N-2 adsorption isotherms and T-2 distribution demonstrated the multifractal nature of different pore sizes. The key multifractal parameter, singularity strength range (Aa) calculated from N-2 adsorption and T-2 distribution are respectively distributed in scopes of 0.72-1.54 and 1.63-2.89, indicating that the heterogeneity of pore space from T-2 distribution is stronger than that from N-2 adsorption. It was observed that the specific surface, micro pore volume, and average pore size are correlated well with Delta alpha. There are no any correlations between Delta alpha and porosity and T-21m, but the cumulative porosity and width of right secondary peaks have an impact on the Delta alpha, which means that the heterogeneity difference between the two methods is attributed by larger pore and micro fractures.",27,27,7
Organic Matter,N-2 Adsorption,"Chen, Kefei; Liu, Xiaoping; Liu, Jie; Zhang, Chen; Guan, Ming; Zhou, Shixin","Lithofacies and pore characterization of continental shale in the second Member of the Kongdian Formation in the Cangdong Sag, Bohai Bay Basin, China",Continental shale; Lithofacies; Pore structure; Controlling factors,FORT-WORTH BASIN; MISSISSIPPIAN BARNETT SHALE; GAS-STORAGE; CARBON-DIOXIDE; SICHUAN BASIN; POROSITY; ADSORPTION; PETROLEUM; EXPULSION; MARCELLUS,"The shale of the second Member of the Kongdian Formation (Ek(2)) in the Cangdong Sag is continental shale with vitrinite reflectance values (%, R-o) ranging from 0.45% to 0.84%. This study adopted systematic microscopic observation and experimental analysis to examine lithofacies and pore structure of the Ek(2) shale. Four primary lithofacies are identified based on mineral compositions and sedimentary structures, namely laminated siliceous shale, laminated argillaceous shale, laminated mixed shale and laminated calcareous shale. Scanning electronic microscopy (SEM) images reveal that organic matter pores are less abundant than inorganic mineral pores. Inorganic mineral pores are mostly developed between rigid minerals, such as quartz, feldspar, calcite and dolomite. Organic matter pores are mainly presented in high mature shales and some are under protection of mutual support from mineral grains. Results of low temperature N-2 adsorption analysis show that micropores are less developed than mesopores and macropores. For shales with R-o ranging from 0.45% to 0.60%, pore volumes decrease with increased R-o; while for shales with It o ranging from 0.60% to 0.84%, pore volumes increase with increased R-o. Total organic carbon (TOC), analcime, plagioclase and calcite contents all have positive correlations with pore volumes for shales with R-o ranging from 0.60% to 0.84%, and dissolved pores make greater contribution to pore volume and permeability than organic matter pores in Ek(2) shale. The geochemical analysis results show that laminated argillaceous shale has highest average TOC content of 5.20%, followed by laminated siliceous shale of 3.94%, laminated mixed shale of 3.04% and laminated calcareous shale of 1.27%. Considering study above, it is inferred that laminated siliceous shale and laminated mixed shale with higher thermal maturity are favorable for petroleum exploration in Ek(2) shale.",18,18,1
Organic Matter,Lucaogou Formation,"Ding, Xiujian; Qu, Jiangxiu; Imin, Ablimit; Zha, Ming; Su, Yang; Jiang, Zhongfa; Jiang, Hang","Organic matter origin and accumulation in tuffaceous shale of the lower Permian Lucaogou Formation, Jimsar Sag",Tuffaceous shale; Volcanic ash; Organic matter origin; Organic matter accumulation; Lucaogou formation,TIGHT OIL ACCUMULATION; GREEN RIVER FORMATION; SOURCE-ROCK; JUNGGAR BASIN; JIMUSAR SAG; DEPOSITIONAL ENVIRONMENT; TUFF RESERVOIR; VOLCANIC ASH; CRUDE OILS; PRESERVATION,"The Jimsar Sag is an important shale oil exploration target area in the Junggar Basin, northwestern China. The lower Permian Lucaogou Formation, with a thickness of 200-300 m, is composed of thin tuffite, tuffaceous dolomite, mudstone and siltstone, and is the primary exploration target. A comprehensive analysis is conducted on the bulk and molecular geochemical characteristics of the tuffaceous shale, to define the organic matter origin, depositional environment and organic matter accumulation. The key features of the tuffaceous shale extracts are short-to long-chain n-alkanes, a range of Pr/Ph ratio values (0.80-1.42), a relatively high content of C-29 steranes and a moderate content of gammacerane, showing that the redox state ranged from oxic to anoxic and that the water salinity conditions varied from fresh to brackish. And the high content of cyanobacteria is the primary cause of the high abundance of beta-carotane and C-29 sterane. It appears that volcanic ash did not change the redox condition of depositional environment. Considering that volcanic ash-bearing sediments usually have relatively high beta-carotane and C-29 sterane content, and previous studies have pointed out that volcanic ash can stimulate phytoplankton and promote productivity in modern sediments, we could speculated volcanic ash may release mineral ions such as iron, and then stimulated cyanobacteria, which was the main cause of organic matter accumulation in the tuffaceous shale of the Jimsar Sag.",25,26,2
Organic Matter,Lucaogou Formation,"Liu, Guoheng; Zhai, Gangyi; Huang, Zhilong; Zou, Caineng; Xia, Xianghua; Shi, Dishi; Zhou, Zhi; Zhang, Cong; Chen, Rong; Yu, Shufang; Chen, Lei; Zhang, Shaohua",The effect of tuffaceous material on characteristics of different lithofacies: A case study on Lucaogou Formation fine-grained sedimentary rocks in Santanghu Basin,Lithofacies characteristics; Tuffaceous material alteration; Oil generation; Shale oil; Lucaogou formation,FORT-WORTH BASIN; MISSISSIPPIAN BARNETT SHALE; PERMIAN TIAOHU FORMATION; WUFENG-LONGMAXI FORMATIONS; SOUTHERN JUNGGAR BASIN; BOHAI BAY BASIN; SICHUAN BASIN; CHINA IMPLICATIONS; ORGANIC-MATTER; TIGHT OIL,"Three types of lithofacies, which are organic-rich massive tuffaceous shale lithofacies (RMTSL), organic-rich laminated and cloddy diamictite lithofacies (RLCDL) and organic-lean massive dolomite lithofacies (LMDL), developed in Lucaogou Formation in this research area. Qualitative descriptions and quantitative analyses were implemented to figure out the reasons why only RMTSL can be considered as potential reservoir from the perspective of unconventional oil and gas resources. RMTSL shows the least development degree of the cracks, and displays the largest content of organic matter, which is mainly in the range of 5% similar to 9%. Organic matter in RMSTL is mainly composed of solid organic matter rather than residual bitumen. The kerogen in RMSTL is chiefly Type I and Type II1 organic matter. Lamalginite is the major component for macerals in RMSTL, which means a better oil generation potential than the other two lithofacies. LMDL interbedded with RMTSL displays a better oil generation potential than thick LMDL. Tuffaceous materials is the key for oil accumulation in Lucaogou Formation fine-grained sediments. The porosity of RMTSL is the highest because of tuffaceous materials alteration. Phytoplankton flourished at the intermittent periods of volcanic eruption because material from volcanic eruptions caused natural iron fertilization. These flourishing phytoplankton would deposit with tuffaceous matter and become sedimentary organic matter. The LMDL contained terrestrial organic matter, which cannot generate as much acid and hydrocarbon as phytoplankton during thermal maturity. Moreover, LMDL contains much less tuffaceous material. All these reasons led to low porosity and oil generating potential for LMDL. For RLCDL, the micro cracks caused by organic matter evolution and tuffaceous material alteration make it difficult to be cemented together tightly, which stop RLCDL from preserving much hydrocarbon.",14,16,1
Organic Matter,Sources,"Xi, Zhaodong; Tang, Shuheng; Zhang, Songhang; Yi, Yongxiang; Dang, Feng; Ye, Yapei","Characterization of quartz in the Wufeng Formation in northwest Hunan Province, south China and its implications for reservoir quality",Authigenic quartz; Silica source; Marine shale; Reservoir; Diagenesis; Pore structure,CAMBRIAN NIUTITANG FORMATION; CONTINENTAL TRANSITIONAL SHALE; MISSISSIPPIAN BARNETT SHALE; MARINE SHALE; PORE STRUCTURE; SILICA DIAGENESIS; AUTHIGENIC QUARTZ; SICHUAN BASIN; YANGTZE PLATFORM; NORTHERN GUIZHOU,"Quartz is one of the most important and common minerals in marine shales. This is especially true for the Wufeng-Longmaxi and Niutitang Formations in south China. However, the type, origin and formation mechanism of the quartz in these marine shales are as yet unclear. Thirteen samples of Ordovician shale from the Wufeng Formation in northwest Hunan Province were collected for this study. The quartz within the Wufeng shale was characterized through a series of experiments employing scanning electron microscopy with cathodoluminescence, nitrogen physisorption, X-ray diffraction, and geochemical analysis. The results were then used to assess the implications of the quartz component for reservoir quality. Three quartz types were identified based on scanning electron microscopy and cathodoluminescence imaging. Type I quartz has a relatively large grain size and exhibits bright luminescence, indicative of a terrigenous origin, whereas Type II and Type III quartz is authigenic and has dull or no luminescence. Type II quartz has small grain sizes and may be mainly biogenic in origin. This type of quartz may have formed during early diagenesis, with the silica being sourced from the dissolution of siliceous organisms. Type III quartz generally appears as dark rims on Type I quartz grains; the silica may have been derived from clay mineral alteration, with quartz-formation occurring during middle or late diagenesis. The authigenic quartz (Types II and III quartz) likely formed as a cement and would be expected to generate brittle behavior. The shale with a high content of authigenic quartz has a high Young's modulus and low Poisson's ratio. The biogenic authigenic quartz (Type II quartz) was pore-filling and formed during shallow burial. It would thus have been able to resist further compaction and provide a rigid framework within which the primary pores in the shale could be preserved, controlling the distribution of organic matter and the development of organic pores. The biogenic authigenic quartz has positive relationships with porosity and pore volume and specific surface area. Shale that was high in biogenic quartz had high porosity and adsorption capacity. The characterization of quartz in marine shales has significance for shale gas exploration and development and provides a new angle for evaluating the fracability and storage capacity of shale gas reservoirs.",15,20,2
Organic Matter,Sources,"Xiao, Hong; Wang, T. -G.; Li, Meijun; Lai, Hongfei; Liu, Jiguo; Mao, Fengjun; Tang, Youjun","Geochemical characteristics of Cretaceous Yogou Formation source rocks and oil-source correlation within a sequence stratigraphic framework in the Termit Basin, Niger",Source rock; Oil-source correlation; Sequence stratigraphic framework; Yogou Formation; Termit basin,MARINE SOURCE ROCKS; CRUDE OILS; DEPOSITIONAL ENVIRONMENT; ORGANIC FACIES; TARIM BASIN; TETRACYCLIC TERPANES; MATURITY PARAMETERS; RIFT BASINS; PETROLEUM; CHINA,"This study investigated the geochemical characteristics of source rocks in each sequence and studied on the oil-source correlation under a sequence stratigraphic framework of the Upper Cretaceous Yogou Formation. The Yogou Formation as the most primary and productive source bed in the Termit Basin (Niger), was further divided into three third-order sequences (i.e. YSQ1, YSQ2 and YSQ3, from bottom to top) in the study. On the basis of the geochemical analysis of a total of 35 rock samples from YSQ3, YSQ2 and YSQ1, the variation of the organic matter abundances, types and maturity of source rocks within different sequences were compared. The TOC content of YSQ2 and YSQ1 source rocks ranges from 0.76% to 1.69% with mature to high mature thermal evaluation stage (R-o: 0.63%-1.29%), while the TOC content of YSQ3 source rocks is much higher (1.11%-6.63%) with a relatively lower maturation levels (R-o: 0.59%-0.91%). All source rocks are dominated by Type II2-III kerogen. Moreover, in order to determine the oil-source correlation under a sequence stratigraphic framework, the composition of biomarkers in 35 source rocks and 25 crude oils were analyzed systematically. Various non-biomarker and biomarker parameters were applied involving source-related, maturity-related and environment-related parameters. The YSQ3 source rocks are typically characterized by relatively higher Pr/Ph ratio, higher concentration of dibenzofurans (DBFs) and lower gammacerane index indicating a suboxic transitional environment, and the relatively higher values of oleanane index and C24TeT/(C24TeT + C26TT) ratio reflecting a significant terrigenous organic matter input. Conversely, the YSQ2, YSQ1 source rocks and studied oils have relatively lower Pr/Ph ratios, higher content of gammacerane and dibenzothiophenes (DBTs) suggesting suboxic to anoxic conditions under shallow marine depositional environment, and low values of oleanane index and C24TeT/(C24TeT + C26TT) ratios indicating predominant algal aquatic organisms input. In addition, other molecular parameters in crude oils, including OEP, CPI, TAR, nC(21)-/nC(22) +, (nC(21) + nC(22))/(nC(28) + nC(29)), Pr/nC(17), Ph/nC(18) ratios and the distribution patterns and relevant parameters of tricyclic terpane series, also have the obviously similar characteristics to YSQ2 and YSQ1 source rocks, rather than YSQ3 source rocks. The result of oil-source correlation shows that the discovered oils are dominantly derived from YSQ2 and YSQ1 source rocks, with minor contribution of YSQ3 source rocks. Therefore, the oil-source correlation within a sequence stratigraphic framework can provide a practical model for source rock assessment and petroleum system study.",14,15,3
Organic Matter,"Hydraulic Fractures,Network Model","Cui, Ronghao; Feng, Qihong; Chen, Hongwei; Zhang, Wei; Wang, Sen",Multiscale random pore network modeling of oil-water two-phase slip flow in shale matrix,Pore network model; Shale oil; Two-phase flow; Slip effect; Computational fluid dynamics,FRACTURED HORIZONTAL WELL; FAST MASS-TRANSPORT; POROUS-MEDIA; RELATIVE PERMEABILITY; DYNAMIC PROPERTIES; CO2 SEQUESTRATION; ORGANIC-MATTER; GAS-FLOW; NANOPORES; RESERVOIR,"The large-scale hydraulic fracturing technology is commonly employed to significantly improve oil recovery in shale. An exceptional phenomenon from many field tests is worthy of attention that the majority of fracturing fluid (mainly water) does not return to the surface during hydraulic fracturing, but flows into shale matrix. As a consequence of this phenomenon, oil-water two-phase flow would happen. However, the fluid transportation in nano-pores is different from that of the conventional sandstone reservoirs. To understand oil-water two-phase flow in shale, an integrated pore network model (PNM) framework including network construction and flow simulation is developed. In the network construction, combined with a pore-size distribution (PSD) curve of shale system, a shale multiscale random pore network model is proposed, where organic pores and inorganic pores can be distinguished appropriately. In the flow simulation, considering that the traditional Hagen-Poiseuille equation may not be applicable in shale system, new bulk fluid and corner film flow models with slip length in various geometric pores (circular, square, equilateral triangle) are developed using the computational fluid dynamic (CFD) method. Through the quasi-static simulation technique, we estimate the flow properties in shale including capillary pressure and relative permeability. Simulation results confirm the slip effect would significantly affect oil-water two-phase flow in shale. And then, influences of shale pore structure on two-phase flow are further investigated. Through coupling network construction and two-phase flow simulation, we believe our work could shed light on the further research for multi-phase transportation in shale.",23,24,9
Organic Matter,"Hydraulic Fractures,Network Model","Feng, Qihong; Xu, Shiqian; Wang, Sen; Li, Yuyao; Gao, Fangfang; Xu, Yajuan",Apparent permeability model for shale oil with multiple mechanisms,Shale oil; Apparent permeability; Natural fracture; Noncircular pore; Production prediction; Embedded discrete fracture model,PORE-SIZE DISTRIBUTION; FAST MASS-TRANSPORT; LIQUID PERMEABILITY; ORGANIC NANOPORES; POROUS-MEDIA; GAS-FLOW; NETWORK; SIMULATION; ROCK; ENHANCEMENT,"Accurate apparent permeability (AP) model for oil transport in shale must consider natural fractures and micro/nano-pores within organic matter and inorganic matrix. Furthermore, the effect of pore geometry, tortuosity, pore size distribution (PSD), the spatial distribution of different pores, total organic content (TOC), and liquid slip should also be taken into account. However, all of the aforementioned factors are not simultaneously considered in one AP model. In this work, we develop an AP model in 3D for shale oil to overcome this drawback. We first validate our model by comparing with the published data. Then sensitivity analysis for some parameters is investigated. After that, shale oil APs are used in a macro-scale reservoir simulation model. In this way, the effect of some micro-scale factors on production performance can be quantitatively evaluated. Notably, on the basis of embedded discrete fracture model (EDFM), our reservoir simulation model considers non-linear flow in shale matrix, complex hydraulic fracture geometry, and pressure-dependent permeability of hydraulic fractures. Results show that natural fractures contribute the most to AP, followed by organic pores and inorganic pores. In general, the AP in the horizontal direction is approximately twice that in the vertical direction in shale. Furthermore, the maximum error caused by the pore type on shale oil production is similar to 31%, followed by tortuosity (similar to 25%), pore shape (similar to 13%) and slip effect (similar to 4.8%). In conclusion, it is necessary to simultaneously incorporate the influences of the aforementioned factors. Our stochastic permeability model can serve as an efficient tool to determine shale oil AP.",17,19,3
Organic Matter,Nuclear Magnetic Resonance,"Zhao, Peiqiang; Wang, Xixin; Cai, Jianchao; Luo, Miao; Zhang, Jin; Liu, Yuming; Rabiei, Minou; Li, Chuncheng",Multifractal analysis of pore structure of Middle Bakken formation using low temperature N-2 adsorption and NMR measurements,Middle Bakken; Multifractal analysis; N-2 adsorption; Nuclear magnetic resonance (NMR),NUCLEAR-MAGNETIC-RESONANCE; RATE-CONTROLLED POROSIMETRY; FORD SHALE SAMPLES; SICHUAN BASIN; GAS-RESERVOIR; FRACTAL CHARACTERIZATION; ORGANIC-MATTER; OIL; SANDSTONE; DIMENSION,"Understanding the complexity and heterogeneity of pore structure can improve the comprehensive characterization for complex unconventional reservoirs and better exploit those resources. In this paper, multifractal analysis was conducted on low temperature N-2 adsorption and NMR T-2 distribution for the pore structure investigation in Middle Bakken formation in Williston Basin, USA. Results show that the averages of specific surface area, total pore volume, the average pore size of five N-2 adsorption samples are 3.31 m(2)/g, 0.008 cm(3)/g, and 19.57 nm, respectively. Six NMR T(2 )distributions are bimodal and the signals of left dominant peaks are mainly distributed between 0.3 ms and 10 ms. The T-2 logarithmic mean value ranges from 2.18 ms to 2.95 ms with an average value of 2.57 ms. Both N-2 adsorption isotherms and T-2 distribution demonstrated the multifractal nature of different pore sizes. The key multifractal parameter, singularity strength range (Aa) calculated from N-2 adsorption and T-2 distribution are respectively distributed in scopes of 0.72-1.54 and 1.63-2.89, indicating that the heterogeneity of pore space from T-2 distribution is stronger than that from N-2 adsorption. It was observed that the specific surface, micro pore volume, and average pore size are correlated well with Delta alpha. There are no any correlations between Delta alpha and porosity and T-21m, but the cumulative porosity and width of right secondary peaks have an impact on the Delta alpha, which means that the heterogeneity difference between the two methods is attributed by larger pore and micro fractures.",27,27,7
Organic Matter,Nuclear Magnetic Resonance,"Josh, Matthew; Delle Piane, Claudio; Esteban, Lionel; Bourdet, Julien; Mayo, Sherry; Pejcic, Bobby; Burgar, Iko; Luzin, Vladimir; Clennell, Michael B.; Dewhurst, David N.","Advanced laboratory techniques characterising solids, fluids and pores in shales",Shale; Organic; Petrophysics; Geomechanics; Laboratory,DISPERSED ORGANIC-MATTER; WUFENG-LONGMAXI SHALE; X-RAY MICROTOMOGRAPHY; RAMAN-SPECTROSCOPY; THERMAL MATURITY; PREFERRED ORIENTATION; CARBONACEOUS MATERIAL; ELASTIC-ANISOTROPY; SICHUAN BASIN; PETROPHYSICAL CHARACTERIZATION,"Shales are of significant interest as reservoirs, seals and overburden in petroleum exploration and production, geological storage of CO2 and in the nuclear waste industry. Their properties and microstructure are difficult to measure and image and as such, there are still considerable gaps in our understanding of shale behaviour. The advent of more advanced and quantitative imaging methods along with novel sample preparation techniques including synchrotron imaging and K-edge subtraction with a contrast fluid, scanning (SEM) and transmission electron microscopy (TEM), have combined to allow the resolution of pores in the matrix and the organic matter in gas shales down to the nanometre scale. Textural quantification methods include neutron diffraction to quantify clay fabric alignment in siliciclastic shales as well as stress-dependent calcite c-axis orientation in carbonate-rich gas shales. The contents of the pores are also critical to the assessment of the preservation state of shales as well as the degree of water/gas saturation in resource shales. Combinations of dielectric analysis and 2 and 23 MHz nuclear magnetic resonance (NMR) measurements in siliciclastic and carbonate-rich gas shales can resolve not only the location of water, but also the interaction between water and mineral/organic surfaces in addition to the water and oil content. The organic content of shales is of particular interest in unconventional resources and this has driven application of Fourier transform infra-red (FTIR), to distinguish both mineral and organic maceral components in gas shales and Raman spectroscopy, which is increasingly used for organic matter characterisation in high maturity shales. Ultimately, shales are extremely complex nano-composite materials which require the application of multiple techniques to help determine their bulk physical and flow properties as well as factors controlling fabric and pore orientations and structure.",14,14,3
Fractal Dimension,"Coal,Adsorption Capacity","Yuan, Yujie; Rezaee, Reza",Fractal analysis of the pore structure for clay bound water and potential gas storage in shales based on NMR and N-2 gas adsorption,Shale; NMR; Low-pressure gas adsorption; Fractal dimension; Clay-bound water; Gas storage capacity,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; SURFACE-AREA; POROSITY; DIMENSION; MODEL; POROSIMETRY; SYSTEMS; QUANTIFICATION; LITHOFACIES,"Fractal dimension (D) is a critical parameter to estimate the heterogeneity of complex pore structure in shale gas reservoirs. To quantify the fractal dimension of various pore types and evaluate their implications on shale effective porosity and gas storage capacity in potential, we performed fractal analysis based on experimental results of low-field nuclear magnetic resonance (LF-NMR) and low-pressure N-2 gas adsorption (LP-N-2-GA) in Permian Carynginia shales. By comparing the calculated fractal dimensions based on the two approaches, we analyzed the 'surface fractal dimension' for ineffective pores occupied by clay bound water (CBW) and the 'volume fractal dimension' for effective pores (D-eff) holding removable fluids for the first time in shales. The NMR-based CBW pore fractal dimension (D-cbw) is linear positively correlated with the fractal dimension of micropore surface (Dl) (R-2= 0.91) and the volume of CBW (R-2= 0.58), while negatively correlated with effective porosity (R-2= 0.58). The NMR-based effective pore fractal dimension (D-eff) is linear positively correlated with the fractal dimension of meso/macropore volume (D2) (R-2= 0.82) and presents a good positive correlation with gas storage capacity (R-2= 0.80). The results indicate that CBW largely complicates the fractal geometry of nanoscaled pore network and potentially resist effective fluid flows in shales. The pore surface of higher heterogeneity (higher Dl) associates with larger surficial CBW retention and would further block the effective pore space for fluid transport. The meso/macropore volumes of higher complexity (higher D2) is intimate with the larger heterogeneity in effective pores for the higher potential of hydrocarbon storage capacity in gas shales.",48,48,14
Fractal Dimension,"Coal,Adsorption Capacity","Niu, Qinghe; Pan, Jienan; Jin, Yi; Wang, Haichao; Li, Meng; Ji, Zhongmin; Wang, Kai; Wang, Zhenzhi","Fractal study of adsorption-pores in pulverized coals with various metamorphism degrees using N-2 adsorption, X-ray scattering and image analysis methods",Coal rank; Adsorption capacity; N-2 adsorption; SAXS; SEM; Fractal dimension,LOW-RANK COAL; BASIN NW TURKEY; GAS-ADSORPTION; METHANE ADSORPTION; CARBONIFEROUS COALS; NITROGEN ADSORPTION; DEFORMED COALS; SICHUAN BASIN; SURFACE-AREA; DIMENSION,"As a highly heterogeneous material, the porous structure of coal is usually described by fractal dimension, which generally can be obtained by gas adsorption, light scattering and image analysis methods. In this paper, the pore structure (pore volume and specific surface area) and adsorption performance (Langmuir volume and Langmuir pressure) of 12 different rank coal samples were investigated by liquid nitrogen adsorption experiment (LNA) and methane isotherm adsorption experiment. And the fractal characteristics of these coals were studied by three fractal dimensions D-1, D-2 and D-3 acquired from LNA and small angle X-ray scattering (SAXS) and scanning electron microscopy (SEM), respectively. Results indicate that the adsorption pore volume and specific surface area show U-shaped evolutionary trends during the coalification process. The changes of pore volume and specific surface area are dominated by the mechanical compaction and dehydration effects before the second coalification jump (R-o,R-max = 1.3%), while they are then mainly controlled by concomitant metamorphic pores until the fourth coalification jump (R-o,R-max = 3.7%). Langmuir volume first increases and then reaches a steady value at the third coalification jump (R-o,R-max = 2.5%) with the increasing coal rank, however, Langmuir pressure monotonously decreases during the whole coalification process. D-1 and D-2 exhibit a dramatically increase from R-o,R-max = 0.6% to R-o,R-max = 2.0% and then a slowly rise when R-o,R-max increases from 2.0% to 3.5%, which is relevant to the changes of pore structure and macromolecule structure in coal. D-3 increases at a low speed first and then increases at a high speed with the increasing coal rank, which reflects the surface morphology of pores in coal. Fractal dimension D-1, D-2 and D-3 can be used to depict the methane adsorption properties of coal in varying metamorphism degrees. Generally, D-2 is larger than D-1, which is because N-2 adsorption can probe more macropores but SAXS can detect more micropores. Additionally, D-1, D-2 and D-3 are all negatively related to P-L. Our investigations also confirm that SAXS may be more superior to character the adsorption capacity of coal according to its highest relativity. This work clarifies the intrinsic sense and difference for characterising the surface irregularity by various methods, and provides an understanding for the experimental means relating to adsorption pores.",32,32,17
Fractal Dimension,"Coal,Adsorption Capacity",Li Fengli; Jiang Bo; Cheng Guoxi; Song Yu; Tang Zheng,"Structural and evolutionary characteristics of pores-microfractures and their influence on coalbed methane exploitation in high-rank brittle tectonically deformed coals of the Yangquan mining area, northeastern Qinshui basin, China",Brittle TDCs; Microfracture; Pore; CBM exploitation,DENSITY-FUNCTIONAL THEORY; SHALE GAS-RESERVOIRS; N-2 ADSORPTION; SEMIANALYTICAL MODEL; FRACTAL DIMENSION; MERCURY INTRUSION; SIZE DISTRIBUTION; SURFACE-AREA; PERMEABILITY; PRESSURE,"The Yangquan mining area is an important anthracite production base in China, but various types of tectonically deformed coals (TDCs) are well developed in its mines and gas outburst accidents take place frequently. By using methods such as optical microscope observation, mercury intrusion porosimetry (MIP) and low pressure nitrogen/carbon dioxide gas adsorption (LP-N-2/CO(2)GA), we tested the structural and evolutionary characteristics of pores-microfractures and their influence on coalbed methane exploitation in high-rank (R-o,R-max = 2.00-2.72%) primary structure coals and brittle TDCs (i.e., cataclastic-, mortor-, and granulitic coals) from the Yangquan mining area. The results show that the tectonic deformation can change the pore-microfracture structure of coals and, thus, their reservoir physical properties. In general, with the enhancement of tectonic deformation, the density of microfractures in coal, which become more and more mussy, gradually increases, the total pore volume (TPV) of coal (pores with a diameter of 5.37-27000 nm) and the pore volume of each pore size range increase, with the greatest increase occurring in pores of 100-1000 nm, and the connectivity between pores is gradually reduced as well. From primary structure coals to granulitic coals, the TPV by the Barret-JoynerHalenda (BJH) model increases with a greater increase in mesopores, and the specific surface area (SSA) by the Brunauer-Emmett-Teller (BET) model shows a trend of ""increase-decrease-increase"", while the average pore diameter changes follow the pattern of ""decrease-increase-decrease"" in 0.7-206 nm. However, tectonic deformation has little effect on micropores with a diameter of less than 1 nm in brittle TDCs. The difference in pore-microfracture structures of different brittle TDCs indicates that the cataclastic coals distribution area is favorable for coalbed methane (CBM) exploitation, while the granulitic coals distribution area is a gas outburst-prone area.",27,27,4
Fractal Dimension,"Coal,Adsorption Capacity","Wei, Qiang; Li, Xianqing; Zhang, Jizhen; Hu, Baolin; Zhu, Wenwei; Lian, Wanle; Sun, Kexin","Full-size pore structure characterization of deep-buried coals and its impact on methane adsorption capacity: A case study of the Shihezi Formation coals from the Panji Deep Area in Huainan Coalfield, Southern North China",Pore structure characterization; Methane adsorption capacity; Fractal dimension; The Shihezi formation coals; Panji deep area; Huainan coalfield,HIGH-RANK COAL; GAS-ADSORPTION; FRACTAL CHARACTERISTICS; TEXTURAL CHARACTERIZATION; MERCURY POROSIMETRY; SHALE RESERVOIRS; JUNGGAR BASIN; POROSITY; CO2; PERMEABILITY,"The characteristics and influence on methane adsorption capacity of the pore structure of coals was investigated through an approach that integrates mercury intrusion porosimetry, low pressure N-2/CO2 adsorption, and field emission scanning electron microscopy. Shihezi Formation coal samples from the Panji Deep Area in Huainan Coalfield in Southern North China were adopted as the study subjects. The fractal features of heterogeneous coal pore structures were quantified on the basis of N-2 adsorption isotherms by using the Frenkel - Halesy - Hill (FHH) model. Pore structure and morphology characterizations confirm that Shihezi Formation coals developed with multiple pore types and heterogeneous pore structures, and the slit-shaped and ink-bottle-shaped pores are mainly distributed at the pore size interval of 3.3-10 nm. Our coal samples present uni-modal and multi-modal pore size distributions, wherein multiple peaks are concentrated in the intervals of 0.45-0.55 nm and 2-20 mu m. The major volumes from mesopores (2 nm < pore diameter < 50 nm) and macropores (pore diameter > 50 nm) occur in the full-scale pore size distributions, revealing Shihezi Formation coals are mesopores and macropores rich. Micropores (pore diameter < 2 nm) provide the majority of pore specific surface area, whereas pore volume is mostly contributed by mesopores and macropores. The volumes and specific surface areas of mesopores and macropores are positively correlated with ash yield and inertinite contents but are negatively correlated with maximum vitrinite reflectance (R-o(,max)). The methane adsorption capacity of Shihezi Formation coals is largely independent of mesopores and macropores but is positively correlated with the pore volume and specific surface area of micropores. This correlation suggests that micropores provide the predominant sites for methane adsorption. The calculated values of pore surface fractal dimension D-1 and spatial fractal dimension D-2 are 2.440-2.610 (avg. 2.515) and 2.542-2.761 (avg. 2.650), respectively, suggesting that the pore structures of Shihezi Formation coals are highly complex and heterogeneous. The positive correlation between D-1 and methane adsorption capacity reveals that high surface roughness of the pore structure is associated with high methane adsorption capacity. However, the irregular pore structure does not influence methane adsorption capacity.",19,20,11
Fractal Dimension,"Coal,Adsorption Capacity","Zhao, Junlong; Tang, Dazhen; Qin, Yong; Xu, Hao","Fractal characterization of pore structure for coal macrolithotypes in the Hancheng area, southeastern Ordos Basin, China",Fractal dimension; Pore structure; Adsorption pore; Seepage pore; Coal macrolithotype,CH4 ADSORPTION CAPACITY; EASTERN MARGIN; MERCURY POROSIMETRY; GAS-ADSORPTION; RANK COAL; METHANE; BLOCK; DIMENSION; MODEL; THERMODYNAMICS,"Coalbed methane (CBM) reservoir pore structure is extremely complex and heterogeneous. With the fractal theory, the geometric and structural characteristics of the pore structure could be quantified. However, few studies have aimed to understand the fractal features of compositional-based macrolithotypes (bright, semibright, semi-dull, and dull coals). In this work, samples from the Hancheng area, in the southeastern Ordos Basin, China, were collected to investigate the fractal features of pore structures for macrolithotypes and calculate fractal dimensions (D-a1 and D-a2 for adsorption pores; D-s1 and D(s2)( )for seepage pores) based on low temperature N-2 adsorption and mercury intrusion data, respectively. Meanwhile, the impact of the fractal dimensions on the gas adsorption capacity and the seepage ability were discussed. The results demonstrate that when bright coal turns into dull coal, the vitrinite content, helium permeability, and gas adsorption capacity gradually decrease, while the coal density, mineral content, and ash yield increase. Since the D-a1 and D-s1 either deviate from the natural fractal dimension (2 < D < 3) or have a poor correlation with macrolithotypes, D(a2 )and D-s2 are regarded as the adsorption and seepage pore fractal dimensions, respectively. Of all the coal macrolithotypes, bright coal has the smallest BET specific surface area and micropore proportion, which results in the smallest fractal dimension D-a2, while for the dull coal, this is just the contrary; due to the higher mineral content, a higher D-a2 of the dull coal indicates a more complicated adsorption pore structure, and the coal with a larger Langmuir volume has a smaller D-a2. For the seepage pores, when the bright coal turns into dull coal, the macropore proportion gradually decreases, but the pore proportion tends toward equilibrium, and the mercury withdrawal efficiency increases; the dull coal has a larger D-s2 , indicating a more complex seepage pore structure than that in the bright coal. Due to the decreasing macropore proportion and mineral filling, D-s2 demonstrates an obvious negative correlation with the helium permeability and macropore proportion.",18,18,4
Fractal Dimension,"Coal,Adsorption Capacity","Zhang, Xiangliang; Lin, Baiquan; Zhu, Chuanjie; Yan, Fazhi; Liu, Ting; Liu, Tong; Li, Yanjun",Petrophysical variation of coal treated by cyclic high-voltage electrical pulse for coalbed methane recovery,Pore variation; Cyclic high-voltage electrical pulse; Coalbed methane; Current; Fractal dimension,ADSORPTION CAPACITY; GAS-ADSORPTION; PORE STRUCTURE; SIZE; IMPACT; ORES; NACL; DISINTEGRATION; FRAGMENTATION; CONDUCTIVITY,"Laboratory experiments and field application of high-voltage electrical pulse (HVEP) technology, a good method for coalbed methane (CBM) enhancement, have achieved great progress. However, previous studies mainly concentrated on the crushing effect of a single pulse on coal, ignoring the influence of multiple cyclic electrical pulses on the pore structure. Besides, the current in electrical breakdown was rarely studied. In this study, the effect of cyclic number on pore variation was investigated, and the mechanism of electrical breakdown was discussed by measuring the current waveform. Moreover, the micro fissure and pore variations of coal before and after electrical breakdown were measured by adopting scanning electron microscopy (SEM) and low temperature liquid nitrogen adsorption (LT-N(2)A). Under the action of cyclic HVEP, both Linhua (LH) anthracite coal and Hongliu (HL) bituminous coal can be crushed into small pieces. SEM results indicate that the number of cracks increase with the number of cycle. LT-N(2)A analyses show that the cumulative pore volumes and surface areas of LH and HL coals both increase after electrical breakdown, so does the pore structure fractal dimension, which provides a smoother channel for CBM desorption. Additionally, the great energy instantly injected into the coal could produce huge expansion stress and immediately break the coal from inside. Current waveforms during the breakdown demonstrate that the peak current increase with the number of cycle, whereas the breakdown time decrease with it. This indicates the alteration of electrical properties of coal during the breakdown, which affects the next discharge.",13,14,7
Fractal Dimension,Relative Permeability,"Guo, Xiaobo; Huang, Zhilong; Zhao, Libin; Han, Wei; Ding, Chao; Sun, Xiongwei; Yan, Ruitao; Zhang, Tonghui; Yang, Xuejun; Wang, Ruomei","Pore structure and multi-fractal analysis of tight sandstone using MIP, NMR and NMRC methods: A case study from the Kuqa depression, China",Tight sandstone; Fractal dimension; Pore structure; Kuqa depression,ORDOS BASIN; TARIM BASIN; SIZE DISTRIBUTION; GAS SANDSTONE; OIL; POROSIMETRY; PARAMETERS; RESERVOIRS; DYNAMICS; ROCKS,"The pore structure and fractal characteristic of tight gas sandstone from Cretaceous Bashijiqike Formation in Kuqa depression were investigated, using thin section, scanning electronic microscope (SEM), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR) and NMR cryoporometry (NMRC) measurements. The pores of tight sandstone samples mainly contain residual primary intergranular pores, intergranular and intragranular dissolved pores, micropores related to clay aggregates and microfractures. The MIP, NMR and NMRC analyses show that the pore structure of tight sandstone is complex and heterogeneous at different pore scales, displaying as a multi-fractal feature. Fractal dimension Dg-s (with respect to small pore throats) from MIP and Dn-1 (long T-2 relaxation time, representing large pores and fractures or movable-fluid pores) are negatively correlated with porosity, permeability, median pore throat radius and skewness, and have inverse relationships with bound water saturation (S-bnd). Fractal dimension Dg-b ( > 3.0, with respect to larger pore throats) and Dn-s ( < 2.0, short T-2 relaxation time, representing small pores or bound-water pores) from NMR don't present clear relationships with most of pore structure parameters. Fractal dimension Dc-(1) and Dc-(2) from NMRC show more complex or inconspicuous relationships with pore structure parameters, in the pore diameter size < 500 nm. Hence, Dg-s from MIP and Dn-1 from NMR can be considered as effective parameters for pore structure and fluid properties characterization of tight sandstone. Fractal dimension Dg-b ( > 3.0) and Dn-s ( < 2.0) have no practical significance to characterize the pore structure of tight sandstone. The formation of residual primary intergranular pores and intergranular dissolution pores can reduce the fractal dimension which could be an important sign of effective reservoirs in the study area.",37,39,10
Fractal Dimension,Relative Permeability,"Wang, Jiulong; Song, Hongqing; Rasouli, Vamegh; Killough, John",An integrated approach for gas-water relative permeability determination in nanoscale porous media,Relative permeability; Nanoscale porous media; Interfacial effects; Fractal,CARBON NANOTUBES; PORE STRUCTURE; CO2; SHALE; SANDSTONE; SEQUESTRATION; PRESSURE; DRAINAGE; STORAGE; MODEL,"This paper provides an integrated approach to simulate gas-water relative permeability in nanoscale porous media with interfacial effects using fractal theory. The calculation results with present model considering the interfacial effects match the laboratory results very well. The characteristics of relative permeability were analyzed under different values of Hydrogen bond (Pi(h)), Double layer repulsive force (Pi(e)), Long-range van der Waals force (Pi(w)) and Short-range structure repulsive force (Pi(s)). The result shows that the interfacial effects can promote the fluid flow in the nanoporous media and the relationship is as follows: Pi(h) > Pi(e) > Pi(w) > Pi(s). Pi(h) and Pi(e) improve spreading obviously, which are accounted for more than 70%. Then the Pi(w) affects spreading accounts for 1/5 nearly. In addition, the analysis of fractal dimension on relative permeability is carried out to indicate that the gas-water relative permeability decreases with the increase of the fractal dimension. While the capillary force has impact on relative permeability slightly. The new insight and theoretical basis could be obtained for CO2 geological storage and shale gas extraction from nanoscale porous media.",18,19,2
Fractal Dimension,Relative Permeability,"Ye, Wenzhuo; Wang, Xiuyu; Cao, Chenguang; Yu, Wenshuai",A fractal model for threshold pressure gradient of tight oil reservoirs,Tight oil reservoir; Capillary bundle model; Fractal theory; Threshold pressure gradient,BINGHAM FLUIDS; FLOW,"In tight oil reservoir, the flow channel of oil and water is tiny and the boundary layer effect is obvious, resulting in large flow resistance and high threshold pressure gradient. Taking into account of the fractal dimension of the pore throat and the tortuosity, a fractal model for calculating the threshold pressure gradient of tight oil reservoir is established. In this model, the rock is considered as a capillary bundle with different diameter distribution as obtained from high-pressure mercury injection measurements for tight rocks. The mathematical model expresses the fractal threshold pressure gradient as a function of ultimate shear stress (eta(0)), pore throat fractal dimension (D-f ), tortuosity fractal dimension (D-T), the maximum pore radius (r(max)), the characteristic length of the core (L-0), and the connate water saturation (S-wi). For 27 tight cores obtained from Changqing oilfield, threshold pressure gradients were determined using the established model and compared with experimental results to check its accuracy. A good fit was found especially for the rock with lower permeability. The relative error is less than 14% for all the rock tested and is only 1.77% for the cores with permeability in the range of 0.001-0.01mD. This model has the advantage of being able to check the impact of the connate water saturation on the threshold pressure gradient of tight rock, which is usually neglected in previous work. The results show that higher S-wi results in largely increased threshold pressure gradient especially for the rock with permeability lower than 0.01mD. This fractal model is of great importance in predicting the threshold pressure gradient of tight oil reservoir and researching on the flow mechanism of tight oil in porous media.",16,17,4
Fractal Dimension,Relative Permeability,"Wang, Huijun; Wu, Wei; Chen, Tao; Yu, Jing; Pan, Jienan","Pore structure and fractal analysis of shale oil reservoirs: A case study of the Paleogene Shahejie Formation in the Dongying Depression, Bohai Bay, China",Dongying depression; Shale oil; Pore structure; Fractal theory; Mercury intrusion capillary pressure (MICP),NIUZHUANG SOUTH SLOPE; MESH PETROLEUM PLAYS; PETROPHYSICAL PROPERTIES; GAS-ADSORPTION; ORDOS BASIN; PART 1; SANDSTONE; SYSTEMS; CLASSIFICATION; CONNECTIVITY,"In the exploration and development of shale gas, the evaluation of reservoir microscopic pore structure is of great significance. In order to study the pore size distribution, pore networks, seepage capacity and heterogeneity of shale reservoirs more effectively, mercury intrusion capillary pressure (MICP) and the fractal theory were carried out on a suite of the shale samples of the Dongying Depression, Bohai Bay, China. The results demonstrate that shale is characterized by complex and heterogeneous microcosmic pore structure. The pore throat size could be divided into four types: micropores (25-100 nm), mesopores (100-1000 nm), macropores II (1000-r(apex), nm, r(apex), is the pore throat radius corresponding to the maximum point in the plot of mercury saturation versus the mercury saturation divided by capillary pressure) and macropores I (> r(apex), nm). The pore throat radii of shale from the Dongying Depression are mostly mesopores and macropores II. Micropores and macropores Hare the controlling factors of porosity, whereas permeability is dominated primarily by macropores II. The fractal dimension of pore throat are clearly separated into two segments: D1 and D2, corresponding to large pores (> r(apex)) and small pores (< r(apex)), respectively. There are no apparent relationships between D1 and the pore structure parameters, whereas D2 are strongly related to the maximum mercury saturation, entry pressure, average pore throat radius and maximum pore throat radius. These relationships enable D2 to represent the complexity of shale. The mercury capillary curves can be divided into three types based on the shape of the curves: type I, type II, type III. According to these types of pore structure, reservoirs can be classified into three categories. The good reservoirs (type I) are characterized by dominant macropores and mesopores volumes, a large porosity and permeability and a low fractal dimension. Medium reservoirs (type II) have a low oil reservoir potential due to the developed mesopores and micropores. The type III pore system is a poor reservoir that is inadequate for shale oil. Our analyses suggest that MICP coupled with the fractal theory is a powerful tool to evaluate the porous structure of shale.",13,14,7
Fractal Dimension,Space,"Sheng, Guanglong; Su, Yuliang; Wang, Wendong",A new fractal approach for describing induced-fracture porosity/permeability/ compressibility in stimulated unconventional reservoirs,Stimulated unconventional reservoirs; Fractal induced-fracture spacing; Fractal induced-fracture aperture; Tortuosity index; Fracture porosity/permeability/compressibility,HORIZONTAL WELLS; GAS-FLOW; MATRIX PERMEABILITY; OIL; MODEL; SIMULATION; PREDICTION; DIFFUSION; VOLUME; MEDIA,"The stimulated reservoir volume (SRV) with complex induced-fracture governs dominant flow rates in unconventional reservoirs. The induced-fracture spacing and aperture greatly affect the fracture properties. In this study, a new method to calculate tortuosity index of fractal induced-fracture is proposed, and the fractal dimension of induced-fracture aperture (d(fa)) is presented to describe the distribution of fractal induced-fracture aperture (FFAD). Combined with fractal induced-fracture spacing (FFSD) and FFAD, the fractal fracture porosity/permeability/compressibility models are given. The FFSD and FFAD influenced by fractal dimensions and their influences on fracture properties are analyzed. The results show that the d(fs) has a wider range than that of natural fractures, and it may be larger than 2 in 2D system in some special reservoirs, e.g. re-stimulated reservoirs. As the distance from the reference point increases, the tortuosity index gradually decreases. The larger the fractal dimension (d(fs) or d(fa)) is, the larger the fracture porosity/compressibility will be. In the cases of d(fs) < 2 (or d(fa) < 2), the fracture porosity/compressibility of the uniformly induced-fracture is smaller than the fractal induced-fracture near the reference point, and larger than that far away from the reference point. While in the cases of d(fs) > 2 (or d(fa) > 2), the fracture porosity/compressibility of the uniformly induced-fracture is larger than the fractal induced-fracture near the reference point, and smaller than that far away from the reference point. When d(fa) > 2, the fracture permeability increases first and then decreases as the distance from the reference point increases. In other cases, the fracture permeability decreases as the distance from the reference point increases. The permeability influenced by distribution of induced-fracture aperture is greater than that influenced by induced-fracture spacing.",92,94,8
Fractal Dimension,Space,"Yuan, Yujie; Rezaee, Reza",Fractal analysis of the pore structure for clay bound water and potential gas storage in shales based on NMR and N-2 gas adsorption,Shale; NMR; Low-pressure gas adsorption; Fractal dimension; Clay-bound water; Gas storage capacity,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; SURFACE-AREA; POROSITY; DIMENSION; MODEL; POROSIMETRY; SYSTEMS; QUANTIFICATION; LITHOFACIES,"Fractal dimension (D) is a critical parameter to estimate the heterogeneity of complex pore structure in shale gas reservoirs. To quantify the fractal dimension of various pore types and evaluate their implications on shale effective porosity and gas storage capacity in potential, we performed fractal analysis based on experimental results of low-field nuclear magnetic resonance (LF-NMR) and low-pressure N-2 gas adsorption (LP-N-2-GA) in Permian Carynginia shales. By comparing the calculated fractal dimensions based on the two approaches, we analyzed the 'surface fractal dimension' for ineffective pores occupied by clay bound water (CBW) and the 'volume fractal dimension' for effective pores (D-eff) holding removable fluids for the first time in shales. The NMR-based CBW pore fractal dimension (D-cbw) is linear positively correlated with the fractal dimension of micropore surface (Dl) (R-2= 0.91) and the volume of CBW (R-2= 0.58), while negatively correlated with effective porosity (R-2= 0.58). The NMR-based effective pore fractal dimension (D-eff) is linear positively correlated with the fractal dimension of meso/macropore volume (D2) (R-2= 0.82) and presents a good positive correlation with gas storage capacity (R-2= 0.80). The results indicate that CBW largely complicates the fractal geometry of nanoscaled pore network and potentially resist effective fluid flows in shales. The pore surface of higher heterogeneity (higher Dl) associates with larger surficial CBW retention and would further block the effective pore space for fluid transport. The meso/macropore volumes of higher complexity (higher D2) is intimate with the larger heterogeneity in effective pores for the higher potential of hydrocarbon storage capacity in gas shales.",48,48,14
Fractal Dimension,Space,"Zhao, Peiqiang; Wang, Xixin; Cai, Jianchao; Luo, Miao; Zhang, Jin; Liu, Yuming; Rabiei, Minou; Li, Chuncheng",Multifractal analysis of pore structure of Middle Bakken formation using low temperature N-2 adsorption and NMR measurements,Middle Bakken; Multifractal analysis; N-2 adsorption; Nuclear magnetic resonance (NMR),NUCLEAR-MAGNETIC-RESONANCE; RATE-CONTROLLED POROSIMETRY; FORD SHALE SAMPLES; SICHUAN BASIN; GAS-RESERVOIR; FRACTAL CHARACTERIZATION; ORGANIC-MATTER; OIL; SANDSTONE; DIMENSION,"Understanding the complexity and heterogeneity of pore structure can improve the comprehensive characterization for complex unconventional reservoirs and better exploit those resources. In this paper, multifractal analysis was conducted on low temperature N-2 adsorption and NMR T-2 distribution for the pore structure investigation in Middle Bakken formation in Williston Basin, USA. Results show that the averages of specific surface area, total pore volume, the average pore size of five N-2 adsorption samples are 3.31 m(2)/g, 0.008 cm(3)/g, and 19.57 nm, respectively. Six NMR T(2 )distributions are bimodal and the signals of left dominant peaks are mainly distributed between 0.3 ms and 10 ms. The T-2 logarithmic mean value ranges from 2.18 ms to 2.95 ms with an average value of 2.57 ms. Both N-2 adsorption isotherms and T-2 distribution demonstrated the multifractal nature of different pore sizes. The key multifractal parameter, singularity strength range (Aa) calculated from N-2 adsorption and T-2 distribution are respectively distributed in scopes of 0.72-1.54 and 1.63-2.89, indicating that the heterogeneity of pore space from T-2 distribution is stronger than that from N-2 adsorption. It was observed that the specific surface, micro pore volume, and average pore size are correlated well with Delta alpha. There are no any correlations between Delta alpha and porosity and T-21m, but the cumulative porosity and width of right secondary peaks have an impact on the Delta alpha, which means that the heterogeneity difference between the two methods is attributed by larger pore and micro fractures.",27,27,7
Fractal Dimension,Space,"Kong, Lingyun; Ostadhassan, Mehdi; Hou, Xiaodong; Mann, Michael; Li, Chunxiao",Microstructure characteristics and fractal analysis of 3D-printed sandstone using micro-CT and SEM-EDS,3D-printed rocks; Microstructures; Sandstone; Micro-computed tomography,RAY COMPUTED-TOMOGRAPHY; MECHANICAL-PROPERTIES; RESERVOIR ROCKS; ORGANIC-MATTER; PORE STRUCTURE; PERMEABILITY; PARTICLES; ALGORITHM; VOLUME; BASIN,"Replicating sedimentary rocks using three-dimensional (3D) printing can support routine reservoir rock analysis in petrophysical and geomechanical experiments, which is done limited in scope due to lack of suitable printing materials and achievable resolution. Following our previous studies on gypsum powder with binder, a new printing material, silica sand, is used and characterized in this study to demonstrate the microstructure and its similarity to Berea Sandstone. Binder jetting printing system was specifically utilized to bond silica sand particles to create intact cylindrical samples without digital porous model as input. Created samples were first scanned by Backscattered Scanning Electron Microscope (BS-SEM) and Energy Dispersive Spectroscopy (EDS) to identify the particles, the packing mode and cement (binder). Next, micro-computed tomography (CT) was used to determine the microstructure of the samples, including the size and the shape of both particles and pores, in the 3D space. In addition, anisotropy that was found to originate from the pore structures was quantified by comparing the characteristics of pores in different directions. Fractal dimensions from different sample sizes, 6 mm and 12 mm in diameter, were also calculated for pore structure analysis in order to illustrate the effect of sample size on pore heterogeneity in 3D printed samples with silica. The results demonstrated the feasibility of substituting 3D-printed sandstones for natural rocks regarding pore structures for experimental validation of petrophysical models.",24,26,10
Fractal Dimension,Coalbed Methane,Li Fengli; Jiang Bo; Cheng Guoxi; Song Yu; Tang Zheng,"Structural and evolutionary characteristics of pores-microfractures and their influence on coalbed methane exploitation in high-rank brittle tectonically deformed coals of the Yangquan mining area, northeastern Qinshui basin, China",Brittle TDCs; Microfracture; Pore; CBM exploitation,DENSITY-FUNCTIONAL THEORY; SHALE GAS-RESERVOIRS; N-2 ADSORPTION; SEMIANALYTICAL MODEL; FRACTAL DIMENSION; MERCURY INTRUSION; SIZE DISTRIBUTION; SURFACE-AREA; PERMEABILITY; PRESSURE,"The Yangquan mining area is an important anthracite production base in China, but various types of tectonically deformed coals (TDCs) are well developed in its mines and gas outburst accidents take place frequently. By using methods such as optical microscope observation, mercury intrusion porosimetry (MIP) and low pressure nitrogen/carbon dioxide gas adsorption (LP-N-2/CO(2)GA), we tested the structural and evolutionary characteristics of pores-microfractures and their influence on coalbed methane exploitation in high-rank (R-o,R-max = 2.00-2.72%) primary structure coals and brittle TDCs (i.e., cataclastic-, mortor-, and granulitic coals) from the Yangquan mining area. The results show that the tectonic deformation can change the pore-microfracture structure of coals and, thus, their reservoir physical properties. In general, with the enhancement of tectonic deformation, the density of microfractures in coal, which become more and more mussy, gradually increases, the total pore volume (TPV) of coal (pores with a diameter of 5.37-27000 nm) and the pore volume of each pore size range increase, with the greatest increase occurring in pores of 100-1000 nm, and the connectivity between pores is gradually reduced as well. From primary structure coals to granulitic coals, the TPV by the Barret-JoynerHalenda (BJH) model increases with a greater increase in mesopores, and the specific surface area (SSA) by the Brunauer-Emmett-Teller (BET) model shows a trend of ""increase-decrease-increase"", while the average pore diameter changes follow the pattern of ""decrease-increase-decrease"" in 0.7-206 nm. However, tectonic deformation has little effect on micropores with a diameter of less than 1 nm in brittle TDCs. The difference in pore-microfracture structures of different brittle TDCs indicates that the cataclastic coals distribution area is favorable for coalbed methane (CBM) exploitation, while the granulitic coals distribution area is a gas outburst-prone area.",27,27,4
Fractal Dimension,Coalbed Methane,"Zhao, Junlong; Tang, Dazhen; Qin, Yong; Xu, Hao","Fractal characterization of pore structure for coal macrolithotypes in the Hancheng area, southeastern Ordos Basin, China",Fractal dimension; Pore structure; Adsorption pore; Seepage pore; Coal macrolithotype,CH4 ADSORPTION CAPACITY; EASTERN MARGIN; MERCURY POROSIMETRY; GAS-ADSORPTION; RANK COAL; METHANE; BLOCK; DIMENSION; MODEL; THERMODYNAMICS,"Coalbed methane (CBM) reservoir pore structure is extremely complex and heterogeneous. With the fractal theory, the geometric and structural characteristics of the pore structure could be quantified. However, few studies have aimed to understand the fractal features of compositional-based macrolithotypes (bright, semibright, semi-dull, and dull coals). In this work, samples from the Hancheng area, in the southeastern Ordos Basin, China, were collected to investigate the fractal features of pore structures for macrolithotypes and calculate fractal dimensions (D-a1 and D-a2 for adsorption pores; D-s1 and D(s2)( )for seepage pores) based on low temperature N-2 adsorption and mercury intrusion data, respectively. Meanwhile, the impact of the fractal dimensions on the gas adsorption capacity and the seepage ability were discussed. The results demonstrate that when bright coal turns into dull coal, the vitrinite content, helium permeability, and gas adsorption capacity gradually decrease, while the coal density, mineral content, and ash yield increase. Since the D-a1 and D-s1 either deviate from the natural fractal dimension (2 < D < 3) or have a poor correlation with macrolithotypes, D(a2 )and D-s2 are regarded as the adsorption and seepage pore fractal dimensions, respectively. Of all the coal macrolithotypes, bright coal has the smallest BET specific surface area and micropore proportion, which results in the smallest fractal dimension D-a2, while for the dull coal, this is just the contrary; due to the higher mineral content, a higher D-a2 of the dull coal indicates a more complicated adsorption pore structure, and the coal with a larger Langmuir volume has a smaller D-a2. For the seepage pores, when the bright coal turns into dull coal, the macropore proportion gradually decreases, but the pore proportion tends toward equilibrium, and the mercury withdrawal efficiency increases; the dull coal has a larger D-s2 , indicating a more complex seepage pore structure than that in the bright coal. Due to the decreasing macropore proportion and mineral filling, D-s2 demonstrates an obvious negative correlation with the helium permeability and macropore proportion.",18,18,4
Fractal Dimension,Coalbed Methane,"Zhang, Xiangliang; Lin, Baiquan; Zhu, Chuanjie; Yan, Fazhi; Liu, Ting; Liu, Tong; Li, Yanjun",Petrophysical variation of coal treated by cyclic high-voltage electrical pulse for coalbed methane recovery,Pore variation; Cyclic high-voltage electrical pulse; Coalbed methane; Current; Fractal dimension,ADSORPTION CAPACITY; GAS-ADSORPTION; PORE STRUCTURE; SIZE; IMPACT; ORES; NACL; DISINTEGRATION; FRAGMENTATION; CONDUCTIVITY,"Laboratory experiments and field application of high-voltage electrical pulse (HVEP) technology, a good method for coalbed methane (CBM) enhancement, have achieved great progress. However, previous studies mainly concentrated on the crushing effect of a single pulse on coal, ignoring the influence of multiple cyclic electrical pulses on the pore structure. Besides, the current in electrical breakdown was rarely studied. In this study, the effect of cyclic number on pore variation was investigated, and the mechanism of electrical breakdown was discussed by measuring the current waveform. Moreover, the micro fissure and pore variations of coal before and after electrical breakdown were measured by adopting scanning electron microscopy (SEM) and low temperature liquid nitrogen adsorption (LT-N(2)A). Under the action of cyclic HVEP, both Linhua (LH) anthracite coal and Hongliu (HL) bituminous coal can be crushed into small pieces. SEM results indicate that the number of cracks increase with the number of cycle. LT-N(2)A analyses show that the cumulative pore volumes and surface areas of LH and HL coals both increase after electrical breakdown, so does the pore structure fractal dimension, which provides a smoother channel for CBM desorption. Additionally, the great energy instantly injected into the coal could produce huge expansion stress and immediately break the coal from inside. Current waveforms during the breakdown demonstrate that the peak current increase with the number of cycle, whereas the breakdown time decrease with it. This indicates the alteration of electrical properties of coal during the breakdown, which affects the next discharge.",13,14,7
Fractal Dimension,Porous Media,"Wang, Fuyong; Jiao, Liang; Lian, Peiqing; Zeng, Jianhui","Apparent gas permeability, intrinsic permeability and liquid permeability of fractal porous media: Carbonate rock study with experiments and mathematical modelling",Permeability; Fractal; Porous media; Tortuosity; Gas slippage; Carbonate,FLOW BEHAVIOR; RESERVOIR; SLIPPAGE; UNITS; SHALE,"This paper develops mathematical models for predicting apparent gas permeability, intrinsic permeability and liquid permeability of carbonates based on fractal capillary tube model. First, the modified Hagen-Poiseuille equation for the fluid flow in a single capillary tube with fractal characteristics of tortuosity was derived. With the assumption of fractal pore size distribution in carbonates, the intrinsic permeability of fractal capillary tube model was developed. Then, considering gas slippage effect and liquid boundary-layer effect, the mathematical models for predicting apparent gas permeability and liquid permeability were proposed, respectively. Finally, the proposed mathematical models for permeability prediction were validated with the experimental permeability data measured from 22 carbonate core plugs. High pressure mercury intrusion (HPMI) tests were utilized to obtain pore size distributions and pore structure parameters. The comparisons between model results and experimental results demonstrate that the developed mathematical models can effectively predict apparent gas permeability, intrinsic permeability and liquid permeability of carbonates. The influences of different pore structures on gas slippage effect and liquid boundary-layer effect were investigated. The research results demonstrate that gas slippage factor is the function of pore structure parameters and fluid properties, and it increases with increasing fractal dimension and decreasing tortuosity fractal dimension, and with carbonate pore size decreasing, the differences between liquid permeability and intrinsic permeability increase due to the increasing liquid boundary-layer effect.",29,32,4
Fractal Dimension,Porous Media,"Wang, Jiulong; Song, Hongqing; Rasouli, Vamegh; Killough, John",An integrated approach for gas-water relative permeability determination in nanoscale porous media,Relative permeability; Nanoscale porous media; Interfacial effects; Fractal,CARBON NANOTUBES; PORE STRUCTURE; CO2; SHALE; SANDSTONE; SEQUESTRATION; PRESSURE; DRAINAGE; STORAGE; MODEL,"This paper provides an integrated approach to simulate gas-water relative permeability in nanoscale porous media with interfacial effects using fractal theory. The calculation results with present model considering the interfacial effects match the laboratory results very well. The characteristics of relative permeability were analyzed under different values of Hydrogen bond (Pi(h)), Double layer repulsive force (Pi(e)), Long-range van der Waals force (Pi(w)) and Short-range structure repulsive force (Pi(s)). The result shows that the interfacial effects can promote the fluid flow in the nanoporous media and the relationship is as follows: Pi(h) > Pi(e) > Pi(w) > Pi(s). Pi(h) and Pi(e) improve spreading obviously, which are accounted for more than 70%. Then the Pi(w) affects spreading accounts for 1/5 nearly. In addition, the analysis of fractal dimension on relative permeability is carried out to indicate that the gas-water relative permeability decreases with the increase of the fractal dimension. While the capillary force has impact on relative permeability slightly. The new insight and theoretical basis could be obtained for CO2 geological storage and shale gas extraction from nanoscale porous media.",18,19,2
Fractal Dimension,Porous Media,"Ye, Wenzhuo; Wang, Xiuyu; Cao, Chenguang; Yu, Wenshuai",A fractal model for threshold pressure gradient of tight oil reservoirs,Tight oil reservoir; Capillary bundle model; Fractal theory; Threshold pressure gradient,BINGHAM FLUIDS; FLOW,"In tight oil reservoir, the flow channel of oil and water is tiny and the boundary layer effect is obvious, resulting in large flow resistance and high threshold pressure gradient. Taking into account of the fractal dimension of the pore throat and the tortuosity, a fractal model for calculating the threshold pressure gradient of tight oil reservoir is established. In this model, the rock is considered as a capillary bundle with different diameter distribution as obtained from high-pressure mercury injection measurements for tight rocks. The mathematical model expresses the fractal threshold pressure gradient as a function of ultimate shear stress (eta(0)), pore throat fractal dimension (D-f ), tortuosity fractal dimension (D-T), the maximum pore radius (r(max)), the characteristic length of the core (L-0), and the connate water saturation (S-wi). For 27 tight cores obtained from Changqing oilfield, threshold pressure gradients were determined using the established model and compared with experimental results to check its accuracy. A good fit was found especially for the rock with lower permeability. The relative error is less than 14% for all the rock tested and is only 1.77% for the cores with permeability in the range of 0.001-0.01mD. This model has the advantage of being able to check the impact of the connate water saturation on the threshold pressure gradient of tight rock, which is usually neglected in previous work. The results show that higher S-wi results in largely increased threshold pressure gradient especially for the rock with permeability lower than 0.01mD. This fractal model is of great importance in predicting the threshold pressure gradient of tight oil reservoir and researching on the flow mechanism of tight oil in porous media.",16,17,4
Fractal Dimension,Shale Oil,"Zhao, Peiqiang; Wang, Xixin; Cai, Jianchao; Luo, Miao; Zhang, Jin; Liu, Yuming; Rabiei, Minou; Li, Chuncheng",Multifractal analysis of pore structure of Middle Bakken formation using low temperature N-2 adsorption and NMR measurements,Middle Bakken; Multifractal analysis; N-2 adsorption; Nuclear magnetic resonance (NMR),NUCLEAR-MAGNETIC-RESONANCE; RATE-CONTROLLED POROSIMETRY; FORD SHALE SAMPLES; SICHUAN BASIN; GAS-RESERVOIR; FRACTAL CHARACTERIZATION; ORGANIC-MATTER; OIL; SANDSTONE; DIMENSION,"Understanding the complexity and heterogeneity of pore structure can improve the comprehensive characterization for complex unconventional reservoirs and better exploit those resources. In this paper, multifractal analysis was conducted on low temperature N-2 adsorption and NMR T-2 distribution for the pore structure investigation in Middle Bakken formation in Williston Basin, USA. Results show that the averages of specific surface area, total pore volume, the average pore size of five N-2 adsorption samples are 3.31 m(2)/g, 0.008 cm(3)/g, and 19.57 nm, respectively. Six NMR T(2 )distributions are bimodal and the signals of left dominant peaks are mainly distributed between 0.3 ms and 10 ms. The T-2 logarithmic mean value ranges from 2.18 ms to 2.95 ms with an average value of 2.57 ms. Both N-2 adsorption isotherms and T-2 distribution demonstrated the multifractal nature of different pore sizes. The key multifractal parameter, singularity strength range (Aa) calculated from N-2 adsorption and T-2 distribution are respectively distributed in scopes of 0.72-1.54 and 1.63-2.89, indicating that the heterogeneity of pore space from T-2 distribution is stronger than that from N-2 adsorption. It was observed that the specific surface, micro pore volume, and average pore size are correlated well with Delta alpha. There are no any correlations between Delta alpha and porosity and T-21m, but the cumulative porosity and width of right secondary peaks have an impact on the Delta alpha, which means that the heterogeneity difference between the two methods is attributed by larger pore and micro fractures.",27,27,7
Fractal Dimension,Shale Oil,"Wang, Huijun; Wu, Wei; Chen, Tao; Yu, Jing; Pan, Jienan","Pore structure and fractal analysis of shale oil reservoirs: A case study of the Paleogene Shahejie Formation in the Dongying Depression, Bohai Bay, China",Dongying depression; Shale oil; Pore structure; Fractal theory; Mercury intrusion capillary pressure (MICP),NIUZHUANG SOUTH SLOPE; MESH PETROLEUM PLAYS; PETROPHYSICAL PROPERTIES; GAS-ADSORPTION; ORDOS BASIN; PART 1; SANDSTONE; SYSTEMS; CLASSIFICATION; CONNECTIVITY,"In the exploration and development of shale gas, the evaluation of reservoir microscopic pore structure is of great significance. In order to study the pore size distribution, pore networks, seepage capacity and heterogeneity of shale reservoirs more effectively, mercury intrusion capillary pressure (MICP) and the fractal theory were carried out on a suite of the shale samples of the Dongying Depression, Bohai Bay, China. The results demonstrate that shale is characterized by complex and heterogeneous microcosmic pore structure. The pore throat size could be divided into four types: micropores (25-100 nm), mesopores (100-1000 nm), macropores II (1000-r(apex), nm, r(apex), is the pore throat radius corresponding to the maximum point in the plot of mercury saturation versus the mercury saturation divided by capillary pressure) and macropores I (> r(apex), nm). The pore throat radii of shale from the Dongying Depression are mostly mesopores and macropores II. Micropores and macropores Hare the controlling factors of porosity, whereas permeability is dominated primarily by macropores II. The fractal dimension of pore throat are clearly separated into two segments: D1 and D2, corresponding to large pores (> r(apex)) and small pores (< r(apex)), respectively. There are no apparent relationships between D1 and the pore structure parameters, whereas D2 are strongly related to the maximum mercury saturation, entry pressure, average pore throat radius and maximum pore throat radius. These relationships enable D2 to represent the complexity of shale. The mercury capillary curves can be divided into three types based on the shape of the curves: type I, type II, type III. According to these types of pore structure, reservoirs can be classified into three categories. The good reservoirs (type I) are characterized by dominant macropores and mesopores volumes, a large porosity and permeability and a low fractal dimension. Medium reservoirs (type II) have a low oil reservoir potential due to the developed mesopores and micropores. The type III pore system is a poor reservoir that is inadequate for shale oil. Our analyses suggest that MICP coupled with the fractal theory is a powerful tool to evaluate the porous structure of shale.",13,14,7
Fractal Dimension,T-2,"Guo, Xiaobo; Huang, Zhilong; Zhao, Libin; Han, Wei; Ding, Chao; Sun, Xiongwei; Yan, Ruitao; Zhang, Tonghui; Yang, Xuejun; Wang, Ruomei","Pore structure and multi-fractal analysis of tight sandstone using MIP, NMR and NMRC methods: A case study from the Kuqa depression, China",Tight sandstone; Fractal dimension; Pore structure; Kuqa depression,ORDOS BASIN; TARIM BASIN; SIZE DISTRIBUTION; GAS SANDSTONE; OIL; POROSIMETRY; PARAMETERS; RESERVOIRS; DYNAMICS; ROCKS,"The pore structure and fractal characteristic of tight gas sandstone from Cretaceous Bashijiqike Formation in Kuqa depression were investigated, using thin section, scanning electronic microscope (SEM), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR) and NMR cryoporometry (NMRC) measurements. The pores of tight sandstone samples mainly contain residual primary intergranular pores, intergranular and intragranular dissolved pores, micropores related to clay aggregates and microfractures. The MIP, NMR and NMRC analyses show that the pore structure of tight sandstone is complex and heterogeneous at different pore scales, displaying as a multi-fractal feature. Fractal dimension Dg-s (with respect to small pore throats) from MIP and Dn-1 (long T-2 relaxation time, representing large pores and fractures or movable-fluid pores) are negatively correlated with porosity, permeability, median pore throat radius and skewness, and have inverse relationships with bound water saturation (S-bnd). Fractal dimension Dg-b ( > 3.0, with respect to larger pore throats) and Dn-s ( < 2.0, short T-2 relaxation time, representing small pores or bound-water pores) from NMR don't present clear relationships with most of pore structure parameters. Fractal dimension Dc-(1) and Dc-(2) from NMRC show more complex or inconspicuous relationships with pore structure parameters, in the pore diameter size < 500 nm. Hence, Dg-s from MIP and Dn-1 from NMR can be considered as effective parameters for pore structure and fluid properties characterization of tight sandstone. Fractal dimension Dg-b ( > 3.0) and Dn-s ( < 2.0) have no practical significance to characterize the pore structure of tight sandstone. The formation of residual primary intergranular pores and intergranular dissolution pores can reduce the fractal dimension which could be an important sign of effective reservoirs in the study area.",37,39,10
Fractal Dimension,T-2,"Zhao, Peiqiang; Wang, Xixin; Cai, Jianchao; Luo, Miao; Zhang, Jin; Liu, Yuming; Rabiei, Minou; Li, Chuncheng",Multifractal analysis of pore structure of Middle Bakken formation using low temperature N-2 adsorption and NMR measurements,Middle Bakken; Multifractal analysis; N-2 adsorption; Nuclear magnetic resonance (NMR),NUCLEAR-MAGNETIC-RESONANCE; RATE-CONTROLLED POROSIMETRY; FORD SHALE SAMPLES; SICHUAN BASIN; GAS-RESERVOIR; FRACTAL CHARACTERIZATION; ORGANIC-MATTER; OIL; SANDSTONE; DIMENSION,"Understanding the complexity and heterogeneity of pore structure can improve the comprehensive characterization for complex unconventional reservoirs and better exploit those resources. In this paper, multifractal analysis was conducted on low temperature N-2 adsorption and NMR T-2 distribution for the pore structure investigation in Middle Bakken formation in Williston Basin, USA. Results show that the averages of specific surface area, total pore volume, the average pore size of five N-2 adsorption samples are 3.31 m(2)/g, 0.008 cm(3)/g, and 19.57 nm, respectively. Six NMR T(2 )distributions are bimodal and the signals of left dominant peaks are mainly distributed between 0.3 ms and 10 ms. The T-2 logarithmic mean value ranges from 2.18 ms to 2.95 ms with an average value of 2.57 ms. Both N-2 adsorption isotherms and T-2 distribution demonstrated the multifractal nature of different pore sizes. The key multifractal parameter, singularity strength range (Aa) calculated from N-2 adsorption and T-2 distribution are respectively distributed in scopes of 0.72-1.54 and 1.63-2.89, indicating that the heterogeneity of pore space from T-2 distribution is stronger than that from N-2 adsorption. It was observed that the specific surface, micro pore volume, and average pore size are correlated well with Delta alpha. There are no any correlations between Delta alpha and porosity and T-21m, but the cumulative porosity and width of right secondary peaks have an impact on the Delta alpha, which means that the heterogeneity difference between the two methods is attributed by larger pore and micro fractures.",27,27,7
Fractal Dimension,Low Temperature N-2 Adsorption,"Zhao, Peiqiang; Wang, Xixin; Cai, Jianchao; Luo, Miao; Zhang, Jin; Liu, Yuming; Rabiei, Minou; Li, Chuncheng",Multifractal analysis of pore structure of Middle Bakken formation using low temperature N-2 adsorption and NMR measurements,Middle Bakken; Multifractal analysis; N-2 adsorption; Nuclear magnetic resonance (NMR),NUCLEAR-MAGNETIC-RESONANCE; RATE-CONTROLLED POROSIMETRY; FORD SHALE SAMPLES; SICHUAN BASIN; GAS-RESERVOIR; FRACTAL CHARACTERIZATION; ORGANIC-MATTER; OIL; SANDSTONE; DIMENSION,"Understanding the complexity and heterogeneity of pore structure can improve the comprehensive characterization for complex unconventional reservoirs and better exploit those resources. In this paper, multifractal analysis was conducted on low temperature N-2 adsorption and NMR T-2 distribution for the pore structure investigation in Middle Bakken formation in Williston Basin, USA. Results show that the averages of specific surface area, total pore volume, the average pore size of five N-2 adsorption samples are 3.31 m(2)/g, 0.008 cm(3)/g, and 19.57 nm, respectively. Six NMR T(2 )distributions are bimodal and the signals of left dominant peaks are mainly distributed between 0.3 ms and 10 ms. The T-2 logarithmic mean value ranges from 2.18 ms to 2.95 ms with an average value of 2.57 ms. Both N-2 adsorption isotherms and T-2 distribution demonstrated the multifractal nature of different pore sizes. The key multifractal parameter, singularity strength range (Aa) calculated from N-2 adsorption and T-2 distribution are respectively distributed in scopes of 0.72-1.54 and 1.63-2.89, indicating that the heterogeneity of pore space from T-2 distribution is stronger than that from N-2 adsorption. It was observed that the specific surface, micro pore volume, and average pore size are correlated well with Delta alpha. There are no any correlations between Delta alpha and porosity and T-21m, but the cumulative porosity and width of right secondary peaks have an impact on the Delta alpha, which means that the heterogeneity difference between the two methods is attributed by larger pore and micro fractures.",27,27,7
Fractal Dimension,Low Temperature N-2 Adsorption,"Zhao, Junlong; Tang, Dazhen; Qin, Yong; Xu, Hao","Fractal characterization of pore structure for coal macrolithotypes in the Hancheng area, southeastern Ordos Basin, China",Fractal dimension; Pore structure; Adsorption pore; Seepage pore; Coal macrolithotype,CH4 ADSORPTION CAPACITY; EASTERN MARGIN; MERCURY POROSIMETRY; GAS-ADSORPTION; RANK COAL; METHANE; BLOCK; DIMENSION; MODEL; THERMODYNAMICS,"Coalbed methane (CBM) reservoir pore structure is extremely complex and heterogeneous. With the fractal theory, the geometric and structural characteristics of the pore structure could be quantified. However, few studies have aimed to understand the fractal features of compositional-based macrolithotypes (bright, semibright, semi-dull, and dull coals). In this work, samples from the Hancheng area, in the southeastern Ordos Basin, China, were collected to investigate the fractal features of pore structures for macrolithotypes and calculate fractal dimensions (D-a1 and D-a2 for adsorption pores; D-s1 and D(s2)( )for seepage pores) based on low temperature N-2 adsorption and mercury intrusion data, respectively. Meanwhile, the impact of the fractal dimensions on the gas adsorption capacity and the seepage ability were discussed. The results demonstrate that when bright coal turns into dull coal, the vitrinite content, helium permeability, and gas adsorption capacity gradually decrease, while the coal density, mineral content, and ash yield increase. Since the D-a1 and D-s1 either deviate from the natural fractal dimension (2 < D < 3) or have a poor correlation with macrolithotypes, D(a2 )and D-s2 are regarded as the adsorption and seepage pore fractal dimensions, respectively. Of all the coal macrolithotypes, bright coal has the smallest BET specific surface area and micropore proportion, which results in the smallest fractal dimension D-a2, while for the dull coal, this is just the contrary; due to the higher mineral content, a higher D-a2 of the dull coal indicates a more complicated adsorption pore structure, and the coal with a larger Langmuir volume has a smaller D-a2. For the seepage pores, when the bright coal turns into dull coal, the macropore proportion gradually decreases, but the pore proportion tends toward equilibrium, and the mercury withdrawal efficiency increases; the dull coal has a larger D-s2 , indicating a more complex seepage pore structure than that in the bright coal. Due to the decreasing macropore proportion and mineral filling, D-s2 demonstrates an obvious negative correlation with the helium permeability and macropore proportion.",18,18,4
Fractal Dimension,Sichuan BASIN,"Niu, Qinghe; Pan, Jienan; Jin, Yi; Wang, Haichao; Li, Meng; Ji, Zhongmin; Wang, Kai; Wang, Zhenzhi","Fractal study of adsorption-pores in pulverized coals with various metamorphism degrees using N-2 adsorption, X-ray scattering and image analysis methods",Coal rank; Adsorption capacity; N-2 adsorption; SAXS; SEM; Fractal dimension,LOW-RANK COAL; BASIN NW TURKEY; GAS-ADSORPTION; METHANE ADSORPTION; CARBONIFEROUS COALS; NITROGEN ADSORPTION; DEFORMED COALS; SICHUAN BASIN; SURFACE-AREA; DIMENSION,"As a highly heterogeneous material, the porous structure of coal is usually described by fractal dimension, which generally can be obtained by gas adsorption, light scattering and image analysis methods. In this paper, the pore structure (pore volume and specific surface area) and adsorption performance (Langmuir volume and Langmuir pressure) of 12 different rank coal samples were investigated by liquid nitrogen adsorption experiment (LNA) and methane isotherm adsorption experiment. And the fractal characteristics of these coals were studied by three fractal dimensions D-1, D-2 and D-3 acquired from LNA and small angle X-ray scattering (SAXS) and scanning electron microscopy (SEM), respectively. Results indicate that the adsorption pore volume and specific surface area show U-shaped evolutionary trends during the coalification process. The changes of pore volume and specific surface area are dominated by the mechanical compaction and dehydration effects before the second coalification jump (R-o,R-max = 1.3%), while they are then mainly controlled by concomitant metamorphic pores until the fourth coalification jump (R-o,R-max = 3.7%). Langmuir volume first increases and then reaches a steady value at the third coalification jump (R-o,R-max = 2.5%) with the increasing coal rank, however, Langmuir pressure monotonously decreases during the whole coalification process. D-1 and D-2 exhibit a dramatically increase from R-o,R-max = 0.6% to R-o,R-max = 2.0% and then a slowly rise when R-o,R-max increases from 2.0% to 3.5%, which is relevant to the changes of pore structure and macromolecule structure in coal. D-3 increases at a low speed first and then increases at a high speed with the increasing coal rank, which reflects the surface morphology of pores in coal. Fractal dimension D-1, D-2 and D-3 can be used to depict the methane adsorption properties of coal in varying metamorphism degrees. Generally, D-2 is larger than D-1, which is because N-2 adsorption can probe more macropores but SAXS can detect more micropores. Additionally, D-1, D-2 and D-3 are all negatively related to P-L. Our investigations also confirm that SAXS may be more superior to character the adsorption capacity of coal according to its highest relativity. This work clarifies the intrinsic sense and difference for characterising the surface irregularity by various methods, and provides an understanding for the experimental means relating to adsorption pores.",32,32,17
Fractal Dimension,Sichuan BASIN,"Zhao, Peiqiang; Wang, Xixin; Cai, Jianchao; Luo, Miao; Zhang, Jin; Liu, Yuming; Rabiei, Minou; Li, Chuncheng",Multifractal analysis of pore structure of Middle Bakken formation using low temperature N-2 adsorption and NMR measurements,Middle Bakken; Multifractal analysis; N-2 adsorption; Nuclear magnetic resonance (NMR),NUCLEAR-MAGNETIC-RESONANCE; RATE-CONTROLLED POROSIMETRY; FORD SHALE SAMPLES; SICHUAN BASIN; GAS-RESERVOIR; FRACTAL CHARACTERIZATION; ORGANIC-MATTER; OIL; SANDSTONE; DIMENSION,"Understanding the complexity and heterogeneity of pore structure can improve the comprehensive characterization for complex unconventional reservoirs and better exploit those resources. In this paper, multifractal analysis was conducted on low temperature N-2 adsorption and NMR T-2 distribution for the pore structure investigation in Middle Bakken formation in Williston Basin, USA. Results show that the averages of specific surface area, total pore volume, the average pore size of five N-2 adsorption samples are 3.31 m(2)/g, 0.008 cm(3)/g, and 19.57 nm, respectively. Six NMR T(2 )distributions are bimodal and the signals of left dominant peaks are mainly distributed between 0.3 ms and 10 ms. The T-2 logarithmic mean value ranges from 2.18 ms to 2.95 ms with an average value of 2.57 ms. Both N-2 adsorption isotherms and T-2 distribution demonstrated the multifractal nature of different pore sizes. The key multifractal parameter, singularity strength range (Aa) calculated from N-2 adsorption and T-2 distribution are respectively distributed in scopes of 0.72-1.54 and 1.63-2.89, indicating that the heterogeneity of pore space from T-2 distribution is stronger than that from N-2 adsorption. It was observed that the specific surface, micro pore volume, and average pore size are correlated well with Delta alpha. There are no any correlations between Delta alpha and porosity and T-21m, but the cumulative porosity and width of right secondary peaks have an impact on the Delta alpha, which means that the heterogeneity difference between the two methods is attributed by larger pore and micro fractures.",27,27,7
Fractal Dimension,Previous Studies,"Kong, Lingyun; Ostadhassan, Mehdi; Hou, Xiaodong; Mann, Michael; Li, Chunxiao",Microstructure characteristics and fractal analysis of 3D-printed sandstone using micro-CT and SEM-EDS,3D-printed rocks; Microstructures; Sandstone; Micro-computed tomography,RAY COMPUTED-TOMOGRAPHY; MECHANICAL-PROPERTIES; RESERVOIR ROCKS; ORGANIC-MATTER; PORE STRUCTURE; PERMEABILITY; PARTICLES; ALGORITHM; VOLUME; BASIN,"Replicating sedimentary rocks using three-dimensional (3D) printing can support routine reservoir rock analysis in petrophysical and geomechanical experiments, which is done limited in scope due to lack of suitable printing materials and achievable resolution. Following our previous studies on gypsum powder with binder, a new printing material, silica sand, is used and characterized in this study to demonstrate the microstructure and its similarity to Berea Sandstone. Binder jetting printing system was specifically utilized to bond silica sand particles to create intact cylindrical samples without digital porous model as input. Created samples were first scanned by Backscattered Scanning Electron Microscope (BS-SEM) and Energy Dispersive Spectroscopy (EDS) to identify the particles, the packing mode and cement (binder). Next, micro-computed tomography (CT) was used to determine the microstructure of the samples, including the size and the shape of both particles and pores, in the 3D space. In addition, anisotropy that was found to originate from the pore structures was quantified by comparing the characteristics of pores in different directions. Fractal dimensions from different sample sizes, 6 mm and 12 mm in diameter, were also calculated for pore structure analysis in order to illustrate the effect of sample size on pore heterogeneity in 3D printed samples with silica. The results demonstrated the feasibility of substituting 3D-printed sandstones for natural rocks regarding pore structures for experimental validation of petrophysical models.",24,26,10
Fractal Dimension,Previous Studies,"Zhang, Xiangliang; Lin, Baiquan; Zhu, Chuanjie; Yan, Fazhi; Liu, Ting; Liu, Tong; Li, Yanjun",Petrophysical variation of coal treated by cyclic high-voltage electrical pulse for coalbed methane recovery,Pore variation; Cyclic high-voltage electrical pulse; Coalbed methane; Current; Fractal dimension,ADSORPTION CAPACITY; GAS-ADSORPTION; PORE STRUCTURE; SIZE; IMPACT; ORES; NACL; DISINTEGRATION; FRAGMENTATION; CONDUCTIVITY,"Laboratory experiments and field application of high-voltage electrical pulse (HVEP) technology, a good method for coalbed methane (CBM) enhancement, have achieved great progress. However, previous studies mainly concentrated on the crushing effect of a single pulse on coal, ignoring the influence of multiple cyclic electrical pulses on the pore structure. Besides, the current in electrical breakdown was rarely studied. In this study, the effect of cyclic number on pore variation was investigated, and the mechanism of electrical breakdown was discussed by measuring the current waveform. Moreover, the micro fissure and pore variations of coal before and after electrical breakdown were measured by adopting scanning electron microscopy (SEM) and low temperature liquid nitrogen adsorption (LT-N(2)A). Under the action of cyclic HVEP, both Linhua (LH) anthracite coal and Hongliu (HL) bituminous coal can be crushed into small pieces. SEM results indicate that the number of cracks increase with the number of cycle. LT-N(2)A analyses show that the cumulative pore volumes and surface areas of LH and HL coals both increase after electrical breakdown, so does the pore structure fractal dimension, which provides a smoother channel for CBM desorption. Additionally, the great energy instantly injected into the coal could produce huge expansion stress and immediately break the coal from inside. Current waveforms during the breakdown demonstrate that the peak current increase with the number of cycle, whereas the breakdown time decrease with it. This indicates the alteration of electrical properties of coal during the breakdown, which affects the next discharge.",13,14,7
Fractal Dimension,Total Pore Volume,"Zhao, Peiqiang; Wang, Xixin; Cai, Jianchao; Luo, Miao; Zhang, Jin; Liu, Yuming; Rabiei, Minou; Li, Chuncheng",Multifractal analysis of pore structure of Middle Bakken formation using low temperature N-2 adsorption and NMR measurements,Middle Bakken; Multifractal analysis; N-2 adsorption; Nuclear magnetic resonance (NMR),NUCLEAR-MAGNETIC-RESONANCE; RATE-CONTROLLED POROSIMETRY; FORD SHALE SAMPLES; SICHUAN BASIN; GAS-RESERVOIR; FRACTAL CHARACTERIZATION; ORGANIC-MATTER; OIL; SANDSTONE; DIMENSION,"Understanding the complexity and heterogeneity of pore structure can improve the comprehensive characterization for complex unconventional reservoirs and better exploit those resources. In this paper, multifractal analysis was conducted on low temperature N-2 adsorption and NMR T-2 distribution for the pore structure investigation in Middle Bakken formation in Williston Basin, USA. Results show that the averages of specific surface area, total pore volume, the average pore size of five N-2 adsorption samples are 3.31 m(2)/g, 0.008 cm(3)/g, and 19.57 nm, respectively. Six NMR T(2 )distributions are bimodal and the signals of left dominant peaks are mainly distributed between 0.3 ms and 10 ms. The T-2 logarithmic mean value ranges from 2.18 ms to 2.95 ms with an average value of 2.57 ms. Both N-2 adsorption isotherms and T-2 distribution demonstrated the multifractal nature of different pore sizes. The key multifractal parameter, singularity strength range (Aa) calculated from N-2 adsorption and T-2 distribution are respectively distributed in scopes of 0.72-1.54 and 1.63-2.89, indicating that the heterogeneity of pore space from T-2 distribution is stronger than that from N-2 adsorption. It was observed that the specific surface, micro pore volume, and average pore size are correlated well with Delta alpha. There are no any correlations between Delta alpha and porosity and T-21m, but the cumulative porosity and width of right secondary peaks have an impact on the Delta alpha, which means that the heterogeneity difference between the two methods is attributed by larger pore and micro fractures.",27,27,7
Fractal Dimension,Total Pore Volume,Li Fengli; Jiang Bo; Cheng Guoxi; Song Yu; Tang Zheng,"Structural and evolutionary characteristics of pores-microfractures and their influence on coalbed methane exploitation in high-rank brittle tectonically deformed coals of the Yangquan mining area, northeastern Qinshui basin, China",Brittle TDCs; Microfracture; Pore; CBM exploitation,DENSITY-FUNCTIONAL THEORY; SHALE GAS-RESERVOIRS; N-2 ADSORPTION; SEMIANALYTICAL MODEL; FRACTAL DIMENSION; MERCURY INTRUSION; SIZE DISTRIBUTION; SURFACE-AREA; PERMEABILITY; PRESSURE,"The Yangquan mining area is an important anthracite production base in China, but various types of tectonically deformed coals (TDCs) are well developed in its mines and gas outburst accidents take place frequently. By using methods such as optical microscope observation, mercury intrusion porosimetry (MIP) and low pressure nitrogen/carbon dioxide gas adsorption (LP-N-2/CO(2)GA), we tested the structural and evolutionary characteristics of pores-microfractures and their influence on coalbed methane exploitation in high-rank (R-o,R-max = 2.00-2.72%) primary structure coals and brittle TDCs (i.e., cataclastic-, mortor-, and granulitic coals) from the Yangquan mining area. The results show that the tectonic deformation can change the pore-microfracture structure of coals and, thus, their reservoir physical properties. In general, with the enhancement of tectonic deformation, the density of microfractures in coal, which become more and more mussy, gradually increases, the total pore volume (TPV) of coal (pores with a diameter of 5.37-27000 nm) and the pore volume of each pore size range increase, with the greatest increase occurring in pores of 100-1000 nm, and the connectivity between pores is gradually reduced as well. From primary structure coals to granulitic coals, the TPV by the Barret-JoynerHalenda (BJH) model increases with a greater increase in mesopores, and the specific surface area (SSA) by the Brunauer-Emmett-Teller (BET) model shows a trend of ""increase-decrease-increase"", while the average pore diameter changes follow the pattern of ""decrease-increase-decrease"" in 0.7-206 nm. However, tectonic deformation has little effect on micropores with a diameter of less than 1 nm in brittle TDCs. The difference in pore-microfracture structures of different brittle TDCs indicates that the cataclastic coals distribution area is favorable for coalbed methane (CBM) exploitation, while the granulitic coals distribution area is a gas outburst-prone area.",27,27,4
Pressure Gradients,non-Darcy Flow,"Wu, Zhongwei; Cui, Chuanzhi; Lv, Guangzhong; Bing, Shaoxian; Cao, Gang",A multi-linear transient pressure model for multistage fractured horizontal well in tight oil reservoirs with considering threshold pressure gradient and stress sensitivity,Multi-linear transient pressure model; Multistage fractured horizontal well; Stress sensitivity; Threshold pressure gradient; Pedrosa's transformation; Perturbation theory,NON-DARCY FLOW; SHALE; PERMEABILITY; PERFORMANCE,"In general, tight oil reservoirs has a numerous tiny and complicated throats, and ultra-low permeability, which leads to a low-velocity non-Darcy flow when the fluid flows in tight reservoirs. The permeability of tight oil reservoirs is no longer a constant, but a variable, which is dependent on reservoir pressure. In other word, the tight oil reservoir is stress sensitive media. The low-velocity non-Darcy flow and stress sensitivity will greatly affect the bottom hole pressure response. So, the low-velocity non-Darcy flow and stress sensitivity should be taken into consideration when researching the transient pressure behaviors of multistage fractured horizontal wells. Currently, there are many researches on transient pressure behaviors of the multistage fractured horizontal well, but none of these researches has taken the low-velocity non-Darcy flow and stress sensitivity into consideration simultaneously. In this paper, threshold pressure gradient and permeability modulus are used to characterize the low-velocity non-Darcy flow and stress sensitivity, respectively. And, a multi-linear transient pressure model of multistage fractured horizontal well with considering low-velocity non-Darcy flow and stress sensitivity is established. The Pedrosa's transformation, perturbation theory, Laplace transformation and stehfest numerical inverse are used to solve this transient pressure model. The novel model is verified by comparing the result of proposed model with that of Ekaterina Stalagorova's model. According to the dimensionless pressure derivative curve, the flow process can be identified as six regimes: (1)the main fracture linear flow stage, (2)the first transition flow stage, (3)dual-linear flow stage,(4)the second transition flow stage, (5)the formation linear flow stage, (6)the boundary flow stage. Finally, the effects of threshold pressure gradient, permeability modulus and fracture density of stimulated reservoir on dimensionless pressure derivative are analyzed. This research provides theoretical support for correctly understanding the flow law of multistage fractured horizontal well.",42,44,6
Pressure Gradients,non-Darcy Flow,"Teng, Teng; Xue, Yi; Zhang, Cun",Modeling and simulation on heat-injection enhanced coal seam gas recovery with experimentally validated non-Darcy gas flow,Enhanced coal seam gas recovery; Non-Darcy flow; Heat-injection; Thermo-hydro-mechanical model; Modeling and simulation,THERMAL-STIMULATION; SHALE GAS; CO2 INJECTION; MECHANICAL MODEL; CARBON-DIOXIDE; METHANE; PERMEABILITY; WATER; STORAGE; WELL,"Heat-injection into coal seam has gained great attention as a supplementary method for the improvement of unconventional gas recovery from deep reservoirs in recent years. However, it involves a lot of ambiguous interactions among the deformation of formation, the transport of gas and the diffusion of heat in the porous coal media, especially the property of gas. In this paper, the seepage behavior of coal seam gas (CSG) that obeys nonDarcy flow law was directly observed in a conducted laboratory experiments. Then, a general Forchheimer equation was confirmed and strictly validated by the experimental data to characterize the non-Darcy seepage phenomenon. Subsequently, a fully coupled thermo-hydro-mechanical model was mathematically established. Based on the finite element approach, a numerical simulation for heat-injection enhanced coal seam gas recovery was then implemented. The susceptibilities of coal permeability and gas production to the gas sorption, heatmass transfer, and the porosity-seepage characteristics of coal were quantified by a series of numerical scenarios. Final modeling and simulation results reveal that (1) coal seam gas flow obeys non-Darcy law when the gradient of gas pressure is higher, but trends to be laminar flow that obeys Darcy law when the gradient is lower, and (2) heat-injection to stimulate coal seam could improve the production efficiency, increasing the Langmuir volume sorption parameter, the temperature correction coefficient and the initial values of permeability can improve coal permeability and enhance gas production.",18,20,5
Pressure Gradients,non-Darcy Flow,"Chen, Mingqiang; Cheng, Linsong; Wang, Xiukun; Lyu, Chaohui; Cao, Renyi",Pore network modelling of fluid flow in tight formations considering boundary layer effect and media deformation,Stochastic network model; Boundary layer effect; Media deformation effect; Absolute permeability; Tight formations,PERMEABILITY STRESS SENSITIVITY; NON-DARCY FLOW; SPONTANEOUS IMBIBITION; OIL-RESERVOIRS; POROUS-MEDIA; SHALE; MULTISCALE; PHYSICS; LIQUID; RESOLUTION,"Fluid flow in tight formations deviates significantly from that in conventional reservoirs due to the micro/nano pores and high confining pressure; non-linear flow occurs at low displacement pressure gradients. The effects of boundary layer and media deformation on fluid flow cannot be ignored. In this paper, a stochastic network model with anisotropic topology is firstly constructed to represent the complex structures of tight formations. Subsequently, a series of network models with different physical scales are generated to obtain the representative elementary volume (REV). Based on the representative network model, a pore network flow model coupling the boundary layer effect with media deformation is developed. Iterative methods are proposed to solve the strong nonlinear mathematical model. Microtube experiments with different radii and three corresponding representative networks with different distributions of throat radii are employed to verify the accuracy and reliability of the numerical results. After the validation, pore scale flow regularity considering the boundary layer effect and media deformation of tight formations is obtained. Furthermore, the factors influencing pore scale flow, such as the effective stress, aspect ratio, coordination number and fluid viscosity, are studied. The results show that pore scale flow velocity considering the boundary layer effect and media deformation is smaller than that without considering the two mechanisms. Nonlinear flow occurs at low displacement pressure gradients because of the boundary layer effect, and media deformation aggravates the nonlinear phenomenon. Similarly, the absolute permeability also decreases when the two mechanisms are considered. It is no longer constant when boundary layer effect is taken into consideration, which increases with increasing displacement pressure gradient and reaches a plateau when the displacement pressure gradient is large enough. The effects of different factors on pore scale flow considering boundary layer effect and media deformation differ from their roles in conventional flow network models. Although the absolute permeability increases with decreasing aspect ratio and increasing coordination number, the value is far smaller than that without considering the two mechanisms because they result in the compression of the effective flow space. Additionally, the absolute permeability no longer remains unchanged when the variation of fluid viscosity is included. This indicates that the absolute permeability considering the boundary layer effect is not only affected by the pore structures but also the fluid viscosity. The methodology developed in this work provides a novel way to study the effects of boundary layer and media deformation on pore scale flow. The results provide new insights into fluid flow in tight formations.",15,16,6
Pressure Gradients,non-Darcy Flow,"Liu, Wenchao; Yao, Jun; Chen, Zhangxin; Zhu, Weiyao",An exact analytical solution of moving boundary problem of radial fluid flow in an infinite low-permeability reservoir with threshold pressure gradient,Low-permeability reservoir; Threshold pressure gradient; Radial flow; Moving boundary; Similarity transformation; Exact analytical solution,NON-DARCY FLOW; ONE-DIMENSIONAL CONSOLIDATION; MODIFIED BESSEL-FUNCTIONS; LONG POROUS-MEDIA; BINGHAM FLUIDS; HORIZONTAL WELL; GAS-RESERVOIRS; FRACTAL MODEL; VELOCITY; INEQUALITIES,"Many engineering technologies involve the moving boundary problems for the radial seepage flow with a threshold pressure gradient, such as the well testing in the development of low-permeability reservoirs, heavy oil reservoirs and groundwater resources. However, as a result of the strong nonlinearity, an exact analytical solution of the moving boundary problems for the radial seepage flow with a threshold pressure gradient has not been obtained yet. Here, a dimensionless moving boundary mathematical model for the radial fluid flow in an infinite low-permeability reservoir with a threshold pressure gradient is developed first. The setting of a variable well production rate for an inner boundary condition can make the mathematical model exhibit a full self-similarity property. Second, by introducing some similarity transformations, the nonlinear system of PDEs of the model can be equivalently transformed into a closed pseudo-linear system of ODEs, whose exact analytical solution can be easily obtained. What's more, the existence and the uniqueness of the exact analytical solution to the moving boundary model are also proved strictly through the mathematical analysis. Third, it is also strictly proved that the exact analytical solution can be degenerated to that of the model of the Darcy's radial fluid flow as the threshold pressure gradient approaches to zero. Finally, by a comparison of model analytical solutions, it is demonstrated that the moving boundary conditions must be incorporated in the modeling of the radial seepage flow with a threshold pressure gradient; otherwise, the effect of the threshold pressure gradient on the radial seepage flow can be overestimated largely.",14,14,1
Pressure Gradients,Threshold Pressure Gradient,"Wu, Zhongwei; Cui, Chuanzhi; Lv, Guangzhong; Bing, Shaoxian; Cao, Gang",A multi-linear transient pressure model for multistage fractured horizontal well in tight oil reservoirs with considering threshold pressure gradient and stress sensitivity,Multi-linear transient pressure model; Multistage fractured horizontal well; Stress sensitivity; Threshold pressure gradient; Pedrosa's transformation; Perturbation theory,NON-DARCY FLOW; SHALE; PERMEABILITY; PERFORMANCE,"In general, tight oil reservoirs has a numerous tiny and complicated throats, and ultra-low permeability, which leads to a low-velocity non-Darcy flow when the fluid flows in tight reservoirs. The permeability of tight oil reservoirs is no longer a constant, but a variable, which is dependent on reservoir pressure. In other word, the tight oil reservoir is stress sensitive media. The low-velocity non-Darcy flow and stress sensitivity will greatly affect the bottom hole pressure response. So, the low-velocity non-Darcy flow and stress sensitivity should be taken into consideration when researching the transient pressure behaviors of multistage fractured horizontal wells. Currently, there are many researches on transient pressure behaviors of the multistage fractured horizontal well, but none of these researches has taken the low-velocity non-Darcy flow and stress sensitivity into consideration simultaneously. In this paper, threshold pressure gradient and permeability modulus are used to characterize the low-velocity non-Darcy flow and stress sensitivity, respectively. And, a multi-linear transient pressure model of multistage fractured horizontal well with considering low-velocity non-Darcy flow and stress sensitivity is established. The Pedrosa's transformation, perturbation theory, Laplace transformation and stehfest numerical inverse are used to solve this transient pressure model. The novel model is verified by comparing the result of proposed model with that of Ekaterina Stalagorova's model. According to the dimensionless pressure derivative curve, the flow process can be identified as six regimes: (1)the main fracture linear flow stage, (2)the first transition flow stage, (3)dual-linear flow stage,(4)the second transition flow stage, (5)the formation linear flow stage, (6)the boundary flow stage. Finally, the effects of threshold pressure gradient, permeability modulus and fracture density of stimulated reservoir on dimensionless pressure derivative are analyzed. This research provides theoretical support for correctly understanding the flow law of multistage fractured horizontal well.",42,44,6
Pressure Gradients,Threshold Pressure Gradient,"Ye, Wenzhuo; Wang, Xiuyu; Cao, Chenguang; Yu, Wenshuai",A fractal model for threshold pressure gradient of tight oil reservoirs,Tight oil reservoir; Capillary bundle model; Fractal theory; Threshold pressure gradient,BINGHAM FLUIDS; FLOW,"In tight oil reservoir, the flow channel of oil and water is tiny and the boundary layer effect is obvious, resulting in large flow resistance and high threshold pressure gradient. Taking into account of the fractal dimension of the pore throat and the tortuosity, a fractal model for calculating the threshold pressure gradient of tight oil reservoir is established. In this model, the rock is considered as a capillary bundle with different diameter distribution as obtained from high-pressure mercury injection measurements for tight rocks. The mathematical model expresses the fractal threshold pressure gradient as a function of ultimate shear stress (eta(0)), pore throat fractal dimension (D-f ), tortuosity fractal dimension (D-T), the maximum pore radius (r(max)), the characteristic length of the core (L-0), and the connate water saturation (S-wi). For 27 tight cores obtained from Changqing oilfield, threshold pressure gradients were determined using the established model and compared with experimental results to check its accuracy. A good fit was found especially for the rock with lower permeability. The relative error is less than 14% for all the rock tested and is only 1.77% for the cores with permeability in the range of 0.001-0.01mD. This model has the advantage of being able to check the impact of the connate water saturation on the threshold pressure gradient of tight rock, which is usually neglected in previous work. The results show that higher S-wi results in largely increased threshold pressure gradient especially for the rock with permeability lower than 0.01mD. This fractal model is of great importance in predicting the threshold pressure gradient of tight oil reservoir and researching on the flow mechanism of tight oil in porous media.",16,17,4
Pressure Gradients,Threshold Pressure Gradient,"Liu, Wenchao; Yao, Jun; Chen, Zhangxin; Zhu, Weiyao",An exact analytical solution of moving boundary problem of radial fluid flow in an infinite low-permeability reservoir with threshold pressure gradient,Low-permeability reservoir; Threshold pressure gradient; Radial flow; Moving boundary; Similarity transformation; Exact analytical solution,NON-DARCY FLOW; ONE-DIMENSIONAL CONSOLIDATION; MODIFIED BESSEL-FUNCTIONS; LONG POROUS-MEDIA; BINGHAM FLUIDS; HORIZONTAL WELL; GAS-RESERVOIRS; FRACTAL MODEL; VELOCITY; INEQUALITIES,"Many engineering technologies involve the moving boundary problems for the radial seepage flow with a threshold pressure gradient, such as the well testing in the development of low-permeability reservoirs, heavy oil reservoirs and groundwater resources. However, as a result of the strong nonlinearity, an exact analytical solution of the moving boundary problems for the radial seepage flow with a threshold pressure gradient has not been obtained yet. Here, a dimensionless moving boundary mathematical model for the radial fluid flow in an infinite low-permeability reservoir with a threshold pressure gradient is developed first. The setting of a variable well production rate for an inner boundary condition can make the mathematical model exhibit a full self-similarity property. Second, by introducing some similarity transformations, the nonlinear system of PDEs of the model can be equivalently transformed into a closed pseudo-linear system of ODEs, whose exact analytical solution can be easily obtained. What's more, the existence and the uniqueness of the exact analytical solution to the moving boundary model are also proved strictly through the mathematical analysis. Third, it is also strictly proved that the exact analytical solution can be degenerated to that of the model of the Darcy's radial fluid flow as the threshold pressure gradient approaches to zero. Finally, by a comparison of model analytical solutions, it is demonstrated that the moving boundary conditions must be incorporated in the modeling of the radial seepage flow with a threshold pressure gradient; otherwise, the effect of the threshold pressure gradient on the radial seepage flow can be overestimated largely.",14,14,1
Pressure Gradients,Gas,"Kanin, E. A.; Osiptsov, A. A.; Vainshtein, A. L.; Burnaev, E., V",A predictive model for steady-state multiphase pipe flow: Machine learning on lab data,Multiphase flow; Machine learning; Surrogate modeling; Pressure gradient; Flow pattern; Liquid holdup,LIQUID HOLDUP; SLUG,"Engineering simulators used for steady-state multiphase flows in oil and gas wells and pipelines are commonly utilized to predict pressure drop and phase velocities. Such simulators are typically based on either empirical correlations (e.g., Beggs and Brill, Mukherjee and Brill, Duns and Ros) or first-principles mechanistic models (e.g., Ansari, Xiao, TUFFP Unified, Leda Flow Point model, OLGAS). The simulators allow one to evaluate the pressure drop in a multiphase pipe flow with acceptable accuracy. However, the only shortcoming of these correlations and mechanistic models is their applicability (besides steady-state versions of transient simulators such as Leda Flow and OLGA). Empirical correlations are commonly applicable in their respective ranges of data fitting; and mechanistic models are limited by the applicability of the empirically based closure relations that are a part of such models. In order to extend the applicability and the accuracy of the existing accessible methods, a method of pressure drop calculation in the pipeline is proposed. The method is based on well segmentation and calculation of the pressure gradient in each segment using three surrogate models based on Machine Learning (ML) algorithms trained on a representative lab data set from the open literature. The first model predicts the value of a liquid holdup in the segment, the second one determines the flow pattern, and the third one is used to estimate the pressure gradient. To build these models, several ML algorithms are trained such as Random Forest, Gradient Boosting Decision Trees, Support Vector Machine, and Artificial Neural Network, and their predictive abilities are cross-compared. The proposed method for pressure gradient calculation yields R-2 = 0.95 by using the Gradient Boosting algorithm as compared with R-2 = 0.92 in case of Mukherjee and Brill correlation and R-2 = 0.91 when a combination of Ansari and Xiao mechanistic models is utilized. The application of the above-mentioned ML algorithms and the larger database used for their training will allow extending the proposed methodology to a wider applicability range of input parameters as compared to standard accessible techniques. The method for pressure drop prediction based on ML algorithms trained on lab data is also validated on three real field cases. Validation indicates that the proposed model yields the following coefficients of determination: R-2 = 0.806, 0.815 and 0.99 as compared with the highest values obtained by commonly used techniques: R-2 = 0.82 (Beggs and Brill correlation), (Mukherjee and Brill correlation) and R-2 = 0.98 (Beggs and Brill correlation). Hence, the method for calculating the pressure distribution could give comparable or even higher scores on field data by contrast to correlations and mechanistic models. This fact is an indicator that the model can be scalable from the lab to the field conditions without any additional retraining of ML algorithms.",21,21,1
Pressure Gradients,Gas,"Teng, Teng; Xue, Yi; Zhang, Cun",Modeling and simulation on heat-injection enhanced coal seam gas recovery with experimentally validated non-Darcy gas flow,Enhanced coal seam gas recovery; Non-Darcy flow; Heat-injection; Thermo-hydro-mechanical model; Modeling and simulation,THERMAL-STIMULATION; SHALE GAS; CO2 INJECTION; MECHANICAL MODEL; CARBON-DIOXIDE; METHANE; PERMEABILITY; WATER; STORAGE; WELL,"Heat-injection into coal seam has gained great attention as a supplementary method for the improvement of unconventional gas recovery from deep reservoirs in recent years. However, it involves a lot of ambiguous interactions among the deformation of formation, the transport of gas and the diffusion of heat in the porous coal media, especially the property of gas. In this paper, the seepage behavior of coal seam gas (CSG) that obeys nonDarcy flow law was directly observed in a conducted laboratory experiments. Then, a general Forchheimer equation was confirmed and strictly validated by the experimental data to characterize the non-Darcy seepage phenomenon. Subsequently, a fully coupled thermo-hydro-mechanical model was mathematically established. Based on the finite element approach, a numerical simulation for heat-injection enhanced coal seam gas recovery was then implemented. The susceptibilities of coal permeability and gas production to the gas sorption, heatmass transfer, and the porosity-seepage characteristics of coal were quantified by a series of numerical scenarios. Final modeling and simulation results reveal that (1) coal seam gas flow obeys non-Darcy law when the gradient of gas pressure is higher, but trends to be laminar flow that obeys Darcy law when the gradient is lower, and (2) heat-injection to stimulate coal seam could improve the production efficiency, increasing the Langmuir volume sorption parameter, the temperature correction coefficient and the initial values of permeability can improve coal permeability and enhance gas production.",18,20,5
Pressure Gradients,Gas,"Guo, Shaobin; Mao, Wenjing","Division of diagenesis and pore evolution of a Permian Shanxi shale in the Ordos Basin, China",Shale; Pore evolution; Diagenesis; Hydrocarbon production,MATURE POSIDONIA SHALE; ORGANIC-RICH SHALES; GAS-STORAGE; TRANSITIONAL SHALES; BIB-SEM; SIZE DISTRIBUTIONS; SPACE MORPHOLOGY; SURFACE-AREA; HILS AREA; SANDSTONES,"This research analyzed the pore evolution and diagenesis in a Permian Shanxi shale from the Ordos Basin. Thermal simulation method simulated the thermal evolution of organic matter in a sample from mature (R-o = 0.96%) to overmature (R-o = 3.05%). Gas adsorption and mercury intrusion capillary pressure techniques were used to analyze pore-size distribution across a maturation gradient. X-ray diffraction, Focused Ion Beam-Scanning Electron Microscopy and rock pyrolysis techniques were used to divide the stages of diagenesis and pore evolution. Results showed that mesopores and macropores dominate pore volume while micropores and mesopores dominate surface area. Pore volume and surface area initially decreased and then increased with maturity. Kaolinite is converted to illite and illite-smectite mixedlayer in the middle to late diagenesis stage. Pore evolution and diagenesis can be divided into four stages in a sample from mature to overmature. Factors influencing pore-size distribution are different in four stages.",17,17,3
Pressure Gradients,Gas,"Jia, Pin; Cheng, Linsong; Huang, Shijun; Xue, Yongchao; Clarkson, Christopher R.; Williams-Kovacs, Jesse D.; Wang, Suran; Wang, Deqiang",Dynamic coupling of analytical linear flow solution and numerical fracture model for simulating early-time flowback of fractured tight oil wells (planar fracture and complex fracture network),Linear flow; Flowback; Flow regimes; Tight oil reservoir,MULTIFRACTURED HORIZONTAL WELLS; 2-PHASE FLOWBACK; SEMIANALYTICAL MODEL; SECONDARY FRACTURES; HYDRAULIC FRACTURE; TRANSIENT-BEHAVIOR; GAS; SYSTEM,"Quantitative analysis of flowback data provides an early opportunity to interpret hydraulic fracture properties of fractured wells in unconventional reservoirs. In recent years, a number of studies have been dedicated to the analysis of single-phase flow data prior to hydrocarbon breakthrough and multi-phase flow data after hydrocarbon breakthrough during flowback. This study provides a new model to simulate flowback of fractured tight oil wells with planar fractures or a complex fracture network. In the model, fractures are discretized into a number of segments and the fully numerical method is used to model fracture flow. It is assumed that the pressure interference in the matrix caused by these fracture segments can be accounted using a no-flow boundary condition and that the drainage volumes of fracture segments form isolated regions to allow for linear flow from the matrix to each segment. To model this behavior, matrix flow is simulated using the analytical transient linear flow solution which is dynamically coupled with the fracture flow model by imposing continuity of pressure and flux on the fracture surfaces. The model is simple, but rigorous enough to take into account the important physics of the fracture system, including arbitrary fracture geometries and fracture conductivity distributions. The pressure and saturation gradients of each phase in fractures are accounted for. The ease of model setup and improved computational performance makes it convenient for practical application. The new model is verified with a commercial reservoir simulator. Investigation of the assumption of no-flow boundary condition for the pressure interference in the matrix caused by the fracture segments reveals that the assumption becomes poorer with increasing matrix permeability and decreasing fracture permeability. Flow regime analysis demonstrates that, for planar fractures, water exhibits an early transient linear flow period (first linear flow in the fracture) followed by boundary-dominated flow (first boundary-dominated flow in the fracture) prior to hydrocarbon breakthrough, after which a second transient linear flow in the fracture develops. The final flow period is boundary-dominated flow (second boundary-dominated flow in the fracture), indicating the end time of the flowback period. At this stage, oil will be the dominant phase in the fracture, and will exhibit transient linear flow in the matrix, which is the first flow-regime typically observed during the long-term production period. The case of a complex fracture network exhibits a similar sequence of flow regimes. The second transient linear flow for this case has not been discussed in the literature. The development of this flow period may be caused by the maintenance of fracture pressure, and decrease of water relative permeability due to hydrocarbon contribution from the matrix. A field example from western Canada exhibits the flow regimes noted above and is history-matched successfully using the new model. The results demonstrate the practical application of the new model for deriving reservoir/fracture properties from flowback data and for forecasting.",15,15,3
Pressure Gradients,Results Show,"Guo, Shaobin; Mao, Wenjing","Division of diagenesis and pore evolution of a Permian Shanxi shale in the Ordos Basin, China",Shale; Pore evolution; Diagenesis; Hydrocarbon production,MATURE POSIDONIA SHALE; ORGANIC-RICH SHALES; GAS-STORAGE; TRANSITIONAL SHALES; BIB-SEM; SIZE DISTRIBUTIONS; SPACE MORPHOLOGY; SURFACE-AREA; HILS AREA; SANDSTONES,"This research analyzed the pore evolution and diagenesis in a Permian Shanxi shale from the Ordos Basin. Thermal simulation method simulated the thermal evolution of organic matter in a sample from mature (R-o = 0.96%) to overmature (R-o = 3.05%). Gas adsorption and mercury intrusion capillary pressure techniques were used to analyze pore-size distribution across a maturation gradient. X-ray diffraction, Focused Ion Beam-Scanning Electron Microscopy and rock pyrolysis techniques were used to divide the stages of diagenesis and pore evolution. Results showed that mesopores and macropores dominate pore volume while micropores and mesopores dominate surface area. Pore volume and surface area initially decreased and then increased with maturity. Kaolinite is converted to illite and illite-smectite mixedlayer in the middle to late diagenesis stage. Pore evolution and diagenesis can be divided into four stages in a sample from mature to overmature. Factors influencing pore-size distribution are different in four stages.",17,17,3
Pressure Gradients,Results Show,"Perissinotto, Rodolfo Marcilli; Verde, William Monte; Gallassi, Mariana; Goncalves, Gabriel F. N.; de Castro, Marcelo Souza; Carneiro, Joao; Biazussi, Jorge Luiz; Bannwart, Antonio Carlos",Experimental and numerical study of oil drop motion within an ESP impeller,Centrifugal pump; Two-phase liquid-liquid flow; Flow visualization; Oil drop dynamics; CFD,2-PHASE FLOW PATTERNS; CENTRIFUGAL PUMPS; WATER FLOW,"The Electrical Submersible Pump (ESP) is a multistage centrifugal pump used in the petroleum industry as an artificial lift method. The ESP usually works with the presence of two-phase liquid-liquid flows that constitute dispersions and emulsions, causing performance losses and operational problems. This research aims to investigate the behavior and evaluate the dynamics of individual oil drops in an oil-in-water dispersion within an ESP impeller. The study adopts experimental and numerical approaches. Initially, experiments were performed using an experimental facility with a high-speed camera and an ESP prototype working at 600 rpm and 900 rpm, for water flows around the Best Efficiency Point (BEP) and with the injection of oil drops at a low flow rate. The acquired images were processed, and a drop sample was tracked, enabling the analysis of the size, shape, path, velocity, and acceleration of the oil drops. Numerical simulations were executed in ANSYS (R) software to define relevant parameters related to water and oil drops, such as velocities, accelerations, forces, turbulent dissipation, and residence time. The images reveal a unique flow pattern of dispersed drops in a continuous water phase. The oil drops' diameters vary from tenths of a millimeter to around 3 mm. The drops' trajectories can be classified into three different regions within the impeller channels. The drops' velocities stay in the order of 1 m/s, while accelerations can reach hundreds of m/s(2). The velocity profiles show that the oil drops tend to decelerate during their trajectory, while the acceleration profiles suggest peaks at the channel inlet and outlet. High intense turbulence is present in the impeller entrance zone. The evaluation of the residence time and the particle Reynolds number suggest that smaller oil drops follow the water streamlines, while larger oil drops tend to be affected by external forces. The main forces that govern the oil drop motion are the drag, the pressure gradient, and the virtual mass forces. The force from the pressure gradient is tenfold greater than the force from the drag. The virtual mass effect is significant only in the impeller inlet. In general, in this research, numerical results show a satisfactory agreement with the experimental data.",17,17,0
Pressure Gradients,Results Show,"Ye, Wenzhuo; Wang, Xiuyu; Cao, Chenguang; Yu, Wenshuai",A fractal model for threshold pressure gradient of tight oil reservoirs,Tight oil reservoir; Capillary bundle model; Fractal theory; Threshold pressure gradient,BINGHAM FLUIDS; FLOW,"In tight oil reservoir, the flow channel of oil and water is tiny and the boundary layer effect is obvious, resulting in large flow resistance and high threshold pressure gradient. Taking into account of the fractal dimension of the pore throat and the tortuosity, a fractal model for calculating the threshold pressure gradient of tight oil reservoir is established. In this model, the rock is considered as a capillary bundle with different diameter distribution as obtained from high-pressure mercury injection measurements for tight rocks. The mathematical model expresses the fractal threshold pressure gradient as a function of ultimate shear stress (eta(0)), pore throat fractal dimension (D-f ), tortuosity fractal dimension (D-T), the maximum pore radius (r(max)), the characteristic length of the core (L-0), and the connate water saturation (S-wi). For 27 tight cores obtained from Changqing oilfield, threshold pressure gradients were determined using the established model and compared with experimental results to check its accuracy. A good fit was found especially for the rock with lower permeability. The relative error is less than 14% for all the rock tested and is only 1.77% for the cores with permeability in the range of 0.001-0.01mD. This model has the advantage of being able to check the impact of the connate water saturation on the threshold pressure gradient of tight rock, which is usually neglected in previous work. The results show that higher S-wi results in largely increased threshold pressure gradient especially for the rock with permeability lower than 0.01mD. This fractal model is of great importance in predicting the threshold pressure gradient of tight oil reservoir and researching on the flow mechanism of tight oil in porous media.",16,17,4
Pressure Gradients,Results Show,"Chen, Mingqiang; Cheng, Linsong; Wang, Xiukun; Lyu, Chaohui; Cao, Renyi",Pore network modelling of fluid flow in tight formations considering boundary layer effect and media deformation,Stochastic network model; Boundary layer effect; Media deformation effect; Absolute permeability; Tight formations,PERMEABILITY STRESS SENSITIVITY; NON-DARCY FLOW; SPONTANEOUS IMBIBITION; OIL-RESERVOIRS; POROUS-MEDIA; SHALE; MULTISCALE; PHYSICS; LIQUID; RESOLUTION,"Fluid flow in tight formations deviates significantly from that in conventional reservoirs due to the micro/nano pores and high confining pressure; non-linear flow occurs at low displacement pressure gradients. The effects of boundary layer and media deformation on fluid flow cannot be ignored. In this paper, a stochastic network model with anisotropic topology is firstly constructed to represent the complex structures of tight formations. Subsequently, a series of network models with different physical scales are generated to obtain the representative elementary volume (REV). Based on the representative network model, a pore network flow model coupling the boundary layer effect with media deformation is developed. Iterative methods are proposed to solve the strong nonlinear mathematical model. Microtube experiments with different radii and three corresponding representative networks with different distributions of throat radii are employed to verify the accuracy and reliability of the numerical results. After the validation, pore scale flow regularity considering the boundary layer effect and media deformation of tight formations is obtained. Furthermore, the factors influencing pore scale flow, such as the effective stress, aspect ratio, coordination number and fluid viscosity, are studied. The results show that pore scale flow velocity considering the boundary layer effect and media deformation is smaller than that without considering the two mechanisms. Nonlinear flow occurs at low displacement pressure gradients because of the boundary layer effect, and media deformation aggravates the nonlinear phenomenon. Similarly, the absolute permeability also decreases when the two mechanisms are considered. It is no longer constant when boundary layer effect is taken into consideration, which increases with increasing displacement pressure gradient and reaches a plateau when the displacement pressure gradient is large enough. The effects of different factors on pore scale flow considering boundary layer effect and media deformation differ from their roles in conventional flow network models. Although the absolute permeability increases with decreasing aspect ratio and increasing coordination number, the value is far smaller than that without considering the two mechanisms because they result in the compression of the effective flow space. Additionally, the absolute permeability no longer remains unchanged when the variation of fluid viscosity is included. This indicates that the absolute permeability considering the boundary layer effect is not only affected by the pore structures but also the fluid viscosity. The methodology developed in this work provides a novel way to study the effects of boundary layer and media deformation on pore scale flow. The results provide new insights into fluid flow in tight formations.",15,16,6
Pressure Gradients,Linear Flow,"Wu, Zhongwei; Cui, Chuanzhi; Lv, Guangzhong; Bing, Shaoxian; Cao, Gang",A multi-linear transient pressure model for multistage fractured horizontal well in tight oil reservoirs with considering threshold pressure gradient and stress sensitivity,Multi-linear transient pressure model; Multistage fractured horizontal well; Stress sensitivity; Threshold pressure gradient; Pedrosa's transformation; Perturbation theory,NON-DARCY FLOW; SHALE; PERMEABILITY; PERFORMANCE,"In general, tight oil reservoirs has a numerous tiny and complicated throats, and ultra-low permeability, which leads to a low-velocity non-Darcy flow when the fluid flows in tight reservoirs. The permeability of tight oil reservoirs is no longer a constant, but a variable, which is dependent on reservoir pressure. In other word, the tight oil reservoir is stress sensitive media. The low-velocity non-Darcy flow and stress sensitivity will greatly affect the bottom hole pressure response. So, the low-velocity non-Darcy flow and stress sensitivity should be taken into consideration when researching the transient pressure behaviors of multistage fractured horizontal wells. Currently, there are many researches on transient pressure behaviors of the multistage fractured horizontal well, but none of these researches has taken the low-velocity non-Darcy flow and stress sensitivity into consideration simultaneously. In this paper, threshold pressure gradient and permeability modulus are used to characterize the low-velocity non-Darcy flow and stress sensitivity, respectively. And, a multi-linear transient pressure model of multistage fractured horizontal well with considering low-velocity non-Darcy flow and stress sensitivity is established. The Pedrosa's transformation, perturbation theory, Laplace transformation and stehfest numerical inverse are used to solve this transient pressure model. The novel model is verified by comparing the result of proposed model with that of Ekaterina Stalagorova's model. According to the dimensionless pressure derivative curve, the flow process can be identified as six regimes: (1)the main fracture linear flow stage, (2)the first transition flow stage, (3)dual-linear flow stage,(4)the second transition flow stage, (5)the formation linear flow stage, (6)the boundary flow stage. Finally, the effects of threshold pressure gradient, permeability modulus and fracture density of stimulated reservoir on dimensionless pressure derivative are analyzed. This research provides theoretical support for correctly understanding the flow law of multistage fractured horizontal well.",42,44,6
Pressure Gradients,Linear Flow,"Jia, Pin; Cheng, Linsong; Huang, Shijun; Xue, Yongchao; Clarkson, Christopher R.; Williams-Kovacs, Jesse D.; Wang, Suran; Wang, Deqiang",Dynamic coupling of analytical linear flow solution and numerical fracture model for simulating early-time flowback of fractured tight oil wells (planar fracture and complex fracture network),Linear flow; Flowback; Flow regimes; Tight oil reservoir,MULTIFRACTURED HORIZONTAL WELLS; 2-PHASE FLOWBACK; SEMIANALYTICAL MODEL; SECONDARY FRACTURES; HYDRAULIC FRACTURE; TRANSIENT-BEHAVIOR; GAS; SYSTEM,"Quantitative analysis of flowback data provides an early opportunity to interpret hydraulic fracture properties of fractured wells in unconventional reservoirs. In recent years, a number of studies have been dedicated to the analysis of single-phase flow data prior to hydrocarbon breakthrough and multi-phase flow data after hydrocarbon breakthrough during flowback. This study provides a new model to simulate flowback of fractured tight oil wells with planar fractures or a complex fracture network. In the model, fractures are discretized into a number of segments and the fully numerical method is used to model fracture flow. It is assumed that the pressure interference in the matrix caused by these fracture segments can be accounted using a no-flow boundary condition and that the drainage volumes of fracture segments form isolated regions to allow for linear flow from the matrix to each segment. To model this behavior, matrix flow is simulated using the analytical transient linear flow solution which is dynamically coupled with the fracture flow model by imposing continuity of pressure and flux on the fracture surfaces. The model is simple, but rigorous enough to take into account the important physics of the fracture system, including arbitrary fracture geometries and fracture conductivity distributions. The pressure and saturation gradients of each phase in fractures are accounted for. The ease of model setup and improved computational performance makes it convenient for practical application. The new model is verified with a commercial reservoir simulator. Investigation of the assumption of no-flow boundary condition for the pressure interference in the matrix caused by the fracture segments reveals that the assumption becomes poorer with increasing matrix permeability and decreasing fracture permeability. Flow regime analysis demonstrates that, for planar fractures, water exhibits an early transient linear flow period (first linear flow in the fracture) followed by boundary-dominated flow (first boundary-dominated flow in the fracture) prior to hydrocarbon breakthrough, after which a second transient linear flow in the fracture develops. The final flow period is boundary-dominated flow (second boundary-dominated flow in the fracture), indicating the end time of the flowback period. At this stage, oil will be the dominant phase in the fracture, and will exhibit transient linear flow in the matrix, which is the first flow-regime typically observed during the long-term production period. The case of a complex fracture network exhibits a similar sequence of flow regimes. The second transient linear flow for this case has not been discussed in the literature. The development of this flow period may be caused by the maintenance of fracture pressure, and decrease of water relative permeability due to hydrocarbon contribution from the matrix. A field example from western Canada exhibits the flow regimes noted above and is history-matched successfully using the new model. The results demonstrate the practical application of the new model for deriving reservoir/fracture properties from flowback data and for forecasting.",15,15,3
Pressure Gradients,Boundary Layer Effect,"Ye, Wenzhuo; Wang, Xiuyu; Cao, Chenguang; Yu, Wenshuai",A fractal model for threshold pressure gradient of tight oil reservoirs,Tight oil reservoir; Capillary bundle model; Fractal theory; Threshold pressure gradient,BINGHAM FLUIDS; FLOW,"In tight oil reservoir, the flow channel of oil and water is tiny and the boundary layer effect is obvious, resulting in large flow resistance and high threshold pressure gradient. Taking into account of the fractal dimension of the pore throat and the tortuosity, a fractal model for calculating the threshold pressure gradient of tight oil reservoir is established. In this model, the rock is considered as a capillary bundle with different diameter distribution as obtained from high-pressure mercury injection measurements for tight rocks. The mathematical model expresses the fractal threshold pressure gradient as a function of ultimate shear stress (eta(0)), pore throat fractal dimension (D-f ), tortuosity fractal dimension (D-T), the maximum pore radius (r(max)), the characteristic length of the core (L-0), and the connate water saturation (S-wi). For 27 tight cores obtained from Changqing oilfield, threshold pressure gradients were determined using the established model and compared with experimental results to check its accuracy. A good fit was found especially for the rock with lower permeability. The relative error is less than 14% for all the rock tested and is only 1.77% for the cores with permeability in the range of 0.001-0.01mD. This model has the advantage of being able to check the impact of the connate water saturation on the threshold pressure gradient of tight rock, which is usually neglected in previous work. The results show that higher S-wi results in largely increased threshold pressure gradient especially for the rock with permeability lower than 0.01mD. This fractal model is of great importance in predicting the threshold pressure gradient of tight oil reservoir and researching on the flow mechanism of tight oil in porous media.",16,17,4
Pressure Gradients,Boundary Layer Effect,"Chen, Mingqiang; Cheng, Linsong; Wang, Xiukun; Lyu, Chaohui; Cao, Renyi",Pore network modelling of fluid flow in tight formations considering boundary layer effect and media deformation,Stochastic network model; Boundary layer effect; Media deformation effect; Absolute permeability; Tight formations,PERMEABILITY STRESS SENSITIVITY; NON-DARCY FLOW; SPONTANEOUS IMBIBITION; OIL-RESERVOIRS; POROUS-MEDIA; SHALE; MULTISCALE; PHYSICS; LIQUID; RESOLUTION,"Fluid flow in tight formations deviates significantly from that in conventional reservoirs due to the micro/nano pores and high confining pressure; non-linear flow occurs at low displacement pressure gradients. The effects of boundary layer and media deformation on fluid flow cannot be ignored. In this paper, a stochastic network model with anisotropic topology is firstly constructed to represent the complex structures of tight formations. Subsequently, a series of network models with different physical scales are generated to obtain the representative elementary volume (REV). Based on the representative network model, a pore network flow model coupling the boundary layer effect with media deformation is developed. Iterative methods are proposed to solve the strong nonlinear mathematical model. Microtube experiments with different radii and three corresponding representative networks with different distributions of throat radii are employed to verify the accuracy and reliability of the numerical results. After the validation, pore scale flow regularity considering the boundary layer effect and media deformation of tight formations is obtained. Furthermore, the factors influencing pore scale flow, such as the effective stress, aspect ratio, coordination number and fluid viscosity, are studied. The results show that pore scale flow velocity considering the boundary layer effect and media deformation is smaller than that without considering the two mechanisms. Nonlinear flow occurs at low displacement pressure gradients because of the boundary layer effect, and media deformation aggravates the nonlinear phenomenon. Similarly, the absolute permeability also decreases when the two mechanisms are considered. It is no longer constant when boundary layer effect is taken into consideration, which increases with increasing displacement pressure gradient and reaches a plateau when the displacement pressure gradient is large enough. The effects of different factors on pore scale flow considering boundary layer effect and media deformation differ from their roles in conventional flow network models. Although the absolute permeability increases with decreasing aspect ratio and increasing coordination number, the value is far smaller than that without considering the two mechanisms because they result in the compression of the effective flow space. Additionally, the absolute permeability no longer remains unchanged when the variation of fluid viscosity is included. This indicates that the absolute permeability considering the boundary layer effect is not only affected by the pore structures but also the fluid viscosity. The methodology developed in this work provides a novel way to study the effects of boundary layer and media deformation on pore scale flow. The results provide new insights into fluid flow in tight formations.",15,16,6
Pressure Gradients,Stress Sensitivity,"Wu, Zhongwei; Cui, Chuanzhi; Lv, Guangzhong; Bing, Shaoxian; Cao, Gang",A multi-linear transient pressure model for multistage fractured horizontal well in tight oil reservoirs with considering threshold pressure gradient and stress sensitivity,Multi-linear transient pressure model; Multistage fractured horizontal well; Stress sensitivity; Threshold pressure gradient; Pedrosa's transformation; Perturbation theory,NON-DARCY FLOW; SHALE; PERMEABILITY; PERFORMANCE,"In general, tight oil reservoirs has a numerous tiny and complicated throats, and ultra-low permeability, which leads to a low-velocity non-Darcy flow when the fluid flows in tight reservoirs. The permeability of tight oil reservoirs is no longer a constant, but a variable, which is dependent on reservoir pressure. In other word, the tight oil reservoir is stress sensitive media. The low-velocity non-Darcy flow and stress sensitivity will greatly affect the bottom hole pressure response. So, the low-velocity non-Darcy flow and stress sensitivity should be taken into consideration when researching the transient pressure behaviors of multistage fractured horizontal wells. Currently, there are many researches on transient pressure behaviors of the multistage fractured horizontal well, but none of these researches has taken the low-velocity non-Darcy flow and stress sensitivity into consideration simultaneously. In this paper, threshold pressure gradient and permeability modulus are used to characterize the low-velocity non-Darcy flow and stress sensitivity, respectively. And, a multi-linear transient pressure model of multistage fractured horizontal well with considering low-velocity non-Darcy flow and stress sensitivity is established. The Pedrosa's transformation, perturbation theory, Laplace transformation and stehfest numerical inverse are used to solve this transient pressure model. The novel model is verified by comparing the result of proposed model with that of Ekaterina Stalagorova's model. According to the dimensionless pressure derivative curve, the flow process can be identified as six regimes: (1)the main fracture linear flow stage, (2)the first transition flow stage, (3)dual-linear flow stage,(4)the second transition flow stage, (5)the formation linear flow stage, (6)the boundary flow stage. Finally, the effects of threshold pressure gradient, permeability modulus and fracture density of stimulated reservoir on dimensionless pressure derivative are analyzed. This research provides theoretical support for correctly understanding the flow law of multistage fractured horizontal well.",42,44,6
Pressure Gradients,Stress Sensitivity,"Chen, Mingqiang; Cheng, Linsong; Wang, Xiukun; Lyu, Chaohui; Cao, Renyi",Pore network modelling of fluid flow in tight formations considering boundary layer effect and media deformation,Stochastic network model; Boundary layer effect; Media deformation effect; Absolute permeability; Tight formations,PERMEABILITY STRESS SENSITIVITY; NON-DARCY FLOW; SPONTANEOUS IMBIBITION; OIL-RESERVOIRS; POROUS-MEDIA; SHALE; MULTISCALE; PHYSICS; LIQUID; RESOLUTION,"Fluid flow in tight formations deviates significantly from that in conventional reservoirs due to the micro/nano pores and high confining pressure; non-linear flow occurs at low displacement pressure gradients. The effects of boundary layer and media deformation on fluid flow cannot be ignored. In this paper, a stochastic network model with anisotropic topology is firstly constructed to represent the complex structures of tight formations. Subsequently, a series of network models with different physical scales are generated to obtain the representative elementary volume (REV). Based on the representative network model, a pore network flow model coupling the boundary layer effect with media deformation is developed. Iterative methods are proposed to solve the strong nonlinear mathematical model. Microtube experiments with different radii and three corresponding representative networks with different distributions of throat radii are employed to verify the accuracy and reliability of the numerical results. After the validation, pore scale flow regularity considering the boundary layer effect and media deformation of tight formations is obtained. Furthermore, the factors influencing pore scale flow, such as the effective stress, aspect ratio, coordination number and fluid viscosity, are studied. The results show that pore scale flow velocity considering the boundary layer effect and media deformation is smaller than that without considering the two mechanisms. Nonlinear flow occurs at low displacement pressure gradients because of the boundary layer effect, and media deformation aggravates the nonlinear phenomenon. Similarly, the absolute permeability also decreases when the two mechanisms are considered. It is no longer constant when boundary layer effect is taken into consideration, which increases with increasing displacement pressure gradient and reaches a plateau when the displacement pressure gradient is large enough. The effects of different factors on pore scale flow considering boundary layer effect and media deformation differ from their roles in conventional flow network models. Although the absolute permeability increases with decreasing aspect ratio and increasing coordination number, the value is far smaller than that without considering the two mechanisms because they result in the compression of the effective flow space. Additionally, the absolute permeability no longer remains unchanged when the variation of fluid viscosity is included. This indicates that the absolute permeability considering the boundary layer effect is not only affected by the pore structures but also the fluid viscosity. The methodology developed in this work provides a novel way to study the effects of boundary layer and media deformation on pore scale flow. The results provide new insights into fluid flow in tight formations.",15,16,6
Pressure Gradients,Crude Oil,"Aldousary, Salem; Kovscek, Anthony R.",The diffusion of water through oil contributes to spontaneous emulsification during low salinity waterflooding,Waterflooding; Microfluidics; Low salinity; Emulsion; Spontaneous,BRINE COMPOSITION; CRUDE-OIL; RECOVERY; MECHANISMS; EOR,"Increases in oil recovery due to Low Salinity Waterfloods (LSW) have been widely investigated. Literature is abundant with studies attempting to pinpoint the relevant mechanisms involved in the LSW process. Recently, there was clear evidence of spontaneous formation of emulsions during LSW under certain conditions. This work examines the diffusion of water through oil as a contributing factor for spontaneous emulsification during LSW. Experimental observations are pore scale using etched-silicon micromodels. Observations are accompanied by pore-scale mass transfer calculations. Spontaneous emulsification is observed as a result of so-called ""low salinity water"" and crude oil phases contacting under non-equilibrium conditions. The experimental observations provide clear evidence that physical contact between oil and low salinity water phases is imperative for emulsification. In addition, it is concluded that a larger salinity gradient results in greater emulsion concentrations. In such cases, the crude oil is preequilibrated through exposure to a formation brine that has substantial salinity and divalent cations. Emulsification results as the oil phase comes into equilibrium with a brine of lower salinity and different composition. A key mechanism is the osmotic pressure imbalance between water and oil phases that drives water into the oil phase by diffusion. Water reaches a supersaturated state and spontaneous nucleation of the water phase results in emulsions, under appropriate conditions. The experimental and numerical modeling schemes presented here demonstrate and quantify time scales of water-in-oil emulsion formation.",25,25,2
Pressure Gradients,Crude Oil,"Abedi, Behbood; Mendes, Rafael; de Souza Mendes, Paulo R.",Startup flow of yield-stress non-thixotropic and thixotropic materials in a tube,Startup flow; Gelled waxy crude oil; Yield stress materials; Thixotropy; Wall slip,WAXY CRUDE OILS; WALL SLIP; RHEOLOGICAL BEHAVIOR; LAPONITE; MODEL; SUSPENSIONS; FLUID; EMULSIONS,"An experimental study of the flow of yield stress materials was conducted. The main goal was to understand the relationship between the minimum axial pressure gradient required for the onset of motion and the rheological properties. The sought-for application is the startup flow of waxy crude oils in subsea pipelines. We examined two types of yield stress materials, namely a non-thixotropic acrylic polymer solution and a layered silicate suspension which presents thixotropic properties. We observed that for both materials the measured minimum axial pressure gradient was in good agreement with the prediction of a simple force balance. On the other hand, a puzzling fact is observed in the oil industry, namely that the just mentioned force balance result grossly overestimates the minimum axial pressure gradient for the case of gelled waxy crude oils. One often evoked explanation is the thixotropic behavior of the gelled crude, but the present results serve to falsify it.",14,14,3
Pressure Gradients,Water Flooding,"Aldousary, Salem; Kovscek, Anthony R.",The diffusion of water through oil contributes to spontaneous emulsification during low salinity waterflooding,Waterflooding; Microfluidics; Low salinity; Emulsion; Spontaneous,BRINE COMPOSITION; CRUDE-OIL; RECOVERY; MECHANISMS; EOR,"Increases in oil recovery due to Low Salinity Waterfloods (LSW) have been widely investigated. Literature is abundant with studies attempting to pinpoint the relevant mechanisms involved in the LSW process. Recently, there was clear evidence of spontaneous formation of emulsions during LSW under certain conditions. This work examines the diffusion of water through oil as a contributing factor for spontaneous emulsification during LSW. Experimental observations are pore scale using etched-silicon micromodels. Observations are accompanied by pore-scale mass transfer calculations. Spontaneous emulsification is observed as a result of so-called ""low salinity water"" and crude oil phases contacting under non-equilibrium conditions. The experimental observations provide clear evidence that physical contact between oil and low salinity water phases is imperative for emulsification. In addition, it is concluded that a larger salinity gradient results in greater emulsion concentrations. In such cases, the crude oil is preequilibrated through exposure to a formation brine that has substantial salinity and divalent cations. Emulsification results as the oil phase comes into equilibrium with a brine of lower salinity and different composition. A key mechanism is the osmotic pressure imbalance between water and oil phases that drives water into the oil phase by diffusion. Water reaches a supersaturated state and spontaneous nucleation of the water phase results in emulsions, under appropriate conditions. The experimental and numerical modeling schemes presented here demonstrate and quantify time scales of water-in-oil emulsion formation.",25,25,2
Pressure Gradients,Water Flooding,"Aitkulov, Almas; Mohanty, Kishore K.",Investigation of alkaline-surfactant-polymer flooding in a quarter five-spot sandpack for viscous oil recovery,Viscous oil recovery; Chemical flooding; Enhanced oil recovery; Alkaline-surfactant-polymer flooding; Optimum viscosity,,"The alkaline-surfactant-polymer (ASP) flood has been shown in the past to reduce residual oil saturation significantly after waterflood. ASP floods for light oils are designed to be stable where the mobility ratio of the oil bank to the ASP slug is kept close to one. For viscous oils, such stable recovery processes may be unreasonably slow due higher oil viscosity. The goal of this paper is to study unstable ASP flooding (i.e., oil to ASP slug mobility ratio < 1) in secondary and tertiary modes. A viscous oil of viscosity 100 cp was displaced by an ASP slug in a quarter 5-spot sandpack. The ASP formulation was developed by studying the phase behavior of the oil with several alkaline-surfactant formulations. The effectiveness of the ASP formulation was validated in a 1D sandpack by conducing a water flood followed by a stable tertiary ASP flood. A reservoir sand was used to create a sandpack inside a square steel cell similar to a quarter five-spot pattern. Several ASP floods were then conducted in this cell to study both the displacement efficiency and the sweep efficiency of ASP floods. The tertiary ASP flood recovered most of the oil (similar to 98% of OOIP) when the ASP slug viscosity exceeded the oil viscosity, but pressure gradients were high at similar to 1 ft/d injection. When the ASP slug viscosity was lowered to about 1/3 of the oil viscosity, the oil recovery dropped slightly to 90% OOIP, but the pressure gradient decreased significantly. As the extent of waterflood preceding the ASP flood became shorter, the oil was recovered faster for the same pore volumes injected. The ultimate recovery was independent of the extent of waterflood. The laboratory 5-spot floods were modeled by the simulator UTCHEM. The calibrated simulator can be used at the field scale to determine optimum viscosity ratio and ASP flood timing for viscous oil reservoirs.",14,14,2
Pressure Gradients,"Flow Patterns,Pressure Drop","Kanin, E. A.; Osiptsov, A. A.; Vainshtein, A. L.; Burnaev, E., V",A predictive model for steady-state multiphase pipe flow: Machine learning on lab data,Multiphase flow; Machine learning; Surrogate modeling; Pressure gradient; Flow pattern; Liquid holdup,LIQUID HOLDUP; SLUG,"Engineering simulators used for steady-state multiphase flows in oil and gas wells and pipelines are commonly utilized to predict pressure drop and phase velocities. Such simulators are typically based on either empirical correlations (e.g., Beggs and Brill, Mukherjee and Brill, Duns and Ros) or first-principles mechanistic models (e.g., Ansari, Xiao, TUFFP Unified, Leda Flow Point model, OLGAS). The simulators allow one to evaluate the pressure drop in a multiphase pipe flow with acceptable accuracy. However, the only shortcoming of these correlations and mechanistic models is their applicability (besides steady-state versions of transient simulators such as Leda Flow and OLGA). Empirical correlations are commonly applicable in their respective ranges of data fitting; and mechanistic models are limited by the applicability of the empirically based closure relations that are a part of such models. In order to extend the applicability and the accuracy of the existing accessible methods, a method of pressure drop calculation in the pipeline is proposed. The method is based on well segmentation and calculation of the pressure gradient in each segment using three surrogate models based on Machine Learning (ML) algorithms trained on a representative lab data set from the open literature. The first model predicts the value of a liquid holdup in the segment, the second one determines the flow pattern, and the third one is used to estimate the pressure gradient. To build these models, several ML algorithms are trained such as Random Forest, Gradient Boosting Decision Trees, Support Vector Machine, and Artificial Neural Network, and their predictive abilities are cross-compared. The proposed method for pressure gradient calculation yields R-2 = 0.95 by using the Gradient Boosting algorithm as compared with R-2 = 0.92 in case of Mukherjee and Brill correlation and R-2 = 0.91 when a combination of Ansari and Xiao mechanistic models is utilized. The application of the above-mentioned ML algorithms and the larger database used for their training will allow extending the proposed methodology to a wider applicability range of input parameters as compared to standard accessible techniques. The method for pressure drop prediction based on ML algorithms trained on lab data is also validated on three real field cases. Validation indicates that the proposed model yields the following coefficients of determination: R-2 = 0.806, 0.815 and 0.99 as compared with the highest values obtained by commonly used techniques: R-2 = 0.82 (Beggs and Brill correlation), (Mukherjee and Brill correlation) and R-2 = 0.98 (Beggs and Brill correlation). Hence, the method for calculating the pressure distribution could give comparable or even higher scores on field data by contrast to correlations and mechanistic models. This fact is an indicator that the model can be scalable from the lab to the field conditions without any additional retraining of ML algorithms.",21,21,1
Pressure Gradients,"Flow Patterns,Pressure Drop","Perissinotto, Rodolfo Marcilli; Verde, William Monte; Gallassi, Mariana; Goncalves, Gabriel F. N.; de Castro, Marcelo Souza; Carneiro, Joao; Biazussi, Jorge Luiz; Bannwart, Antonio Carlos",Experimental and numerical study of oil drop motion within an ESP impeller,Centrifugal pump; Two-phase liquid-liquid flow; Flow visualization; Oil drop dynamics; CFD,2-PHASE FLOW PATTERNS; CENTRIFUGAL PUMPS; WATER FLOW,"The Electrical Submersible Pump (ESP) is a multistage centrifugal pump used in the petroleum industry as an artificial lift method. The ESP usually works with the presence of two-phase liquid-liquid flows that constitute dispersions and emulsions, causing performance losses and operational problems. This research aims to investigate the behavior and evaluate the dynamics of individual oil drops in an oil-in-water dispersion within an ESP impeller. The study adopts experimental and numerical approaches. Initially, experiments were performed using an experimental facility with a high-speed camera and an ESP prototype working at 600 rpm and 900 rpm, for water flows around the Best Efficiency Point (BEP) and with the injection of oil drops at a low flow rate. The acquired images were processed, and a drop sample was tracked, enabling the analysis of the size, shape, path, velocity, and acceleration of the oil drops. Numerical simulations were executed in ANSYS (R) software to define relevant parameters related to water and oil drops, such as velocities, accelerations, forces, turbulent dissipation, and residence time. The images reveal a unique flow pattern of dispersed drops in a continuous water phase. The oil drops' diameters vary from tenths of a millimeter to around 3 mm. The drops' trajectories can be classified into three different regions within the impeller channels. The drops' velocities stay in the order of 1 m/s, while accelerations can reach hundreds of m/s(2). The velocity profiles show that the oil drops tend to decelerate during their trajectory, while the acceleration profiles suggest peaks at the channel inlet and outlet. High intense turbulence is present in the impeller entrance zone. The evaluation of the residence time and the particle Reynolds number suggest that smaller oil drops follow the water streamlines, while larger oil drops tend to be affected by external forces. The main forces that govern the oil drop motion are the drag, the pressure gradient, and the virtual mass forces. The force from the pressure gradient is tenfold greater than the force from the drag. The virtual mass effect is significant only in the impeller inlet. In general, in this research, numerical results show a satisfactory agreement with the experimental data.",17,17,0
Pressure Gradients,Force,"Perissinotto, Rodolfo Marcilli; Verde, William Monte; Gallassi, Mariana; Goncalves, Gabriel F. N.; de Castro, Marcelo Souza; Carneiro, Joao; Biazussi, Jorge Luiz; Bannwart, Antonio Carlos",Experimental and numerical study of oil drop motion within an ESP impeller,Centrifugal pump; Two-phase liquid-liquid flow; Flow visualization; Oil drop dynamics; CFD,2-PHASE FLOW PATTERNS; CENTRIFUGAL PUMPS; WATER FLOW,"The Electrical Submersible Pump (ESP) is a multistage centrifugal pump used in the petroleum industry as an artificial lift method. The ESP usually works with the presence of two-phase liquid-liquid flows that constitute dispersions and emulsions, causing performance losses and operational problems. This research aims to investigate the behavior and evaluate the dynamics of individual oil drops in an oil-in-water dispersion within an ESP impeller. The study adopts experimental and numerical approaches. Initially, experiments were performed using an experimental facility with a high-speed camera and an ESP prototype working at 600 rpm and 900 rpm, for water flows around the Best Efficiency Point (BEP) and with the injection of oil drops at a low flow rate. The acquired images were processed, and a drop sample was tracked, enabling the analysis of the size, shape, path, velocity, and acceleration of the oil drops. Numerical simulations were executed in ANSYS (R) software to define relevant parameters related to water and oil drops, such as velocities, accelerations, forces, turbulent dissipation, and residence time. The images reveal a unique flow pattern of dispersed drops in a continuous water phase. The oil drops' diameters vary from tenths of a millimeter to around 3 mm. The drops' trajectories can be classified into three different regions within the impeller channels. The drops' velocities stay in the order of 1 m/s, while accelerations can reach hundreds of m/s(2). The velocity profiles show that the oil drops tend to decelerate during their trajectory, while the acceleration profiles suggest peaks at the channel inlet and outlet. High intense turbulence is present in the impeller entrance zone. The evaluation of the residence time and the particle Reynolds number suggest that smaller oil drops follow the water streamlines, while larger oil drops tend to be affected by external forces. The main forces that govern the oil drop motion are the drag, the pressure gradient, and the virtual mass forces. The force from the pressure gradient is tenfold greater than the force from the drag. The virtual mass effect is significant only in the impeller inlet. In general, in this research, numerical results show a satisfactory agreement with the experimental data.",17,17,0
Pressure Gradients,Force,"Abedi, Behbood; Mendes, Rafael; de Souza Mendes, Paulo R.",Startup flow of yield-stress non-thixotropic and thixotropic materials in a tube,Startup flow; Gelled waxy crude oil; Yield stress materials; Thixotropy; Wall slip,WAXY CRUDE OILS; WALL SLIP; RHEOLOGICAL BEHAVIOR; LAPONITE; MODEL; SUSPENSIONS; FLUID; EMULSIONS,"An experimental study of the flow of yield stress materials was conducted. The main goal was to understand the relationship between the minimum axial pressure gradient required for the onset of motion and the rheological properties. The sought-for application is the startup flow of waxy crude oils in subsea pipelines. We examined two types of yield stress materials, namely a non-thixotropic acrylic polymer solution and a layered silicate suspension which presents thixotropic properties. We observed that for both materials the measured minimum axial pressure gradient was in good agreement with the prediction of a simple force balance. On the other hand, a puzzling fact is observed in the oil industry, namely that the just mentioned force balance result grossly overestimates the minimum axial pressure gradient for the case of gelled waxy crude oils. One often evoked explanation is the thixotropic behavior of the gelled crude, but the present results serve to falsify it.",14,14,3
Pressure Gradients,Multi-stage,"Wu, Zhongwei; Cui, Chuanzhi; Lv, Guangzhong; Bing, Shaoxian; Cao, Gang",A multi-linear transient pressure model for multistage fractured horizontal well in tight oil reservoirs with considering threshold pressure gradient and stress sensitivity,Multi-linear transient pressure model; Multistage fractured horizontal well; Stress sensitivity; Threshold pressure gradient; Pedrosa's transformation; Perturbation theory,NON-DARCY FLOW; SHALE; PERMEABILITY; PERFORMANCE,"In general, tight oil reservoirs has a numerous tiny and complicated throats, and ultra-low permeability, which leads to a low-velocity non-Darcy flow when the fluid flows in tight reservoirs. The permeability of tight oil reservoirs is no longer a constant, but a variable, which is dependent on reservoir pressure. In other word, the tight oil reservoir is stress sensitive media. The low-velocity non-Darcy flow and stress sensitivity will greatly affect the bottom hole pressure response. So, the low-velocity non-Darcy flow and stress sensitivity should be taken into consideration when researching the transient pressure behaviors of multistage fractured horizontal wells. Currently, there are many researches on transient pressure behaviors of the multistage fractured horizontal well, but none of these researches has taken the low-velocity non-Darcy flow and stress sensitivity into consideration simultaneously. In this paper, threshold pressure gradient and permeability modulus are used to characterize the low-velocity non-Darcy flow and stress sensitivity, respectively. And, a multi-linear transient pressure model of multistage fractured horizontal well with considering low-velocity non-Darcy flow and stress sensitivity is established. The Pedrosa's transformation, perturbation theory, Laplace transformation and stehfest numerical inverse are used to solve this transient pressure model. The novel model is verified by comparing the result of proposed model with that of Ekaterina Stalagorova's model. According to the dimensionless pressure derivative curve, the flow process can be identified as six regimes: (1)the main fracture linear flow stage, (2)the first transition flow stage, (3)dual-linear flow stage,(4)the second transition flow stage, (5)the formation linear flow stage, (6)the boundary flow stage. Finally, the effects of threshold pressure gradient, permeability modulus and fracture density of stimulated reservoir on dimensionless pressure derivative are analyzed. This research provides theoretical support for correctly understanding the flow law of multistage fractured horizontal well.",42,44,6
Pressure Gradients,Multi-stage,"Perissinotto, Rodolfo Marcilli; Verde, William Monte; Gallassi, Mariana; Goncalves, Gabriel F. N.; de Castro, Marcelo Souza; Carneiro, Joao; Biazussi, Jorge Luiz; Bannwart, Antonio Carlos",Experimental and numerical study of oil drop motion within an ESP impeller,Centrifugal pump; Two-phase liquid-liquid flow; Flow visualization; Oil drop dynamics; CFD,2-PHASE FLOW PATTERNS; CENTRIFUGAL PUMPS; WATER FLOW,"The Electrical Submersible Pump (ESP) is a multistage centrifugal pump used in the petroleum industry as an artificial lift method. The ESP usually works with the presence of two-phase liquid-liquid flows that constitute dispersions and emulsions, causing performance losses and operational problems. This research aims to investigate the behavior and evaluate the dynamics of individual oil drops in an oil-in-water dispersion within an ESP impeller. The study adopts experimental and numerical approaches. Initially, experiments were performed using an experimental facility with a high-speed camera and an ESP prototype working at 600 rpm and 900 rpm, for water flows around the Best Efficiency Point (BEP) and with the injection of oil drops at a low flow rate. The acquired images were processed, and a drop sample was tracked, enabling the analysis of the size, shape, path, velocity, and acceleration of the oil drops. Numerical simulations were executed in ANSYS (R) software to define relevant parameters related to water and oil drops, such as velocities, accelerations, forces, turbulent dissipation, and residence time. The images reveal a unique flow pattern of dispersed drops in a continuous water phase. The oil drops' diameters vary from tenths of a millimeter to around 3 mm. The drops' trajectories can be classified into three different regions within the impeller channels. The drops' velocities stay in the order of 1 m/s, while accelerations can reach hundreds of m/s(2). The velocity profiles show that the oil drops tend to decelerate during their trajectory, while the acceleration profiles suggest peaks at the channel inlet and outlet. High intense turbulence is present in the impeller entrance zone. The evaluation of the residence time and the particle Reynolds number suggest that smaller oil drops follow the water streamlines, while larger oil drops tend to be affected by external forces. The main forces that govern the oil drop motion are the drag, the pressure gradient, and the virtual mass forces. The force from the pressure gradient is tenfold greater than the force from the drag. The virtual mass effect is significant only in the impeller inlet. In general, in this research, numerical results show a satisfactory agreement with the experimental data.",17,17,0
Pressure Gradients,Slug,"Kanin, E. A.; Osiptsov, A. A.; Vainshtein, A. L.; Burnaev, E., V",A predictive model for steady-state multiphase pipe flow: Machine learning on lab data,Multiphase flow; Machine learning; Surrogate modeling; Pressure gradient; Flow pattern; Liquid holdup,LIQUID HOLDUP; SLUG,"Engineering simulators used for steady-state multiphase flows in oil and gas wells and pipelines are commonly utilized to predict pressure drop and phase velocities. Such simulators are typically based on either empirical correlations (e.g., Beggs and Brill, Mukherjee and Brill, Duns and Ros) or first-principles mechanistic models (e.g., Ansari, Xiao, TUFFP Unified, Leda Flow Point model, OLGAS). The simulators allow one to evaluate the pressure drop in a multiphase pipe flow with acceptable accuracy. However, the only shortcoming of these correlations and mechanistic models is their applicability (besides steady-state versions of transient simulators such as Leda Flow and OLGA). Empirical correlations are commonly applicable in their respective ranges of data fitting; and mechanistic models are limited by the applicability of the empirically based closure relations that are a part of such models. In order to extend the applicability and the accuracy of the existing accessible methods, a method of pressure drop calculation in the pipeline is proposed. The method is based on well segmentation and calculation of the pressure gradient in each segment using three surrogate models based on Machine Learning (ML) algorithms trained on a representative lab data set from the open literature. The first model predicts the value of a liquid holdup in the segment, the second one determines the flow pattern, and the third one is used to estimate the pressure gradient. To build these models, several ML algorithms are trained such as Random Forest, Gradient Boosting Decision Trees, Support Vector Machine, and Artificial Neural Network, and their predictive abilities are cross-compared. The proposed method for pressure gradient calculation yields R-2 = 0.95 by using the Gradient Boosting algorithm as compared with R-2 = 0.92 in case of Mukherjee and Brill correlation and R-2 = 0.91 when a combination of Ansari and Xiao mechanistic models is utilized. The application of the above-mentioned ML algorithms and the larger database used for their training will allow extending the proposed methodology to a wider applicability range of input parameters as compared to standard accessible techniques. The method for pressure drop prediction based on ML algorithms trained on lab data is also validated on three real field cases. Validation indicates that the proposed model yields the following coefficients of determination: R-2 = 0.806, 0.815 and 0.99 as compared with the highest values obtained by commonly used techniques: R-2 = 0.82 (Beggs and Brill correlation), (Mukherjee and Brill correlation) and R-2 = 0.98 (Beggs and Brill correlation). Hence, the method for calculating the pressure distribution could give comparable or even higher scores on field data by contrast to correlations and mechanistic models. This fact is an indicator that the model can be scalable from the lab to the field conditions without any additional retraining of ML algorithms.",21,21,1
Pressure Gradients,Slug,"Aitkulov, Almas; Mohanty, Kishore K.",Investigation of alkaline-surfactant-polymer flooding in a quarter five-spot sandpack for viscous oil recovery,Viscous oil recovery; Chemical flooding; Enhanced oil recovery; Alkaline-surfactant-polymer flooding; Optimum viscosity,,"The alkaline-surfactant-polymer (ASP) flood has been shown in the past to reduce residual oil saturation significantly after waterflood. ASP floods for light oils are designed to be stable where the mobility ratio of the oil bank to the ASP slug is kept close to one. For viscous oils, such stable recovery processes may be unreasonably slow due higher oil viscosity. The goal of this paper is to study unstable ASP flooding (i.e., oil to ASP slug mobility ratio < 1) in secondary and tertiary modes. A viscous oil of viscosity 100 cp was displaced by an ASP slug in a quarter 5-spot sandpack. The ASP formulation was developed by studying the phase behavior of the oil with several alkaline-surfactant formulations. The effectiveness of the ASP formulation was validated in a 1D sandpack by conducing a water flood followed by a stable tertiary ASP flood. A reservoir sand was used to create a sandpack inside a square steel cell similar to a quarter five-spot pattern. Several ASP floods were then conducted in this cell to study both the displacement efficiency and the sweep efficiency of ASP floods. The tertiary ASP flood recovered most of the oil (similar to 98% of OOIP) when the ASP slug viscosity exceeded the oil viscosity, but pressure gradients were high at similar to 1 ft/d injection. When the ASP slug viscosity was lowered to about 1/3 of the oil viscosity, the oil recovery dropped slightly to 90% OOIP, but the pressure gradient decreased significantly. As the extent of waterflood preceding the ASP flood became shorter, the oil was recovered faster for the same pore volumes injected. The ultimate recovery was independent of the extent of waterflood. The laboratory 5-spot floods were modeled by the simulator UTCHEM. The calibrated simulator can be used at the field scale to determine optimum viscosity ratio and ASP flood timing for viscous oil reservoirs.",14,14,2
ROP,,"Ashrafi, Seyed Babak; Anemangely, Mohammad; Sabah, Mohammad; Ameri, Mohammad Javad",Application of hybrid artificial neural networks for predicting rate of penetration (ROP): A case study from Marun oil field,Rate of penetration; Artificial neural network; Feature selection; Evolutionary algorithms,SUPPORT VECTOR REGRESSION; KRILL HERD ALGORITHM; DRILLING RATE; FEATURE-SELECTION; MODELS; ROCKS; OPTIMIZATION; RESERVOIRS; VISCOSITY; IDENTIFICATION,"Rate of Penetration (ROP) can be considered as a crucial factor in optimization and cost minimization of drilling operations. In order to predict ROP with satisfactory precision, some hybrid artificial intelligence models were developed in the present research. To achieve this, dataset including petrophysical logs and drilling data was collected from a vertical well drilled in Marun oil field where is in southwest corner of Iran. Then, overall noise of the collected data was reduced with implementing Savitzky-Golay (SG) smoothing filter. In the next stage, a feature selection method with application of genetic algorithm was employed for choosing the unrivaled features and lessening the input vectors. Regarding results of the feature selection method, eight parameters including weight on bit, bit rotational speed, pump flow rate, pump pressure, pore pressure, gamma ray, density log and shear wave velocity were identified as the most influential parameters in drilling rate. After that, eight hybrid artificial neural networks (ANN) were developed and trained by four evolutionary algorithms. These algorithms are genetic algorithm (GA), particle swarm optimization (PSO), biogeography-based optimizer (BBO) and imperialist competitive algorithm (ICA). After model developments, to provide an objective assessment of performances of the proposed hybrid models, their results were compared with results of conventional ANN models and two multiple regression methods (NLMR and LMR) using different performance indices such as root mean square error (RMSE), variance account for (VAF), and performance index (PI). Results showed that PSO-multilayer perception (PSO-MLP) and PSO-radial basis function (PSO-RBF) neural networks with RMSE of 1.12 and 1.4, respectively yielded the highest performance in prediction comparing to results of other developed models. Concluding remark is that hybrid ANNs exhibit much more efficiency and reliability than conventional ANNs and regression methods in terms of ROP prediction, indicating superiority of evolutionary algorithms over back propagation (BP) methods in the ANNs training.",44,44,7
ROP,,"Soares, Cesar; Gray, Kenneth",Real-time predictive capabilities of analytical and machine learning rate of penetration (ROP) models,Rate of penetration; ROP modeling; Real-time retraining; Machine learning; PDC bit,PRESSURE; BOURGOYNE,"Real-time drilling optimization consists of selecting operational parameters that maximize a desirable measure of drilling performance. Drilling optimization efforts often aspire to improve drilling speed, commonly referred to as rate of penetration (ROP). Three operational drilling parameters may be constantly adjusted at surface to influence ROP: weight on bit (WOB), drillstring rotational speed (RPM), and drilling fluid (mud) flow rate. In the traditional, analytical approach to ROP modeling, inflexible equations relate WOB, RPM, flow rate and/or other measurable drilling parameters to ROP and empirical model coefficients are computed for each rock formation to best fit field data. Over the last decade, enhanced data acquisition technology and widespread cheap computational power have driven a surge in applications of machine learning (ML) techniques to ROP prediction. Machine learning algorithms leverage statistics to uncover relations between any prescribed inputs (features/predictors) and the quantity of interest (response). The biggest advantage of ML algorithms over analytical models is their flexibility in model form. With no set equation, ML models permit segmentation of the drilling operational parameter space. However, the increased model complexity diminishes interpretability of how an adjustment to the inputs will affect the output. There is no single ROP model applicable in every situation. This study investigates real-time predictive capabilities of analytical and ML ROP models in a continuous learning setting. Data are constantly recorded as a well is drilled, and it is postulated that ROP models can learn and adapt in real-time to become more accurate. Novel learning metrics demonstrate that machine learning models reduce test error much more effectively than analytical models with incremental training data availability. Both analytical and ML model performance improves with shortened retraining intervals, defined either by length or number of data points. Cross-validation is investigated as a methodology to select the best performing ROP model in real-time.",42,42,8
ROP,,"Ahmed, Omogbolahan S.; Adeniran, Ahmed A.; Samsuri, Ariffin",Computational intelligence based prediction of drilling rate of penetration: A comparative study,ROP prediction; Neural network; Least square support vector regression; Specific energy; Drilling efficiency; Extreme learning machine,EXTREME LEARNING-MACHINE; SUPPORT VECTOR MACHINES,"Application of artificial intelligence in the accurate prediction of the rate of penetration (ROP), an important measure of drilling performance, has lately gained significant interest in oil and gas well drilling operations. Consequently, several computational intelligence techniques (CITs) for the prediction of ROP have been explored in the literature. This study explores the predictive capabilities of four commonly used CITs in the pre- diction of ROP and experimentally compare their predictive performance. The CIT algorithm utilizes predictors which are easily accessible continuous drilling data that have physical but complex relationship with ROP based on hydro-mechanical specific energy ROP model. The four CITs compared are the artificial neural network (ANN), extreme learning machine, support vector Regression and least-square support vector regression (LSSVR). Two experiments were carried out; the first experiment investigates the comparative performance of the CITs while the second investigates the effect of reduced number of predictors on the performance of the models. The results show that all the CITs perform within acceptable accuracy with testing root mean square error range (RMSE) of 18.27-28.84 and testing correlation coefficient (CC) range of 0.71-0.94. LS-SVR has the best predictive performance in terms of accuracy with RMSE of 18.27 and CC of 0.94 while ANN has the best testing execution time at 0.03 s. Also utilizing the specific energy concept in chosen drilling parameters to be included among the predictors shows improved performance with five drilling parameters showing an improvement of 3%-9% in RMSE for LS-SVR in the two well studied. The utilization of the specific energy concept in the selection of the predictors in this study has demonstrated that the easily accessible drilling parameters have immense value to provide acceptable performance in the development of ROP model with CITs.",35,35,6
ROP,,"Gan, Chao; Cao, Wei-Hua; Wu, Min; Chen, Xin; Hu, Yu-Le; Liu, Kang-Zhi; Wang, Fa-Wen; Zhang, Suo-Bang","Prediction of drilling rate of penetration (ROP) using hybrid support vector regression: A case study on the Shennongjia area, Central China",Rate of penetration; Support vector regression; Hybrid bat algorithm; Prediction model; Drilling process,RESPONSE-SURFACE METHODOLOGY; MUTUAL INFORMATION; SENSITIVITY-ANALYSIS; MODELING METHOD; NEURAL-NETWORK; OIL-FIELD; OPTIMIZATION; HYPERPARAMETERS; SELECTION; TREE,"Rate of penetration (ROP) prediction is crucial for the optimization and control in drilling process due to its vital role in maximizing the drilling efficiency. This paper proposes a novel intelligent model to predict the drilling ROP considering the process characteristics. First, the geological background and the drilling process of the case study are described. Based on the mechanism and frequency spectrum analysis, the strong nonlinearity and different low-frequency and high-frequency data noises between the data variables are detected. After that, the intelligent model is established via three stages. In the first stage, a wavelet filtering method is introduced to reduce these noises in the drilling data. In the next stage, the model inputs are determined by the mutual information method, which significantly decreased the model redundancy. In the last stage, a hybrid bat algorithm is proposed to optimize the hyper-parameters of the support vector regression model. Finally, the proposed model is validated by using the data from a drilling site in the Shennongjia area, Central China. The results demonstrate that the proposed method outperforms eight well-known methods and another three methods without different data preprocessing procedures in prediction accuracy.",22,22,6
ROP,,"Cheng, Zhen; Li, Gensheng; Huang, Zhongwei; Sheng, Mao; Wu, Xiaoguang; Yang, Jiawei",Analytical modelling of rock cutting force and failure surface in linear cutting test by single PDC cutter,PDC bits; Single cutter; Rock failure; Analytical model,NUMERICAL-SIMULATION; FRAGMENTATION,"The PDC (Polycrystalline Diamond Compact) bits are the most widely used bits in oil drilling engineering, in order to further improve their longevity and ROP (Rate of Penetration), single PDC cutter research is very important. However, previous work focused mostly on experiment and numerical simulation while analytical modelling still lacks progress. In this paper, a new analytical model of rock cutting force and failure surface is proposed based on the stress state calculation of each micro-unit inside the rock. The cutting force predicted by this model is well verified by experiments under different parameters like depth of cut, back rack angle, rock type, cutter size and confining pressure. It is also found that the shape of failure surface is a curved line rather than straight, and long and thin cuttings will be formed. Finally, on the basis of this model, the influence mechanism of each parameter on cutting force and the shape of failure surface are analyzed. The method and result of this study are expected to provide a better understanding of cutting force and rock breaking mechanism by PDC bits.",20,22,5
ROP,,"Anemangely, Mohammad; Ramezanzadeh, Ahmad; Behboud, Mohammad Mohammadi",Geomechanical parameter estimation from mechanical specific energy using artificial intelligence,Mechanical specific energy; Geomechanical parameters prediction; Artificial intelligence; Outlier detection,KRISHNA-GODAVARI BASIN; MUD WEIGHT; PREDICTION; OIL,"A comprehensive knowledge of geomechanical characteristics of the formations above a reservoir (cap rock, in particular) can prevent a large spectrum of problems during drilling operation. Furthermore, access to such information during drilling operation greatly contributes to proper adjustment of controllable parameters and enhanced rate of penetration (ROP). Unfortunately, due to the high costs associated with the acquisition of petrophysical logs, these sets of data are commonly acquired within the reservoir interval only, i.e. at most 20% of total drilled length. As such, the present contribution is an attempt to use the concept of mechanical specific energy (MSE) to estimate geomechanical parameters of rock. For this purpose, data was collected from two vertical wells drilled into an oilfield in southwest of Iran. Firstly, based upon available drilling reports and Tukey method, outlier data points were detected and omitted. Then, MSE was evaluated using different models proposed for this purpose previously. The evaluation results indicated that, the results obtained from Dupriest and Koederitz (2005) model were in good agreement with actual conditions at the considered wells. Therefore, the obtained MSE from this model along with flow rate (FR), bit tooth wear (CT), and Depth logs were used as input for multivariate nonlinear regression (MNLR) method as well as multi-layer perceptron neural network combined with cuckoo optimization algorithm (MLP-COA) and also with particle swarm optimization (MLP-PSO) to estimate confined compressive strength (CCS), uniaxial compressive strength (UCS), internal friction angle (phi), and Poisson's ratio (nu). Models were trained on data from one well and then validation-tested on the other well's data. Results of adopting these models indicated that, as far as the estimation of geomechanical parameters was concerned, intelligent models were of higher accuracy and reliability than the regression model. A comparison between the results of MLP-COA and MLP-PSO models showed that, COA outperforms PSO algorithm in achieving a model of higher accuracy and reliability. Results of the three models indicated that, the presented method in this research possesses large potentials for estimating CCS, UCS, and phi parameters, and it can be stipulated with certainty that, the proposed method can be used to estimate the parameters at other wells across the field under study provided further data is available from more wells and even the formations overlying the reservoir. However, application of this method for estimating nu shall be practiced with care.",15,15,3
ROP,,"Hegde, Chiranth; Millwater, Harry; Gra, Ken",Classification of drilling stick slip severity using machine learning,Vibrations; Logistic regression; Gaussian mixture models; Linear discriminant analysis; Machine learning,MODELS,"Rate of penetration (ROP) is a key metric used to monitor the success of drilling a well. It is directly affected by drilling vibrations since excessive vibrations result in a reduction of ROP. Vibration modeling and monitoring is a complex process often requiring many simplifying assumptions that may not always generalize to different BHAs, reservoirs, geology and formations. Therefore, it would be desirable to minimize drill string vibrations using data driven models using readily available drilling data. The hypothesis tested is the classification of stick slip severity due to drilling vibrations using open source machine learning algorithms. The stick slip index (SSI) - measuring the severity of stick slip due to drilling vibrations - is classified as low or high using machine learning classification algorithms such as logistic regression, support vector machines, random forests, gaussian mixture models and discriminant analysis. Each algorithm was evaluated based on classification accuracy, F-1 score and area under the receiver operating characteristic curve (AUC). The random forest algorithm outperforms other algorithms with an average accuracy of 90% (F-1 score of 0.91 and AUC score of 0.89). The classification model can then be used within a ROP optimization model (or framework) to determine optimal operation parameters which do not result in stick-slip conditions while drilling addressing a serious limitation of previously published ROP optimization papers.",14,15,4
Rock Breaking,,"Liu, Weiji; Qian, Xudong; Li, Tao; Zhou, Yunlai; Zhu, Xiaohua",Investigation of the tool-rock interaction using Drucker-Prager failure criterion,Tool-rock interaction; FEM; Rock breaking; Rock indentation; Rock cutting,MODE TRANSITION; NUMERICAL-SIMULATION; INDENTATION; DEPTH,"Mechanical rock breaking in different forms have found wide applications in the mining and civil engineering industry such as drilling, tunnelling and grinding. A detailed understanding of the tool-rock interaction is essential to achieve high efficiency in rock breaking and to optimize the cutting parameters. The finite element simulation of the tool-rock interaction remains a challenging task due to the complexity caused by the physical rock properties, the crack initiation and propagation, as well as the chip generation phenomenon. This study has implemented the Drucker-Prager constitutive model with an isotropic damage model in a finite element analysis to examine the rock failure modes, considering the interaction of cutting tool and the rock. The material parameters for the rock derive from the uniaxial compressive strength (UCS) and Brazilian tensile strength (BTS) tests performed on rock specimens. This study includes an experimental program to examine the crack initiation, crack propagation and the chip generation in rock specimens. The results show the Drucker-Prager failure criterion with the calibrated material parameters and element sizes simulate closely the tool-rock interaction phenomenon. The mesh size imposes a great effect on the parameter selection of the rock model, particularly for the fully damaged plastic strain value. This study leads to an enhanced understanding of rock breaking mechanisms in the mechanical excavation, and provides the basis to improve the rock excavation machine design.",31,32,4
Rock Breaking,,"He, Wenhao; Chen, Keyong; Hayatdavoudi, Asadollah; Sawant, Kaustubh; Lomas, Matthew","Effects of clay content, cement and mineral composition characteristics on sandstone rock strength and deformability behaviors",Clay content; Rock strength; Deformability; Cement; Mineral composition; Scanning electron microscope (SEM),,"To keep the stability and integrity of wellbore, it is required to figure out the interaction between clays, water and rock strength in the drilling process. As revealed in available literatures, a high content of clays usually leads to a low value of rock strength and can easily result in the deformation of rocks. However, few studies can succeed in taking the mineral composition and the cement type of clays into consideration. By combining scanning electron microscope (SEM), X-ray diffraction (XRD) analysis with the Brazilian tests, this research can explain the overall effects of clays on the rock strength and deformability behaviors in three kinds of sandstones. The results indicate that the content contrast cannot be a determinant factor in specifying the rock strength. When compared with a lower value, a higher clay content can also exhibit high tensile strength due to a difference in the cement and mineral composition characteristics of clays. Moreover, chlorites were found to contribute more to the strength loss when encountered with water than montmorillonite and illite. This is most likely due to its undulatory surface which can trap much water and thus locally cause massive expansion of clays. According to the cement types, the fracture patterns can be classified into three groups: (1) Grain sliding occurs when abundant clays cement the matrix. The fracture goes through the soft clay cement and the contact surface between clays and grains. (2) Grain fracturing occurs when the clays cannot prohibit the quartz overgrowth, and the fracture can run across the silica-cemented grains. (3) Grain shearing occurs when the rock matrix is un-consolidated and is filled with few clays between grains. The fracture tends to break the rock grains apart in an irregular behavior. Meanwhile, the strengthening mechanism of lost circulation materials was also studied by tracking their migrations through porous media using energy-dispersive system (EDS).",23,23,11
Rock Breaking,,"Cheng, Zhen; Li, Gensheng; Huang, Zhongwei; Sheng, Mao; Wu, Xiaoguang; Yang, Jiawei",Analytical modelling of rock cutting force and failure surface in linear cutting test by single PDC cutter,PDC bits; Single cutter; Rock failure; Analytical model,NUMERICAL-SIMULATION; FRAGMENTATION,"The PDC (Polycrystalline Diamond Compact) bits are the most widely used bits in oil drilling engineering, in order to further improve their longevity and ROP (Rate of Penetration), single PDC cutter research is very important. However, previous work focused mostly on experiment and numerical simulation while analytical modelling still lacks progress. In this paper, a new analytical model of rock cutting force and failure surface is proposed based on the stress state calculation of each micro-unit inside the rock. The cutting force predicted by this model is well verified by experiments under different parameters like depth of cut, back rack angle, rock type, cutter size and confining pressure. It is also found that the shape of failure surface is a curved line rather than straight, and long and thin cuttings will be formed. Finally, on the basis of this model, the influence mechanism of each parameter on cutting force and the shape of failure surface are analyzed. The method and result of this study are expected to provide a better understanding of cutting force and rock breaking mechanism by PDC bits.",20,22,5
Rock Breaking,,"Cheng, Zhen; Sheng, Mao; Li, Gensheng; Huang, Zhongwei; Shi, Huaizhong; Dai, Xianwei; Guo, Zhansheng",Cracks imaging in linear cutting tests with a PDC cutter: Characteristics and development sequence of cracks in the rock,PDC bits; Single cutter test; Crack pattern; Rock breaking mechanism,BRITTLE; MECHANISMS; BEHAVIOR; GROWTH,"Imaging cracks is a direct way to learn the rock breaking mechanism beneath a PDC cutter. In this study, a series of linear cutting tests and precise observations of cracks were conducted. The formation of major cracks was captured in-situ with a high speed camera in the process of cutting rock sheets. Then the cracks under the cutting groove (subsurface cracks) were studied by reproducing the cutting groove after cuffing some rock blocks and further observed by means of thin-section optical microscopy. Finally, the development sequence of the cracks and adjacent crushed zone was determined by recording the cutting process on a rock-like silica glass block. The results show that the shape of major cracks is mainly curved, both upward and downward curves were observed. The major cracks mainly initiate at the tip of the cutter when cuffing sandstone and granite, while they initiate more randomly in marble. The length and angle of the subsurface cracks vary with the rocks: the subsurface cracks extend the longest in granite, while propagating more vertically in sandstone. Finally, it is determined that the major cracks initiate after the formation of crushed zone. And the initiation of major cracks will enlarge the crushed zone and lead to the initiation and propagation of the subsurface cracks. The results in this paper are expected to further reveal the rock breaking mechanism beneath a PDC cutter.",17,18,4
Rock Breaking,,"Ren, Fushen; Fang, Tiancheng; Cheng, Xiaoze",Theoretical modeling and experimental study of rock-breaking depth in particle jet impact drilling process,Particle jet impact; Rock-breaking depth; Semi-analytical model; Dynamic simulation; Experimental study,WATER-JET,"Particle jet impact drilling technology is an efficient method to improve rock-breaking speed by high-speed particles and water-jet impact. The process and damage stage of rock-breaking by combined impact of highspeed water-jet and particles are very complicated, therefore, it is of great significance to study the rock-breaking depth in different damage stages for particle jet impact drilling. Therefore, laboratory test was carried out to study the effects of rock breaking depth on particle diameter, impact velocity and particle mixing ratio. Then, the semi-analytical model of rock-breaking depth under particle jet impact was established in stable damage condition, and the effect factors of rock-breaking depth were numerically analyzed. Based on SPH-FEM coupling algorithm, the dynamical simulation model of particle jet impact rock was established, and the simulation of rock-breaking process and damage evolution under particle jet impact was carried out. Effects of different particle jet parameters on rock-breaking depth were studied by comparing the semi-analytical mode calculation, dynamic simulation and experimental results. Analysis results showed that rock-breaking depth by particle jet impact increases with the increase of jet velocity and particle mixing ratio in high-pressure water-jet, and decreases with the increase of particle diameter. According to the requirements of particle jet impact drilling technology and the analysis findings, it is recommended to adopt water-jet velocity of 200-220 m/s, particle mixing ratio in water-jet of 0.20%, and particle diameter of 1.0 mm. Research results can provide theoretical basis for the parameters optimization and field application of particle jet impact drilling technology.",15,16,9
Rock Breaking,,"Zhang, Shikun; Huang, Zhongwei; Wang, Haizhu; Li, Gensheng; Sepehrnoori, Kamy; Wu, Xiaoguang; Hong, Chunyang",Experimental study on the rock-breaking characteristics of abrasive liquid nitrogen jet for hot dry rock,Rock breaking; Geothermal energy; Hot dry rock; Liquid nitrogen; Abrasive jet,FRACTURING STIMULATION; NUMERICAL-SIMULATION; TECHNOLOGY; FEASIBILITY,"Abrasive liquid nitrogen (LN2) jet is regarded as one of the most efficient methods to break hard rock, such as hot dry rock (HDR), due to its unite low-temperature property. In this study, a novel experimental setup is designed to achieve abrasive LN2 jet under high-pressure condition. The impingement experiments with abrasive water jet is also conducted to characterize the rock-breaking features under cryogenic condition. The influences of six important parameters on rock-breaking are investigated in detail. The results indicate that compared with abrasive water jet, abrasive LN2 jet can create a larger and more irregular cavity with the lower threshold pressure. The parametric study shows that nozzle pressure drop mainly affects the cavity depth, while the nozzle diameter affects the cavity-opening diameter noticeably. The particle diameter and rock temperature both have a great influence on cavity-opening diameter and cavity depth. This study can provide theoretical support for abrasive-LN2-jet application.",13,13,11
Rock Breaking,,"Huang, Kuilin; Ai, Zhijiu; Yang, Yingxin; Xie, Zongliang",The improved rock breaking efficiency of an annular-groove PDC bit,Annular groove; PDC bit; Rock breaking efficiency; Bottomhole topography,,"To solve a major problem faced by drilling technicians, that of how to improve rock breaking efficiency in complex strata, this paper introduces a polycrystalline diamond compact (PDC) drill bit with a special structure. Static-pressure breaking tests show that the breaking work ratio of a single tooth on a ridge is much smaller than that on flat rock samples, and the effect of ridge height on breaking work ratio is greater than that of ridge width. Single-tooth scrape tests show that the tangential force, axial force, and breaking work ratio of PDC teeth when scraping on a ridge are greatly reduced compared with flat rock samples, and the ridge width has a greater influence on the breaking work ratio than ridge height. A test bit with a diameter of 215.9 mm and the possibility of zero, one, or two annular grooves is designed and manufactured. Compared with the conventional, full-coverage PDC bit, the specific energy of the double-groove bit is reduced by 26.9%. The annular-groove PDC bits achieve large-scale cuttings when breaking the ridge created by the bit, and the rock breaking efficiency is greatly improved. At the same time, the raised ridges of the bottomhole increase the stability of the drill bit, providing a feasible solution for rock breaking when drilling complex strata.",13,13,9
Asphaltenes Precipitation,,"Tirjoo, Amin; Bayati, Behrouz; Rezaei, Hossein; Rahmati, Mahmoud",Molecular dynamics simulations of asphaltene aggregation under different conditions,Solubility parameter; Asphaltene; Molecular simulation; Inhibitor,CRUDE-OIL; PHASE-BEHAVIOR; MODEL; PRECIPITATION; AMPHIPHILES; SOLVENT; RESINS; THERMODYNAMICS; ASSOCIATION; DISPERSANTS,"The formation of organic sediments, especially asphaltene in reservoirs, wells and equipment, has a harmful effect on the oil production economy, which reduces oil production and can block oil production facilities. In order to investigate the asphaltene aggregation and solubility, a series of molecular dynamics simulations in different conditions were performed on two famous asphaltene based model, of M1 and VI. VI asphaltene has two high aliphatic side chains, whereas M1 asphaltene has only two methyl groups on its sides. The simulation results show that the solubility parameter increases with increasing number of aromatic rings and decreasing the number of carbon atoms in the side chain. The aggregation of asphaltene molecules in toluene, heptane and isopropyl benzene solvents and also in the mixture of solvents has been investigated. The results show that the aggregation of M1 asphaltene in toluene and isopropyl benzene is lower than that of VI asphaltene. The mixture isopropyl benzene-heptane is appropriate solvent for both asphaltenes M1 and VI which represents less interaction between asphaltene molecules. The effect of six types of inhibitors on the aggregation of asphaltene was investigated. Based on the simulation results, the aggregation of asphaltene with the presence of DETPMP inhibitor significantly decreases due to the delay in the growth of crystals and by increasing the concentration of all used inhibitors, their inhibitory properties were decreased.",29,30,3
Asphaltenes Precipitation,,"Ruwoldt, Jost; Sorland, Geir Humborstad; Simon, Sebastien; Oschmann, Hans-Jorg; Sjoblom, Johan","Inhibitor-wax interactions and PPD effect on wax crystallization: New approaches for GC/MS and NMR, and comparison with DSC, CPM, and rheometry",Wax inhibitor; Pour point depressant; Waxy crude oil; Wax deposition; Differential scanning calorimetry (DSC); Nuclear magnetic resonance (NMR),POUR-POINT DEPRESSANTS; CRUDE-OIL; APPEARANCE TEMPERATURE; FLOW PROPERTIES; ASPHALTENES; FRACTIONATION; ADSORPTION; PRECIPITATION; RELAXATION; COPOLYMERS,"Three pour point depressants (PPDs) with different chemistries, and extracted asphaltenes were studied in their influence on wax crystallization in a model system. A new procedure for nuclear magnetic resonance (NMR) was developed to monitor changes in liquid phase as wax precipitated. Similar experiments were used to study nalkane depletion during precipitation via the use of GC/MS. Additive performance was furthermore evaluated via differential scanning calorimetry (DSC), rheometry, and cross-polarized microscopy (CPM). All additives induced morphological changes to wax crystals, which also affected apparent viscosity and waxy gelling. Some additives improved flow-ability of the waxy model oil significantly, while others showed less pronounced or even adverse effects. Following DSC and NMR results, PPDs with good wax inhibition could delay both the onset of wax crystallization and reduce the amount of precipitated wax. In accordance with that, GC/MS showed additives to delay certain stages in compositional change during wax precipitation. Moreover, efficient PPDs could suppress interactions between liquid and solid waxes that showed in the NMR T-2-distribution. It appears that PPD beneficiation greatly influences the mobility of dissolved wax molecules, which would also entail an effect on interactions at the solid-liquid interface of wax crystals. In conclusion, experimental procedures for NMR and GC/MS were extended to study PPD-wax interactions more in-depth, and experimental results show potential for improving the knowledge of wax inhibition.",21,20,2
Asphaltenes Precipitation,,"Ghloum, Ebtisam F.; Rashed, Abeer M.; Safa, Muhieddine A.; Sablit, Rachid C.; Al-Jouhar, Saleh M.",Mitigation of asphaltenes precipitation phenomenon via chemical inhibitors,Asphaltenes precipitation; Inhibitors; Downhole; Solid detection system (SDS),MOLECULAR-INTERACTIONS; SOLVENTS; SIZE,"The main aim of this study is to mitigate asphaltenes precipitation phenomenon using chemical inhibitors under reservoir conditions. Different conventional screening test methods such as UV-Vis and solids detection system (SDS) equipped with a low-intensity near infrared (NIR) light and a high-pressure microscope (HPM) were used to assess the effectiveness of asphaltenes inhibitors on a stock tank oil (STO) and downhole samples (DHS). These tests have been employed as part of a rigorous investigation to understand (evaluate) the performance of chemical inhibitors in mitigating asphaltene precipitation and deposition. The extracted asphaltenes were characterized by higher aromaticity due to relatively low hydrogen/carbon molar ratios, hence, the higher tendency of asphaltenes aggregation and subsequent precipitation upon changes in thermodynamic factors. Moreover, the evaluation tests of the commercial asphaltenes inhibitors showed efficient asphaltenes dispersion performance when tested by using different conventional methods. Finally, the high-pressure microscope tests conducted on the DHS at reservoir temperature showed that the most efficient inhibitors reduced the aggregated asphaltenes average particles size by 58%. This is attributed to the presence of the high aromatic content, and polar acidic and/or alcoholic functionalities in the molecular structures of those inhibitors, which is vital for the dispersion of the asphaltenes and the prevention of the formation of large asphaltenes aggregates through pi-pi interactions and van der Waals forces.",18,18,2
Asphaltenes Precipitation,,"Mehana, Mohamed; Abraham, Jocin; Fahes, Mashhad",The impact of asphaltene deposition on fluid flow in sandstone,Asphaltene; Waterflooding; Wettability; Recovery; Relative pereability,PRECIPITATION; SOLUBILITY; RESINS; SIZE,"Asphaltene deposition in oil reservoirs is a contentious issue affecting both well and reservoir productivity. Though the phenomenon has been previously studied in several laboratory experiments, the uniformity aspects of the asphaltene deposit are usually overlooked. We have previously developed an experimental workflow to create a uniform deposit of asphaltene inside the core sample. In this study, the impact of this uniform deposit on fluid flow is quantified through imbibition, corefloods and relative permeability experiments. In addition, the lab results are used in a field scale simulation to investigate the impact of deposition on field performance. The results exhibit a shift in the wettability state where a reduction in both water imbibition rate and capacity are observed after deposition. Besides, up to 25% reduction in absolute permeability is detected. Results of pressure drop experiments across the core conducted on the exposed rocks indicate a change in the wetting characteristics, with the exposed rocks becoming more mixed/intermediate wet and varying with the change in the initial brine saturation in the rock. Subsequently, the relative permeability set is affected where a shift in the oil residual saturation, a downgrade in the oil curve and an upgrade in the water curve are observed. Upscaling this new data to field scale indicated a loss of more than half of the well productivity and an earlier breakthrough if waterflooding is implemented.",17,19,0
Asphaltenes Precipitation,,"Peng, Xiyi; Wang, Yanyong; Diao, Yuqian; Zhang, Liang; Yazid, Iddi M.; Ren, Shaoran",Experimental investigation on the operation parameters of carbon dioxide huff-n-puff process in ultra low permeability oil reservoirs,Low permeability oil reservoirs; CO2 huff-n-puff; Enhanced oil recovery; Oil swelling; CO2 injection,CYCLIC STEAM STIMULATION; CO2 INJECTION PROCESS; TIGHT OIL; ASPHALTENE PRECIPITATION; PERFORMANCE EVALUATION; RECOVERY PERFORMANCE; ENERGY EFFICIENCY; MOBILITY CONTROL; SIMULATION; STORAGE,"For oil reservoirs featured with ultra low permeability, CO2 huff-n-puff can be a promising approach for enhanced oil recovery. To understand its production performance and the effects of different factors in field operation, a series of CO2 huff-n-puff experiments under various conditions were conducted using a 1D sandpack model, and the extraction effect of CO2 and its influence on oil production have been analyzed. The experimental results show that, as cyclic CO2 injection quantity increases, the cyclic oil recovery factor is improved, but the CO2 utilization factor is reduced, and there will be an optimum cyclic injection quantity from economic point of view. Both cyclic oil recovery factor and CO2 utilization factor are improved with the increasing reservoir temperature, while injection of low temperature CO2 may impose an adverse influence on oil recovery performance. In addition, the cyclic oil recovery factor and CO2 utilization factor firstly rise and then fall with the increasing soaking period. The results presented in this study are expected to provide some guidance to the field implementation of CO2 huff-n-puff technique in ultra low permeability oil reservoirs.",16,17,7
Asphaltenes Precipitation,,"Alrashidi, Hessah; Afra, Salar; Nasr-El-Din, Hisham A.",Application of natural fatty acids as asphaltenes solvents with inhibition and dispersion effects: A mechanistic study,Asphaltene; Asphaltene Inhibitor; Asphaltene Dispersant,ALKYLBENZENE-DERIVED AMPHIPHILES; RESONANCE MASS-SPECTROMETRY; X-RAY-SCATTERING; HEAVY CRUDE-OIL; PETROLEUM ASPHALTENES; IONIC LIQUIDS; PRECIPITATION; AGGREGATION; ADSORPTION; VISCOSITY,"Asphaltenes precipitation, flocculation, and deposition may cause severe damages to reservoirs, wells, and production facilities. Asphaltenes precipitation may occur during all production stages, e.g., primary depletion, acidizing jobs, and the injection of rich gas or carbon dioxide. The organic deposition removal is considered a costly workover job with the current oil prices. The solvents that are usually used are toluene and xylene, which are considered carcinogenic and toxic chemicals. Also, the use of a dispersant to inhibit the organic deposition can be expensive, as it is required for the life of the well. The objective of the present study is to propose new types of chemicals that can be primarily used as asphaltenes solvents while they can exhibit asphaltenes inhibition and dispersion effects as well. The efficiencies of these natural fatty acids were compared with the effectiveness of the combination of nonylphenol formaldehyde resin as a synthetic dispersant and toluene, in terms of the inhibition of asphaltenes precipitation as well as dissolving and dispersion of deposited asphaltenes. A Kuwaiti crude oil sample was used in this study with an API of approximately 38 degrees and asphaltenes content of 2 wt%, yet showing severe asphaltenes precipitation problem during production stage. The effects of the tested chemicals on the behavior of crude oil and its asphaltenes content were evaluated using infra-red spectroscopy, UV-vis spectroscopy, and dynamic light scattering. The results of this study show that the natural fatty acids can inhibit asphaltenes precipitation and disperse aggregates of asphaltenes. Asphaltenes size distribution was decreased from 10 mu m in the neat sample to 1-2 mu m in the treated solutions. Moreover, the asphaltenes precipitation onset point was delayed after the model oil was treated with these fatty acids. The primary advantages of these fatty acids when used as solvents are their high flash points, green nature, and abilities to inhibit asphaltenes precipitation and disperse asphaltenes aggregates. The main working mechanisms for these chemicals were determined to be acid-base reactions and steric hindrance through aliphatic side chains. Despite of their lower efficiencies compared to nonylphenol formaldehyde resin when used solely in the treatment, since these chemicals are naturally occurred, environmentally friendly, and cost effective, they would be proper substitutions for the commercial dispersants.",16,17,2
Asphaltenes Precipitation,,"Cui, Jiangfeng",Oil transport in shale nanopores and micro-fractures: Modeling and analysis,Shale oil; Asphaltenes; Mixed wettability; Adsorption; Mathematical model,MOLECULAR-DYNAMICS SIMULATION; ASPHALTENE PRECIPITATION; APPARENT PERMEABILITY; LIQUID PERMEABILITY; ORGANIC NANOPORES; FLOW; ENHANCEMENT; DIFFUSION; WATER; SLIP,"The mathematical modeling and analysis for the apparent permeability of shale oil with complicated compositions in dual-wettability shales (superior to existing single-component or single-wettability analysis), which is the core of this work, will help understand the detailed contributions of the considered mechanisms. Based on a previously established flow enhancement model, the effects of the mixed wettability and those triggered by asphaltenes, namely, the wettability alteration, the pore radius reduction, and the viscosity increment, are taken into account by respective corrections of the variables in the model. The effect of the mixed wettability is quantified by the water-wet area ratio, while the surface coverage, the adsorption thickness, and the volume fraction in the free phase are utilized to quantify the effects of asphaltenes. The volume fraction of asphaltenes in the free phase is related to that in both phases by the volume conservation equation. The full mathematical model and its several simplifications are achieved. Comprehensive sensitivity analysis and comparisons are carried out to demonstrate the effects of each variable (i.e., the pore radius, the initial water-wet surface ratio, the relative adsorption thickness, and the surface coverage) on: (1) the flow enhancement; (2) the relative importance of all mechanisms; (3) the differences among organic pores/inorganic pores/micro-fractures; and (4) the overall contribution of asphaltenes. The effect of different adsorption patterns (characterized by the relative adsorption thickness and the surface coverage) is also discussed.",14,14,3
Mercury Injection,,"Shi, Bingbing; Chang, Xiangchun; Yin, Wei; Li, Yang; Mao, Lixin","Quantitative evaluation model for tight sandstone reservoirs based on statistical methods - A case study of the Triassic Chang 8 tight sandstones, Zhenjing area, Ordos Basin, China",Tight sandstone; Comprehensive quantitative evaluation; Statistical methods; Reservoir quality; Ordos basin,YANCHANG FORMATION; QUALITY; HETEROGENEITY; DIAGENESIS; SEQUENCE; POROSITY; IMPACT; MEMBER; FIELD,"Petroleum exploration for tight sandstone reservoirs in the Ordos Basin has attracted much attention in recent years. However, the effective evaluation of the quality of tight sandstones is challenging due to their low porosity, low permeability, non-Darcy flow, continuously or quasi-continuously distribution and strong heterogeneity. Using constant velocity mercury injection, cathodoluminescence micrography, energy spectrum analysis, scanning electron microscopy and casting thin sections, a set of parameters, including the clay mineral index, Lorentz coefficient, compositional maturity, and plane porosity are tentatively proposed to evaluate the quality of tight reservoir rocks. Coupled with statistical methods, i.e., Principal Component Analysis, Grey Correlation Analysis, Analytic Hierarchy Process and Hierarchical Cluster Analysis, a comprehensive quantitative reservoir evaluation model is established. Then, the evaluation index (REI) is calculated, and the thresholds of various types of reservoirs are determined. The case study based on the above evaluation model shows that most of the type I reservoirs are petroleum-enriched, which are favourable targets for exploration and development. By contrast with sedimentary microfacies, the sandbodies in favourable targets were deposited in ancient subaqueous distributary channels, and they show a large herringbone-like distribution. Whereas the poor type-III reservoirs and non-prospective layers are mainly located in the southeastern part of the study area. The case evaluation based on the statistical methods is consistent with the results of previous multi-parameter evaluations, which has important implications for further exploration in the study area as well as other tight sandstone reservoirs.",64,69,6
Mercury Injection,,"Mirzaei-Paiaman, Abouzar; Sabbagh, Ereshteh; Ostadhassan, Mehdi; Shafiei, Ali; Rezaee, Reza; Saboorian-Jooybari, Hadi; Chen, Zhangxin",A further verification of FZI* and PSRTI: Newly developed petrophysical rock typing indices,Petrophysics; Rock typing; FZI-Star (FZI*); PSRTI; Winland r35; FZI,HYDRAULIC FLOW UNITS; SPONTANEOUS IMBIBITION; CAPILLARY-PRESSURE; PERMEABILITY; CENTRALITY; SELECTION,"Despite the differences between petrophysical static (PSRTs) and dynamic rock types (PDRTs), previous indices were unable to distinguish between them. FZI-Star (FZI*) and PSRTI are recently developed petrophysical dynamic and static rock typing indices, respectively. Considering the importance of rock typing in reservoir characterization and the need for reliable and user-friendly techniques, in this study we attempt to further verify the performance of FZI* and PSRTI by comparing them with FZI, Winland r35, and MFZI using data belonging to a heterogeneous carbonate reservoir from the Asmari Formation. The experimental data set includes 10 primary drainage mercury injection, 29 water-oil, and 45 gas-oil capillary pressure tests for PSRTs prediction in conjunction with 52 water-oil and 51 gas-oil relative permeability data for PDRTs. Moreover, we investigated the correlation between various indices and several petrophysical attributes. We defined these attributes as the integrals of mercury injection capillary pressure, mercury injection threshold capillary pressure, measured r35, capillary pressure, and relative permeability curves along with residual saturations. The results showed that our indices are able to successfully identify static and dynamic rock units with higher accuracy than other indices. Among the other existing methods, Winland r35 was the only one that showed an acceptable outcome; while, FZI, and MFZI underperformed in identifying the existing rock types. Using the experimental data we also propose the empirical equations that can be used to model capillary pressure and relative permeability characteristics of rocks.",26,26,0
Mercury Injection,,"Lai, Fengpeng; Li, Zhiping; Zhang, Tiantian; Zhou, Anqi; Gong, Bao","Characteristics of microscopic pore structure and its influence on spontaneous imbibition of tight gas reservoir in the Ordos Basin, China",Tight gas reservoir; Microscopic pore structure; Spontaneous imbibition; Experiments; Grey relational analysis,SANDSTONE RESERVOIRS; FLOW; PERMEABILITY; SHALE; MODEL,"Spontaneous imbibition is an important mechanism governing the tight reservoir production performance, especially in the early stage of production after hydraulic fracturing. The microscopic pore structure of reservoirs is an important factor affecting imbibition. In this study, high-pressure mercury injection (HPMI), rate-controlled mercury injection, and low-temperature nitrogen adsorption (LP-N(2)GA) were preformed to study pore structure characteristics and fluid distribution in samples from the Ordos Basin, China. Nuclear magnetic resonance (NMR) and imbibition experiments were used to investigate the fluid distribution in porous media during imbibition. The porosity of samples ranges from 11.378% to 12.356%, with an average of 12.034%. The permeability of samples ranges from 0.034 mD to 0.056 mD, with an average of 0.048 mD. Results show that the recovery ranges from 68% to 94.81%, with an average of 81.09%. The reservoir is dominated by open flat slit micropores and mesopores. Sample pore volume ranges from 0.0155 ml/g to 0.0193 ml/g, with an average of 0.01687 ml/g. Micropores and mesopores less than 50 nm provide most of the pore volume. Pore radius and pore-throat ratio were obtained from experiments. Imbibition occurs primarily in pores ranging from 0.1 mu m to 1 mu m in radius, followed by pores ranging from 1 mu m to 10 mu m. The effects of porosity, permeability, average pore radius, average throat radius, average pore-throat ratio, specific surface area, and pore volume on imbibition recovery were statistically analyzed. Grey relational analysis was applied to sequence the imbibition influencing factors and determine the most influential factor. Results demonstrate that imbibition recovery is the most affected by average pore radius, followed by permeability, porosity, average pore-throat ratio, median radius, average throat radius, and specific surface area.",19,18,4
Mercury Injection,,"Nazari, Marzieh Honarvar; Tavakoli, Vahid; Rahimpour-Bonab, Hossain; Sharifi-Yazdi, Masoud","Investigation of factors influencing geological heterogeneity in tight gas carbonates, Permian reservoir of the Persian Gulf",Tight carbonate reservoir; Mercury injection; Rock typing; Diagenesis; Persian Gulf; FZI* (FZI-Star),SEQUENCE STRATIGRAPHIC FRAMEWORK; CAPILLARY-PRESSURE CURVES; TRIASSIC SUCCESSIONS; GEOCHEMICAL EVIDENCE; ARCHIES EXPONENTS; KHUFF FORMATION; ARABIAN GULF; POROSITY; OFFSHORE; PERMEABILITY,"Understanding the spatial distribution of petrophysical properties in carbonate reservoirs is complicated due to their heterogeneity and sensitivity to diagenesis along with important facies variations. The reservoir evaluation in tight carbonates is even more complicated. The Permian Dalan Formation in the central part of Persian Gulf is generally considered as conventional carbonate reservoir. However, in this study, a part of K3 unit of this formation is introduced as a tight carbonate reservoir. To identify the factors influencing the quality of this unit, the sedimentary facies, depositional environments, diagenetic processes, and pore-type distribution were studied in details on 402 thin sections. Porosity and permeability of K3 are mainly controlled by dolomitization, dissolution, compaction, and cementation. MICP-based (mercury injection capillary pressure) methods, FZI*(FZI-star), and rock fabric numbers were considered to recognize the factors controlling heterogeneity of this unit. The MICP-based methods of Winland, Pittman, and Rezaee were combined with 3 porosity cutoffs to detect the heterogeneities of tight carbonates. None of these methods provided a high degree of correlation between porosity and permeability of the samples. The results of rock fabric number showed that samples with similar reservoir quality are the product of different diagenetic processes. Results obtained in this study demonstrate that the FZI*(FZI-star) and rock fabric number classifications are the most suitable methods for differentiating the tight zone and non-reservoir/reservoir parts in carbonates of K3 unit.",17,18,3
Mercury Injection,,"Ye, Wenzhuo; Wang, Xiuyu; Cao, Chenguang; Yu, Wenshuai",A fractal model for threshold pressure gradient of tight oil reservoirs,Tight oil reservoir; Capillary bundle model; Fractal theory; Threshold pressure gradient,BINGHAM FLUIDS; FLOW,"In tight oil reservoir, the flow channel of oil and water is tiny and the boundary layer effect is obvious, resulting in large flow resistance and high threshold pressure gradient. Taking into account of the fractal dimension of the pore throat and the tortuosity, a fractal model for calculating the threshold pressure gradient of tight oil reservoir is established. In this model, the rock is considered as a capillary bundle with different diameter distribution as obtained from high-pressure mercury injection measurements for tight rocks. The mathematical model expresses the fractal threshold pressure gradient as a function of ultimate shear stress (eta(0)), pore throat fractal dimension (D-f ), tortuosity fractal dimension (D-T), the maximum pore radius (r(max)), the characteristic length of the core (L-0), and the connate water saturation (S-wi). For 27 tight cores obtained from Changqing oilfield, threshold pressure gradients were determined using the established model and compared with experimental results to check its accuracy. A good fit was found especially for the rock with lower permeability. The relative error is less than 14% for all the rock tested and is only 1.77% for the cores with permeability in the range of 0.001-0.01mD. This model has the advantage of being able to check the impact of the connate water saturation on the threshold pressure gradient of tight rock, which is usually neglected in previous work. The results show that higher S-wi results in largely increased threshold pressure gradient especially for the rock with permeability lower than 0.01mD. This fractal model is of great importance in predicting the threshold pressure gradient of tight oil reservoir and researching on the flow mechanism of tight oil in porous media.",16,17,4
Mercury Injection,,"Liu, Yisheng; Liu, Yuetian; Zhang, Qichen; Li, Changyong; Feng, Yueli; Wang, Yunpeng; Xue, Yanpeng; Ma, Huan",Petrophysical static rock typing for carbonate reservoirs based on mercury injection capillary pressure curves using principal component analysis,Carbonate reservoirs; PSRT; Reservoir characterization; Mercury injection capillary pressure curve; Principal component analysis,HYDRAULIC FLOW UNITS; SOUTH PARS GASFIELD; NEURAL-NETWORK; PREDICTION; MACHINE; EXAMPLE,"Rock typing lay the profound basis of rational and efficient development of oil and gas reservoirs. In carbonate reservoirs, however, the identification of petrophysical static rock type (PSRT) has always been a great challenge to reservoir engineers and geologists due to its strong heterogeneity arising from the diagenetic process. The objective of this study was to propose a new method for petrophysical static rock typing in carbonate reservoirs. First, the evaluation equation of mercury injection capillary pressure (MICP) curve was established based on parameters analysis, and parameters weight was assigned by using the entropy method. Then, by analyzing and selecting the key influential parameters regarding the PSRTs in carbonate reservoirs, the novel rock typing model was established by principal component analysis (PCA) and ordinary least square (OLS) method. Finally, a realistic field case in Mishrif formation was presented through comparing the results from the proposed model with that of the existing methods, such as Winland plot (r35), flow zone indicator (FZI), FZI-star (FZI*) as well as bulk volume water method (BVW). The results indicated that the PSRTs identified by the new proposed model were superior to the others. What is reflected in the proposed model is that this approach can directly identify the PSRTs of the target formation. In contrast, neither the method of FZI nor the r35 can independently identify the PSRTs of carbonate reservoirs, they have to work jointly to determine the PSRTs.",15,15,0
Mercury Injection,,"Wang, Meng; Xie, Weidong; Huang, Kai; Dai, Xuguang","Fine characterization of lithofacies and pore network structure of continental shale: Case study of the Shuinan Formation in the north Jiaolai Basin, China",Jiaolai basin; Continental shale; Lithofacies; Pore network structure,GAS-STORAGE; BARNETT,"There is a continuously growing collection of research on continental shale reservoirs. This paper characterizes the Lower Cretaceous Shuinan Formation, a continental shale in the Jiaolai Basin, China, by adopting the improved ternary diagram of carbonate and clay minerals, and argon ion milling-SEM, high-pressure mercury injection, low-temperature N-2 adsorption, low-temperature CO2 adsorption and related geochemical experiments. The pore network structure is visually characterized under an electron microscope and indirect quantitative statistics of reservoir space. The influence factors of the full-scale pore development are classified according to the geochemistry and mineral content of different lithofacies within the shale reservoir. The results reveal that, there are five types of shale lithofacies in the Shuinan Formation: siliceous calcareous shale lithofacies (Ca1), calcareous/siliceous mixed shale lithofacies (F2), calcareous siliceous shale lithofacies (Si3), mixed siliceous shale lithofacies (Si2) and argillaceous siliceous shale lithofacies (Si1). The pores are characterized as intergranular pores and intragranular pores, with microcracks dominating the pores. Combined with the results of surface porosity and joint characterization of the pores, the pores within the shale in the Shuinan Formation that would be advantageous for shale gas development are mainly mesopores and macropores, greater than 10 nm in diameter. Pore development is controlled by mineralogy. Brittle minerals are beneficial to the development of micropores, mesopores and macropores, while carbonate minerals are not conducive to the development of pores in general. Filling occurs mainly in pores of 30-50 nm range. Finally, based upon the lithofacies classification, geochemical properties and pore characterization, the most suitable sections of the LC-1 well for shale gas development are concentration in the middle-lower Shuinan Formation.",14,14,4
Lattice Boltzmann Method,,"Cheng, Zhilin; Ning, Zhengfu; Wang, Qing; Zeng, Yan; Qi, Rongrong; Huang, Liang; Zhang, Wentong",The effect of pore structure on non-Darcy flow in porous media using the lattice Boltzmann method,Porous media; Pore structure; Darcy flow; Non-Darcy flow; Lattice Boltzmann method,RANDOM ARRAYS; RELATIVE PERMEABILITY; FLUID-FLOW; SIMULATION; INERTIA; NUMBER; COEFFICIENTS; PREDICTION; CYLINDERS; TRANSPORT,"Non-Darcy flows associated with high Reynolds numbers often occur in the near-wellbore regions of gas reservoirs or hydraulic fractures and thus should not be ignored. However, investigating non-Darcy flow in these porous rocks through laboratory experiments is always expensive and time-consuming. As such, this article sought an alternative method, and a lattice Boltzmann study of non-Darcy flow in various porous models was performed. The applicability of two non-Darcy correlations in porous media and the effect of pore structure on non-Darcy flow were examined. In addition, the reasons for the deviation from the linear Darcy flow and different flow patterns related to inertial effects of the fluid were also studied. The results showed that the characterization of non-Darcy flow in porous media with the cubic law can only be valid in a narrow range of Reynolds number beyond the Darcy regime, outside of which the strong inertia-dominated flow yields to the quadratic correction. On the whole, representing the non-Darcy flows using the quadratic correction is acceptable, especially for porous media with a higher complexity. The features of non-Darcy flow greatly depend on the pore structure of a porous medium, and more heterogeneous pore models always have a faster cessation for Darcy flow and a higher beta factor. Furthermore, for simple porous media a small amount of parameters may be adequate for the prediction of the beta factor; while the correlations involving more parameters would be needed to determine the beta factor for more intricate porous models, although such correlations may not be widely used in various industries. Besides, the non-Darcy flow that occurs in porous media is collectively controlled by different mechanisms. At elevated velocities, the inertial core effect in a large channel will lead the flow to be more homogeneous and less tortuous, while in porous models with complicated pore space, the steady eddy and reversal flow resulting from drag force will make the flow paths more tortuous. As such, it is the hope of this study to provide some new insights into the non-Darcy flow in porous media.",22,23,10
Lattice Boltzmann Method,,"Zhao, Yan-long; Wang, Zhi-ming; Qin, Xing; Li, Jiang-tao; Yang, Hu",Stress-dependent permeability of coal fracture networks: A numerical study with Lattice Boltzmann method,Coal fracture networks; Lattice Boltzmann method; Fracture roughness; Effective stress; Stress sensitivity,GAS-FLOW; TRANSPORT-PROPERTIES; PREDICTION; SIMULATION; PRESSURE; MICROSTRUCTURE; MODEL,"Since coal permeability is sensitive to stress, fundamental understanding of gas flow in coal fracture networks and permeability change with varying effective stress are necessary in the processes of CBM production. Based on the rock elastic theory and finite difference method, the stress-strain model of reconstructed coal fracture networks is established. It has provided a more accurate geometry model under stress condition. For comparison purposes, gas permeability and porosity of coal sample with artificially generated fracture are measured under varying effective stress. Based on the experimental results and the Walsh model, fracture width and roughness are estimated. Lattice Boltzmann methods are implemented to model the flows in a single rough fracture under stress condition and the stress-dependent permeability is predicted. Compared with laboratory measurement, the maximum relative error is 25%. Furthermore, applications and case studies are performed for the flows in the 2D and 3D fracture networks. The effects of stress, fracture density, surface roughness and aperture on the associated permeability are discussed. The present study provides an alternative to investigate the microcosmic stress sensitivity mechanism of coal permeability.",18,18,3
Lattice Boltzmann Method,,"Wang, Han; Su, Yuliang; Zhao, Zhenfeng; Wang, Wendong; Sheng, Guanglong; Zhan, Shiyuan",Apparent permeability model for shale oil transport through elliptic nanopores considering wall-oil interaction,Shale oil; Apparent permeability; Flow enhancement; Adsorbed oil; Elliptical cross-sections,REAL-GAS TRANSPORT; ORGANIC NANOPORES; PORE STRUCTURE; ADSORPTION CAPACITY; LONGMAXI FORMATION; PHASE-EQUILIBRIA; POROSITY MODEL; SICHUAN BASIN; FLOW; RESERVOIRS,"The shale oil transport mechanisms in inorganic matrix (iOM) and organic matrix (OM) nanopores are still not well understood, and the shape of nanopores is complex and diverse. Therefore, it is of critical importance to clarify the oil transport mechanisms in nanopores with different cross-sectional shapes. In this study, a model for oil transport is proposed to analyze the apparent permeability and flow enhancement based on the Hagen-Poiseuille equation. The proposed model takes into account the near-wall oil flow in iOM nanopores and the adsorbed oil flow in OM nanopores. In addition, the effects of different circular and elliptical cross-sections of nanopores and size of nanopores are considered. The proposed model is validated with the simulation data of non-equilibrium molecular dynamics and the Lattice Boltzmann method. The results indicate that: (1) the flow enhancement in iOM and OM nanopores first decreases rapidly and then stabilizes with an increasing length of semi-major axis a and semi-minor axis b because of the decreasing wall-oil interaction, and the apparent permeability of iOM increases as the axis a and axis b increase. When axis b is 2 nm, the permeability of OM increases with an increase in length of axis a, as length of axis b becomes larger, the permeability first decreases and then increases; (2) in iOM and OM nanopores, with a constant cross-sectional area, compared to nanopores with circle cross-sections, the flow enhancement becomes greater in nanopores with elliptical cross-sections, and the higher the ratio omega of the length of axis a to that of axis b, the greater the flow enhancement. The permeability of iOM nanopores decreases with an increasing ratio omega, while the permeability of OM nanopores first decreases and then increases. When the cross-sectional area is small, the permeability of OM nanopores increases with an increase in ratio omega, and as the cross-sectional area becomes greater, the permeability decreases with an increasing ratio omega. The proposed model demonstrates that elliptical cross-sections of nanopores can provide theoretical support for the development of shale oil reservoirs.",17,18,2
Lattice Boltzmann Method,,"Zhao, Yan-long; Wang, Zhi-ming",Prediction of apparent permeability of porous media based on a modified lattice Boltzmann method,LBGK; QSGS; Knudsen number; Correction factor,GAS-FLOW; TRANSPORT-PROPERTIES; UNIFIED DESCRIPTION; DIRECT SIMULATION; MODEL; PORE; SHALES; MICRO,"To characterize the micro-flow and predict the apparent permeability of porous media, a modified lattice Boltzmann method considering the volume diffusion effect was presented based on Klimontovich's kinetic equation and Enskog equation-based lattice Boltzmann Bhatnagar-Gross- Krook (LBGK) model. For comparison purposes, simulations of gas flow in the periodic body-centered cubic and tube were carried out initially. The simulation results show a good agreement with empirical correlations in the literatures. The porous structures were reconstructed using the QSGS (Quartet Structure Generation Set) method. Then, with the modified effective viscosity and the second-order slip boundary condition, a series of numerical simulations of gas flow in the reconstructed porous media with different mean Knudsen numbers was carried out based on the proposed model. The correction factor under different Knudsen number was predicted and compared with the Beskok & Karniadakis-Civan's correction. The present work provides a promising tool for handling the micro gas flow with complex geometries and boundaries.",14,14,3
Lattice Boltzmann Method,,"Zhao, Yan-long; Zhao, Lin; Wang, Zhi-ming; Yang, Hu",Numerical simulation of multi-seam coalbed methane production using a gray lattice Boltzmann method,Interlayer interference; Gray lattice Boltzmann method; Permeability; Pressure difference; Interference coefficient,PERMEABILITY PREDICTION; WESTERN GUIZHOU; EASTERN YUNNAN; FLUID-FLOW; GAS-FLOW; MEDIA; MODEL,"Multi-zone or multi-seam commingled production in CBM reservoir is an attractive option for extending and/or increasing existing gas production. To solve the problem of interlayer interference during commingled production, with varying permeability and pressure difference between coal seams, numerical simulations are carried out using a gray lattice Boltzmann method. Under different conditions of multi-seam commingled production, the pressure and velocity distributions are obtained. Then, the effects of permeability and pressure contrast on multi-seam commingled production are investigated. The results show that under the condition of commingled production with different permeability contrast, a greater permeability contrast will lead to a greater difference in gas production of each seam. And the smaller the reservoir permeability is, the faster the decrease of reservoir pressure near the wellbore is. For commingled production with different pressure contrast, the interlayer interference coefficient increases linearly with the increase of the pressure contrast. The interference degree of low pressure seam is far greater than that of high pressure seam. A lower reservoir permeability will lead to a greater interference coefficient. The research results provide a basis for revealing the interlayer interference mechanism, production dynamic analysis and production system optimization in multi-seam commingled production.",13,14,5
Volume Fraction,,"Wang, Zhihua; Bai, Ye; Zhang, Hongqi; Liu, Yang",Investigation on gelation nucleation kinetics of waxy crude oil emulsions by their thermal behavior,Water-in-oil emulsion; Gelation behavior; Nucleation kinetics; Waxy crude oil; Thermal analysis,WATER-IN-OIL; FLOW BEHAVIOR; TEMPERATURE; GAS; OPTIMIZATION; STABILITY; VISCOSITY; PIPELINES; MIXTURES,"Waxy crude oil emulsions exhibit gelation behavior, with nucleation observed within a certain temperature range. A kinetic model was developed and validated based on the thermal parameters obtained from differential scanning calorimetry cooling thermograms, and the nucleation rates of various water-in-waxy crude oil emulsions were determined in the temperature range in which gelation occurs. Although temperature had a dominant effect on the gelation and nucleation behavior of waxy crude oil emulsions, the nucleation rate also increased as the water volume fraction in the emulsion increased. Emulsified water droplets with smaller radii can be completely covered by wax particles, inducing a greater nucleation rate. Subjecting the emulsions to a greater shearing strength also increased the nucleation rate. This study provided new insights into the nucleation processes that occur during the formation of waxy crude oil emulsion gels and, in particular, the role of the emulsification properties.",63,62,7
Volume Fraction,,"Gharibshahi, Reza; Jafari, Arezou; Ahmadi, Hamid",CFD investigation of enhanced extra-heavy oil recovery using metallic nanoparticles/steam injection in a micromodel with random pore distribution,Oil recovery factor; Steam; Nanoparticles; CFD; Design experiment; Taguchi method; Optimization; Micromodel,MULTIPHASE MIXTURE MODEL; CAPILLARY-POROUS MEDIA; MULTICOMPONENT TRANSPORT; WETTABILITY ALTERATION; STEAM INJECTION; SANDSTONE CORES; SIMULATION; NANOFLUID; CATALYST,"The present study simulated thermal enhanced oil recovery (steam and nanoparticles) for the first time using computational fluid dynamics. To better visualize fluid flow in the reservoir, a 2D micromodel generated by commercial grid generation tools was used as the porous medium. Four parameters that have a great impaction on the process were studied to determine the best combination of factors to attain maximum oil recovery. Type of nanoparticle, volume fraction of nanoparticles, diameter of nanoparticles and temperature of injected fluid were examined using the Taguchi method. All governing equations were solved in Fluent software based on finite volume. The numerical results were in a good agreement with the experimental results and the data shows that Al2O3 nanoparticles have the greatest potential for enhanced oil recovery in comparison with CuO and Fe3O4 nanoparticles. Decreasing the diameter of the nanoparticles and increasing their volume fraction in the base fluid and the temperature of the injected fluid improved oil recovery and a large amount of oil was produced from the porous medium. Injecting the nanofluid at an optimal level decreased the viscosity of the extra heavy oil from 35 to 25 Pas.",18,20,6
Volume Fraction,,"Taheri-Shakib, Jaber; Keshavarz, Vahid; Kazemzadeh, Ezzatallah; Hosseini, Seyed Ahmad; Rajabi-Kochi, Mahyar; Salimidelshad, Yaser; Naderi, Hassan; Bakhtiari, Hesam Aloki",Experimental and mathematical model evaluation of asphaltene fractionation based on adsorption in porous media: Part 1. calcite reservoir rock,Asphaltene fractions; Porous media; Permeability; Porosity; Modelling,FUNCTIONAL-GROUP ADSORPTION; APPEARANCE TEMPERATURE WAT; VOLATILE ORGANIC-COMPOUNDS; HEAVY CRUDE-OIL; GAS-CHROMATOGRAPHY; SOLVENT INJECTION; HEATING TIME; DEPOSITION; MICROWAVE; SURFACE,"This study investigates the properties of asphaltene fractions in porous media and their role in reducing permeability and porosity. Based on the classification of a whole asphaltene deposited in porous media, the fractions can be defined as bulk, hard (h)-adsorbed, normal (n)-adsorbed, and irreversible (i)-adsorbed, which effects on porosity and permeability reduction in the reservoir rock. According to laboratory results for five types of calcite cores with porosity and permeability close to each other, the highest reduction in porosity (55%) and permeability (76%) is related to bulk asphaltene fractions. The n-adsorbed and h-adsorbed asphaltenes have approximately equal influence in reducing the porosity and permeability values in the reservoir rock. The i-adsorbed asphaltene, which has the highest adsorption on the rock surface, has the lowest porosity and permeability decrease due to lower amounts of asphaltene deposits in porous media. The amounts of hydrogen (H), nitrogen (N), sulfur (S), and oxygen (O) are higher in adsorbed fractions of asphaltene. In the case of hadsorbed asphaltene, H has the highest value in the asphaltene fractions (7.13 wt%). Compared with adsorbed asphaltene fractions, N values are higher in n-adsorbed (1.89 wt%) than h-adsorbed (1.41 wt%) fractions. This suggests that the S element plays a more significant role in the adsorption of asphaltene to the calcite surface. Based on the results, asphaltene compounds that adhere to the rock surface contain lighter carbon compounds than whole asphaltene. This means that the peak of the carbon compounds of h-adsorbed asphaltene in each rock sample is C-17. Fourier-transform infrared spectroscopy (FTIR) results show that the highest concentrations of carbonyl, carboxylic acid or derivative groups are found in h-adsorbed and n-adsorbed asphaltenes, respectively. A new experimental model of asphaltene deposition has been presented based on the deposition analysis of each asphaltene fraction in a porous medium under dynamic conditions, which results in a high correlation coefficient for each of the asphaltene classifications in the porosity and permeability reduction model. The reason for the high accuracy and uniqueness of the model is the use of parameters such as the velocity of fluid flow in the pores and the amount of volume injected in the reservoir rock sample, as well as the asphaltene fractions and their polarization ratio.",18,18,2
Volume Fraction,,"Su, Junwei; Chai, Guoliang; Wang, Le; Cao, Weidong; Yu, Jinbiao; Gu, Zhaolin; Chen, Chungang",Direct numerical simulation of pore scale particle-water-oil transport in porous media,Pore scale; Discrete element method; Fictitious domain method; OpenFOAM; RIGID,DISCRETE ELEMENT SIMULATION; IMMERSED BOUNDARY METHOD; CIRCULAR-CYLINDER; TRACKING METHOD; FLOW; DEPOSITION; ALGORITHM; SYSTEMS; VOLUME; MODEL,"In this work, a direct numerical simulation method, for pore scale particle-water-oil transport in porous media is proposed in hybrid Eulerian-Lagrangian framework. In this method, Navier-Stokes equation in Eulerian framework is coupled with discrete element method (DEM) in Lagrangian framework through direct numerical evaluation of fluid-particle interaction using fictitious domain method (FDM). In Eulerian framework, volume of fluid (VOF) method is employed to capture immiscible two-phase interface; Ghost fluid method and balanced-force scheme are used to treat the surface tension to lower interface spurious currents. In Lagrangian framework, RIGID algorithm is employed to detect the contact states between spherical particles with arbitrarily topological pore walls, making the method adapt to arbitrary pore space; Injection of particles with arbitrary size distribution at a specific mass flow rate makes the method adapt to open system. After validating the new method using two benchmark test cases, a numerical simulation of particle flooding process in a real rock is performed. Numerical results show that in the particle flooding process, three different stages, i.e. drainage period, analogy water flooding period and effective period of particle flooding, are involved. Distinct macroscopic flow characteristics are observed in different periods. Particle size is an important factor influencing the pore scale behaviors (such as, particle space translation and diffusion, remaining oil distribution, degree of fluid diversion) and macroscopic flow phenomena (such as, average oil fraction, average water or oil migration velocity in mainstream direction and transverse direction, sweeping efficiency).",16,18,7
Volume Fraction,,"Cui, Jiangfeng",Oil transport in shale nanopores and micro-fractures: Modeling and analysis,Shale oil; Asphaltenes; Mixed wettability; Adsorption; Mathematical model,MOLECULAR-DYNAMICS SIMULATION; ASPHALTENE PRECIPITATION; APPARENT PERMEABILITY; LIQUID PERMEABILITY; ORGANIC NANOPORES; FLOW; ENHANCEMENT; DIFFUSION; WATER; SLIP,"The mathematical modeling and analysis for the apparent permeability of shale oil with complicated compositions in dual-wettability shales (superior to existing single-component or single-wettability analysis), which is the core of this work, will help understand the detailed contributions of the considered mechanisms. Based on a previously established flow enhancement model, the effects of the mixed wettability and those triggered by asphaltenes, namely, the wettability alteration, the pore radius reduction, and the viscosity increment, are taken into account by respective corrections of the variables in the model. The effect of the mixed wettability is quantified by the water-wet area ratio, while the surface coverage, the adsorption thickness, and the volume fraction in the free phase are utilized to quantify the effects of asphaltenes. The volume fraction of asphaltenes in the free phase is related to that in both phases by the volume conservation equation. The full mathematical model and its several simplifications are achieved. Comprehensive sensitivity analysis and comparisons are carried out to demonstrate the effects of each variable (i.e., the pore radius, the initial water-wet surface ratio, the relative adsorption thickness, and the surface coverage) on: (1) the flow enhancement; (2) the relative importance of all mechanisms; (3) the differences among organic pores/inorganic pores/micro-fractures; and (4) the overall contribution of asphaltenes. The effect of different adsorption patterns (characterized by the relative adsorption thickness and the surface coverage) is also discussed.",14,14,3
Volume Fraction,,"Ghanbarian, Behzad; Torres-Verdin, Carlos; Lake, Larry W.; Marder, Michael",Gas permeability in unconventional tight sandstones: Scaling up from pore to core,Effective-medium approximation; Effective pore size; Electrical conductivity; Gas permeability; Pore-throat size distribution; Tight-gas sandstone,ELECTRICAL-CONDUCTIVITY; HYDRAULIC CONDUCTIVITY; APPARENT PERMEABILITY; TOMOGRAPHIC-IMAGES; EFFECTIVE STRESS; PARTICLE-SIZE; POROUS-MEDIA; MODEL; PRESSURE; FLOW,"Upscaling Klinkenberg-corrected gas permeability, k, in unconventional tight sandstones has numerous practical applications, particularly in gas exploration and production. In this study, we adapt the effective-medium approximation (EMA) model of Doyen - proposed first to estimate bulk electrical conductivity, sigma(b), and permeability in sandstones from rock images - to scale up sigma(b) and k in tight-gas sandstones from pore to core. For this purpose, we calculate two characteristic pore sizes: an effective hydraulic and an effective electrical pore size from porethroat size distributions - determined from mercury intrusion capillary pressure (MICP) curves - and pore-throat connectivity. The latter is estimated from critical volume fraction (or percolation threshold) for macroscopic flow. Electrical conductivity and permeability are then scaled up from the two characteristic pore sizes, tortuosity, and porosity by assuming two different pore geometries: cylindrical and slit-shaped. Comparison of results obtained for eighteen tight-gas sandstones indicates that the EMA estimates sigma(b) and k more accurately when pores are assumed to be cylindrical. We also estimate k from the pore-throat size distributions and the measured electrical conductivity using the EMA and critical path analysis (CPA), another upscaling technique borrowed from statistical physics. Theoretically, the former is valid in relatively heterogeneous porous media with narrow pore-throat size distribution, while the latter is valid in heterogeneous media with broad pore-throat size distribution. Results show that the EMA estimates k more accurately than CPA and arrives within a factor of two of the measurements on average.",13,13,5
Corrosion,,"Zhong, Xiankang; Lu, Wenjun; Yang, Huaijun; Liu, Min; Zhang, Yang; Liu, Hongwei; Hu, Junying; Zhang, Zhi; Zeng, Dezhi",Oxygen corrosion of N80 steel under laboratory conditions simulating high pressure air injection: Analysis of corrosion products,High pressure air injection; Corrosion products; Oxygen corrosion; Iron oxides,HIGH-TEMPERATURE CORROSION; CARBON-STEEL; CO2 CORROSION; IRON SULFIDE; MILD-STEEL; BEHAVIOR; HEMATITE; TRANSFORMATION; ENVIRONMENT; AKAGANEITE,"High pressure air injection (HPAI) is an effective and economic improved oil recovery process, however, the corrosion of tubing and casing in the injection well is one of the serious safety concerns which have limited its widely application. Until now the structure and composition of corrosion products formed in HPAI condition are still not fully clear because of the difficulty in simulating such a harsh environment in laboratory. In this work, the corrosion rates of N80 steel under laboratory conditions with different oxygen content (21-5% vol%), total pressure (50-20 MPa) and temperature (120-70 degrees C) simulating HPAI in Dagang oil field in China were investigated using weight loss measurement. The corrosion products on N80 steel surface were analyzed using scanning electron microscopy coupled with energy dispersive spectroscopy (SEM + EDS), X-ray diffraction (XRD) and transmission electron microscopy (TEM). The results show that the corrosion rate decreased with the decreasing oxygen partial pressure and temperature. Furthermore, for all the conditions, the corrosion rate was incredibly high in the simulating HPAI environment, consequently, large amount of corrosion products were formed. The corrosion products showed a two-layer structure: outer layer and inner layer. The outer layer was porous, brittle and easily flaked off, while the inner layer was more compact than outer layer. However, both layers could not effectively lower the corrosion rate of N80 steel in HPAI environment. The corrosion products were composed of hematite (alpha-Fe2O3), goethite (alpha-FeOOH), magnetite (Fe3O4) and trace amounts of Ca(OH)(2) and CaO. In addition, the structure and composition of corrosion products did not change with the temperature and oxygen partial pressure in the simulating HPAI conditions.",29,32,5
Corrosion,,"Ituen, Ekemini B.; Solomon, Moses M.; Umoren, Saviour A.; Akaranta, Onyewuchi",Corrosion inhibition by amitriptyline and amitriptyline based formulations for steels in simulated pickling and acidizing media,Amitriptyline; Industrial application; Steels; Corrosion inhibitor formulations; Acidic environment; Corrosion inhibition,1 M HCL; MILD-STEEL; CARBON-STEEL; ST37 STEEL; EXTRACT; BEHAVIOR,"Investigation into amitriptyline (AMI) as a corrosion inhibitor for different grades of pipeline steels (X80, J55 and mild steel) was undertaken under static conditions in 3.7% and 15% HCl solution and temperature ranging from 30 to 90 degrees C using electrochemical, gravimetric, and surface screening approaches. AMI is adjudged an effective steel corrosion inhibitor in 3.7% HCl at 30 degrees C but poor inhibitor at high temperatures and in 15% HCl. The values of enthalpy of adsorption and variation of protection efficacy with temperature point to physical interaction between AMI molecules and the steel surface. Evidence of formation of adsorbed film on the specimen surface has been found via Scanning electron microscope (SEM) and energy dispersive spectroscopy (EDAX) screening. Various formulations consisting of AMI as the base component and other additives (potassium iodide, glutathione and N-acetyl cysteine) have been developed. The formulations were tested at different experimental conditions and inhibition performance compared with that of a commercial corrosion inhibitor. Results obtained show that AMI based formulations can compete favorably with commercial inhibitor even at severe conditions. In 15% HCl solution and temperature of 90 degrees C, inhibition efficiency of 94% is recorded for commercial inhibitor and 92% for AMI based formulation. AMI based formulation can be utilized as effective corrosion inhibitor in oil and gas production.",25,26,4
Corrosion,,"Li, Jiankuan; Sun, Chong; Shuang, Shuo; Roostaei, Morteza; Fattahpour, Vahidoddin; Mahmoudi, Mandi; Zeng, Hongbo; Luo, Jing-Li",Investigation on the flow-induced corrosion and degradation behavior of underground J55 pipe in a water production well in the Athabasca oil sands reservoir,Corrosion scales; Carbon steel; Flow-induced corrosion; Ca-rich layer,CARBON-STEEL; AQUEOUS ENVIRONMENT; TUBE STEEL; X65 STEEL; EROSION; MECHANISM; PIPELINES; O-2; MO,"The corrosion behavior of J55 carbon steel pipe was investigated in a water production well environment in the Athabasca oil sands reservoir. The corrosion morphologies and the chemical compositions of corrosion products were examined by surface analysis techniques. The protection performance of the formed corrosion scales was evaluated using electrochemical measurements. The results show that severe erosion corrosion occurs on the inner wall of the pipe and causes a significant thinning, which is the dominant reason for the pipe failure. Likewise, the failure of the thread zone is originated from the severe corrosion of inner wall as well. Localized corrosion of carbon steel occurs in the welding zone because of the galvanic effect between stainless steel and carbon steel. Furthermore, the distributions of corrosion products on the inner wall are notably affected by the flow. Dense and thick Ca-containing corrosion scales act as a physical barrier layer and prevent the steel from further corrosion, whereas localized corrosion occurs in the regions with loose and thin corrosion scales.",15,16,3
Corrosion,,"Leporini, Mariella; Terenzi, Alessandro; Marchetti, Barbara; Corvaro, Francesco; Polonara, Fabio",On the numerical simulation of sand transport in liquid and multiphase pipelines,Sand deposition; Flow assurance; Oil and gas; Multiphase,DEPOSITION VELOCITY; FLOW; GAS; SUSPENSIONS,"Sand deposition in pipelines represents one of the problems that can arise in oil and natural gas production and transport. The main problems that sand can cause include the pipeline obstruction with the relative production loss, the increase of the lines erosion and corrosion and the compromising of the structural integrity. Moreover, there is a limit in the amount of sand that can be separated and removed. Therefore, methods and strategies to reduce the production of sand are key factors for safety and economic risks. In general sand deposition problems occur in different flow systems such as sand-multiphase mixtures of gas-oil-water or two-phase mixtures. In order to elaborate an effective method able to predict the amount of sand and to have a reliable prediction of sand transport velocity and entrainment processes, several factors requires to be considered, including sand characteristics, sand concentration, flow regimes, fluid properties and pipe properties. This paper presents the results of a detailed testing on the performance of a new sand transport model implemented in one-dimensional dynamic multiphase code, performed by comparing numerical results with experimental data. This study deals with both liquid-solid flow as well as gas-liquid-solid flow. The results demonstrate a good agreement between numerical and experimental data for the sand-liquid flow and sand transport in stratified gas-liquid flow, while show that for the sand transport in gas-liquid slug flow improvements are necessary.",14,14,4
Corrosion,,"Zhao, Jie; Xiong, Dan; Gu, Yanhong; Zeng, Qunfeng; Tian, Bin",A comparative study on the corrosion behaviors of X100 steel in simulated oilfield brines under the static and dynamic conditions,Corrosion behavior; X100 steel; Dynamic system; Temperature; Simulated oilfield brines,API-X100 PIPELINE STEEL; N80 CARBON-STEEL; CO2 CORROSION; PITTING CORROSION; EROSION-CORROSION; FORMATION WATER; CRUDE-OIL; TEMPERATURE; INHIBITION; CHLORIDE,"The influence of temperatures on the corrosion behaviors of X100 steel in simulated oilfield brines including CO2 under static and dynamic conditions at various temperatures up to 65 degrees C is investigated in the present paper. The static corrosion tests were conducted in a thermostatic water bath, and the dynamic corrosion tests were performed in the dynamic corrosion system. Potentiodynamic polarization (PDP) and electrochemical impedance spectroscopy (EIS) were used to study the corrosion performances of X100 steel. The microstructure and surface topography of the corrosion products were characterized by scanning electron microscope (SEM) and X-ray diffraction (XRD), respectively. The results show that the dynamic corrosions became serious comparing with the static corrosions regardless of the temperature and immersion time. The corrosion current of the dynamic tests was 8 times higher than that of the static tests at 60 degrees C. When just immersed, the corrosion resistance of X100 steel decreased with the increase of temperature. When immersed for 24 h under static conditions, the corrosion resistance was highest at 60 degrees C. Under the dynamic conditions, the corrosion resistance decreased first and then increased with the increase of temperature. The corrosion products were mainly FeCO3 and Fe3C. The corrosion model was established. The relationship between the formation of the corrosion products and working conditions was also discussed and clarified.",14,16,4
PDC Bit,,"Soares, Cesar; Gray, Kenneth",Real-time predictive capabilities of analytical and machine learning rate of penetration (ROP) models,Rate of penetration; ROP modeling; Real-time retraining; Machine learning; PDC bit,PRESSURE; BOURGOYNE,"Real-time drilling optimization consists of selecting operational parameters that maximize a desirable measure of drilling performance. Drilling optimization efforts often aspire to improve drilling speed, commonly referred to as rate of penetration (ROP). Three operational drilling parameters may be constantly adjusted at surface to influence ROP: weight on bit (WOB), drillstring rotational speed (RPM), and drilling fluid (mud) flow rate. In the traditional, analytical approach to ROP modeling, inflexible equations relate WOB, RPM, flow rate and/or other measurable drilling parameters to ROP and empirical model coefficients are computed for each rock formation to best fit field data. Over the last decade, enhanced data acquisition technology and widespread cheap computational power have driven a surge in applications of machine learning (ML) techniques to ROP prediction. Machine learning algorithms leverage statistics to uncover relations between any prescribed inputs (features/predictors) and the quantity of interest (response). The biggest advantage of ML algorithms over analytical models is their flexibility in model form. With no set equation, ML models permit segmentation of the drilling operational parameter space. However, the increased model complexity diminishes interpretability of how an adjustment to the inputs will affect the output. There is no single ROP model applicable in every situation. This study investigates real-time predictive capabilities of analytical and ML ROP models in a continuous learning setting. Data are constantly recorded as a well is drilled, and it is postulated that ROP models can learn and adapt in real-time to become more accurate. Novel learning metrics demonstrate that machine learning models reduce test error much more effectively than analytical models with incremental training data availability. Both analytical and ML model performance improves with shortened retraining intervals, defined either by length or number of data points. Cross-validation is investigated as a methodology to select the best performing ROP model in real-time.",42,42,8
PDC Bit,,"Cheng, Zhen; Li, Gensheng; Huang, Zhongwei; Sheng, Mao; Wu, Xiaoguang; Yang, Jiawei",Analytical modelling of rock cutting force and failure surface in linear cutting test by single PDC cutter,PDC bits; Single cutter; Rock failure; Analytical model,NUMERICAL-SIMULATION; FRAGMENTATION,"The PDC (Polycrystalline Diamond Compact) bits are the most widely used bits in oil drilling engineering, in order to further improve their longevity and ROP (Rate of Penetration), single PDC cutter research is very important. However, previous work focused mostly on experiment and numerical simulation while analytical modelling still lacks progress. In this paper, a new analytical model of rock cutting force and failure surface is proposed based on the stress state calculation of each micro-unit inside the rock. The cutting force predicted by this model is well verified by experiments under different parameters like depth of cut, back rack angle, rock type, cutter size and confining pressure. It is also found that the shape of failure surface is a curved line rather than straight, and long and thin cuttings will be formed. Finally, on the basis of this model, the influence mechanism of each parameter on cutting force and the shape of failure surface are analyzed. The method and result of this study are expected to provide a better understanding of cutting force and rock breaking mechanism by PDC bits.",20,22,5
PDC Bit,,"Cheng, Zhen; Sheng, Mao; Li, Gensheng; Huang, Zhongwei; Shi, Huaizhong; Dai, Xianwei; Guo, Zhansheng",Cracks imaging in linear cutting tests with a PDC cutter: Characteristics and development sequence of cracks in the rock,PDC bits; Single cutter test; Crack pattern; Rock breaking mechanism,BRITTLE; MECHANISMS; BEHAVIOR; GROWTH,"Imaging cracks is a direct way to learn the rock breaking mechanism beneath a PDC cutter. In this study, a series of linear cutting tests and precise observations of cracks were conducted. The formation of major cracks was captured in-situ with a high speed camera in the process of cutting rock sheets. Then the cracks under the cutting groove (subsurface cracks) were studied by reproducing the cutting groove after cuffing some rock blocks and further observed by means of thin-section optical microscopy. Finally, the development sequence of the cracks and adjacent crushed zone was determined by recording the cutting process on a rock-like silica glass block. The results show that the shape of major cracks is mainly curved, both upward and downward curves were observed. The major cracks mainly initiate at the tip of the cutter when cuffing sandstone and granite, while they initiate more randomly in marble. The length and angle of the subsurface cracks vary with the rocks: the subsurface cracks extend the longest in granite, while propagating more vertically in sandstone. Finally, it is determined that the major cracks initiate after the formation of crushed zone. And the initiation of major cracks will enlarge the crushed zone and lead to the initiation and propagation of the subsurface cracks. The results in this paper are expected to further reveal the rock breaking mechanism beneath a PDC cutter.",17,18,4
PDC Bit,,"Chen, Pengju; Meng, Meng; Miska, Stefan; Yu, Mengjiao; Ozbayoglu, Evren; Takach, Nicholas",Study on integrated effect of PDC double cutters,PDC bit design; Double cutters; Linear poroelasticity; Cutter interval; Depths of cut,HORIZONTAL WELL; ROCK; MODEL; PRESSURE; FORCE,"This paper studies the integrated effect of double cutters on cutting rock. The rock being cut is subjected to hydrostatic pressure. Double cutters paralleled to each other and separated with a distance are advancing in the same direction and removing rock materials over constant depths of cut. The integrated effect indicates the situation where stresses in rock induced by double cutters can be large enough to even fragment the rock between double cutters. Once this happens, double cutters will have a large cutting area, thus increasing cutting efficiency. A cutting model is built in this paper to study the integrated effect of double cutters. The model calculates coupled stresses and pore pressure in the rock induced by double cutters and predicts cutting forces and MSE. The influences of depths of cut and cutter interval on the integrated effect are discussed. The MSE of double cutters is compared to that of a single cutter under the same cutting condition. Case studies on Indiana limestone show that when the depths of cut are large and the cutter interval is small enough, the integrated effect of double cutters can help reduce the MSE by 5-25 percent. Results in this paper can provide new insights on bit-rock interaction and PDC bit design.",14,15,3
PDC Bit,,"Huang, Kuilin; Ai, Zhijiu; Yang, Yingxin; Xie, Zongliang",The improved rock breaking efficiency of an annular-groove PDC bit,Annular groove; PDC bit; Rock breaking efficiency; Bottomhole topography,,"To solve a major problem faced by drilling technicians, that of how to improve rock breaking efficiency in complex strata, this paper introduces a polycrystalline diamond compact (PDC) drill bit with a special structure. Static-pressure breaking tests show that the breaking work ratio of a single tooth on a ridge is much smaller than that on flat rock samples, and the effect of ridge height on breaking work ratio is greater than that of ridge width. Single-tooth scrape tests show that the tangential force, axial force, and breaking work ratio of PDC teeth when scraping on a ridge are greatly reduced compared with flat rock samples, and the ridge width has a greater influence on the breaking work ratio than ridge height. A test bit with a diameter of 215.9 mm and the possibility of zero, one, or two annular grooves is designed and manufactured. Compared with the conventional, full-coverage PDC bit, the specific energy of the double-groove bit is reduced by 26.9%. The annular-groove PDC bits achieve large-scale cuttings when breaking the ridge created by the bit, and the rock breaking efficiency is greatly improved. At the same time, the raised ridges of the bottomhole increase the stability of the drill bit, providing a feasible solution for rock breaking when drilling complex strata.",13,13,9
Digital Rock,,"Wang, Ying Da; Armstrong, Ryan T.; Mostaghimi, Peyman",Enhancing Resolution of Digital Rock Images with Super Resolution Convolutional Neural Networks,Digital rock; Super resolution; Neural networks; Micro-CT imaging,X-RAY MICROTOMOGRAPHY,"Single Image Super Resolution (SISR) techniques based on Super Resolution Convolutional Neural Networks (SRCNN) are applied to micro-computed tomography (micro-CT) images of sandstone and carbonate rocks. Digital rock imaging is limited by the capability of the scanning device resulting in a trade-off between resolution and field of view, and super resolution methods tested in this study aim to compensate for this limitation. SRCNN models SR-Resnet, Enhanced Deep SR (EDSR), and Wide-Activation Deep SR (WDSR) are used on the Digital Rock Super Resolution 1 (DRSRD1) Dataset of 4x downsampled images, comprising of 2000 high resolution (800 x 800) raw micro-CT images of Bentheimer sandstone and Estaillades carbonate. The trained models are applied to the validation and test data within the dataset and show a 3-5 dB rise (50%-70% reduction in relative error) in image quality compared to bicubic interpolation, with all tested models performing within a 0.1 dB range. Difference maps indicate that edge sharpness is completely recovered in images within the scope of the trained model, with only high frequency noise related detail loss. We find that aside from generation of high-resolution images, a beneficial side effect of super resolution methods applied to synthetically downgraded images is the removal of image noise while recovering edgewise sharpness which is important for the segmentation process. The model is also tested against low-resolution images of Bentheimer rock with image augmentation to account for natural noise and blur. The SRCNN method is shown to act as a preconditioner for image segmentation under these circumstances which naturally leads to further future development and training of models that segment an image directly. Image restoration by SRCNN on the rock images is of significantly higher quality than traditional methods and suggests SRCNN methods are a viable processing step in a digital rock workflow.",25,25,7
Digital Rock,,"Kong, Lingyun; Ostadhassan, Mehdi; Hou, Xiaodong; Mann, Michael; Li, Chunxiao",Microstructure characteristics and fractal analysis of 3D-printed sandstone using micro-CT and SEM-EDS,3D-printed rocks; Microstructures; Sandstone; Micro-computed tomography,RAY COMPUTED-TOMOGRAPHY; MECHANICAL-PROPERTIES; RESERVOIR ROCKS; ORGANIC-MATTER; PORE STRUCTURE; PERMEABILITY; PARTICLES; ALGORITHM; VOLUME; BASIN,"Replicating sedimentary rocks using three-dimensional (3D) printing can support routine reservoir rock analysis in petrophysical and geomechanical experiments, which is done limited in scope due to lack of suitable printing materials and achievable resolution. Following our previous studies on gypsum powder with binder, a new printing material, silica sand, is used and characterized in this study to demonstrate the microstructure and its similarity to Berea Sandstone. Binder jetting printing system was specifically utilized to bond silica sand particles to create intact cylindrical samples without digital porous model as input. Created samples were first scanned by Backscattered Scanning Electron Microscope (BS-SEM) and Energy Dispersive Spectroscopy (EDS) to identify the particles, the packing mode and cement (binder). Next, micro-computed tomography (CT) was used to determine the microstructure of the samples, including the size and the shape of both particles and pores, in the 3D space. In addition, anisotropy that was found to originate from the pore structures was quantified by comparing the characteristics of pores in different directions. Fractal dimensions from different sample sizes, 6 mm and 12 mm in diameter, were also calculated for pore structure analysis in order to illustrate the effect of sample size on pore heterogeneity in 3D printed samples with silica. The results demonstrated the feasibility of substituting 3D-printed sandstones for natural rocks regarding pore structures for experimental validation of petrophysical models.",24,26,10
Digital Rock,,"Sun, Huafeng; Belhaj, Hadi; Tao, Guo; Vega, Sandra; Liu, Luofu",Rock properties evaluation for carbonate reservoir characterization with multi-scale digital rock images,Digital rock analysis; Carbonate rocks; Multi-scale CT images; Rock properties evaluation; Heterogeneity,,"Digital rock analysis (DRA) following the digital imaging techniques can be used to image detailed rock microstructures and simulate rock properties, such as porosity and permeability, for reservoir characterization. However, for most carbonate rocks, there are apparent differences in rock texture and minerals and clear variations of rock properties with location. This kind of heterogeneity often leads to a degree of unpredictability in DRA simulation. In addition, smaller sample size is necessary for a higher resolution image but the rock properties derived from bigger physical sample are more representative. Therefore, for a heterogeneous rock sample, it is impractical to predict its rock properties with only single resolution image. In this paper, we evaluate the rock properties using two heterogeneous carbonate rock samples and their corresponding multi-scale digital rock images including thin sections, scanning electron microscope (SEM) and X-ray computed tomography (XCT) images. A DRA upscaling method is also proposed. The analysis and results show that: 1) the simulated porosity and permeability agree well with their lab measurements; 2) the heterogeneity is clearly observed with these 2D and 3D rock images and their corresponding simulations; 3) the rock properties of the two carbonate rock samples are well evaluated by these rock images, lab measurements and numerical simulations.",24,24,5
Digital Rock,,"Connolly, Paul R. J.; Yan, Weichao; Zhang, Daniel; Mahmoud, Mohamed; Verrall, Michael; Lebedev, Maxim; Iglauer, Stefan; Metaxas, Peter J.; May, Eric F.; Johns, Michael L.",Simulation and experimental measurements of internal magnetic field gradients and NMR transverse relaxation times (T-2) in sandstone rocks,NMR; T-2; Internal magnetic field gradients; Simulation,POROUS-MEDIA; SURFACE RELAXIVITY; PORE-SIZE; DIFFUSION; SUSCEPTIBILITY; DISTRIBUTIONS; ENHANCEMENT; EQUATIONS; DECAY; WATER,"NMR T-2 measurements are widely used to determine various petrophysical properties of rock cores. Internal magnetic field gradients, which occur in rock cores during NMR measurements due to magnetic susceptibility differences between the rock matrix and the pore fluid, can however distort these T-2 measurements. Here we implement a FEM simulation of these internal magnetic field gradients on 3D digital mu CT images for five different sandstone rocks, coupled with a random walk simulation of the T-2 NMR signal relaxation process. The FEM simulations required the magnetic susceptibility of each sandstone, this was directly measured using a SQUID magnetometer over a range of magnetic field strengths. The resultant probability distributions of internal magnetic field gradients were then compared against equivalent experimental measurements; they were generally in reasonable agreement, however the simulations failed to capture the larger magnetic field gradients that were observed experimentally. By consideration of various potential reasons for this, we identify the assumption of a single mean magnetic susceptibility as being the primary source of the variation between simulated and measured results. Simulations of 2 MHz T-2 relaxation process are shown however to be in good agreement with experimental measurements across the five sandstones studied.",24,24,1
Digital Rock,,"Wang, Xiukun; Sheng, James J.",Multi-scaled pore network modeling of gas-water flow in shale formations,Multi-scaled pore network modeling; Shale gas; Relative permeability,RELATIVE PERMEABILITY; NANOPOROUS SHALE; WETTING LIQUID; POROUS-MEDIA; BAKKEN SHALE; MECHANISMS; DISPLACEMENT; PROPAGATION; RESERVOIRS; TRANSPORT,"Multiphase flow is commonly encountered within shale reservoirs, however, the previous studies are more focused on single phase flow. Due to the extremely low permeability of shale formations, the experimental measurements are not capable to be performed. Attempts are made by applying the techniques of digital rock analysis and pore network modeling to investigate the multiphase flow mechanisms in shale reservoirs. This work follows this way. Firstly, a stochastic pore network generation algorithm and a two-phase flow simulation method are presented. This algorithm is applied and validated in Berea sandstone. By applying the proposed algorithm, the organic and inorganic pore networks are generated for shale formations, then the multi-scaled pore network is established after upscaling the organic pores to an organic path. Finally, the gas-water flow is simulated within this established multi-scaled pore network and some analysis and discussions are conducted. The results imply that the characteristics of pore systems in shale formations pose an extreme impact on the gas-water flow mechanisms, especially the proportion of organic pores and pore-throat aspect ratio.",17,19,7
Computational Fluid Dynamics,,"Zhu, Jianjun; Zhu, Haiwen; Zhang, Jiecheng; Zhang, Hong-Quan",A numerical study on flow patterns inside an electrical submersible pump (ESP) and comparison with visualization experiments,Electrical submersible pump; Multiphase flow; Flow pattern; Eulerian-Eulerian; VOF,CENTRIFUGAL PUMP; ENTRAINED AIR; SIMULATION; PERFORMANCE; VISCOSITY; IMPELLER; NUMBER; WATER; OIL,"This paper presents a numerical study of flow pattern recognition inside the rotating impeller of an electrical submersible pump (ESP) using the transient multiphase Computational Fluid Dynamics (CFD) simulations. The calculation domain is constructed based on the previous experimental facility for visualizing flow patterns in an ESP (Barrios (2007)). The high-quality structured mesh comprising hexahedral grids is generated using multi-block technique in ANSYS ICEM. For CFD simulations, the realizable k-epsilon turbulence model with volume of fluid (VOF) and Eulerian-Eulerian multiphase models is successfully implemented in ANSYS Fluent solver. The sliding mesh technique is applied to interfaces where rotating and stationary parts interact. By incorporating the same boundary conditions as Barrios experimental study, three flow cases with constant gas flow rates and varying liquid flow rates are selected to conduct numerical simulations. The comparison of simulation results with Barrios' observations shows that the Eulerian-Eulerian multiphase model is superior to VOF model for simulating gas-liquid two-phase flow in a rotating ESP. The single-phase simulation results match catalog curves, which validates the numerical methodology. For two-phase simulations, the simulated flow patterns using Eulerian-Eulerian model agree well with visualization experiments. Different flow patterns prevailing inside the rotating ESP impeller are captured. At low gas flow rate, bubbles are dispersed in liquid phase, and the flow pattern is categorized as dispersed bubble flow. As gas flow rate increases, bubbles can accumulate and coalesce, causing large gas-pocket formation leading to intermittent/slug flow. Transient multiphase CFD simulation is an efficient and reliable tool to predict flow patterns inside ESPs.",26,28,2
Computational Fluid Dynamics,,"Cui, Ronghao; Feng, Qihong; Chen, Hongwei; Zhang, Wei; Wang, Sen",Multiscale random pore network modeling of oil-water two-phase slip flow in shale matrix,Pore network model; Shale oil; Two-phase flow; Slip effect; Computational fluid dynamics,FRACTURED HORIZONTAL WELL; FAST MASS-TRANSPORT; POROUS-MEDIA; RELATIVE PERMEABILITY; DYNAMIC PROPERTIES; CO2 SEQUESTRATION; ORGANIC-MATTER; GAS-FLOW; NANOPORES; RESERVOIR,"The large-scale hydraulic fracturing technology is commonly employed to significantly improve oil recovery in shale. An exceptional phenomenon from many field tests is worthy of attention that the majority of fracturing fluid (mainly water) does not return to the surface during hydraulic fracturing, but flows into shale matrix. As a consequence of this phenomenon, oil-water two-phase flow would happen. However, the fluid transportation in nano-pores is different from that of the conventional sandstone reservoirs. To understand oil-water two-phase flow in shale, an integrated pore network model (PNM) framework including network construction and flow simulation is developed. In the network construction, combined with a pore-size distribution (PSD) curve of shale system, a shale multiscale random pore network model is proposed, where organic pores and inorganic pores can be distinguished appropriately. In the flow simulation, considering that the traditional Hagen-Poiseuille equation may not be applicable in shale system, new bulk fluid and corner film flow models with slip length in various geometric pores (circular, square, equilateral triangle) are developed using the computational fluid dynamic (CFD) method. Through the quasi-static simulation technique, we estimate the flow properties in shale including capillary pressure and relative permeability. Simulation results confirm the slip effect would significantly affect oil-water two-phase flow in shale. And then, influences of shale pore structure on two-phase flow are further investigated. Through coupling network construction and two-phase flow simulation, we believe our work could shed light on the further research for multi-phase transportation in shale.",23,24,9
Computational Fluid Dynamics,,"Gharibshahi, Reza; Jafari, Arezou; Ahmadi, Hamid",CFD investigation of enhanced extra-heavy oil recovery using metallic nanoparticles/steam injection in a micromodel with random pore distribution,Oil recovery factor; Steam; Nanoparticles; CFD; Design experiment; Taguchi method; Optimization; Micromodel,MULTIPHASE MIXTURE MODEL; CAPILLARY-POROUS MEDIA; MULTICOMPONENT TRANSPORT; WETTABILITY ALTERATION; STEAM INJECTION; SANDSTONE CORES; SIMULATION; NANOFLUID; CATALYST,"The present study simulated thermal enhanced oil recovery (steam and nanoparticles) for the first time using computational fluid dynamics. To better visualize fluid flow in the reservoir, a 2D micromodel generated by commercial grid generation tools was used as the porous medium. Four parameters that have a great impaction on the process were studied to determine the best combination of factors to attain maximum oil recovery. Type of nanoparticle, volume fraction of nanoparticles, diameter of nanoparticles and temperature of injected fluid were examined using the Taguchi method. All governing equations were solved in Fluent software based on finite volume. The numerical results were in a good agreement with the experimental results and the data shows that Al2O3 nanoparticles have the greatest potential for enhanced oil recovery in comparison with CuO and Fe3O4 nanoparticles. Decreasing the diameter of the nanoparticles and increasing their volume fraction in the base fluid and the temperature of the injected fluid improved oil recovery and a large amount of oil was produced from the porous medium. Injecting the nanofluid at an optimal level decreased the viscosity of the extra heavy oil from 35 to 25 Pas.",18,20,6
Computational Fluid Dynamics,,"Wee, Siaw Khur; Yap, Yung Jian",CFD study of sand erosion in pipeline,CFD; Erosion; Particle size; Reynolds stress model; Rosin rammler expression,SOLID PARTICLE EROSION; ELBOWS; SIZE; MODELS; WEAR,"Pipeline erosion remain a major headache for petroleum industry with its underlying safety threats and financial integrity. The main objective of this research paper is to investigate sand erosion behaviour in 76.2 mm diameter with Computational Fluid Dynamics (CFD). According to literature, simulation erosion by fine sand particles (< 50 mu m) tend overpredict the erosion result; transportation of sand particles in elbow are under the influence of fluid particles; slight altered geometries produce significantly different erosion results. Thus, CFD analysis with Eulerian-Lagrangian approach is utilised to solve continuous phase with Navier-Stokes equations, while secondary phase with particle force balance. Reynolds Stress Model along with low Reynolds number correction is used to model the turbulence behaviour of continuous fluid phase to address viscous boundary effect at near wall region and secondary flows in elbow for more accurate results. Validation results of this study shown that assumption of constant size for every sand particle led to more than 10% overprediction of maximum erosion rate. Overprediction had been successfully reduced to less than 5% by fitting actual size distribution of particle into Rosin Rammler equation to model the particle size. In addition, effect of sand size, flow orientation, elbow bending angle and fluid type were investigated. The following conclusion had been made: power law relationship observed between erosion rate and sand size; 30 mu m particle produced a local maximum erosion at the trendline due to combination effect of sliding and direct collision; horizontal oriented flow shown asymmetric erosion behaviour due to effect of gravity; erosion with increasing elbow angle from 30 degrees to 90 degrees showed increasing erosion rate; water sand erosion was focused at the side of the elbow rather than the outer radius indicated erosion was highly dependent on carrier fluid properties.",17,23,4
Computational Fluid Dynamics,,"Asim, Taimoor; Mishra, Rakesh; Oliveira, Antonio; Charlton, Matthew",Effects of the geometrical features of flow paths on the flow capacity of a control valve trim,Continuous-resistance trim; Control valve; Computational fluid dynamics; Flow capacity; Valve opening position,HYDRAULIC CAPSULE PIPELINES; OPTIMAL-DESIGN; PERFORMANCE; MODELS; SHAPE,"Control valves are an integral part of a number of energy systems, such as those used in chemical and nuclear industries. These valves are used to regulate the amount of fluid flow passing through these systems. A key component of a control valve is its trim, which in case of a multi-stage continuous-resistance trim consists of a staggered arrangement of columns. Flow passing through the channels formed between adjacent columns (also called as flow paths), loses a significant amount of its energy and regulates the pressure field. As the geometrical features of these flow paths dictate the flow capacity of the trim, systematic investigations have been carried out to analyse the complex flow behaviour within these flow paths. Well-verified computational fluid dynamics based solver has been used to investigate the effects of the geometrical features of flow paths on the flow capacity of the trim, at various valve opening positions. It has been noticed that reducing the size of flow paths increases the flow capacity of the trim, however, at a critical flow path size, the inherent opening characteristics of a trim have been observed to alter. In order to recover the original opening behaviour of the trim, careful manipulation of the flow paths is required, which has been successfully achieved in the present investigation.",15,16,3
Real Time,,"Wang, Lei; Fan, Yiren",Fast inversion of logging-while-drilling azimuthal resistivity measurements for geosteering and formation evaluation,Azimuthal resistivity measurement; Boundary detection; Distance to boundary (DTB); Sliding window technique,TRIAXIAL INDUCTION TOOL; ELECTROMAGNETIC-FIELDS; HIGH-ANGLE; COMPUTATION; 2.5D,"We developed an efficient parametric inversion method for the determination of the distances to boundaries (DTBs), dip angle, and formation anisotropic resistivities from logging-while-drilling (LWD) azimuthal resistivity measurements (ARM) in real time. To increase the efficiency, the development employed a depth window, which will slide along the well trajectory during data processing. The local structure inside the depth window can be regarded as one-dimensional (1D) layered formation. A three-layer model (one transverse isotropic (TI) layer embedded between two isotropic shoulder layers) is assumed in the inversion to rebuild the formation structure. Then, the inversion problem is solved using a regularized Levenberg-Marquardt minimization approach. Multiple initial guesses are employed in order to avoid local minima and to find the global solution. Synthetic experiments show that the developed algorithm, which is capable of handling a large subset of the complex 3D conditions and arbitrary well trajectory, is robust and efficient. Discussions are also made to further demonstrate the advantages and limitations of ARM and the inversion processing in geosteering and formation evaluation.",23,25,2
Real Time,,"Tang, Hewei; Zhang, Shang; Zhang, Feifei; Venugopal, Suresh",Time series data analysis for automatic flow influx detection during drilling,Kick detection; Time series data; Automatic detection; Offshore drilling; Dimensionless kick indicators,KICK DETECTION; PREDICTION,"Automatic and early detection of flow influx during drilling is important for improving well-control safety. In this paper, a new method that can automatically analyze real-time drilling data and detect the flow influx event is presented. The new method combines the physics-based dimension reduction and time-series data mining approaches. Two kick indicators are defined, representing the drilling parameter group (DPG) and flow parameter group (FPG), respectively. Additionally, two real-time trend-analysis methods, the divergence of moving average (DMA), and the divergence of moving slope average (DMSA) are applied to quantify trend evolutions of the two indicators. The kick event is identified based on the anomalous trends held by the two kick indicators. A final kick-risk index (KRI) is calculated in real time to indicate the probability of kick events and to trigger the alarm. The method is tested against four offshore kick events. With KRI threshold setting as 0.8, the average detection time is 64% less than the reported detection time. The application of DPG kick indicator allows the early kick detection without additional downhole sensors or costly flow meters.",22,23,0
Real Time,,"Geng, Zhi; Wang, Hanqing; Fan, Meng; Lu, Yunhu; Nie, Zhen; Ding, Yunhong; Chen, Mian",Predicting seismic-based risk of lost circulation using machine learning,Machine learning; Lost circulation; Seismic attribute; Mud loss; Seismic interpretation,CURVATURE,"Lost circulation during well drilling and completion wastes productive time, and even kills the well in severe cases. Timely identifying lost circulation events and taking countermeasures has been the focus of related study. However, a real prediction of lost circulation risk before drilling would be an active response to the challenge. In this paper, a technical solution is proposed to evaluate geological lost-circulation risk in the field using 3D seismic data attributes and machine learning technique. First, four seismic attributes (variance, attenuation, sweetness, RMS amplitude) that are the most correlated with lost circulation incidents are recommended. Then a prediction model is built by conducing supervised learning that involves a majority voting algorithm. The performance of the model is illustrated by six unseen drilled wells and shows the ability and potential to forecast lost circulation probability both along well trajectory and in the region far away from the drilled wells. The prediction resolution in the lateral and vertical direction is about 25 m and 6 m (2 ms), respectively, which are distinct advantages over the traditional description of geological structures using seismic data. It shows that the lost circulation risk can be hardly recognized by interpreting one specific seismic attribute, which is a common practice. Finally, the challenges in predicting lost circulation risk using seismic data are summarized. Overall, the study suggests that machine learning would be a practical solution to predict various construction risks that are related to seismic-based geological issues. Knowing in advance the risks, people could avoid or at least minimize the losses by optimizing well deployment in the field and taking preventive measures.",14,16,5
Real Time,,"Aarsnes, Ulf Jakob F.; Auriol, Jean; Di Meglio, Florent; Shor, Roman J.",Estimating friction factors while drilling,Coulomb friction; Estimation; PDEs; Drill string torsional dynamics,SELF-EXCITED VIBRATIONS; STICK-SLIP; MODEL,"We design and test an algorithm for estimating the bit angular velocity and side forces on a drill string using only topside measurements fed into an adaptive observer. To derive the algorithm gains the drill string is modeled as a distributed wave equation coupled with Ordinary Differential Equations (ODEs) at the boundaries which represent the lumped dynamics of the top-drive and BHA, respectively. Here, the algorithm uses only measurements from the top-drive, while the non-linear side-forces are lumped at the BHA. The obtained observer gains are then implemented on a previously validated torsional drill string model with a distributed BHA model and distributed Coulomb side forces implemented as an inclusion. This design approach combines a high fidelity model with recent theoretical developments on estimation of PDEs to find appropriate feedback gains to ensure a fast and robust tuning. The feasibility of the approach is illustrated by showing convergence in estimated friction factors to the true values when testing on simulated data. When testing on full scale field data, friction factors converge to the same value for different initial values which indicates both good estimates and a robustness of the approach. The estimates produced by the algorithm can be displayed to a driller in real time in an advisory system, and the result can be built on to help optimize the drilling operation, detect faults and unwanted incidents, aid on-site decision making, and improve control of directional drilling.",14,14,1
Carboxylic Acids,,"Sayed, Amr M.; Olesen, Kristian B.; Alkahala, Abdul Sattar; Solling, Theis, I; Alyafei, Nayef",The effect of organic acids and salinity on the interfacial tension of n-decane/water systems,IFT; Salinity; Pendant droplet; Carboxylic acids; Surfactants,CRUDE-OIL; WATER; SURFACTANT; WETTABILITY; PRESSURE; BEHAVIOR; TEMPERATURE; FRACTIONS; RULES; BASES,"We have investigated how a homologous series of straight-chain carboxylic acids with a cyclohexyl substituent in the opposite end of the functional groups impacts the interfacial tension (IFT) between decane (oil) and water. The employed method was the pendant droplet technique. We do not observe any striking effect of expanding the chain length: all acids reduced the IFT compared to water by approximately 20 mN/m. Additionally, the effect of changing the chemical character and the concentration of the cation in a series of brines where studied too, and again we do not observe a significant IFT impact. The only modification that significantly reduces the IFT is the modification of the anion from chloride to carbonate, a change that results in an increased pH and thus a transformation of the constituent acids from their neutral to their anionic form. This is expected to result in a reduced IFT because of the polar end of the surfactant is even more polar which alleviates the stress on the surface.",22,22,0
Carboxylic Acids,,"Al-Saedi, Hasan N.; Brady, Patrick V.; Flori, Ralph E.; Heidari, Peyman",Insights into the role of clays in low salinity water flooding in sand columns,Geochemistry; Low salinity Water Flooding; Mechanisms of the Low Salinity Water; Enhanced Oil Recovery,OIL-RECOVERY; WETTABILITY ALTERATION; MAGNESITE DISSOLUTION; SPATIAL-DISTRIBUTION; HETEROGENEITY; FLOW; SORPTION; AQUIFER; IMPACT; BRINE,"Clays in sandstone are thought to be a key factor in low salinity (LS) water flooding. This study investigates the effects of quartz, kaolinite and illite in LS water flooding in synthetic sand columns as a function of temperature. Four chromatography columns containing different amounts of pure quartz sand, illite, and kaolinite (100% quartz sand; 95/5% sand/illite; 95/5 sand/kaolinite; and 95/2.5/2.5% sand/illite/kaolinite). The use of these synthetic columns gives full control over mineralogy. These columns were saturated with high salinity (HS) formation water with 0.01 M (M) sodium acetate and aged for a week at 70 degrees C. They were then flooded with waters (yes, the use of water to displace water) with various salinities at four different temperatures (25, 70, 90 and 120 degrees C). Effluent concentrations of Ca2+ and acetate (CH3COO-) and pH were measured. This is a novel experimental design, where formation water containing sodium acetate is flooded with waters of varying salinity to gain insight into LS flood performance and possible recovery mechanisms. The hypothesis pursued here is that the behavior of the acetate ion (attached to matrix minerals during the aging process and then released due to ionic exchange) in an LS flood would provide a valuable analog that would simulate the bonding of carboxylic acids in crude oils with reservoir matrix minerals (and subsequent desorption during LS flooding). Key results include the following: (a) Our hypothesis was correct-the use of Na acetate behaved analogously to carboxylic acid, giving useful insights; (b) The quartz-only column showed strong evidence (elevated pH, presence of Ca2+ and acetate in effluent) of ionic exchange due to LS flooding, showing that pure quartz is responsive to LS flooding and that clays are not absolutely needed; (c) Quartz plus kaolinite plus illite gave a slightly higher response than pure quartz so clays can play a role. Oil displacement results were also done for a pure quartz sand column, and this showed a strong response to the LS flood, confirming that clays are not absolutely needed.",18,19,3
Carboxylic Acids,,"Taheri-Shakib, Jaber; Keshavarz, Vahid; Kazemzadeh, Ezzatallah; Hosseini, Seyed Ahmad; Rajabi-Kochi, Mahyar; Salimidelshad, Yaser; Naderi, Hassan; Bakhtiari, Hesam Aloki",Experimental and mathematical model evaluation of asphaltene fractionation based on adsorption in porous media: Part 1. calcite reservoir rock,Asphaltene fractions; Porous media; Permeability; Porosity; Modelling,FUNCTIONAL-GROUP ADSORPTION; APPEARANCE TEMPERATURE WAT; VOLATILE ORGANIC-COMPOUNDS; HEAVY CRUDE-OIL; GAS-CHROMATOGRAPHY; SOLVENT INJECTION; HEATING TIME; DEPOSITION; MICROWAVE; SURFACE,"This study investigates the properties of asphaltene fractions in porous media and their role in reducing permeability and porosity. Based on the classification of a whole asphaltene deposited in porous media, the fractions can be defined as bulk, hard (h)-adsorbed, normal (n)-adsorbed, and irreversible (i)-adsorbed, which effects on porosity and permeability reduction in the reservoir rock. According to laboratory results for five types of calcite cores with porosity and permeability close to each other, the highest reduction in porosity (55%) and permeability (76%) is related to bulk asphaltene fractions. The n-adsorbed and h-adsorbed asphaltenes have approximately equal influence in reducing the porosity and permeability values in the reservoir rock. The i-adsorbed asphaltene, which has the highest adsorption on the rock surface, has the lowest porosity and permeability decrease due to lower amounts of asphaltene deposits in porous media. The amounts of hydrogen (H), nitrogen (N), sulfur (S), and oxygen (O) are higher in adsorbed fractions of asphaltene. In the case of hadsorbed asphaltene, H has the highest value in the asphaltene fractions (7.13 wt%). Compared with adsorbed asphaltene fractions, N values are higher in n-adsorbed (1.89 wt%) than h-adsorbed (1.41 wt%) fractions. This suggests that the S element plays a more significant role in the adsorption of asphaltene to the calcite surface. Based on the results, asphaltene compounds that adhere to the rock surface contain lighter carbon compounds than whole asphaltene. This means that the peak of the carbon compounds of h-adsorbed asphaltene in each rock sample is C-17. Fourier-transform infrared spectroscopy (FTIR) results show that the highest concentrations of carbonyl, carboxylic acid or derivative groups are found in h-adsorbed and n-adsorbed asphaltenes, respectively. A new experimental model of asphaltene deposition has been presented based on the deposition analysis of each asphaltene fraction in a porous medium under dynamic conditions, which results in a high correlation coefficient for each of the asphaltene classifications in the porosity and permeability reduction model. The reason for the high accuracy and uniqueness of the model is the use of parameters such as the velocity of fluid flow in the pores and the amount of volume injected in the reservoir rock sample, as well as the asphaltene fractions and their polarization ratio.",18,18,2
Carboxylic Acids,,"Al-Busaidi, Intisar K.; Al-Maamari, Rashid S.; Karimi, Mahvash; Naser, Jamil",Effect of different polar organic compounds on wettability of calcite surfaces,Wettability; Calcite; Double bond; Benzene ring; Carboxylic acids; Asphaltene,FATTY-ACIDS; CRUDE-OIL; WATER; ADSORPTION; CHALK; ASPHALTENES; SOLUBILITY; PETROLEUM,"The average oil recovery by conventional water flooding from oil-wet and naturally fractured carbonate reservoirs is often less than 30%. Removal of adsorbed acidic components and/or asphaltene from the carbonate surface results in wettability alteration towards water-wet which is an effective approach to enhance oil recovery. Long chain fatty acids, long chain naphthenic acids and asphaltene are major components in crude oil which are responsible for wettability alteration in carbonate reservoirs while unsaturated acids have minor effect. In this study, a more accurate quantification of the effects of different types and structures of polar components that contribute to the initial oil-wetting extent of the reservoir rocks were used (aliphatic saturated acids, aliphatic unsaturated acids, naphthenic acids, aromatic acids and asphaltene). Different analytical tools (contact angle, zeta potential, Fourier transform infrared spectroscopy and thermal analysis) were utilized for all acids in order to study surface characteristics. The results indicated that polar organic compounds act in different ways according to their structure and properties. Presence of double bond could make the acid molecule more polar, reactive and less hydrophobic. In addition, it can affect the spatial arrangement of the molecule and hence its orientation on the surface. Presence of benzene ring increases the reactivity and polarity of carboxylic group. Moreover, it enhances hydrophilic properties of the acid due to electrons of pi double bonds that can resonate over aromatic carbon atoms. The results revealed that, in the presence of water film, combination of acid dissociation in water, surface activity of acid and water solubility controls the acid adsorption and hence wettability alteration of the surface during aging process. Chemisorption of carboxylic acids/asphaltene changes the wettability of calcite surface. In addition to chemical adsorption, some acids adsorb physically on the surface. Physical adsorption of polar compounds may happen via hydrogen bonding between carboxylic groups and carbonate ions on the surface. Although physical adsorption is reversible and forms weak bonds between adsorbate and adsorbent, it may partially contribute to wettability alteration.",14,14,2
Wax,,"Wang, Zhihua; Bai, Ye; Zhang, Hongqi; Liu, Yang",Investigation on gelation nucleation kinetics of waxy crude oil emulsions by their thermal behavior,Water-in-oil emulsion; Gelation behavior; Nucleation kinetics; Waxy crude oil; Thermal analysis,WATER-IN-OIL; FLOW BEHAVIOR; TEMPERATURE; GAS; OPTIMIZATION; STABILITY; VISCOSITY; PIPELINES; MIXTURES,"Waxy crude oil emulsions exhibit gelation behavior, with nucleation observed within a certain temperature range. A kinetic model was developed and validated based on the thermal parameters obtained from differential scanning calorimetry cooling thermograms, and the nucleation rates of various water-in-waxy crude oil emulsions were determined in the temperature range in which gelation occurs. Although temperature had a dominant effect on the gelation and nucleation behavior of waxy crude oil emulsions, the nucleation rate also increased as the water volume fraction in the emulsion increased. Emulsified water droplets with smaller radii can be completely covered by wax particles, inducing a greater nucleation rate. Subjecting the emulsions to a greater shearing strength also increased the nucleation rate. This study provided new insights into the nucleation processes that occur during the formation of waxy crude oil emulsion gels and, in particular, the role of the emulsification properties.",63,62,7
Wax,,"Ruwoldt, Jost; Sorland, Geir Humborstad; Simon, Sebastien; Oschmann, Hans-Jorg; Sjoblom, Johan","Inhibitor-wax interactions and PPD effect on wax crystallization: New approaches for GC/MS and NMR, and comparison with DSC, CPM, and rheometry",Wax inhibitor; Pour point depressant; Waxy crude oil; Wax deposition; Differential scanning calorimetry (DSC); Nuclear magnetic resonance (NMR),POUR-POINT DEPRESSANTS; CRUDE-OIL; APPEARANCE TEMPERATURE; FLOW PROPERTIES; ASPHALTENES; FRACTIONATION; ADSORPTION; PRECIPITATION; RELAXATION; COPOLYMERS,"Three pour point depressants (PPDs) with different chemistries, and extracted asphaltenes were studied in their influence on wax crystallization in a model system. A new procedure for nuclear magnetic resonance (NMR) was developed to monitor changes in liquid phase as wax precipitated. Similar experiments were used to study nalkane depletion during precipitation via the use of GC/MS. Additive performance was furthermore evaluated via differential scanning calorimetry (DSC), rheometry, and cross-polarized microscopy (CPM). All additives induced morphological changes to wax crystals, which also affected apparent viscosity and waxy gelling. Some additives improved flow-ability of the waxy model oil significantly, while others showed less pronounced or even adverse effects. Following DSC and NMR results, PPDs with good wax inhibition could delay both the onset of wax crystallization and reduce the amount of precipitated wax. In accordance with that, GC/MS showed additives to delay certain stages in compositional change during wax precipitation. Moreover, efficient PPDs could suppress interactions between liquid and solid waxes that showed in the NMR T-2-distribution. It appears that PPD beneficiation greatly influences the mobility of dissolved wax molecules, which would also entail an effect on interactions at the solid-liquid interface of wax crystals. In conclusion, experimental procedures for NMR and GC/MS were extended to study PPD-wax interactions more in-depth, and experimental results show potential for improving the knowledge of wax inhibition.",21,20,2
Wax,,"Huang, Huirong; Wang, Wei; Peng, Zeheng; Li, Kai; Gan, Dongying; Zhang, Shengnan; Ding, Yanfen; Wu, Haihao; Gong, Jing",The effect of cooling processes on the yield stress of waxy model oil with nanocomposite pour point depressant,Nanocomposite pour point depressant; Waxy model oil; Step-cooling frequency; Yield stress; Crystal morphology,APPEARANCE TEMPERATURE WAT; CRUDE-OIL; N-PARAFFINS; CRYSTALLIZATION; COPOLYMERS; MORPHOLOGY; QUIESCENT; PRESSURE; STRENGTH; DEPOSITS,"The crystal morphology has significant effect on the macroscopic properties of waxy oil, which indeed determines the rheological behavior of waxy oil. It is critical to investigate the influence of crystallization on the rheological properties of waxy oil from the insight of crystal nucleation and growth. In this work, the effects of step-cooling frequencies on the yield stress of undoped/pour point depressant (PPD) doped waxy model oil and inherent crystal morphology were particularly discussed, based on the developed nanocomposite pour point depressant (NPPD) and conventional PPD (EVA). Results reveal that step-cooling frequency has little effect on the yield stress of undoped pure waxy oil; similarly, morphology of wax crystal exhibits that crystals in undoped oil appears insensitive to the step-cooling frequency. However, for waxy oil doped with NPPD or EVA, the higher the frequency, the lower the yield stress; meanwhile the amount of wax crystals increases and the morphology of crystals turn to be more dispersed in doped oil at high frequencies. Results indicate that NPPD provides better modification effect on the yield stress with the frequency increases. It actually reflects the inner nature of crystal nucleation and growth with PPD at different step-cooling frequency.",14,14,6
Wax,,"Sondermann, Carina Nogueira; Baptista, Renan Martins; de Freitas Rachid, Felipe Bastos; Rachid Bodstein, Gustavo Cesar",Numerical simulation of non-isothermal two-phase flow in pipelines using a two-fluid model,Two-phase flow; Two-fluid model; Flux-corrected transport method; Numerical simulation; Gas pipelines; Hyperbolicity analysis,FLUX-CORRECTED TRANSPORT; SLUG FLOW; EQUATIONS; PIPES,"The analysis of two-phase flows through numerical simulations is a very useful tool to design and operate long pipelines. It is also important for monitoring the flow during adverse situations, such as the formation of hydrates and wax deposition that may occur due to temperature variations in the fluids along the pipe. The present work aims to validate a model along with a numerical technique for analyzing non-isothermal stratified-pattern two-phase flows that occur in typical gas-gathering offshore pipelines. The mathematical model is one-dimensional and based on a two-fluid model that comprises two mass and two momentum conservation equations, one for each phase, along with one energy conservation equation for the mixture. The system of equations is discretized in a conservative form within a finite-difference framework and is solved by the flux-corrected transport (FCT) numerical method. Because an ill-posed mathematical problem is obtained if the system of equations is not hyperbolic, a hyperbolicity analysis is performed for all cases simulated in this work, which also indicates how to impose the boundary conditions adequately and avoids the production of non-physical output. The results obtained for the distribution of pressure, fluid velocities, holdup and temperature along the pipeline demonstrated that even relatively small temperature differences between the fluids and the external environment at the pipe inlet cause significant thermal effects on the entire flow. The simulations also predicted results in good agreement with those of a commercial software used for comparison, for steady-state regime, and significantly different results from those produced by an isothermal-flow model, which emphasizes the importance of considering the heat transfer in the problem. In summary, the results showed that the mathematical model and the numerical method form together a reliable tool of second-order accuracy in space that perform accurate numerical simulations of two-phase flows in long pipelines that are subject to non-isothermal conditions.",14,14,1
Migration and Accumulation,,"Xu, Shang; Hao, Fang; Xu, Changgui; Zou, Huayao; Zhang, Xintao; Zong, Yi; Zhang, Yuanyin; Cong, Fuyun","Hydrocarbon migration and accumulation in the northwestern Bozhong subbasin, Bohai Bay Basin, China",Hydrocarbon migration; Preferential petroleum migration pathways (PPMPs); Reactivated faults; Exploration target; Bohai Bay basin,SECONDARY OIL MIGRATION; NORMAL-FAULT GROWTH; PETROLEUM MIGRATION; CHARGE CONCENTRATION; 3-DIMENSIONAL MODEL; MECHANICAL STRATIGRAPHY; SEDIMENTARY BASINS; SHIJIUTUO UPLIFT; LEVANT BASIN; FLUID-FLOW,"An important exploration breakthrough has been achieved in the western subsag of the Bozhong subbasin, but the hydrocarbon accumulation mechanism was not clear. The hydrocarbon migration and accumulation mechanism of the western subsag of the Bozhong subbasin is discussed based on the modeling of hydrocarbon migration pathways and the study of late-stage reactivation of neotectonic faults. Three processes for lateral petroleum migration and accumulation can be recognized in the studied area: 1) migration and accumulation along the T8 unconformity; 2) migration and accumulation within the Guantao Formaiton (N(1)g); and 3) interaction of migration and accumulation along the T8 unconformity and Guantao Formation (N(1)g). The reactivation of faults in the studied area began 5.1 Ma. Following hydrocarbon lateral migration, late-stage reactivated neotectonic faults serve as effective vertical conduits for hydrocarbon migration and accumulation into the shallow Minghuazhen Formation (N(1)m) reservoirs. The modeling results of preferential petroleum migration pathways (PPMPs) and favorable accumulation areas are consistent with the actual exploration results. Two kinds of potential exploration targets can be predicted in the northwestern Bozhong subbasin: the first kind is hydrocarbon accumulation areas near or within generative kitchens (e.g. Target 1); the other kind is hydrocarbon accumulation areas removed from the generative kitchens, but with hydrocarbon sourcing from multiple generative kitchen and numerous PPMPs (e.g. Target 2). Studying preferential petroleum migration pathways will help reduce exploration risk.",19,20,3
Migration and Accumulation,,"Gong, Lei; Su, Xiaocen; Gao, Shuai; Fu, Xiaofei; Jabbari, Hadi; Wang, Xixin; Liu, Bo; Yue, Wenting; Wang, Zhaosheng; Gao, Ang","Characteristics and formation mechanism of natural fractures in the tight gas sandstones of Jiulongshan gas field, China",Tight gas sandstone; Natural fractures; Fracture characteristics; Formation mechanism; Jiulongshan gas field,SICHUAN BASIN; STRATIGRAPHY; RESERVOIRS; POROSITY,"Natural fractures control the migration and accumulation of oil and gas in the tight sandstones. Understanding the characteristics and formation mechanism of natural fractures has important guiding significance to the comprehensive prediction and evaluation of the fracture distribution. Focusing on the tight sandstones of the Xujiahe Formation (T(3)x) of Jiulongshan gas field, northwest Sichuan Basin, China, the characteristics of natural fractures were characterized quantificationally, and a comprehensive evaluation method of fracture formation mechanism is proposed. Two types of natural fractures were identified in the T(3)x, namely tectonic fractures and diagenetic fractures. Most of the natural fractures are tectonic shear fractures, which can be subdivided into steep fractures and nearly horizontal fractures according to their dip angles. Three sets of tectonic fractures were identified in the study area, namely: NW-SE trending, NNE-SSW trending and NEE-SWW trending fractures. According to the characteristics of fracture sets, crosscutting relationships, acoustic emission tests and fluid inclusion analysis, and combined with the tectonic evolution history of the study area, the natural fractures were formed in four periods. Among them, the diagenetic fractures formed at the process of diagenesis are the first period fractures. The second to fourth periods are tectonic fractures formed at the end of the Triassic to the Early Jurassic, the Late Cretaceous and the end of Pliocene to the early of Pleistocene, respectively. Horizontal tectonic compression, uplift denudation and overpressure were the main force sources for the formation of the steep tectonic fractures. The formation of nearly horizontal fractures is related with the thrusting or inter-formational sliding caused by tectonic compression.",17,19,2
Migration and Accumulation,,"Zhang, Zhiyao; Zhang, Yijie; Zhu, Guangyou; Han, Jianfa; Chi, Linxian","Variations of diamondoids distributions in petroleum fluids during migration induced phase fractionation: A case study from the Tazhong area, NW China",Diamondoids; Secondary condensates; Phase fractionation; Ordovician; Tarim basin,TARIM BASIN; OIL CRACKING; HYDROCARBON ACCUMULATION; GAS CONDENSATE; COMPOSITIONAL CHANGES; GASEOUS HYDROCARBONS; PVT PROPERTIES; NATURAL GASES; DEEP OIL; EXPLORATION,"Diamondoids, resistant to thermal and biological destruction, are useful in identifying the genesis and alteration history of petroleum fluids, especially for condensates in which conventional biomarkers are of trace amounts. Tremendous condensate resources have been discovered in the Ordovician carbonates from the central Tarim Basin, however, the complex genesis and distribution of the condensates have brought challenges in effective exploration and fluid prediction. In this study, the GC x GC-TOFMS analyses were applied on several condensate oil samples. Results showed great variance in the distribution and absolute concentration of diamondoids. Accompany the integrated geochemical and geologic analyses, the studied condensates are 'daughter' condensates generated from the similar 'parent' condensates that have undergone severe phase fractionation induced by migration. Phase fractionation led to the constant loss of vapor fractions and enriched heavy fractions in the residual condensates during the migration of petroleum fluids towards structural highs. Accordingly, diamondoids were preferentially enriched in shallower condensates and depleted in residual condensates, such variations of diamondoids distributions are attributed to phase fractionation because diamondoids with different molecular sizes differ in the solubilities in vapor phase. This will bring insight into the genesis of secondary condensates and the evaluation of the fractionation extent of petroleum fluids, with which effective petroleum exploration and prediction can be obtained.",16,18,2
Seal,,"Patel, Harshkumar; Salehi, Saeed; Teodoriu, Catalin; Ahmed, Ramadan",Performance evaluation and parametric study of elastomer seal in conventional hanger assembly,Elastomer seal; Finite element analysis; Contact pressure; Sensitivity analysis; Empirical correlation; Well integrity; Liner hanger,,"Seal assembly is a critical component of wellhead for maintaining well integrity. Failure of seal assembly is often cited as a cause for well control incidents. Comprehensive review of existing literature and industry standards and guidelines indicate that limited information is available in public domain on functional aspects and fitness for service evaluation of elastomer hanger seal assembly. This work presents finite element modelling approach to evaluate performance and fitness-for-service of conventional elastomer hanger seal assembly. Three-dimensional computer models consisting of liner, casing, and seal assembly elements were used for this purpose. Sealability was assessed in terms of the contact stress generated at the seal-pipe interface. An analytical model was used to validate and confirm accuracy of FEA results. Parametric analyses were performed and operating curves were generated to understand the behavior of elastomer seal considering different design parameters, such as dimensions and material properties. Sensitivity analysis was performed to identify critical design parameters. Seal annular fit, amount of energization, elastic modulus, and Poisson's ratio were observed to be the most critical factors affecting sealability. All major predictors were incorporated into an empirical correlation that can be used to estimate contact pressure with +/- 2% error. Based on all the simulation results, recommendations are provided that will help industry/regulators alike in designing and assessing ""fitness-for-service"" of seal assemblies.",24,24,3
Seal,,"Al Ramadan, Mustafa; Salehi, Saeed; Kwatia, George; Ezeakacha, Chinedum; Teodoriu, Catalin",Experimental investigation of well integrity: Annular gas migration in cement column,Gas migration; Anti-gas migration additives; Wellbore leakage; Annular gas flow; Shallow flow; Microannuli,EFFECTIVE PERMEABILITIES; FLOW; FREQUENCY; FAILURE; LEAKAGE; FLUID; OIL,"Cementing operations present various difficulties attributed to shallow flows all around the world. Cement ability to seal the annular space, aids in sustaining the well integrity by mitigating and preventing fluid migration to other formations and to surface. Failure of cement to seal the annular space can result in serious problems that might jeopardize the well integrity. In this study, a wellbore model setup was designed and fabricated to mimic the gas migration in cemented annulus. A series of experiments were conducted on this setup to examine the cement sealability of neat Class H and neat Class G cements, and to also evaluate the effect of anti-gas migration additive on the cement sealability. Different additives were used such as bentonite and latex. Experiments conducted revealed that neat Class H, Class G, and any other slurry design with additives (but without anti-gas migration additives) does not have the ability to serve in mitigating gas migration. The wellbore permeability of annular cement using neat Class H and Class G cement was ranging between 10(-3) to 10(-1) mD. In addition, it has been found that the wellbore permeability of annular cement increases as cement age increases. Annular cement should not be considered as the primary barrier when liner-hanger is used.",19,19,5
Seal,,"Yan, Xiaopeng; Kang, Yili; You, Lijun; Xu, Chengyuan; Lin, Chong; Zhang, Jingyi","Drill-in fluid loss mechanisms in brittle gas shale: A case study in the Longmaxi Formation, Sichuan Basin, China",Brittle gas shale; Drill-in fluid loss; Plugging zone stability; Dynamic fracture width; Case study,CIRCULATION; DAMAGE; COEFFICIENT; STABILITY; IMPACT; WELLS,"Brittle gas shale consists of a high content of brittle mineral and developed natural fractures and has become the focus of petroleum industry in recent years. Lost circulation may easily occur due to the long soaking time and an overbalanced pressure difference during the drill-in process of the horizontal long section. The dynamic fracture width simulation induced by drill-in fluid invasion, plugging zone pressure containment test, friction coefficient test between lost circulation materials and shale surface, oil based drill-in fluid filtrate immersion test were conducted to investigate the drill-in fluid loss mechanisms in the brittle Longmaxi Shale in the Sichuan Basin of China. Results show that the fracture width at the fracture mouth increased from 2 mu m to 239 mu m for the two mutually perpendicular fractures connecting to the wellbore due to drill-in fluid invasion. Effective plugging for dynamic fractures was failed to be achieved for the original drill-in fluid. Fracture width increase induced by drill-in fluid invasion is the major cause of plugging failure of brittle gas shale. Instability of the brittle shale induced by oil phase lubrication and high pH drill-in fluid erosion further exacerbates lost circulation problems. Optimized LCMs considering the dynamic apertures of fractures should be selected and added into drill-in fluid to rapidly seal pre-exiting fractures and induced fractures for lost circulation control in brittle shale. The results serve as a guide for the drill-in fluid design of shale gas in brittle gas shale formation.",16,19,3
Oxygen Partial Pressure,,"Zhong, Xiankang; Lu, Wenjun; Yang, Huaijun; Liu, Min; Zhang, Yang; Liu, Hongwei; Hu, Junying; Zhang, Zhi; Zeng, Dezhi",Oxygen corrosion of N80 steel under laboratory conditions simulating high pressure air injection: Analysis of corrosion products,High pressure air injection; Corrosion products; Oxygen corrosion; Iron oxides,HIGH-TEMPERATURE CORROSION; CARBON-STEEL; CO2 CORROSION; IRON SULFIDE; MILD-STEEL; BEHAVIOR; HEMATITE; TRANSFORMATION; ENVIRONMENT; AKAGANEITE,"High pressure air injection (HPAI) is an effective and economic improved oil recovery process, however, the corrosion of tubing and casing in the injection well is one of the serious safety concerns which have limited its widely application. Until now the structure and composition of corrosion products formed in HPAI condition are still not fully clear because of the difficulty in simulating such a harsh environment in laboratory. In this work, the corrosion rates of N80 steel under laboratory conditions with different oxygen content (21-5% vol%), total pressure (50-20 MPa) and temperature (120-70 degrees C) simulating HPAI in Dagang oil field in China were investigated using weight loss measurement. The corrosion products on N80 steel surface were analyzed using scanning electron microscopy coupled with energy dispersive spectroscopy (SEM + EDS), X-ray diffraction (XRD) and transmission electron microscopy (TEM). The results show that the corrosion rate decreased with the decreasing oxygen partial pressure and temperature. Furthermore, for all the conditions, the corrosion rate was incredibly high in the simulating HPAI environment, consequently, large amount of corrosion products were formed. The corrosion products showed a two-layer structure: outer layer and inner layer. The outer layer was porous, brittle and easily flaked off, while the inner layer was more compact than outer layer. However, both layers could not effectively lower the corrosion rate of N80 steel in HPAI environment. The corrosion products were composed of hematite (alpha-Fe2O3), goethite (alpha-FeOOH), magnetite (Fe3O4) and trace amounts of Ca(OH)(2) and CaO. In addition, the structure and composition of corrosion products did not change with the temperature and oxygen partial pressure in the simulating HPAI conditions.",29,32,5
Oxygen Partial Pressure,,"Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Yuan, Chengdong; Qin, Shan; Wang, Liangliang; Emelianov, Dmitrii A.; Khachatrian, Artashes A.",Thermal behavior and kinetics of heavy crude oil during combustion by high pressure differential scanning calorimetry and accelerating rate calorimetry,In-situ combustion; Thermal behavior; Kinetics; Heavy crude oil; High pressure differential scanning calorimetry; Accelerating rate calorimetry,IN-SITU COMBUSTION; LOW-TEMPERATURE OXIDATION; AIR INJECTION; PYROLYSIS; LIGHT; DSC; COMPONENTS; MECHANISM; EVOLUTION; VISCOSITY,"Because the thermal release correlates directly with the success of in-situ combustion (ISC) technology, this research performs a series of investigations concerning thermal behavior and kinetics of heavy crude oil during combustion using high pressure differential scanning calorimetry (HP-DSC) and accelerating rate calorimetry (ARC). The results obtained from HP-DSC profiles indicated that for oil alone and its mixtures with quartz sand/crushed core, the peak temperature was lowered, and the heat flow increased with increasing oxygen partial pressure. The heat enthalpy of low temperature oxidation (LTO) was higher than that of high temperature oxidation (HTO) under oxygen partial pressures of 0.5, 1 and 1.5 MPa, and the increase in heat enthalpy of LTO with oxygen partial pressure was more pronounced than that of HTO. Unlike the crushed core, the addition of quartz sand delayed exothermic oxidation reactions. Compared with oil only and oil + quartz sand, the LTO and HTO peak temperatures of oil + crushed core were considerably lowered, and the effect of crushed core on increasing heat release for LTO at oxygen partial pressure of 1.5 MPa was more prominent. It was observed that the heat enthalpy of LTO and HTO increased quasi-linearly with the oxygen partial pressure in both the presence and absence of quartz sand/crushed core. ISC might be considered as an appropriate candidate for Jiqi block, based on exothermic continuity of the ARC curves, with the near-wellbore zone of target block heated to 180 degrees C where the exothermic oxidation activity is notably intensified. The kinetic results showed that the LTO and HTO intervals were divided into 6 and 2 subintervals, respectively, which facilitated more precise modelling of the ISC process.",20,20,3
Shaped Charge,,"Yan, Yan; Guan, Zhichuan; Xu, Yuqiang; Yan, Weijun; Wang, Hongtu",Numerical investigation of perforation to cementing interface damage area,Perforation fluid channeling cementing; interface damage area numerical simulation,PENETRATION DEPTH; SHEATH INTEGRITY; TARGET STRENGTH; CRACK-GROWTH; PROPAGATION; SIMULATION; IMPACT; FORMULATION; INITIATION,"Perforation will cause local damage to the cement and cementing interface, increasing the possibility of fluid channeling during hydraulic fracturing. Perforation experiment of ring target is extremely dangerous and cementing interface damage is difficult to observe, so the numerical model based on LS-DYNA software is set up in this paper. Cylindrical target penetration test is used to verify the interface damage area caused by perforation. Then, the effects of confining pressure, shear modulus of cement and diameter of shaped charge on interface damage area are analyzed. The results reveal that the damage area of casing/cement interface and the confining pressure shows a quadratic function relationship. The interface damage area has a logarithm function relationship with cement shear modulus and a strongly linear relationship with diameter of the shaped charge. In order to reduce interface damage caused by perforation, cement with lower shear modulus should be selected.",16,16,0
Shaped Charge,,"Liu, Jun; Guo, Xiaoqiang; Liu, Zhenjia; Liu, Xian; Liu, Qingyou",Pressure field investigation into oil&gas wellbore during perforating shaped charge explosion,Pressure field; Overpressure simulation; Perforating completion; LS-DYNA; Tubing vibration,UNDERWATER EXPLOSION; NUMERICAL-SIMULATION; BUBBLE; SHOCK,"The impact pressure field in oil&gas wellbore during perforating shaped charge (PSC) explosion has strong impact on the perforation tubing string vibration as well as perforation operation safety. Based on PSC jet theory, pi theorem and similarity law, a pressure field model of oil&gas wellbore during PSC explosion is presented and its important parameters are discussed by numerically simulating the evolution process of perforation overpressure using the nonlinear finite element software LS-DYNA combined with the ALE and AMR techniques. Firstly, the evolution process of underwater explosion overpressure is simulated numerically, based on which the key parameters of the peak pressure formula in the pressure field model are fitted out. Secondly, using the analysis method, the simulation model of the shaped charge jet is established, and the energy conversion rate of the PSC to the detonation shock wave is analyzed. The influence of the explosive type, the charge density, the PSC diameter and the charge height on the conversion rate are investigated. Thirdly, On the basis of the above work, a simulation model for the actual wellbore overpressure analysis is established and the mechanism of the overpressure evolution are analyzed.",15,15,5
Other topics ,,"Xie, Kun; Cao, Bao; Lu, Xiangguo; Jiang, Weidong; Zhang, Yunbao; Li, Qiang; Song, Kaoping; Liu, Jinxiang; Wang, Wei; Lv, Jinlong; Na, Risu",Matching between the diameter of the aggregates of hydrophobically associating polymers and reservoir pore-throat size during polymer flooding in an offshore oilfield,Hydrophobically associating polymer; Offshore oilfield; Matching; Beta-cyclodextrin; Viscosity; Oil displacement effect; Experimental research,PROFILE-CONTROL; POROUS-MEDIA; SURFACTANT; SYSTEM; MODEL; FLOW; CONFIGURATION; PERFORMANCE; SIMULATION; MECHANISM,"In order to quantitatively study the matching between hydrophobically associating polymers (HAPs) and reservoir pore-throat size in offshore oilfields, the geological characteristics and fluid properties of the S area reservoir in the Bohai Oilfield were used as a research platform. After determining the matching of HAP solutions with different association degrees and core permeabilities using a seepage experiment at a constant flow rate, the matching between the diameter of the HAP aggregates (D-h) and the median pore-throat radius was quantified by combining the relationship between core permeability and median pore-throat radius. Finally, the importance of matching on the oil displacement effect of the HAP solution was demonstrated using homogeneous cores and heterogeneous cores with separate injection and production interlayers. The results showed that the diameter of the HAP aggregates, as well as their morphology and ability to increase viscosity, were highly related to the association degree of HAP. As the association degree of HAP was varied, the matching between cores with different permeabilities and the beta-cyclodextrin (beta-CD)/HAP compound systems also changed. Under the experimental conditions used in this study, the ratio between the median pore-throat radius and D-h ranged from 4 to 7. During the process of HAP flooding, suitably increasing the D-h, i.e., increasing the association degree between HAP molecules, could allow control of the mobility of the HAP solution. The oil displacement effect of HAP was closely related to the matching between the HAP and reservoir pore-throat, rather than the viscosity of the HAP solution. Good matching between the HAP and reservoir pore-throat not only achieves fluid diversion but can also expand the swept volume in the low-permeability layer to ensure good oil displacement ability.",52,52,4
Other topics ,,"Meng, Meng; Zamanipour, Zahra; Miska, Stefan; Yu, Mengjiao; Ozbayoglu, E. M.",Dynamic stress distribution around the wellbore influenced by surge/swab pressure,Stress distribution; Wellbore; Surge/swab pressure; Elastodynamics; Poroelastodynamics,NUMERICAL INVERSION; TRANSIENT-RESPONSE; PROPAGATION; BOREHOLE; CAVITY,"The calculation of dynamic stress distribution around the wellbore under surge/swab pressure is an unsolved issue. The conventional method to calculate wellbore stress is only applicable to the steady state without considering the coupled effect of deformation-diffusion. In this paper, an elastodynamics model and a poroelastodynamics model have been established to overcome these deficiencies. The numerical solution is provided by the implicit finite difference method, and it is verified by the analytical solution achieved from Laplace transform and Crump inversion. Through sensitivity analysis, it shows that the period of the sine function (inner boundary condition), Biot coefficient, hydraulic diffusivity, and rock types could influence the stress distribution. Then the dynamic surge/swab pressure predicted based on Lubinski's method is implemented into these two models. Two field cases with different depths have been analyzed, and it demonstrates that the surge/swab pressure is more significant for a shallow formation because the static formation pressure and in-situ stresses are relatively small. If the tripping velocity is high, the stress distribution will be significantly changed. Finally, the stress calculated by these two models is compared with the stress obtained using the conventional solution. The comparison shows that the poroelastodynamics solution is different from the elastodynamics solution because pore pressure is significant in the poroelastodynamics solution. The poroelastodynamics solution is also significantly distinguishable from the conventional solution, which demonstrates the importance of the poroelastodynamics model. Overall, it fills the gap in calculating dynamic wellbore stress under tripping conditions, which can be applied to wellbore stability analysis and contribute to a reduction in both tripping time and drilling costs.",47,48,4
Other topics ,,"Ashraf, Umer; Zhu, Peimin; Yasin, Qamar; Anees, Aqsa; Imraz, Muhammad; Mangi, Hassan Nasir; Shakeel, Saiq","Classification of reservoir facies using well log and 3D seismic attributes for prospect evaluation and field development: A case study of Sawan gas field, Pakistan",Facies; Gamma-ray log; Seismic attributes; Delta; Lower Goru formation,LOWER INDUS BASIN; IDENTIFICATION; STRATIGRAPHY; SANDSTONES,"The Sawan Gas Field is one of the most promising gas fields of Middle Indus Basin in Pakistan with a cumulative production of 850 BCF. In the reservoir interval, the thin shale sequence is interbedded and dispersed resulting in extreme heterogeneity. Consequently, conventional seismic amplitude interpretation fails to delineate the sand-shale facies distribution. In this case study, the depositional facies of the reservoir C-sand interval with the integration of electrofacies analyses, historical production data, and seismic attribute analyses using 3D seismic and well log data were analyzed for prospect evaluation and field development plan to achieving maximized production. The electrofacies analyses show that the reservoir C-sand interval falls in funnel-shaped, bell-shaped, and cylindrical-shaped trends. The obtained results suggest deposition of C-sand in proximal delta front to pro-delta settings with medium to fine grain pore size distribution. Conversely fine grained lime mud, silt, and shale with poor-sorting fall in the irregular-shaped trend which suggests deposition in pro-delta settings. C-sand interval was evaluated using multiple seismic attributes including relative acoustic impedance, root mean square amplitude, envelope, sweetness, instantaneous frequency, structural smoothing, and phase shift. The results of all the seismic attributes demarcate the transitional boundary between the delta front sand facies and pro-delta sandy-shale facies. The calibration of electrofacies analysis with 3D seismic attributes indicates an appropriate agreement between them. This study effectively predicted the spatial distribution of sweet spots in the heterogeneous reservoir using 3D seismic attributes analysis, which can provide valuable guidance for the development of the area.",39,40,3
Other topics ,,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Zhang, Shikun; Xu, Zhengming; Shi, Yu; Li, Xiangfang",A slip-flow model for oil transport in organic nanopores,Shale oil; Kerogen nanopores; Boundary slip and physical adsorption; Flow enhancement; Correction factor,CARBON NANOTUBE MEMBRANES; SUPERHEATED STEAM FLOW; MOLECULAR-DYNAMICS SIMULATION; HEAT-TRANSFER CHARACTERISTICS; GEOTHERMAL-ENERGY EXTRACTION; MULTICOMPONENT THERMAL FLUID; INJECTION HORIZONTAL WELLS; PEROXIDE PRESOAKING PRIOR; FAST WATER TRANSPORT; FAST MASS-TRANSPORT,"Shale oil reserves are becoming more important with the development of oil & gas industry. However, the transport mechanisms of oil in nanopores of kerogen remain a mystery. The understanding of the multiple transport mechanisms of oil in nanopores is crucial in the successful development of shale oil reservoirs. In this paper, a new model for flow enhancement of oil transport in nanopores of kerogen is proposed. Both boundary slip and physical adsorption are taken into consideration in the analytical model. Based on the previous experimental and theoretical studies, the model is validated. Results show that (a) Covering the Hagen-Poiseuille flow, specific oil flow and the water flow, the new model is more universal in practice; (b) When the radius of the nanotube is equal to 1 nm, the value of slip factor is between 24081 and 48161 (the corresponding correction factor is between 0.7 and 1.4); (c) the flow enhancement is negligible when the radius is larger than 10 nm under various values of correction factor conditions. Besides, the flow enhancement increases with the increasing of the correction factor; (d) when the correction factor is small, the section of the curve higher than zero is characterized with short and low; (e) when the correction factor is smaller than 0.007, the normalized velocity increases slowly with increasing of the correction factor. When the correction factor is higher than 0.07, the normalized velocity increases rapidly when the transport length in nanopores is increased from 10 nm to 200 nm.",39,40,2
Other topics ,,"Iordache, Mihaela; Schitea, Dorin; Deveci, Muhammet; Akyurt, Ibrahim Zeki; Iordache, Loan",An integrated ARAS and interval type-2 hesitant fuzzy sets method for underground site selection: Seasonal hydrogen storage in salt caverns,Hydrogen seasonal storage; Salt caverns; Site selection; Interval type-2 hesitant fuzzy sets; Multi-criteria decision making (MCDM); Romania,SERVICE QUALITY; MCDM APPROACH; ROMANIA,"The hydrogen seasonal storage, as pure gas or mixture with natural gas, is expected to sustain both the energy storage and sectorial integration. The salt caverns are able to store the large quantities of hydrogen at elevated pressures for seasonal period of time. In this study, a new approach integrating Additive Ratio ASsessment (ARAS) method and interval type-2 hesitant fuzzy sets (IT2HFSs) is proposed to tackle the underground hydrogen storage site selection problem in Romania. This study presents an integrated method to select the best location among four alternative sites based on 7 main and 14 sub-criteria. The result shows that the proposed method can be useful to handle fuzzy multi criteria decision-making (MCDM) problems.",35,35,5
Other topics ,,"Abdullahi, Mohammed Bashir; Rajaei, Kourosh; Junin, Radzuan; Bayat, Ali Esfandyari",Appraising the impact of metal-oxide nanoparticles on rheological properties of HPAM in different electrolyte solutions for enhanced oil recovery,Rheology; Hydrophilic nanoparticles; HPAM; Salt tolerance; Thermo-stability; EOR,SILICA NANOPARTICLES; POLYMER-SOLUTIONS; POLYACRYLAMIDES; TEMPERATURES; PERFORMANCE; STABILITY; BEHAVIOR,"Polymer has been employed as a valuable chemical to increase mobility ratio and subsequently to improve sweep efficiency of water flooding. However, its sensitivity to harsh reservoir conditions which are high formation brine salinity with high temperature has degraded its thickening characteristics and lowered its performance in oil reservoirs. Recently, the application of nanoparticles (NPs) has shown a magnificent impact on chemical performance and eventually boosted chemical flooding recovery under reservoir condition. It has been observed that the role of NPs type as rheology control agents in modification of the polymer performance in reservoir condition has not earned enough attention. The aim of this study is to develop NPs-HPAM hybrid dispersions by employing aluminium oxide, silicon dioxide and titanium oxide NPs to partially hydrolyzed polyacrylamide (HPAM) solutions. The rheological properties of NPs-HPAM hybrid dispersions were examined in the presence of mono- and divalent ions at different shear rates and NPs concentrations. The results revealed that increasing the salt concentration decreases viscosity of the polymer solutions. NPs-HPAM hybrid dispersions exhibit higher viscosity than that of HPAM solutions at the same salinity which contributed to the NPs shield against cations present in the salt. In addition, the Fourier transform infrared spectral data established the presence of hydrogen bonds between NPs and carbonyl groups in HPAM solutions which confirmed improve performance of HPAM solutions by NPs under saline condition. Moreover, NPs-HPAM hybrid dispersions showed higher viscosity than polymer solution at low and medium shear rates, while the reversed trend was detected at higher shear rate due to the adsorption interaction of polymer molecules on NPs surface. Furthermore, the efficiency of NPs-HPAM hybrid dispersions as innovative tertiary recovery technique was put to the test through a water-wet sand pack saturated with intermediate oil. The results indicated that alumina-, silica- and titanium-polymers dispersions have ultimate oil recoveries of 15%, 10% and 6% higher than polymer flooding. Results of these researches prove that application of NPs-HPAM hybrid dispersions is the innovative and advanced method since NPs improve the HPAM solution thickening behaviour and rheological properties in the high salinity reservoir conditions.",31,32,6
Other topics ,,"Sun, Zheng; Shi, Juntai; Wu, Keliu; Liu, Wenyuan; Wang, Suran; Li, Xiangfang",A prediction model for desorption area propagation of coalbed methane wells with hydraulic fracturing,Desorption area; Coal-bed methane; Hydraulic fracturing; Propagation behavior; Gas saturation,REAL-GAS TRANSPORT; VERTICAL WELL; SEMIANALYTICAL MODEL; NUMERICAL-SIMULATION; LOW-PERMEABILITY; TRANSIENT FLOW; SORPTION TIME; 2-PHASE FLOW; PRESSURE; RESERVOIRS,"Precise characterization of dynamic desorption area is crucial for accurate production prediction, production strategy formulation, and well pattern optimization of coalbed methane (CBM) reservoirs. However, little attention has been focused on this topic and a handful of related previous researches suffer some fatal deficiencies. Thus, the objective of this work is to overcome these deficiencies and then extensively investigate the propagation behavior of desorption area during CBM recovery. During depressurization development process of CBM reservoirs, due to the effect of gas desorption, gas saturation takes place in the original water-saturated coal seams, which will decrease the expansion speed of desorption area. Moreover, saturation distribution in the whole coal seam is a dynamic parameter during CBM recovery, which plays an important role for the propagation behavior of desorption area but has not yet been captured in current models. Firstly, pressure-squared concept is utilized to describe pressure distribution within desorption area, which has been considered as an effective method. Secondly, based on the partial differential equation of subface fluid flow accounting for gas desorption, the formulas for pressure-saturation relationship are derived. Finally, according to material balance equation for infinitesimal coal seams, a novel mathematical model for desorption area is developed. Results show that (a) shape of desorption area will transition from ellipse into a circle with production proceed; (b) matrix shrinkage effect has few influences on the expansion of desorption area at a certain cumulative gas production; (c) rapid decrease of BHP will result in a small desorption area for actual production of CBM wells. The research, for the first time, provides an accurate and fast semi-analytical model to simulate propagation behavior of desorption area. Also, the proposed model is easier to setup and less data-intensive than a numerical simulator. Considering the interests for development of CBM reservoirs, the research can serve as an effective tool for gaining a better understanding of the flow physics in the whole coal seam.",28,29,2
Other topics ,,Bobo Li; Kang Yang; Peng Xu; Jiang Xu; Mei Yuan; Min Zhang,An experimental study on permeability characteristics of coal with slippage and temperature effects,Permeability; Coal; Gas slippage; Gas pressure; Temperature; Fractal,EFFECTIVE STRESS; GAS-ADSORPTION; METHANE RESERVOIRS; CO2; EVOLUTION; SORPTION; DEFORMATION; DEPENDENCE; MODEL; SIMULATION,"Ground temperature rises with the increase of mining depth. In this study, in order to investigate the seepage properties of coal with slippage and temperature effects, a thermo-fluid-solid coupling experiment on the methane-bearing coal was performed via the triaxial servo-controlled seepage equipment. Then, the permeability of coal in the gas loading-unloading processes was measured under different temperatures. Finally, a fractal slippage effect model with the temperature effect was developed to study the influences of pore pressure and temperature on permeability characteristics. The results indicate that as pore pressure rises, the axial strain of coal increases, while the radial strain decreases in the loading process. On the contrary, the axial and radial strains exhibit opposite trends with the rise of pore pressure in the unloading process. With the rise of temperature, the axial strain grows firstly and then falls, while the radial strain keeps decreasing. The permeability of coal decreases firstly and then levels off with the rise of pore pressure in both loading and unloading processes. Moreover, the slippage effect gradually weakens and flattens out with the rise of pore pressure. As the temperature rises, the slippage-induced permeability variation grows in the loading process, whereas it increases firstly and then goes down in the unloading process. The present work can provide a theoretical basis for coal seam gas extraction.",27,29,13
Other topics ,,"Sabah, Mohammad; Talebkeikhah, Mohsen; Agin, Farough; Talebkeikhah, Farzaneh; Hasheminasab, Erfan","Application of decision tree, artificial neural networks, and adaptive neuro-fuzzy inference system on predicting lost circulation: A case study from Marun oil field",Lost circulation; Marun oil field; ANFIS; Artificial neural network; Decision tree,UNCONFINED COMPRESSIVE STRENGTH; WELL LOG DATA; IDENTIFICATION; VISCOSITY; MODEL; ANFIS; ROCKS,"One of the most prevalent problems in drilling industry is lost circulation which causes intense increase in drilling expenditure as well as operational obstacles such as well instability and blowout. The aim of this research is to develop smart systems for estimating amount of lost circulation making able to use appropriate prevention and remediation methods. To obtain this aim, a large data set were collected from 61 recently drilled wells in Marun oil field in Iran to be used for developing relevant models. After that, using the extracted data set consisting of 1900 data subset, intelligent prediction models including decision tree (DT), adaptive neuro-fuzzy inference systems (ANFIS), artificial neural networks (ANN) and also hybrid artificial neural network namely genetic algorithm-multi-layer perception (GA-MLP) were developed to make a quantitative prediction on lost circulation. The model outputs are then analyzed by various performance indices such as variance accounted for (VAF), root mean square error (RMSE), performance index (PI) and coefficient of determination (R-2). Eventually, it is found that developed models are highly applicable in lost circulation prediction. Concluding remark is that DT model having determination coefficient of 0.9355 and RMSE of 0.091 is superior comparing to other developed models and hybrid ANN (GA-MLP) exhibits lowest prediction performance among other implemented models.",27,29,6
Other topics ,,"Canchumuni, Smith W. A.; Emerick, Alexandre A.; Pacheco, Marco Aurelio C.",History matching geological facies models based on ensemble smoother and deep generative models,Reservoir history matching; Geological facies; Deep learning; Deep belief network; Ensemble smoother,PRINCIPAL-COMPONENT ANALYSIS; KALMAN FILTER; DATA ASSIMILATION; DIFFERENTIABLE PARAMETERIZATION; REPRESENTATION; EFFICIENT,"The current research trend in history matching is to consider more realistic reservoir models with complex geology. Hence, it is important to be able to update facies models during the solution. Although Kalman filter-based methods have been applied with success in several real-life history-matching problems, their performance is severely degraded when the prior geology is described in terms of complex facies distributions, since these methods rely on Gaussian assumptions. This paper investigates a novel parameterization based on deep learning techniques for proper history matching of facies models with methods based on the Kalman filter. The proposed method consists on a parameterization of geological facies by means of a deep generative model, with a deep belief network used as an autoencoder. To perform the history matching, we use the ensemble smoother with multiple data assimilation (ES-MDA) that iteratively updates the model to account the observed production data. The proposed method is compared to the standard ES-MDA and ES-MDA combined with optimization-based principal component analysis (OPCA). The results showed clear improvements over the standard ES-MDA in terms of preserving channelized features in the realizations and a performance comparable to the parameterization with OPCA.",26,28,3
Other topics ,,"Gao, Qi; Cheng, Yuanfang; Han, Songcai; Yan, Chuanliang; Jiang, Long",Numerical modeling of hydraulic fracture propagation behaviors influenced by pre-existing injection and production wells,Hydraulic fracturing; Fracture propagation; Pre-existing wells; Extended finite element method (XFEM); Cohesive zone method (CZM),PORE PRESSURE INFLUENCE; FINITE-ELEMENT-METHOD; SIMULATION; BRITTLE,"Hydraulic fracturing treatments are capable of enhancing the well production performance in low-porosity and low-permeability reservoirs because of the resulted improvement in communication between the formation and wellbore through created hydraulic fractures (HFs). In fact, not only the in-situ stress underground but also the pre-existing offset wells induced non-uniform pore pressure field will influence the HF propagation process. In this work, to investigate the HF propagation behaviors under the effects of adjacent production and injection wells, a new numerical model is developed within the framework of extended finite element method (XFEM) and cohesive zone method (CZM). The model can simultaneously simulate the HF initiation, propagation and re-orientation, fracturing fluid flow and leakoff, formation fluid flow and rock deformation. Reliability of the new model is validated by comparing the numerically calculated fracture geometry with the experimental observation in the literature. The interesting and new results show that pore pressure field, stress field and fracture propagation speed can be altered around the pre-existing offset wells. Also, HF prefers to propagate toward injection wells when production and injection wells co-exist, and the fracture propagation trajectory will not be affected in the cases that only production or injection wells exist. The fracture will be shorter and wider when only injection wells exist or production and injection wells co-exist, while the pre-existence of only production wells leads to a longer and thinner HF. Moreover, a smaller pumping pressure can be applied to generate the HF when only production wells locate nearby, while a greater injection pressure is required to drive the HF forward when only injection wells pre-exist or injection and production wells co-exist. The obtained results provide new insights for understanding the fracture propagation behaviors in the field scale.",25,25,3
Other topics ,,"Yang, Chen; Zhou, Fujian; Feng, Wei; Tian, Zhida; Yuan, Lishan; Gao, Liyang",Plugging mechanism of fibers and particulates in hydraulic fracture,Divert; Fibers; Particulates; Plugging; Fracture; Visualized,PERMEABILITY,"Degradable fibers and particulates are the typical diverting agents which can temporarily plug the preexisting hydraulic fractures and redirect the treating fluid to the under-stimulated area. However, it is still unclear how the plugging is initiated and formed in the hydraulic fracture. In this paper, a large-scale visualized experimental system is built based on the similarity criterion to observe the dynamic plugging performance of fibers and particulates in a mimicked hydraulic fracture. Through a series of comparative experiments, it is found that the plugging process starts from the attachment of fibers on fracture bottoms, roofs and faces, then the attached fibers keep capturing the flowing particulates to form scattered plugged zones, finally one flow channel is formed and gradually narrowed until it is plugged completely. Results indicate that the fibers initiate the plugging process, while the particulates accelerate the following plugging process and withstand the pressure difference by acting as the skeleton of the plugged zone. It is suggested that particulates need to be injected into the hydraulic fracture with fibers at least 50 seconds after the injection of fibers, and the ratio between fibers and particulates is recommended to be 1:1. As the fracture width increases, the plugging rate is reduced accordingly. Adding big particulates whose diameters are 60%-80% of the fracture width can improve the plugging effect significantly.",24,27,6
Other topics ,,"Al-Hameedi, Abo Taleb T.; Alkinani, Husam H.; Dunn-Norman, Shari; Al-Alwani, Mustafa A.; Alshammari, Abdullah F.; Albazzaz, Hussien W.; Alkhamis, Mohammed M.; Alashwak, Naser F.; Mutar, Rusul A.",Insights into the application of new eco-friendly drilling fluid additive to improve the fluid properties in water-based drilling fluid systems,Drilling fluid; Environmentally friendly additive; Filtration properties; Biodegradable waste,MECHANISM,"The objective of this work is to develop an eco-friendly drilling fluid additive to regulate filtrate and mud cake thickness as well as to assess other drilling fluid properties. The biodegradable Grass Powder (GP) was selected as a fibrous fluid-loss agent to be compared with the conventional chemical additive (starch). Fluid samples including GP and starch additives were prepared in various concentrations to examine the effect of concentration variation on the reference fluid. The effects of introducing different concentrations of GP and starch on the physical and chemical properties of the drilling fluid (e.g. mud weight (MW), plastic viscosity (PV), yield point (YP), the filtration characteristics, rheological properties, calcium content (Ca++), solid content (SC), NaCl concentration, and pH) were evaluated. The evaluation included conducting lab experiments with full-set measurements following the specifications of the American Petroleum Institute (API). The test results of 0.5%, 1%, and 1.5% GP were compared to the same concentrations of starch. Starch was less effective than GP in improving filtration specifications. For instance, in low-temperature and low-pressure (LTLP) filtration test, the fluid loss was decreased by 42% and 28% using 0.5% of GP and starch additives, respectively. Similarly, in high-temperature and high-pressure (HTHP) filtration test, 0.5% of GP and starch decreased fluid loss by 26% and 3%, respectively when comparing them to the reference fluid. On the other hand, starch was more efficient than GP in terms of improving the rheological properties for all different concentrations; while both GP and starch had no effect on MW and negligible impact on SC. In addition, GP additives resulted in increasing NaCl more than starch at different concentrations; while GP reduced the alkalinity and Ca++ more than starch for all concentrations as compared to the reference fluid. In brief, this study shows that GP can reduce the amount of non-biodegradable waste, and it has a promising potential to be utilized as a supportive biodegradable drilling fluid additive.",24,24,5
Other topics ,,"Zhang, Xinxin; Zhang, Shaohe; Luo, Yongjiang; Wu, Dongyu",Experimental study and analysis on a fluidic hammer-an innovative rotary-percussion drilling tool,Rotary-percussion drilling; Fluidic oscillator; Fluidic hammer; Penetration rate,LIQUID-JET HAMMER; OSCILLATOR; PARAMETERS; DESIGN; ROCK,"Rotary-percussion drilling with mud as the energy carrier is a competitive method for the production of drill-holes. Fluidic hammer is a type of rotary-percussion drilling tool actuated by a fluidic oscillator based on the Coanda effect. By using a fluidic hammer, penetration rate can be significantly improved. With few movable or deformable parts, fluidic hammers are resistant to high temperatures, high pressure, corrosive and other extreme environments. Moreover, drilling through soft or inter-bedded formations need not stop to change bottom-hole assembly and can continue even though the fluidic hammer fail to operate. Given these advantages, fluidic hammers are convinced to be popular in the coming years and deserve being better known in the rotary-percussion drilling. In this work, a sequence of experimental investigations focused on the operability and effectiveness of a newly designed fluidic hammer under different sets of operational and physical parameters were performed. Some important impacting performance parameters in terms of impact velocity, impact frequency and impact force were obtained from the experimental results to evaluate the working performance of the fluidic hammer and the effect on bit life. An exponential function model was proposed to describe the piston motion. Comparison between the predicted values of the impact period obtained from the theoretical model and the experimental results reveals the rebound effect of the piston-hammer as it strikes the anvil or cylinder on the impact performance of the fluidic hammer. Furthermore, a field trial using a fluidic hammer was conducted in a horizontal directional well drilling to evaluate its effectiveness. An average improvement of 32.7% in penetration rate was recorded.",24,24,2
Other topics ,,"Liu, Cuiwei; Li, Yuxing; Xu, Minghai",An integrated detection and location model for leakages in liquid pipelines,Liquid pipelines; Leak detection and location; Dynamic monitoring module; Static testing module; Experiments,PRESSURE; SYSTEM; OIL; PIPES; LEAKS; WAVES; FLOW,"Many liquids, such as water and oil, are transported by pipelines, where leakages can occur, causing energy wastage, environmental pollution, and risk to human health. This paper describes an integrated model implementing leak detection and location that can be used for background leakages, even micro-leakages in liquid pipelines. The model includes a dynamic monitoring module (DMM) and static testing module (STM). The DMM can detect larger leakages of background ones using the amplitude propagation and attenuation model of pressure waves. The STM, based on the pressure loss model, can detect micro-leakages, which is an effective compensation for the DMM. To verify the proposed model, experiments on the laboratory scale and in the field were carried out, and field applications were implemented. The results show that the integrated model can detect nearly all leakages. For the DMM, the smallest detected ratio of leakage orifice to pipe diameter (RLOPD) in the field is 1/41.4, with location errors on the order of 1%. For STM, the smallest detected leakage rate is just 0.0044%/h in the field. Thus, the model detects and locates leakages for liquid pipelines.",23,24,11
Other topics ,,"Wei, Mingyao; Liu, Yingke; Liu, Jishan; Elsworth, Derek; Zhou, Fubao",Micro-scale investigation on coupling of gas diffusion and mechanical deformation of shale,Nanopores; Micro-scale; Explicit simulation approach; Diffusion coefficient,APPARENT PERMEABILITY; COAL; EVOLUTION; TRANSPORT; MATRIX; FLOW; POROSITY; OPTIMIZATION; ADSORPTION; SIMULATION,"The nanopore structure usually exhibit complex geometry in the shale formation. The interactions between gas and pore structure in such heterogeneous property impacts the properties of shale gas transport in micro-scale. The precise description of this shale gas flow processes in detail is impossible if the micropore is not properly characterized. Thus, this study provides a simulation approach to model the complex geometry of nanopore structures in the shale formation. Based on SEM image segmentation of the shale matrix, the geometry of three compositions (nanopore, kerogen, and matrix) are explicitly simulated. Mass storage, transport mechanisms, and geomechanical properties are fully modeled in the micro-scale model. It demonstrates that the conventional dual porosity model fails to capture the storage and transport mechanisms in micro-scale by comparison with the micro-scale model. The simulation results reveal that stress-induced decrease of the diffusion coefficient is both time-dependent and space-dependent. The reduction of the diffusion coefficient can significantly cut down the adsorbed gas production in kerogen. It results in the low recovery rate of shale gas that a large proportion of adsorbed gas is unable to liberate. Moreover, the later stage of gas production is depended on the supply of adsorbed gas in kerogen.",23,24,9
Other topics ,,"Korrani, Aboulghasem K. N.; Jerauld, Gary R.",Modeling wettability change in sandstones and carbonates using a surface-complexation-based method,Mechanistic modeling; Surface complexation; Wettability change; Ionically tuned waterflood,OIL-RECOVERY; SALINITY; BRINE; WATER; ELECTROKINETICS; INTERFACES; IONS; PERMEABILITY; COEFFICIENTS; PARTICLES,"After testing proposed models in the literature on sandstones and carbonates, we propose a mechanistic surfacecomplexation-based model that quantitatively describes observations for ionically treated waterfloods. We model wettability change by directly linking wettability to brine chemistry using detailed colloidal science. Brine has charged ions that interact with polar acidic/basic components at the oil-water interface and rock surface and therefore oil/brine and rock/brine interfaces are charged and exert both Van der Waals and electrostatic forces on each other. If the net result of the forces is repulsive, the thin water film between the two interfaces is stable (i.e., the rock is water-wet) otherwise, the thin water film is unstable and the rock becomes oil-wet. We describe a ratio of electrostatic force to Van der Waals force with a dimensionless group, called ""wetting film stability number,"" where rock wettability is water-wet for values greater than one and oil-wet for values less than one. For sandstones, the zeta potentials of oil/brine and rock/brine interfaces become more negative/less positive by diluting or softening the brine and/or increasing pH. Similarly, for carbonates, dilution and/or sulfate enrichment of brine makes surface potentials more negative. Such brine modification can therefore be used to improve oil recovery. We implemented the improved wettability change model in a comprehensive coupled reservoir simulator, UTCOMP-IPhreeqc, in which oil/brine and rock/brine zeta potentials are modelled using the IPhreeqc surface complexation module. Surface potentials obtained from the geochemical model are used to calculate the dimensionless group controlling wettability change, which is dynamically modelled in the transport simulator. The model is validated in sandstones and carbonates by simulating an inter-well test, and several corefloods and imbibition tests reported in the literature. For sandstones, we model Kozaki (2012) and BP's Endicott trial. For simple dilution in carbonates we model experiments by Shehata a al. (2014) and Yousef et al. (2010). For enrichment with sulfate we model Zhang and Austad (2006) and for increasing total ionic strength via sodium chloride enrichment, Fathi et al. (2010a).",23,23,1
Other topics ,,"Torrealba, V. A.; Hoteit, H.",Improved polymer flooding injectivity and displacement by considering compositionally-tuned slugs,Polymer flooding; Polymer injectivity; Sweep efficiency; Enhanced oil recovery; Chemical enhanced oil recovery,MOLECULAR-WEIGHT; ADSORPTION,"Polymer flooding (PF) is an enhanced oil recovery technology that consists of the addition of polymer to the injected water to create a high-viscosity solution to control the mobility of the displacement process. Deploying polymers with high viscosity and maintaining high injection rate are two desired but competing attributes that impact the success of PF. In this research, we propose a simple, yet effective PF injection scheme that relies on the cyclical injection of compositionally-tuned slugs. This scheme achieves low polymer viscosity near the wellbore and high polymer viscosity away from the wellbore. This results in improved sweep efficiency compared to constant-composition injection, without impairing fluid injectivity. The new scheme harnesses known aspects of polymer rheology and rock interaction. We analyze the mechanisms that control slug mixing that include polymer rheology, inaccessible-pore-volume, and adsorption. Our results show that by injecting the compositionally-tuned polymer slugs with low injection viscosity, a higher polymer injectivity is preserved. Once the fluids mix in-situ away from the injector, the viscosity significantly increases, which improves sweep efficiency and incremental oil recovery over both waterflooding and continuous polymer injection. This new PF injection scheme can reduce chemical usage and improve the recovery effectiveness of PF, and therefore could be a potential alternative to conventional PF schemes.",23,24,0
Other topics ,,"Zhou, Jun; Peng, Jinghong; Liang, Guangchuan; Deng, Tao",Layout optimization of tree-tree gas pipeline network,Layout design; Two-level tree-tree pipeline network; Hierarchical optimization strategy; Delaunay triangulation; Discrete optimization,MODEL; ALGORITHM,"With the development of petroleum industry and the exploitation of unconventional gas reservoir, the topological form of surface pipeline network is changing gradually and a tree-tree structure is put forward in gas field. Therefore, optimization of the tree-tree pipeline network becomes urgent and indispensable. In this paper, a comprehensive optimization objective function and constraints is established to allow layout design. In view of the characteristics of the model comprising numerous discrete variables (e.g. location, number, allocation relationship, connection decision variable etc), a hierarchical optimization strategy is proposed to decompose it into three sub-problems. On the basis of the proposed model, an optimization program based on Delaunay triangulation has been presented to solve the non-linear constrained optimization problem which contains connection decision variable between wells in clusters on the constraint condition of path length restriction. Further, the reason of using Delaunay triangulation is analyzed and the optimization process of the essential sub-problem has been illustrated. Moreover, the developed program has been applied to a practical coalbed methane field project. The model and method in this paper is shown to be feasible and effective to solve layout optimization on two-level tree-tree pipeline network.",22,24,0
Other topics ,,"Rezvani, Hosein; Kazemzadeh, Yousef; Sharifi, Mohammad; Riazi, Masoud; Shojaei, Sanaz",A new insight into Fe3O4-based nanocomposites for adsorption of asphaltene at the oil/water interface: An experimental interfacial study,Emulsion stabilization; Interfacial viscosity; Asphaltene adsorption; Nanocomposite; Fe3O4/Chitosan; Fe3O4/TiO2; Fe3O4/SiO2,ENHANCED OIL-RECOVERY; W/O EMULSIONS; WATER; NANOPARTICLES; STABILITY; PARTICLES; INJECTION; SURFACES; ZRO2,"Concerning the potential positive role of water in oil emulsification in enhancing oil recovery, the current research builds on finding reasons responsible for the considerable water in oil emulsification observed in the produced fluid during carbonate sand pack floodings in the previous works. Allowing a systematic comparison, the results on floodings of three Fe3O4-based nanocomposites were selected from previous studies. The XRD and FESEM of nanocomposites, zeta potentials, stability of synthetic emulsions, IFT, bulk and interfacial oil/water viscosities, and asphaltene adsorption in the presence of nanocomposites were analyzed. The XRD and FESEM results showed a successful synthesis for all nanocomposites. Zeta potential measurements showed values far above -40 mV, which confirm a good stability for all nanocomposites in the base fluid. In terms of emulsion stability, microscopic images showed that all synthesized nanocomposites had better performance in stabilizing synthetic emulsion droplets as compared to Fe3O4 NPs. IFT measurements indicated an 18-21 mN/m decrease with the addition of nanocomposites to the seawater. The bulk viscosity measurements indicated that Fe3O4/Chitosan nanocomposites present in the aqueous phase increase the water/oil (30/70 vol %) emulsion viscosity up to 334 cp. The interfacial viscosity measurements also showed a reduced oil/water interfacial viscosity by the addition of nanocomposites to the aqueous phase, which is probably due to the increased presence of asphaltene molecules at the interface. In the end, the absorbed asphaltene particles by nanocomposites were measured using batch adsorption experiments and fitted to the BET adsorption isotherm. The results showed that by deploying at the interface, Fe3O4-based nanocomposites are highly capable of asphaltene adsorption, which can stabilize the water in oil emulsions.",21,21,2
Other topics ,,"Mirzaei-Paiaman, Abouzar; Saboorian-Jooybari, Hadi; Chen, Zhangxin; Ostadhassan, Mehdi",New technique of True Effective Mobility (TEM-Function) in dynamic rock typing: Reduction of uncertainties in relative permeability data for reservoir simulation,Reservoir simulation; Relative permeability; True effective mobility; TEM-Function; Dynamic rock typing; Quasi-relative permeability,SPONTANEOUS IMBIBITION,"Performance predictions made by reservoir simulators are highly dependent on experimentally-determined relative permeability data assigned to simulation grid cells. There is often no apparent relationship between this type of data and a quantifiable property of cells, meaning that samples within a group of neighboring relative permeability curves do not have similar values of a common characterization property. On the other hand, it is easier to correlate primary drainage capillary pressure data to cell properties and create a petrophysical static rock type (PSRT) from a group of similar capillary pressure data. The common approach is to average the relative permeability data corresponding to each PSRT and input that into a simulator. In practice, relative permeability curves corresponding to a given PSRT would exhibit a significant scatter, especially in carbonate formations. This will cause the resulting average relative permeability data to be highly uncertain and poorly representative of true dynamic behavior of the cells. In this study, a new technique is proposed to reduce uncertainties associated with classical methods of assigning relative permeability data to grid cells of a simulation model. The idea is based on a robust and universal criterion for characterization of dynamic characteristics of rocks from laboratory-derived flow data to define a petrophysical dynamic rock type (PDRT). A PDRT is defined as a collection of rocks with similar True Effective Mobility (TEM) behavior. A TEM-function for analysis of relative permeability is defined as a product of relative mobility by the square of a mean pore radius, and is analogous to the well-known J-function for scaling capillary pressure curves. For a given PDRT, a special weighted average of corresponding relative permeability data, or average TEM data should be used as input to a simulator. In the latter case, the simulator should have the capability to back-calculate cells' quasi-relative permeabilities using the inputted average TEM data. Moreover, we show that factors such as wettability and pore-scale heterogeneity can cause phase-dependent dynamic characteristics (i.e., different dynamics with respect to each fluid phase). Hence, different dynamic rock typing schemes should be applied to the flow of each fluid in system. A structured methodology is presented to identify PDRTs using TEM-function and prepare input parameters to simulators by analyzing relative permeabilities using the universal criterion developed in this work. Ultimately, special core analysis data from the Asmari Formation, a carbonate reservoir from one of the Iranian Fields, is used to verify and demonstrate the applicability of the presented technique.",21,21,1
Other topics ,,"Xu, Xiaokai; Meng, Zhaoping; Wang, Yun",Experimental comparisons of multiscale pore structures between primary and disturbed coals and their effects on adsorption and seepage of coalbed methane,Coal body structure; Pore structure; Adsorption; Seepage; Coalbed methane,PERMEABILITY; MECHANISM; CAPACITY; BEHAVIOR; STRESS; CO2,"The investigation of pore structures in coal is supposed to be a primary approach to ascertain coal structure's influence mechanism on CBM storage and migration. In this study, pore structures in multiscale have been comprehensively and systematically explored for high-rank primary coal and granulated-mylonitized coal (tectonically disturbed coal with high deformation degree), two main typical kinds of coal structures in southeastern Qinshui Basin, by a series of pore-detecting experiments. Based on pore structure differences between two coals, the influences of tectonic stress on pore structures were discussed and the control mechanisms of pore structures on gas adsorption and seepage were further analyzed. It turns out that, (1) adsorption pores (< 100 nm) are more well-developed for disturbed coal than for primary coal, which determines stronger gas adsorption and reservoir capacities in disturbed coal; (2) micron-level seepage pores (0.1 mu m-0.1 mm) could be clearly divided into two ranges, namely seepage major-pores and seepage minor-pores. It could be deduced that the main seepage pore/fracture system generally consists of macroscopic cleats/fractures and seepage majorpores. The system is less developed in disturbed coal than in primary coal, which is the essential reason for the low permeability in disturbed coal; (3) strong dynamic metamorphism and ductile deformation induced by intense tectonic compression/shear stress, facilitate further generation of adsorption pores, and also result in the destruction of the main seepage pore/fracture structure. That's the control mechanism of tectonic stress for strong gas bearing potential and poor seepage capability in granulated-mylonitized coal reservoir. This research is of an important enlightening significance in CBM production aiming at high-rank disturbed coal reservoir with high deformation intensity in the study area.",20,20,18
Other topics ,,"Ye, Haitang; Li, Qi; Sun, Fengrui",Numerical simulation of CO2 circulating in a retrofitted geothermal well,Geothermal energy extraction; Retrofitted abandoned wells; CO2 circulating; Insulation layer length; Optimization and sensitivity analysis,HEAT-TRANSFER CHARACTERISTICS; SUPERHEATED STEAM FLOW; MULTICOMPONENT THERMAL FLUID; INJECTION HORIZONTAL WELLS; ABANDONED OIL; MULTIOBJECTIVE OPTIMIZATION; THERMOPHYSICAL PROPERTIES; COGENERATION SYSTEM; NONCONDENSING GASES; TRANSPORT BEHAVIOR,"Abandoned oil and gas wells are proved to be effective in geothermal energy extraction, especially when the wellbore is located at a perfect geothermal reservoir. In this paper, CO2 is selected as the working fluid and a model is proposed to simulate the CO2 flow in the retrofitted wellbores. The CO2 is injected into the inner tube (injector) and then flows out through the annuli (producer) to surface. The proper length of the insulation layer installed outside the casing is predicted. Results show that (a) when the CO2 flows from well-bottom to wellhead in the producer, its temperature has an increase at first and then turns to decrease. An insulation layer outside the casing is an efficiency way to prevent CO2 from transferring heat to the stratum. (b) From the temperature point of view, a smaller mass flow rate is recommended to obtain a higher CO2 temperature at outlet of the producer. (c) A higher mass flow rate leads to a higher geothermal energy extraction rate but a lower temperature. (d) A small increase in temperature or the geothermal energy extraction rate need a large pressure increase, which can be high-cost for field practice.",20,20,3
Other topics ,,"Sun, Fengrui; Yao, Yuedong; Li, Guozhen; Dong, Mingda",Transport behaviors of real gas mixture through nanopores of shale reservoir,Shale gas reservoir; Nanopores; Real gas effect; Multi-component effect; Coupled model; Analytic equations,GEOTHERMAL-ENERGY EXTRACTION; KNUDSEN NUMBER; OIL TRANSPORT; FLOW; MODEL; CO2; DIFFUSION; PERMEABILITY; PERFORMANCE; SIMULATION,"The modeling of shale gas transport through nanopores is the basis for shale gas production simulation. The real shale gas always consists of a series of gases, including ethane, propane and hydrogen sulfide etc. Previous models neglected the multi-component effect on the shale gas transport mechanisms. In this paper, a novel model is presented for simulating the real gas mixture transport through nanopores of shale formation. Firstly, a model is presented for ideal shale gas transport through nanopores considering the multi-component effect, then, the real gas effect is coupled into the model. Simulation results show that: (a) When it is under low pressure level condition, the conductivities of slippage flow and Knudsen diffusion increase with decreasing methane fraction. (b) When it is under medium pressure level condition, the conductivities of slippage flow and Knudsen diffusion increase with decreasing methane fraction. (c) Under high pressure condition, the conductivities of different flow patterns increase with decreasing methane fraction.",20,20,2
Other topics ,,"Lu, Hao; Liu, Yi-Qian; Cai, Jing-Bo; Xu, Xiao; Xie, Lin-Sheng; Yang, Qiang; Li, Yue-Xi; Zhu, Kai",Treatment of offshore oily produced water: Research and application of a novel fibrous coalescence technique,Offshore gas-field; Produced water treatment; Combined fibrous coalescer; Oil pollutant,LIQUID LIQUID-SYSTEMS; PLATE SEPARATORS; BED; EMULSION; FLOW,"Rapidly removing oil from emulsified produced water has become one of the most common problems that needs to be urgently resolved as gas-field exploitation enters its later stages, and an effective technique has not yet been established thus far. This paper introduces experimental research and further industrial application of a novel combined fibrous coalescer in the treatment of produced water in an offshore gas-field. Metal and oleophilic polymer fibers were combined at a certain proportion and woven into a fibrous bed with specific structural and geometric properties, which was used as the core separation component of the coalescer. The industrial operation results showed that the oil pollutant concentration of the produced water treated with the novel coalescer was reduced from 1200 to 25 mg/L, well below the 45 mg/L national discharge standard, under a residence time of 180 s and pressure drop of 30 psi. This is the first successful and significant industrial application of the technique in an offshore gas-field, providing a promising alternative for resolving the difficulty of produced water treatment in similar gas-fields, promoting further applications of the technique, and contributing to cleaner production and marine conservation.",19,21,12
Other topics ,,"Shen, Jian; Qin, Yong; Li, Yepeng; Wang, Geoff",Experimental investigation into the relative permeability of gas and water in low-rank coal,Erlian Basin; Relative permeability; Low-rank coal; Pore structure; Confining pressure; Displacing pressure,DYNAMIC PREDICTION MODEL; SOUTHERN QINSHUI BASIN; METHANE PRODUCTION; IMBIBITION; RESOURCES; INTRUSION; RECOVERY; PRESSURE; STRESS; FLOW,"Understanding the relative permeability characteristics of coal in a gas-water system is crucial for coalbed methane development. Due to a lack of experimental information on the gas-water relative permeability of coal, the relative permeability of the low-rank coals in the Erlian Basin in the north of China was investigated under different conditions using the unsteady-state method. The studied coals are dominated by huminite with high moisture content, volatile yield, and low ash yield. The pore sizes of the coals feature a bimodal pattern distribution with a higher left peak of approximately 10-100 nm and a relatively lower right peak of approximately 10000 nm. The measurement of mercury intrusion-extrusion hysteresis also suggests that ink bottle-shaped pores are possibly developed within the coals. The results from relative permeability tests with methane (CH4) and water depend on the pore structure, coal wettability, confining pressure, and pressure difference in the coal. The results show that a definite correlation does not exist between relative permeability and porosity in the low-rank coal. However, macropore porosity rather than the whole range of the porosity is the most likely property affecting the water relative permeability, whereas the effect of pore size on gas relative permeability varies along with a broader range. It has been observed that the low-rank coal with higher water wettability exhibits lower water relative permeability, narrower two-phase span, higher gas relative permeability, and irreducible water saturation. With the increase in the confining pressure, both the methane and water relative permeabilities decrease, while the ratio of relative permeability (k(rw)/k(rg)) increases. This suggests that the confining pressure has less influence on water relative permeability than that on gas. As the pressure difference increases under the same effective stress, the residual water saturation in the low-rank coals decreases, and the associated two-phase span increases. Water relative permeability obviously increases above the crossover point water saturation, whereas gas relative permeability increases below the crossover point water saturation.",19,20,6
Other topics ,,"Liu, Yuming; Zhang, Bo; Dong, Yue; Qu, Zhipeng; Hou, Jiagen","The determination of variogram in the presence of horizontal wells - An application to a conglomerate reservoir modeling, East China",Variogram; Reservoir modeling; Horizontal wells; Conglomerate reservoirs,BOHAI BAY BASIN; OIL-FIELD,"Building a reliable numerical geological model is critical in reservoir development and management. Inferring a stable 3D variogram is one of the most important processes in the building of numerical geological model. We usually can obtain a well-defined vertical variogram from wells in most cases due to the regular sampling in the vertical direction. The quality of horizontal variogram highly depends on the number of wells, geometric of the well locations, and the trajectory of wells. Horizontal wells usually have preferred trajectory directions due to the geological and geomechanical consideration. As a result, it is very difficult to obtain a reliable horizontal variogram by using the data of horizontal wells. We proposed a three-step procedure to infer the horizontal variogram by integrating geological, seismic, and horizontal well data. We first use the geological information and P-impedance to infer the approximate major azimuth of horizontal variogram. We then obtain the range of the variogram for each horizontal well using the data of horizontal section. We finally determine the major, minor direction and corresponding ranges by least-square fitting the ranges computed using each horizontal well. We illustrate our workflow by applying it to a conglomeratic reservoir modeling, East China. The modeled reservoir properties have a very good correlation with the production data.",19,19,1
Other topics ,,"Zhang, Xiaoyang; Wu, Caifang; Wang, Ziwei",Experimental study of the effective stress coefficient for coal permeability with different water saturations,Effective stress coefficient for permeability; Water saturation; Response surface method; Stress sensitivity; Dynamic change of permeability,DYNAMIC PREDICTION MODEL; EFFECTIVE PRESSURE LAW; METHANE PRODUCTION; PORE PRESSURE; SENSITIVITY; DESORPTION; STRAIN; CLEAT,"The effect of effective stress on coal reservoir permeability is inevitable during coalbed methane (CBM) production. Studying the effective stress coefficient for permeability (ESCK) is crucial because it determines the effective stress and stress sensitivity of a coal reservoir. Considering the actual drainage process of a CBM well, a series of stress sensitivity experiments with different water saturations were designed and implemented. The experimental results show that the gas measured permeability of the coal sample decreased with increasing water saturation. The change in permeability with different water saturations had a significant power relationship with increasing net pressure. Using the response surface method (RSM), ESCK values with different water saturations were obtained. The ESCK value, regardless of the stress conditions, is a constant at a certain water saturation, and it shows an increasing trend with increasing water saturation. The ESCK values with different water saturations indicate that the effective stress decreases with increasing water saturation. The stress sensitivity and dynamic change in coal reservoir permeability were also analyzed using ESCK values with different water saturations. The stress sensitivity coefficient decreased with increased water saturation, and the reservoir permeability decreased more obviously with an ESCK value of 0.7675 than that with a value of 1.0. During CBM well production, water saturation decreases, and the stress sensitivity of coal reservoir permeability increases.",18,18,8
Other topics ,,"Zhang, Wenwu; Yu, Zhiyi; Li, Yongjiang",Application of a non-uniform bubble model in a multiphase rotodynamic pump,Non-uniform bubble model (NUBM); Multiphase pump; Interphase force; Inlet gas void fraction (IGVF); Numerical simulation,GAS-LIQUID FLOW; NUMERICAL-SIMULATION; SIZE DISTRIBUTION; DISTRIBUTIONS; IMPELLER; DYNAMICS; PATTERNS; FRACTION,"Thus far, the break-up and the coalescence of bubbles have never been considered in the simulations of the multiphase pumps, while the non-uniform bubble model (NUBM) considered in this study has been successfully applied to predict the external characteristics, phase interaction and internal flow characteristics of a multiphase rotodynamic pump. On the basis of the Euler two-fluid model, the drag model considered to be the most important phase interaction model was modified using the secondary development technology of ANSYS CFX 16.0. The correctness of the modified drag model and that of the applied NUBM were verified by comparing with the experimental data at different inlet gas void fractions (IGVFs). When the IGVF was 21%, the relative errors of the pump heads with C-D_(0.34), C-D_SN, and C-D_(modified) were 10.30%, 8.19% and 1.43%, respectively. Meanwhile, the comparative results with and without NUBM showed a small difference in the corresponding interphase forces (drag, added mass force, and lift) under the relatively small IGVF condition (IGVF = 3%), while the difference became obvious under a large IGVF condition (IGVF = 15%).",18,21,3
Other topics ,,"Wang, Zhuangzhuang; Li, Zhaomin; Sarma, Hemanta K.; Xu, Yajie; Wu, Peng; Yang, Jianping; Wang, Hongyuan; Lu, Teng",A visualization experimental study on gas penetration through interlayer to improve SAGD performance,Gas assisted SAGD; Penetration through interlayer; Condensation heat transfer; 2D visualization experiment; Synergistic effect,ASSISTED GRAVITY-DRAINAGE; HEAVY OIL; NUMERICAL-SIMULATION; STEAM CHAMBER; MASS-TRANSFER; CONDENSATION; IMPACT,"Low-permeability interlayer is common in reservoir, which can hinder the steam chamber expansion and the gravity drainage in SAGD. It is crucial to find an economical and practicable method to promote the steam chamber to break through the interlayer. In this work, four condensation heat transfer experiments were conducted to investigate the effect of flue gas on steam condensation heat transfer. On this basis, 2D visualization tests, including a SAGD experiment and two flue gas assisted SAGD experiments, were carried out to see if the steam chamber can break through the interlayer under the effect of flue gas. Results show with the increase of gas proportion in the steam-flue gas mixture, the condensation heat transfer coefficient decreased and the condensation pattern was transformed from drop condensation to film condensation gradually. This indicates that flue gas can inhibit the condensation heat transfer, which has great influence on the heat transfer and steam chamber growth in SAGD. Visualization tests show the interlayer could block the steam chamber development. After the interlayer was heated sufficiently, flue gas could penetrate the interlayer and promote steam chamber to break through the interlayer because of its inhibiting effect on condensation heat transfer. Besides, the horizontal sweep efficiency was improved significantly under the synergistic effects of steam, gas, and interlayer. The gas addition can reduce the adverse impact of interlayer on SAGD performance, which provides a potential method to improve SAGD development in the reservoir with interlayer.",18,19,2
Other topics ,,"Lu, Han; Shen, Qiuyang; Chen, Jiefu; Wu, Xuqing; Fu, Xin",Parallel multiple-chain DRAM MCMC for large-scale geosteering inversion and uncertainty quantification,Well logging; Geosteering; Inverse problem; DRAM MCMC; Data clustering; Parallel computing,CONVERGENCE; ALGORITHM,"Geosteering is the proactive control of a wellbore placement based on the downhole measurements, aiming at maximizing economic production from the well. The recent development of azimuthal resistivity logging-whiledrilling (LWD) tools have a much larger depth of detection, thus sets higher demands for geosteering inversion as more unknown parameters need to be taken into account in the earth model to be inverted. For complicated non-linear problems, traditional deterministic inversion methods are more likely to be trapped near local optima. In general, Markov chain Monte Carlo (MCMC) inversion methods are more capable of finding the global optimal solution and providing additional uncertainty analyses by sampling from the target distribution. However, MCMC methods usually have the problem of slow convergence. Even though optimization methods like delayed rejection (DR) and adaptive Metropolis (AM) were proposed to speed up the convergence, using MCMC methods to solve geosteering inversion problems may still incur unacceptable time cost. To reduce the sampling cost of MCMC methods, we use parallel multiple-chain DRAM MCMC methods to solve geosteering inverse problems and estimate the corresponding uncertainty. A clustering method, density-based spatial clustering of applications with noise (DBSCAN), is applied to select the best solution among many results. The simulation results show that running many relatively short MCMC chains for one problem can obtain a similar result as running a long single chain. Besides, avoiding communications between multiple Markov chains during the sampling process yields almost linear scalability.",18,18,2
Other topics ,,"Zhao, Hui; Xu, Lingfei; Guo, Zhenyu; Liu, Wei; Zhang, Qi; Ning, Xuewei; Li, Guohao; Shi, Lihua",A new and fast waterflooding optimization workflow based on INSIM-derived injection efficiency with a field application,,ISENTHALPIC FLASH; INTERWELL CONNECTIVITY; PERFORMANCE; DISPLACEMENT; INVERSION; MODEL,"Traditionally, production optimization is performed based on repeatedly running a full-scale reservoir simulation model, which is quite time-consuming. Recently, we developed a computationally efficient data-driven model, which is referred to as interwell-numerical-simulation model (INSIM), for history matching, characterizing interwell connectivity, monitoring, and optimization for a waterflood. In this research, we develop a new workflow for fast optimization of waterflooding performance which only requires one single INSIM forward run. Specifically, the optimized well injection rate and production rate are determined with the help of the new INSIM-derived injection efficiency and the existing injector-centered allocation factor. The basic idea of the proposed optimization workflow is to recover more oil by injecting more water to those injector-producer pairs that have more remaining oil left; whereas decrease water injection for those connections without much oil left. The major criterion to tune the injection rate is based on the injection efficiency calculated with INSIM, a value to measure the effectiveness of injected water from an injector. The larger the injection efficiency is, the more oil can be produced by injecting a unit amount of water. The advantage of this method is that the well controls are optimized based on the reservoir-engineering point of view which is easy to understand and visualize. Also, the new workflow is very easy to implement and is much more computationally efficient than the traditional optimization workflow. We test the proposed workflow with two examples including a large-scale field example. The computational results indicate that, by using the proposed workflow, the field oil production is increased with less producing water.",18,19,1
Other topics ,,"Shabani, Ali; Kalantariasl, Azim; Parvazdavani, Mohammad; Abbasi, Saeed",Geochemical and hydrodynamic modeling of permeability impairment due to composite scale formation in porous media,Scale formation; Reactive flow; Geochemical; PHREEQC; Formation damage,INJECTIVITY DECLINE; DEEP BED; WATER; DISSOLUTION; PRECIPITATION; SUSPENSION; RESERVOIR; IMPACT; TEMPERATURE; SIMULATION,"Injectivity decline due to mineral scale deposition in near wellbore region of water injection wells is one of the main challenging issues and have been widely reported in the literature. One of the main mechanisms of injectivity loss is incompatibility between injected and formation waters that may result in inorganic scale precipitation and subsequent deposition in porous media. Reliable reactive flow models to predict type and amount of scale along with permeability decline estimation allow planning and risk management of water flood projects. In this paper, we present a coupled geochemical and hydrodynamic model to simulate the scale precipitation and deposition of mineral scales in multicomponent aqueous systems which is able to predict type of scale and permeability decline in porous medium. Geochemical software was used to simulate reactions between injected and formation brine suspicions to risk of composite scale formation and hydrodynamic flow model was applied to predict subsequent permeability decline during water injection. High quality match of permeability decline in following of robust static modeling of mineral scale formation in multicomponent aqueous systems was achieved.",18,18,0
Other topics ,,"Tang, Huiying; Wang, Shihao; Zhang, Ruihan; Li, Sanbai; Zhang, Liehui; Wu, Yu-Shu",Analysis of stress interference among multiple hydraulic fractures using a fully three-dimensional displacement discontinuity method,Hydraulic fracturing; Multiple fracture propagation; Stress interference; Three-dimensional displacement discontinuity method,PERFORATION CLUSTERS; INTEGRAL-EQUATIONS; BOUNDARY DIVISION; CRACK-GROWTH; PROPAGATION; ELEMENT; MODEL; SIMULATION,"Due to the extremely low permeability of shale matrix, a great number of hydraulic fractures are required to enhance the flow capacity of shale reservoirs to obtain economic productivity. The mechanical interactions among closely spaced hydraulic fractures could result in fracture curving, intersection and unbalanced growth. Current hydraulic fracturing models are mainly based on the assumption of 2D or Pseudo-3D, in which the fractures are vertical with constant or equilibrium height. To better analyze and understand the stress interference among multiple hydraulic fractures, a fully three-dimensional (3D) model based on the displacement discontinuity method (DDM) is developed in this paper. The challenges (eq. grid twisting, hyper-singular integrals) in implementing 3D DDM for fracture growth problems are systematically discussed and solved from different aspects. Optimization strategies for the 3D model, including adaptive mesh growth, non-crowding Gaussian points and distance-dependent integrals, are proposed. Using this model, we first compare the strength of stress interactions with different fracture geometries. The simulation results show that the length of the shorter edge of the hydraulic fracture dominates the strength of stress shadowing effect. The stress redistribution due to fracture interference in 3D space is also calculated which delivers a much more complex shape of potentially stress re-orientation region than the 2D results. Then, the simultaneous propagation of multiple hydraulic fractures in different in-situ stress fields is analyzed, highlighting the importance of in-situ stress distribution on fracture geometries and interactions. The limitation on fracture height growth can reduce the mechanical interactions under the constant net pressure assumption. Besides, the detailed introduction of the present stable and efficient 3D DDM-based fracture propagation model can be used as a basis for other investigation purposes.",17,17,7
Other topics ,,"Alkinani, Husam H.; Al-Hameedi, Abo Taleb T.; Dunn-Norman, Shari; Flori, Ralph E.; Alsaba, Mortadha T.; Amer, Ahmed S.; Hilgedick, Steven A.",Using data mining to stop or mitigate lost circulation,Drilling fluid; Lost circulation; Updated classification; Basra oil fields; Iraq,,"Lost circulation materials (LCMs) are available in a great variety of materials, sizes, and can vary in the method of application. Selecting the right LCM and treatment for the job is critical in achieving the successful control of the lost circulation event. After reading a good number of papers and case histories regarding lost circulation materials and treatments and comparing the current classification to actual real field data, a large gap was found in the current calcification of lost circulation materials and treatments. An updated classification of lost circulation materials and treatments was provided based on the type of losses and applications. Data were collected on both LCM and applications from various number of sources in the Basra area of Iraq where drilling operations are highly susceptible to lost circulation in the Dammam, Hartha and Shuaiba formations. After analyzing the data, the best lost circulation treatments and materials to treat seepage, partial, severe, and complete losses in Basra oil fields were provided as a flowchart accomplished by practical guidelines that can serve as a reference material for the drilling personnel when responding to lost circulation in the field. This paper will also discuss methods that are used to ameliorate lost circulation without the use of traditional lost circulation materials. Example of the alternative approaches include discussions of blind drilling and foaling mud cap drilling using case histories from the Basra fields. The results of this analysis provide a path forward for effectively and systematically using lost circulation materials and treatments in the Basra area. The methodologies presented in this work can be adapted and used to treat lost circulation worldwide.",17,18,4
Other topics ,,"Mahzari, Pedram; Jones, Adrian P.; Oelkers, Eric H.",An integrated evaluation of enhanced oil recovery and geochemical processes for carbonated water injection in carbonate rocks,Enhanced oil recovery; Numerical modelling; CO2 WAG; Carbonated water injection rock dissolution; Calcite geochemistry,BINARY INTERACTION PARAMETERS; WORMHOLE FORMATION; CO2 STORAGE; EQUATION; PREDICTION; SYSTEMS; STATE; FLOW; EOR,"During carbonated water injection and CO2-WAG scenarios for enhanced oil recovery, dynamic transfer of CO2 from aqueous phase into resident oil can cause complex pH variations, which can affect mineral dissolution around wellbore and precipitation in reservoir. Also, transfer of CO2 from carbonated water into live oil can liberate light components of the oil, which would create gas phase in-situ. In this investigation, a novel methodology was developed to numerically simulate these complex processes in an integrated approach. This study could present one step closer to realistic evaluations of dynamic CO2 transfer from carbonated water to resident oil and consequent interactions with the reactive minerals in a carbonate reservoir. Taking account of the data of coreflood experiments performed on a carbonate rock under 3100 psi and 100 degrees C, profiles of ionic concentration of produced brine and rock weight during carbonated water injection into a dry core (in the absence of oil) were history-matched to tune reaction parameters. Calcite reaction parameters (surface area and activation energy) were tuned to match profile of concentration of Ca++. Also, for additional oil recovery and dP profiles, secondary and tertiary carbonated water injection experiments were matched simultaneously to obtain relative permeability curves and CO2 mass transfer parameters. This new approach is called co-history-matching. Using the tuned parameters in a radial sector model, a series of simulations was performed to analyse change in rock porosity and enhanced oil recovery for large scales for carbonated water injection. Results of the large-scale model have demonstrated that minerals dissolution takes place mostly in vicinity of the injection wellbore. However, the simulation results demonstrated that injection of short cycle of carbonated water followed by plain water would alleviate the dissolution issue, while significant additional oil recovery is achieved.",17,17,3
Other topics ,,"Hosseini-Dastgerdi, Zeinab; Meshkat, Seyyed Salar",An experimental and modeling study of asphaltene adsorption by carbon nanotubes from model oil solution,Asphaltene; Adsorption; Carbon nanotube; Modeling,CRUDE-OIL; OXIDE NANOPARTICLES; DEPOSITION; SURFACE; TOLUENE; CLAYS,"The adsorption of asphaltene on the surface of nanoparticles in the crude oil industry is a significant issue. In this regard, carbon nanostructures can be applied as an adsorbent for the removal of asphaltene from crude oil. In this paper, carbon nanotubes (CNTs) were used for the adsorption of three different asphaltenes from toluene solutions. The CNTs were synthesized by Chemical Vapor Deposition (CVD) method. The synthesized CNTs were characterized by Brunauer-Emmett-Teller (BET), Field Emission Scanning Electron Microscopy (FESEM) and Transmission Electron Microscopy (TEM). The asphaltenes were analyzed by X-ray Diffraction (XRD) and elemental analysis techniques. In addition, asphaltene adsorption isotherms and kinetics were offered. The adsorption of asphaltene was fast since equilibrium was reached in 1 h. The kinetic data were fitted well to the pseudo-second-order kinetic model. The equilibrium data of asphaltene A and B was fitted well to the Freundlich model. However, for asphaltene C, Temkin model was consistent with the experimental data due to the strong interactions between asphaltene C and surface arising from pyridinic, pyrrolic, sulfide and disulfide functional groups which existed on the surface of asphaltene C. The results indicated that the capacity and affinity depend on the molecular structure of the asphaltenes. The high adsorption capacity of asphaltene A was attributed to its high aromaticity. An increase in the aromatic nature of asphaltenes increases the self-association of asphaltenes and pi - pi interactions between asphaltenes and CNTs, which increases the asphaltene adsorption. The thermodynamic parameters indicated that the adsorption of asphaltenes on CNTs is exothermic and spontaneous. According to the results, CNTs showed high adsorption capacity and can be considered as an appropriate choice for asphaltene removal from crude oil.",16,16,2
Other topics ,,"Oseh, Jeffrey O.; Norddin, M. N. A. Mohd; Ismail, Issham; Gbadamosi, Afeez O.; Agi, Augustine; MohammeD, Hakim N.",A novel approach to enhance rheological and filtration properties of water-based mud using polypropylene-silica nanocomposite,Rheological properties; Water-based mud; Filtrate loss; Lubricity; Polypropylene-silica nanocomposite,DRILLING-FLUID SYSTEM; OXIDE NANOPARTICLES; EMISSION BEHAVIOR; PERFORMANCE; COMPOSITE; COMBUSTION; POLYETHYLENE; NANOSILICA; STABILITY; BENTONITE,"Deeper drilling depths and high pressure high temperature (HPHT) wells require good well planning at minimum cost and unproductive time. Polymer nanocomposite has emerged as a promising additive to enhance the thermal stability of conventional water-based muds (WBMs). In this study, polypropylene-silica nanocomposite (PP-SiO2 NC) was synthesized using hot-emulsion sol-gel method. The performance of the PP-SiO2 NC in WBMs was critically examined and compared with that of partially hydrolyzed polyacrylamide (PHPA). Different characterization techniques were used to examine the morphology, structure information and thermal stability of the PP-SiO2 NC. The effect of 0.3 g, 0.6 g, 0.9 g, 1.2 g and 1.5 g each of PHPA and PP-SiO2 NC towards rheological properties, lubricity, filter cake thickness, and filtrate volume of WBM before and after thermal aging tests were studied. In addition, salt tolerance and cost analysis of the PP-SiO2 NC were evaluated. The results show that the PP-SiO2 NC has a spherical shape and a particle size distributed between 80 and 390 nm. The WBM with PP-SiO2 NC has better performance in controlling filtration and modifying rheological properties than the PHPA owing to the finely dispersed PP-SiO2 NC particles. With a concentration of 0.6 g after aging, the plastic viscosity of the PHPA mud decreased by 52.7% from 27.5 to 13 mPa s, while that of the PP-SiO2 NC mud reduced by 22.7% from 22 to 17 mPa s. Salt tolerance study showed that high concentration of potassium chloride affected the effectiveness of the PP-SiO2 NC in controlling HPHT filtrate volume. The cost analysis of the PP-SiO2 NC shows low cost of formulation. Hence, PP-SiO2 NC showed promising attributes for a good drilling mud.",16,16,2
Other topics ,,"Karimi, Solmaz; Firouzfar, Ehsan; Khoshchehreh, Mohammad Reza",Assessment of gas separation properties and CO2 plasticization of polysulfone/polyethylene glycol membranes,Polysulfone; Polyethylene glycol; Gas separation; Plasticization; Selectivity,PERMEATION PROPERTIES; GRAPHENE OXIDE; PERFORMANCE; HYDROPHILICITY; TEMPERATURE; IMIDE); GLASSY; FLUX; GO,"In the current paper, the effect of various concentrations of polyethylene glycol (PEG) on properties of PEG-blended polysulfone (PSU) gas separation membranes was investigated. Scanning electron microscopy (SEM), Fourier-transform infrared spectroscopy (FTIR), and x-ray diffraction analysis were applied to assess membrane morphology as well as chemical and phase structure, respectively. The obtained results confirmed the dense asymmetric structure in membrane cross sectional morphology. Moreover, the PSU/PEG membranes were found to be consisted of amorphous regions without any crystalline structure. In addition, gas permeability and selectivity of obtained membranes were investigated with respect to pure gases of N-2, O-2, CH4, and CO2 and membrane CO2 plasticization was studied at varying pressures. According to the results, CO(2 )accounted for the highest gas permeability at all PEG concentrations while CH4 and N-2 represented the lowest gas permeability through the pure PSU and PEG-blended PSU membranes, respectively. CO2 permeability was found to decrease and then increase with increasing feed pressure at various PEG concentrations with the highest variation of permeability at 20 wt % PEG.",16,17,0
Other topics ,,"Khalaf, Mohammed H.; Mansoori, G. Ali",Asphaltenes aggregation during petroleum reservoir air and nitrogen flooding,Asphaltene; Compressed gases; Enhanced oil recovery; Interaction energies; Molecular dynamics; Onset of aggregation,MOLECULAR-DYNAMICS SIMULATION; TRANSPORT-PROPERTIES; OIL; CO2; INSIGHTS,"Aggregation onsets of seven different asphaltenes dissolved in model oils, due to the effects of misciblized compressed air or nitrogen injections, were studied through molecular dynamics simulation. Natures of aggregations, cumulative coordination numbers, and interaction energies were investigated. Onset of aggregation processes were highly affected by injected gas concentration. In more cases little differences were observed between using air and pure nitrogen. However, asphaltene aggregation onset was highly affected by its molecular architecture. Asphaltenes with long aliphatic chains and archipelago structure showed low aggregation affinities.",16,16,0
Other topics ,,"Mohammadi, Majid; Safari, Mehdi; Ghasemi, Mostafa; Daryasafar, Amin; Sedighi, Mehdi",Asphaltene adsorption using green nanocomposites: Experimental study and adaptive neuro-fuzzy interference system modeling,Asphaltene removal; NiO/ZSM-5; NiO/AlPO-5; Adsorption; ANFIS; Sensitivity analysis,METHANOL CONVERSION; LANGMUIR ISOTHERM; TIO2/SIO2 NANOFLUIDS; SAPO-34 SYNTHESIS; WASTE-WATER; TOTAL IRON; CRUDE-OIL; REMOVAL; CATALYSTS; NANOPARTICLES,"Asphaltene deposition is a known problem that causes significant cost increases in the oil industry. Two biotemplated adsorbents, namely the NiO/ZSM-5 and NiO/AlPO-5 nanocomposites, were used as new green adsorbents to remove asphaltene from a model oil solution. Composite adsorbents were characterized by FTIR, BET, TEM and XRD analysis. Batch adsorption experiments were carried out as a function of D/C-0 [(g)(adsorbent)/(mg/l)(initial)], pH, and temperature (K). Results showed that maximum adsorption is obtained at D/C-0 = 0.072 [g/ (mg/l)] with a pH of 4.8 and a temperature of 298 K for NiO/ZSM-5 and D/C-0 = 0.084[g/(mg/l)] with a pH of 3.4 and a temperature of 298 K for NiO/AlPO-5. In the experimental data, equilibrium adsorption models were introduced and their constants were calculated. The equilibrium adsorption data on NiO/ZSM-5 were well matched to the Freundlich model at 298 K and 325 K, and Temkin model at 342 K and 353 K. For the NiO/AlPO5 adsorption data, the Temkin model was the best model showing strong adsorption interactions of asphaltene and adsorbent. The adaptive neuro-fuzzy interference system (ANFIS) was also used to model and predict the amount of asphaltene adsorbed by the proposed nanocomposites. ANFIS designed by triangular-shaped membership functions with three nodes and first-order polynomial Sugeno type FIS was the optimal structure and gave R-2 = 0.9999 and R-2 = 0.9996 for train and test data, respectively. Finally, Monte Carlo algorithm was used for sensitivity analysis on the input variables which is necessary for process optimization. Results demonstrated that D/C-0, pH, and temperature have the highest effect on asphaltene removal by nanoparticles.",15,17,1
Other topics ,,"Jafarpour, Hamed; Moghadasi, Jamshid; Khormali, Azizollah; Petrakov, D. G.; Ashena, Rahman",Increasing the stimulation efficiency of heterogeneous carbonate reservoirs by developing a multi-bathed acid system,Carbonate reservoir; Emulsified acid; Heterogeneous reservoir; Matrix acidizing; Stimulation,,"Matrix acidizing is a common practice in the oilfield for minimizing formation damage through dissolution of the reservoir rocks and making appropriate wormholes. For obtaining the highest performance in the acidizing and stimulation treatments, the injecting fluid should be placed in the damaged zones of the reservoir layers, after which the easy flowback could fully improve the formation damage. In mull-layered oil reservoirs the fluid diversion becomes of paramount importance where preferential flow paths are adopted in most of the stimulation fluid and the zones, which have the lower values of the rock permeability, remain untreated. We develop an optimal multi-bached acid system in two steps by determining the diverter formulation and investigating the diverting characteristics of the acid system through core flood tests. The interfacial tension tests were conducted to determine the diverter (fluid packer) formulation. The effects of different concentrations and mixtures of organic acids, HCL and surfactant were investigated to find the most effective main batch (active batch) of the stimulation fluids. In the second experimental phase, the ability of the selected emulsified acid system as a fluid packer and diverter was investigated using the multi-bached acid system in a parallel core flood test. The results showed the efficiency of the emulsified acid system in diverting the second batch (active batch) of the stimulation fluid from the core with the higher permeability to the lower permeability one. We find that the developed multi-batch acid stimulation system is an advantageous technique to use for stimulating the multilayered wells where there is a big difference between the permeabilities of the producing formations. The permeablity improvement in a more uniform manner in both the layers proves the efficiency of the developed stimulation system and emulsion which used as a diverter. In addition, we detect that the mixture of 15%HCL and surfactant (GF - 15 MPS) with 0.5% concentration has provides the optimal reaction rate and dissolution rate in comparison with other mixtures studied by increasing the neutralization time. In short, firstly, in this work the acid distribution rate mechanism (pathway) between the reservoir layers was investigated by simulating the executed actual matrix acidizing operation in the considered well. Then, The self-diverting emulsified acid SDEA (which can be used as a diverter) was developed. Moreover, the main batch of stimulation fluid was developed by analyzing different acid mixtures with various concentrations. Lastly, the efficiency of the developed multi-bached acid system was evaluated by conducing the core-flood experiment. The results show that the developed multi-batch acid stimulation system is significantly efficient for stimulation of the heterogeneous carbonate reservoirs where there is a big difference between the permeabilities of the producing formations so that the stimulation of both layers (with different permeability values) can be accomplished in a more uniform manner.",15,16,0
Other topics ,,"Yuan, Wei; Su, Xuebin; Wang, Wei; Wen, Lei; Chang, Jiangfang",Numerical study of the contributions of shock wave and detonation gas to crack generation in deep rock without free surfaces,Explosive blasting; Shock wave; Detonation gas; Discrete element method; Decoupling charge; Crack propagation,DAMAGE; MODEL,"Explosion gas pressure, combined with the action of an explosive stress wave, has a significant effect on the production and propagation of cracks in deep rock without a free surface. Thus, it is necessary to investigate the corresponding fracturing mechanisms and contributions of the shock wave and detonation gas towards inducing rock damage during blasting. In this work, the rock stratum is simplified as a square model with a circular borehole at its centre and modelled as a particle assembly based on the discrete element method. The shock wave is simulated as a time-varying pressure applied to the particles of the borehole. The action of the detonation gas is imitated as a quasi-static pressure on the fractures connected with the blasthole. To distinguish the role of the detonation gas in the formation and development of cracks, two primary simulation scenarios are studied: first, both the shock wave and detonation gas are simultaneously considered to simulate the blasting-induced rock damage; second, only the explosive stress wave is considered in rock blasting. Moreover, the coupling charge and decoupling charge are simulated in each scenario. In particular, based on the undirected graph theory, the authors present a new approach to efficiently determine the fracture clusters connected to the blasthole at each time-step to apply the quasi-static loads on the cracks. The results show that the shock wave plays a major role in crushing the rock near the wall of the blasthole and manufacturing a few primary radius cracks further away from the blasthole, whereas the detonation gas further extends the fractures to increase the crushed area (the additional stress caused by detonation gas is greater than the tensile strength of the rock) or separates the already formed rock fragments to increase the aperture of the cracks (the additional stress caused by the detonation gas is less than the tensile strength of the rock).",14,14,12
Other topics ,,"Shi, Wenrui; Wang, Xingzhi; Zhang, Chaomo; Feng, Aiguo; Huang, Zisang",Experimental study on gas content of adsorption and desorption in Fuling shale gas field,Shale gas; Gas content; Isothermal adsorption experiment; Desorption experiment; Carbon isotope; Fuling shale gas field,WUFENG-LONGMAXI FORMATIONS; METHANE ADSORPTION; BARNETT SHALE; SICHUAN BASIN; MARINE; COAL,"Shale gas mainly exists in organic-rich shale in the form of free gas and adsorbed gas. Shale gas content has a direct impact on the productivity and life of the gas well, and is also an important indicator for areal selection and reservoir evaluation. Through the study of gas content experiments of shale gas, we can better guide the exploration and development of shale gas. According to the isothermal adsorption and desorption experiments of Wufeng-Longmaxi Formations in Jiaoshiba block of the Fuling shale gas field in Sichuan basin, China, 7 core samples from isothermal adsorption experiment and 30 core samples from desorption experiment were analyzed. The experimental results show that the isothermal adsorption experiment is an effective way to obtain Langmuir Volume (VL) and Langmuir Pressure (PL). The total gas content obtained from shale desorption experiment in the drilling site is mainly adsorption gas content, and the free gas content is relatively small. The desorption rate is different in different desorption stages, and the samples with higher total organic carbon (TOC) content have faster desorption rate and higher total desorption gas content. The carbon isotope value of methane gradually increases with the increase of desorption time. The results of methane isotope analysis in the desorption experiment are compared with the results of carbon isotope monitoring in the producing process. The findings reveal that after years of development in Jiaoshiba block of the Fuling shale gas field, the methane isotope in gas wells has basically remained unchanged, and the current gas production should be dominated by free gas.",14,14,7
Other topics ,,"Aulia, Akmal; Jeong, Daein; Saaid, Ismail Mohd; Kania, Dina; Shuker, Muhannad Taleb; El-Khatib, Noaman A.",A Random Forests-based sensitivity analysis framework for assisted history matching,Global sensitivity analysis; Random forests; Assisted history matching; Genetic algorithms; Waterflooding,VARIABLE SELECTION; MODELS,"Sensitivity analysis is typically required to screen unwanted history matching parameters so that computational cost can be reduced. Random Forests is a well-known statistical learning tool that maps a list of input parameters onto a predicted response. A constructed Random Forests model ranks these input parameters efficiently even for highly nonlinear data. The aim of this study is to investigate the capability of Random Forests in assisted/automatic production history matching in reservoir engineering. A history matching case study has been chosen to rigorously compare the capability of Random Forests and one-parameter-at-time (OPAT) in sensitivity analysis. The capability of Random Forests as a sensitivity analysis tool was investigated and compared with OPAT. By implementing the optimal number of decision trees, which the Random Forests' configuration parameters, and the appropriate design of experiments method Fractional Factorial Design (FFD), the Random Forests-based history matching results have shown to be relatively better than OPAT-based results in this case. Here, Random Forests combined with FFD helped in improving the average error by 23.1%, along with the reduction of the standard deviation of errors by 28.9% relative to OPAT. Combining Random Forests with FFD is relatively better than OPAT because of the rigorous permutation tests of each parameter. In addition, this combination requires only 16 samples, where OPAT requires 21 samples. The combination of Random Forests and FFD as a sensitivity analysis tool successfully selected the top parameters which are horizontal permeability-related. Such parameters are well known in their direct relationship with water production as described by the well-known fractional flow theory. To conclude, this study found there is a strong indication that Random Forests can be a more reliable sensitivity analysis tool in production history matching, given the right configuration and design of experiments strategy.",14,14,6
Other topics ,,"Miao, Wenjuan; Li, Xiangguo; Wang, Yingbin; Lv, Yang",Pyrolysis characteristics of oil-field sludge and the comparison of kinetic analysis with two representative methods,Oil-field sludge; Pyrolysis kinetics; Coast-Redfern method; Flynn-Wall-Ozawa method,SOLID HEAT CARRIER; SEWAGE-SLUDGE; THERMAL-ANALYSIS; FLUIDIZED-BED; COCOMBUSTION; RECOVERY; BIOMASS; FTIR; ASH,"The pyrolysis of oil-field sludge (OS) has the appeal of resource recovery for this kind of waste disposal. In this paper, we investigate the pyrolysis kinetics of OS with Coast-Redfern (CR) and Flynn-Wall-Ozawa (FWO) methods in a wide temperature range (305-1223 K). The pyrolysis process of OS mainly includes light organics vaporization (Stage-2), middle and heavy organics and carbonates decomposition (Stage-3), coke reduction and other inorganics decomposition (Stage-4). The kinetic analysis manifests that Stage-2 meets well with the reaction order mechanism, and the reaction order (n) is 2 and in the range of 1.3-1.9 obtained by CR and FWO, respectively. The divergence of the two methods mainly appears in Stage-3, where E-a calculated by FWO method is much higher than that by CR method. CR method gives D-1 model for this stage, while FWO method picks D-3 model to describe this stage. The simulation plots indicate that the results of CR method are more credible. As for Stage-4, both methods select G(alpha) = alpha as the mechanism, but CR method performs better agreement and a smaller discrepancy than FWO method does. Thus, FWO method is considered less accurate for OS analysis.",14,14,5
Other topics ,,"Li, Yuwei; Weijermars, Ruud",Wellbore stability analysis in transverse isotropic shales with anisotropic failure criteria,Transverse isotropy; Borehole stability; Shale; Breakdown pressure; Collapse pressure,BOREHOLE; MODEL; PRESSURE,"The stress concentrations in the wall of a horizontal well in transversely isotropic shale are quantified and the stable mud weight window is established using a modified Hoek-Brown failure criterion. The upper margin of the safe drilling window is assumed due to the tensile breakdown pressure, which is computed with an anisotropic failure criterion considering the tensile strength and degree of anisotropy of the shale rock. Shear failure occurs at the lower boundary of the safe drilling window and is computed observing the rock's compressive strength anisotropy. The results show that when the degree of tectonic in-situ stress anisotropy increases, the safe pressure window between the tensile breakdown and shear collapse pressures decreases. We suggest that the narrowing of the safe drilling window as compared to isotropic cases may explain the increased occurrence of wellbore instability when drilling in shale. When the anisotropy of the elastic moduli increases further, both the breakdown pressure and collapse pressure decrease. Consequently, the range of recommended mud weights in the window for stable wellbores quickly narrows. Sensitivity analyses of the Poisson's ratio anisotropy effect on the breakdown pressure and collapse pressure indicate that the influence of Poisson's ratio anisotropy on borehole stability is very limited. The opposite holds for the Young's moduli, which are key factors contributing to narrowing of the safe drilling window when these moduli become more anisotropic.",14,15,4
Other topics ,,"Romanova, Yuliya N.; Maryutina, Tatyana A.; Musina, Natalya S.; Yurtov, Evgeny, V; Spivakov, Boris Ya",Demulsification of water-in-oil emulsions by exposure to magnetic field,Demulsification; Water-in-oil emulsion; Permanent magnetic field; Electromagnetic field; Separation of water,,"The influence of various types (permanent magnetic and electromagnetic fields) and parameters of magnetic treatment (induction value, time, temperature) on the efficiency of demulsification of water-in-oil emulsions in dynamic mode was studied. The objects studies were samples of commercial emulsions obtained from oil production facilities, differing in their composition and properties. The experimental data showing the possibility of separation of the aqueous and oil phases of commercial emulsions of different composition and water content by magnetic treatment are presented. It was found that both a permanent magnetic field and an electromagnetic field contribute to the demulsification of emulsions without the use of demulsifiers (the content of water in oil after magnetic treatment is less than 1 wt %). As a result of exposure of water-in-oil emulsion samples to permanent magnetic and electromagnetic fields with an induction of 0.3-0.6 T, up to 99% of water contained in the original sample was separated.",14,15,2
Other topics ,,"Zhou, Chao; Wu, Xiaodong; Zhang, Tongyi; Zhao, Xu; Gai, Shaohua; Xiang, Huizhu",Dynamic analysis for two-phase vortex flow and optimization of vortex tools to unload liquid from gas wells,Gas well; Two-phase vortex flow; Vortex tool; Unload liquid; Dynamic analysis; Optimization,PRESSURE-DROP; PREDICTION; MODEL,"Vortex drainage gas recovery is a new technology to unload liquid from gas wells. However, its operating mechanism and efficiency are still not clearly understood, the dynamic analysis model in the wellbore two-phase vortex flow is still lacking. In this study, the forces of the liquid film in the wellbore gas-liquid vortex flow are analyzed based on the two-phase fluid dynamic theory. A dynamic analysis film model for prediction of the pressure drop in the wellbore two-phase vortex flow and the optimal helical angle of vortex tools is established. Besides, the physical simulation experimental facilities were set up and the wellbore two-phase vortex flow was obtained. Various parameters with vortex tools, including the wellbore pressure drop, the operating envelope and the critical flow rate, were examined. The influences of structure parameters of vortex tools on the drainage effect were analyzed. These structure parameters include the flow section of the flow channel, the leak-tightness around the flow channel and the helical angle. The vortex tool which has the best drainage effect was chosen and tested, and the extent of reduction of the critical flow rate with the optimal vortex tool was determined. Then, a liquid loading gas well in the field was chosen. Vortex tools were optimized and used in the wellbore of the gas well. The dynamic analysis model is verified by the experiment and field test. The results show that the dynamic analysis model of the liquid film in the wellbore two-phase vortex flow is reasonable. The effectiveness of vortex tools can be improved by enhancing the leak-tightness on both sides of the flow channel and reducing the flow section of the flow channel. After installing the optimal vortex tool, the wellbore pressure drop decreased by about 9.6%, the liquid flow rate increased by about 12.4% and the critical flow rate decreased by about 20%. The helical angle of the vortex tool has an optimal value, which can be calculated by using the dynamic analysis model. Research results may provide theoretical guidance for the optimization and design of vortex tools.",14,14,1
Other topics ,,"Trippetta, F.; Geremia, D.",The seismic signature of heavy oil on carbonate reservoir through laboratory experiments and AVA modelling,Heavy oil; Unconventional oil; Carbonate reservoir; Petrophysical properties; AVA\AVO modelling; Seismic properties; Laboratory experiments,ROCK-PHYSICS; COMPRESSIONAL WAVES; BITUMEN CARBONATES; VELOCITY; DISPERSION; POROSITY; SANDS,"The influence of unconventional oil on the petrophysical properties of carbonate rocks is of primary interest in petroleum science. In this work, we first provided a thorough petrophysical characterization in laboratory by measuring density, porosity, V-P and V-S of a bitumen carbonate reservoir rock outcropping in the Majella Mountain (Central Italy). The presence of bitumen stiffens the rock and causes an increases of the acoustic impedance (AI) and a strong decrease of the V-P/V-S ratio respect to brine saturation. On the contrary, lighter oil causes a decrease of the AI and a slight decrease of the V-P/V-S ratio in comparison with a saturation in brine. Then, we performed a Synthetic Amplitude vs Angles (AVA) modelling showing that through the AVA analysis, it is possible to recognize the type of fluid that saturates the analyzed carbonate reservoir rocks. We also observed that the increasing porosity plays a key role in the AVA response, by decreasing the bulk density and seismic waves velocities and increasing the amount of fluids that saturate the rocks. By applying our laboratory and modelling results to a public stacked seismic line we show that our results may help in recognize heavy oil directly from seismic data.",14,14,1
Other topics ,,"Feng, Cheng; Wang, Zhiwei; Deng, Xili; Fu, Jinhua; Shi, Yujiang; Zhang, Haining; Mao, Zhiqiang",A new empirical method based on piecewise linear model to predict static Poisson's ratio via well logs,Origin of abnormal variation of static Poisson's ratio; Piecewise linear model; Static Poisson's ratio prediction; Low permeability reservoirs,BRITTLENESS,"Fracturing often occurs in exploration and development of unconventional oil and gas. Hence, rock mechanical parameters, like Poisson's ratio are very important. However, they are very difficult to predict. In order to solve this problem, the low permeability reservoirs of Chang 8 Member, Yanchang Formation, Triassic, in western Ordos Basin, China, have been selected as the study area. Firstly, 18 typical core plunger samples from 12 wells were selected and the rock mechanical parameters were measured and analyzed, including the helium porosity, the static Young's modulus, the static Poisson's ratio and the compressional and shear wave velocity. Secondly, after analyzing the experimental data, an abnormal phenomenon was found, showing that when the porosity is higher than 7%, the reduction in speed of static Poisson's ratio with the increase of porosity is greater than that one found when the porosity is lower than 7%. Thirdly, from the perspective of rock deformation mechanisms, the origin of the above abnormal phenomenon is proposed, explaining that the deformation is influenced by grains, pores, clay and their contact relationship. When porosity is lower than 7%, it is mainly determined by pores and clay, while it is influenced by not only the two former factors, but also the connected grains when porosity is higher than 7%. Fourthly, based on the above origin, a new empirical method based on piecewise linear model with the boundary of porosity of 7% is proposed in order to predict the static Poisson's ratio through the well logs. Their correlation coefficient squares are 0.92 and 0.70 and their root mean square errors (RMSE) are 0.02 and 0.05 for the modeling and testing data respectively, which are much better than the values occurring in the linear model. In the field study and another study area, the predicted static Poisson's ratio and brittleness indices via piecewise linear models well match with the experimental results, exhibiting a better effect of the application. This study provides a new idea and feasible solution for the static Poisson's ratio prediction and is of critical importance for well design and prediction of formation fracturing.",14,14,0
Other topics ,,"Fang, Huihuang; Sang, Shuxun; Liu, Shiqi",Establishment of dynamic permeability model of coal reservoir and its numerical simulation during the CO2-ECBM process,CO2-ECBM; Porosity; Permeability; Numerical model; Shrinkage and swelling; Effective stress,METHANE RECOVERY; SUPERCRITICAL CO2; EVOLUTION; DEFORMATION; SORPTION; FLOW; DISPLACEMENT; INJECTION; FRACTURE; QINSHUI,"The permeability evolution during the CO2-ECBM process is the key factor affecting the CH4 production. Therefore, it is necessary to clarify the evolution law and its influencing factor of the matrix-permeability (M-P) and fracture-permeability (F-P). The evolution model of the M-P and F-P was derived by analyzing the change of the matrix shrinkage and swelling and the effective stress. Furthermore, the stress field model and seepage field model were derived, and the numerical simulation of permeability evolution was carried out in COMSOL software. The results show that the change of the effective stress caused by the pressure relief and the CO2 pressure injected, and the change of the matrix shrinkage and swelling are the key factors affecting the permeability. Under different CH4 production conditions, the M-P and F-P have the same evolution law, and the F-P is greater than the M-P at the same location and time. The increase of CO2 pressure injected will improve the variation range of permeability, which is more obvious near the injection well (IW) than that near the production well (PW), and the downtrend of permeability is more obvious. When CH4 is directly mined, the permeability gradually increases with the production time, and the closer to the PW, the higher the permeability. During the CO2-ECBM process, the permeability near the IAN gradually decreases, while the permeability near the PW first increases and then decreases. The permeability evolution during the CO2-ECBM process can be divided into three stages according to the difference between M-P and F-P, and the change of reservoir permeability.",13,15,11
Other topics ,,"Wei, Qiang; Li, Xianqing; Hu, Baolin; Zhang, Xueqing; Zhang, Jizhen; He, Yukai; Zhang, Yachao; Zhu, Wenwei","Reservoir characteristics and coalbed methane resource evaluation of deep-buried coals: A case study of the No.13-1 coal seam from the Panji Deep Area in Huainan Coalfield, Southern North China",Coal reservoir characteristics; Coalbed methane resource; Deep-buried coals; Favorable area evaluation; Panji Deep Area; Huainan Coalfield,PORE-STRUCTURE CHARACTERIZATION; GAS CONTENT; POTENTIAL EVALUATION; ADSORPTION CAPACITY; BASIN; EVOLUTION; SYSTEM; IMPACT,"The Panji Deep Area in Huainan Coalfield, Southern North China is a newly discovered deep coal-bearing block with abundant coalbed methane (CBM) resources. To date, systematic geological studies regarding CBM reservoir in this region are still deficient, thereby seriously hindering the further exploitation and utilization of CBM in Huainan Coalfield. Results indicate that No.13-1 coal seam in the Panji Deep Area has good material conditions for CBM accumulation and preservation. All the coal samples from the No.13-1 coal seam are medium ash and medium-high volatile bituminous coals (R-o,(ma)x, 0.72-0.82%), which have different proportions of macerals and minerals. Pore structure and morphology analyses indicate that No.13-1 coal samples have various pore types and complex pore structures. Among them, the ink-bottle shaped pores are mainly observed with a pore size diameter of 4 nm. The gas content of No.13-1 coal samples is 16.11-21.83 m(3)/t (avg. 18.16 m(3)/t), which is strongly affected by the effective thickness of coal reservoir, reservoir pressure and temperature. Gas content is significantly positively correlated with burial depth, reservoir pressure, and temperature below 700 m, 6 MPa, and 34 degrees C, respectively. However, the upward trend tends to be constant after these demarcation points. Numberous micropores hold the retention capacity of coal matrix to methane molecules, thus the residual gas content increases along with the volume and surface area of micropores. By contrast, the correlations between gas content and coal thickness and roof thickness are not obvious. The total CBM resource of No.13-1 coal seam is approximately reserve of 205.36 x 10(8) m(3). Moreover, the total CBM resources in the northern and southern parts of the Panji Deep Area are 73.83 x 10(8) m(3) and 131.53 x 10(8) m(3), respectively. On the basis of multi-level fuzzy model and the evaluated factors, the most favorable areas for CBM development of the No.13-1 coal seam were predicted to be around Zhutuan and south Gugou town in the Panji Deep Area.",13,14,8
Other topics ,,"Zheng, Da; Wang, Wendong; Reza, Zulfiquar",Pore-network extraction algorithm for shale accounting for geometry-effect,Extracted pore-network model; Geometry characterization; Complex connectivity between pores; Shale,POROUS-MEDIA; SPACE; PREDICTION; RECONSTRUCTION; IMAGES; VOLUME; WELLS; FLOW,"Extracted pore-network modeling is an efficient and reliable way to provide a platform for mathematical simulation of fluid flow in porous media and predicting the transport properties. However, the existing algorithms for pore-network extraction have deficiencies in capturing the unique features of shales, including the geometry information and the complex connections between adjacent pore bodies. The newly developed method, based on the maximal-ball algorithm, proposes a novel and enhanced algorithm for the classification of pore bodies and throats. The extremely small pores, composed by only several voxels, can be captured by the new method. We capture the pore-throat geometry by characterizing the cross section of each maximum inscribed sphere connecting the two adjacent pore bodies; the pore-body geometry is characterized using the locally largest maximum inscribed sphere and the overlapping ones. The novel algorithm takes into account the complex connection between the adjacent pore bodies in determining the pore-throat size, where the flow capacity is maintained. A Marcellus shale core sample is used to validate our new method. The core sample is scanned using scanning electron microscope with the resolution of 4 nm, and the three-dimensional reconstruction of the porous media is built. We extract the pore-network model based on the three-dimensional reconstruction and analyze the statistic of the properties, like the distribution of pore size and geometry factor. The pore structures are quantitatively compared with the structures extracted by the previous maximal-ball method. The results show that our new method can capture more extremely small pores than the previous method and the classification of pore throats and bodies is more reasonable. So, the newly developed method is more reliable to extract physically realistic pore networks.",13,13,5
Other topics ,,"Hu, Yongquan; Zhao, Jin; Zhao, Jinzhou; Zhao, Chaoneng; Wang, Qiang; Zhao, Xing; Zhang, Yan",Coiled tubing friction reduction of plug milling in long horizontal well with vibratory tool,Coiled tubing; Mechanical friction; Extended-reach horizontal well; Shale gas; Vibratory tools; Plug-milling,REDUCING TECHNOLOGIES; MODEL,"With the rapid increase in the exploitation of shale reservoirs in the Sichuan province of China, the demand for long horizontal wells for contacting reservoirs has also significantly expanded. With increasing horizontal sections, the coiled tubing (CT) penetration depth and efficiency of the surface weight transferred to the weight-onbit (WOB) downhole are limited by the friction between the CT and wellbore. Plug milling with CT has become less efficient, and the final bridge plugs close to the bottom cannot be removed. Therefore, an experiment is conducted to study the effects of the pump rate on the vibration amplitude of the axial and radial directions, vibration frequency, and pressure difference. An improved tubing force analysis model is used to study the effect of a vibrator with different pump rates and friction coefficients on the CT surface weight, maximum set-down force, maximum pickup force, CT lockup depth, and maximum WOB of different plugs in well wx202 of the Wei Yuan shale block. The calculated data exhibit strong agreement with the real-time data collected from previous CT operations. The simulated results are used to solve the problems faced when milling the final four plugs at the end of a long horizontal section in well wx202. The results indicate that the amplitude variation in the radial vibration at both ends of the hydraulic oscillator is greater than that in the axial direction under the same pump rate. The optimized flow rate for the vibrator is 8.33 L/s. The use of a vibrator can greatly reduce the friction and transfer that are sufficient for a WOB downhole.",13,13,4
Other topics ,,"Klyuchnikov, Nikita; Zaytsev, Alexey; Gruzdev, Arseniy; Ovchinnikov, Georgiy; Antipova, Ksenia; Ismailova, Leyla; Muravleva, Ekaterina; Burnaev, Evgeny; Semenikhin, Artyom; Cherepanov, Alexey; Koryabkin, Vitaliy; Simon, Igor; Tsurgan, Alexey; Krasnov, Fedor; Koroteev, Dmitry",Data-driven model for the identification of the rock type at a drilling bit,Directional drilling; Machine learning; Rock type; Classification; MWD; LWD,,"Directional oil well drilling requires high precision of the wellbore positioning inside the productive area. However, due to specifics of engineering design, sensors that explicitly determine the type of the drilled rock are located farther than 15m from the drilling bit. As a result, the target area runaways can be detected only after this distance, which in turn, leads to a loss in well productivity and the risk of the need for an expensive reboring operation. We present a novel approach for identifying rock type at the drilling bit based on machine learning classification methods and data mining on sensors readings. We compare various machine-learning algorithms, examine extra features coming from mathematical modeling of drilling mechanics, and show that the real-time rock type classification error can be reduced from 13.5% to 9%. The approach is applicable for precise directional drilling in relatively thin target intervals of complex shapes and generalizes appropriately to new wells that are different from the ones used for training the machine learning model.",13,13,4
