Cluster Level 1,Cluster Level 2,AF,TI,DE,"ID",AB,TC,Z9,U1
Fracture,Hydraulic Fracture,"Stopa, Jerzy; Mikolajczak, Edyta",Empirical modeling of two-phase CBM production using analogy to nature,Coal bed methane; Mathematical modeling; Production forecasting; Declines curves; Logistic equation; Lotka-volterra model,COALBED-METHANE-RESERVOIR; WATER; GAS; PERMEABILITY; EXPLORATION; PERFORMANCE; SIMULATION; STABILITY; WELLS; SEAMS,"Acquaintance of production changes is crucial to successful production forecasting of all reservoir types. However, the performance prediction of CBM is very complex due to its specific production behavior. In the case of the coalbed methane formations two-phase flow, which is caused mainly by hydraulic fracturing process occurs. Discussed production system is more complicated than single-phase flow and finding the relationship between produced gas and produced water is required. In this paper, we propose a novel mathematical model for two-phase flow phenomena in CBM reservoirs. The proposed model uses analogies to natural competition processes and is based on the Lotka-Volterra model, which is one of the most popular populations dynamics model. We implement set of two logistic equations with additional term for the purpose of gas and water production forecasting and modeling their declines curves. This set of two ordinary differential equations was originally used to model dynamics of populations, which compete to each other. Both interspecies and intraspecies interactions are considered in the proposed mathematical model. The developed model was validated by some simulated and field examples. The proposed model was firstly used to match the production history data (gas and water flow rates) in order to estimate the model parameters. These parameters were then used to predict the two-phase CBM production. The obtained results show a good match between the production data and created decline curves based on the proposed model. Therefore, the developed model can be used as a helpful tool in predicting the CBM two-phase production.",2,3,0
Fracture,Hydraulic Fracture,"Osiptsov, A. A.; Boronin, S. A.; Zilonova, E. M.; Desroches, J.",Managed Saffman-Taylor instability during overflush in hydraulic fracturing,Hele-Shaw cell; Hydraulic fracturing; Saffman-Taylor instability; Yield stress; Bingham fluid; Proppant transport; Fingering; Slumping; Shale gas fracturing; Fracture,YIELD-STRESS FLUIDS; HELE-SHAW CELL; NEWTONIAN SLURRY; SUSPENSION FLOW; DISPLACEMENT; PLACEMENT; MECHANICS; MODEL,"Overflushing is a common practice in multistage completions of horizontal wells in unconventional formations. It consists in displacing the suspension by a thin fluid, away from the wellbore and into the fracture. It can, however, overly displace proppant and leave a significant portion of the fracture unsupported near the wellbore, or trigger gravity slumping, again leaving unpropped area near the wellbore. That unpropped area can then close during production, damaging the performance of the fracture. A novel modeling approach was investigated to gain insight into the overflush process and determine secure bounds for maintaining the fracture performance. From a fluid mechanics viewpoint, overflushing is the displacement of a Hershel-Bulkley fluid by a power law fluid in a Hele-Shaw cell, leading to Saffman-Taylor instability at the fluids interface. Whereas most hydraulic fracturing simulators use power-law rheology model, we used a novel numerical approach accounting for the yield-stress behavior of the slurry. Using the lubrication approximation, we derived a model, which includes transport equations for fluid volume fractions and a nonlinear elliptic equation for pressure with mixed-type boundary conditions. Validation was previously performed against three sets of experiments in Hele-Shaw cells, comprising gravitational slumping and displacement of fluids with fingering. Based on fracture mechanics, we analyzed how large a portion of the fracture may be left unsupported before it is severely pinched during drawdown. A parametric study was performed on the displacement of the yield-stress slurry by the overflushing fluid. Qualitatively, when fingers of the overflushing fluid can be created at the overflush/slurry interface, large slurry pillars are preserved in the near-wellbore area, which may keep the fracture open. Three main scenarios of fluids distribution are identified and classified in terms of the oveflush fluid-to-slurry viscosity ratio.: (i) the slumping-dominated regime, where light clean overflush fluid goes on top of sedimenting heavy proppant-laden suspension (xi greater than or similar to 0.1), (ii) an intermediate scenario of slumping combined with fingering (xi similar to 0.01), and, finally, (iii) a pure fingering-dominated scenario, when the slurry viscosity is high (xi < 10(-3)). The third scenario minimizes the geomechanical risks of overflushing by providing tiny fingers that are unlikely to be pinched out during fracture closure.",2,2,0
Fracture,Hydraulic Fracture,"Silva-Lopez, Dan; Solano-Barajas, R.; Turcio, M.; Vargas, R. O.; Manero, O.; Balankin, A. S.; Lira-Galeana, C.",A generalization to transient bilinear flows,,,A set of analytical solutions to transient pressure and double-porosity (bilinear) flows in the Cartesian domain for constant and variable flow rated wells having hydraulic fractures are presented. Both finite and infinite-fracture reservoir systems with transient linear-flows for the fracture and the formation in wells intercepted by a finite-conductivity vertical fracture are considered. A new method to obtain Laplace-transformed solutions for bilinear flows leading to predictions of new regions of flow behavior is presented. The accurate match of measured production data of a hydraullicaly-fractured well in northeast Mexico using the proposed solutions shows the adequacy of the new approach.,2,2,0
Fracture,Hydraulic Fracture,"Jadoon, Quaid Khan; Roberts, Eric M.; Henderson, Robert A.; Blenkinsop, Thomas G.; Wust, Raphael A. J.","Mineralogical variability of the Permian Roseneath and Murteree Shales from the Cooper Basin, Australia: Implications for shale properties and hydrocarbon extraction",Shale gas; Roseneath; Murteree; Brittleness; Plasticity; Cooper Basin,SOIL; MODEL; CLAY,"Brittleness and plasticity indices in hydrocarbon reservoirs are calculated to understand how rocks behave under stress, and for assessing the fracturing performance of clay-rich shale reservoirs and assessing borehole stability. Evaluating shale plasticity/brittleness requires careful analysis of clay mineral composition in target shales and the development of fracking strategies for optimal shale stimulation. Here we report on the mineralogical variability of two Permian lacustrine shale units, the Roseneath and Murteree shales in the Cooper Basin, Australia, that are considered to have potential as unconventional hydrocarbon producers. The study involved a combination of X-ray diffraction, scanning electron microscopy and petrophysical modelling of the Roseneath and Murteree shales in order to obtain a better understanding of the compositions and microfabrics of these two units. This is part of a larger investigation of the shale gas potential of these two units in the Cooper Basin, and the results presented here may ultimately lead to improved reservoir stimulation techniques in both units. Core data has been integrated with wireline logging data to better identify brittle and plastic zones within the Roseneath and Murteree shales. Mineralogical analysis shows that both units are composed mainly of detrital quartz and clay/mica minerals with siderite cement. The clay mineral composition is dominated by illite/mica, and kaolinite in both units. However, based on the relative mineralogical differences between the two units, the Murteree Shale has more favourable brittle properties than the Roseneath Shale, and is considered to be more amenable to hydraulic fracturing for gas exploitation. However, the Roseneath Shale also has potential for gas stimulation, especially in intervals where siderite cement is prevalent.",2,3,1
Fracture,Hydraulic Fracture,"Norouzi, Peyman; Baghbanan, Alireza; Hashemolhosseini, Hamid",Effect of coupled triaxial stress-perforation on fracture mechanism and acoustic wave velocity of limestone,Perforation; Triaxial stress; P-Wave velocity; Fracture pattern; In-situ stresses,FORMATION DAMAGE; P-WAVE; TAGUCHI; PERMEABILITY; PENETRATION; EVOLUTION; GRANITE; ROCKS,"Perforation with shaped charges establishes the hydraulic communication between cased wellbore and reservoir. Higher DoP(1) is one of the most important goals of perforation. Performance of a perforation is greatly influenced by confining pressure, which was mostly anisotropic, around the target. Therefore, it is necessary to consider the triaxial confining pressure on the target to achieve the actual results. In this study, a new triaxial perforation machine designed and constructed to investigate the effect of anisotropic in-situ stress on the DoP and failure pattern of limestone targets. The number of tests was optimized by Taguchi's method and ANOVA(2) was used to determine the cross effect of the different combination of applied in-situ stresses on DoP. The ultrasonic P-wave velocity was measured before and after perforation under different conditions of anisotropic loading. The results show that the Measured DoP is more controlled by the off plane stresses (stresses normal to shooting axis) than the stress in the direction of penetration. The created fractures by perforation are more oriented along the maximum horizontal stress, which is less propagated around a hole with increasing the maximum to the minimum off plane stress ratio. The measured p-wave velocity showed that V-P increases along the perforation hole from the beginning of the hole toward the block boundaries. It was found the loading conditions control the V-P values along the shooting axis. In anisotropic loading mode, the velocity of P-waves in direction of the maximum stress was greater than minimum horizontal stress. In the isotropic loading condition, V-P values were same along the direction perpendicular to the firing axis.",3,4,1
Fracture,Hydraulic Fracture,"Tandon, Saurabh; Heidari, Zoya; Aderibigbe, Aderonke; Shi, Jingyu; Fuss-Dezelic, Tihana",A new method for mechanical damage characterization in proppant packs using nuclear magnetic resonance measurements,Mechanical damage; Proppant packs; Nuclear magnetic resonance; Measurements; Pore-size distribution; Fines,HYDRAULIC CONDUCTIVITY; NMR RELAXATION; POROSITY; FLUIDS,"Proppant performance can significantly affect the success of hydraulic fracturing treatments and production in unconventional plays. Performance of proppants can decrease rapidly by mechanical damage. Quantifying the impact of mechanical damage on proppant performance can be challenging either in the laboratory or in-situ condition. This paper introduces a new method based on Nuclear Magnetic Resonance (NMR) Transverse relaxation (T-2) measurements to characterize pore-size distribution in proppant packs. Quantifying the pore-size distribution in proppant packs enables enhanced evaluation of porosity and conductivity of proppant packs and possible mechanical damage to the packs. The objectives of this paper are (a) to evaluate the performance of this new NMR-based method for characterizing pore structure of the proppant packs, and (b) to isolate and quantify the mechanical damage in proppant packs due to generating of fines in the laboratory using this new NMR-based method. First, we prepared proppant pack test samples in three categories including (a) different types of proppants with different surface relaxivity, (b) mixture of proppants with different sizes, and (c) proppants undergone different levels of mechanical damage. We measured NMR response in proppant packs and quantified the impacts of proppant type, size, and mechanical damage on NMR T-2 distribution. Next, we used the fractional packing model to quantify the efficiency of packing of proppant mixture and to quantify the changes in porosity of proppant packs caused by variation in size and fraction of fines. Finally, we used Kozeny-Carman (KC) equation and modified Schlumberger Doll Research (SDR) equation to correlate the variation in T-2 distribution to the decrease in proppant pack permeability. Results showed that NMR T-2 distribution is sensitive to pore-size distribution in the proppant packs. The variable pore-size distribution was either a consequence of having a mixture of proppants with different sizes or different levels of mechanical damage. The impacts of fines on the pore-size distribution of the proppant packs was measureable, which is promising for the successful application of the introduced method for time-lapse quantification of generated fines. We also observed a measurable sensitivity of T-2 distribution to mechanical damage in the proppant packs, which enables quantifying the level of damage in proppants through quantifying pore structure in the proppant packs. The NMR T-2 measurements were, however, sensitive to the presence of paramagnetic materials such as iron in proppants. This sensitivity was more significant in cases where paramagnetic materials were distributed on the proppant surface. The proposed method is considered as an indirect measurement of pore structure and could potentially provide a quantitative assessment of the proppant pack conductivity both in the lab-scale and in-situ conditions. Improved assessment of proppant conductivity can help in enhancing the design and execution of fracture treatments for successful development of unconventional plays.",4,4,0
Fracture,Hydraulic Fracture,"Zhao, Hongbo; Li, Zhen; Zhu, Changxing; Ru, Zhongliang",Reliability analysis models for hydraulic fracturing,Hydraulic fracturing; Uncertainty; Reliability analysis; First order reliability method,PRINCIPAL STRESS; ELEMENT-METHOD; FLUID LAG; PROPAGATION; SIMULATION; ALGORITHM; DESIGN; SPREADSHEET; XFEM,"For many decades, hydraulic fracturing has been the technique most commonly used in the oil and gas industry to increase the productivity of low permeability reservoirs. However, much uncertainty remains when applying this technique, which can influence performance. It has proved difficult, for example, to evaluate the uncertainties inherent in traditional deterministic hydraulic fracturing models using classic analytical and numerical methods. Thus, in this study, we adapted reliability analysis to evaluate the performance of hydraulic fracturing including the length, width, and nature of a fracture when considering uncertainty. Random variables are assumed to follow a normal distribution, and the first-order reliability method (FORM) was used to calculate a reliability index for hydraulic fracturing based on Khristianovic-Geertsma-de Klerk (KGD) and Perkins-Kern-Nordgren (PKN) models. Reliability indexes obtained under different conditions show excellent agreement with Monte Carlo simulations, and indicate that use of this method provides an efficient and effective scientific approach for the uncertainty analysis of hydraulic fracturing. We also investigate and discuss the influence of elastic mechanical parameters of rock formations as well as in situ stress as random variables affecting the performance of hydraulic fracturing alongside various other factors that can influence this process, including rock tensile strength, injection rate and time. This analysis provides quantitative insights into the uncertainties that underlie hydraulic fracturing models and enables the identification of potentially influencing factors to reduce performance uncertainties. The results also show reliability analysis provides an appropriate solution for evaluation of uncertainty and can further improve the performance of hydraulic fracturing.",4,4,0
Fracture,Hydraulic Fracture,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun; Almansour, Abdullah",Numerical simulation study to understand the performance of RPM gels in water-shutoff treatments,,DISPROPORTIONATE PERMEABILITY REDUCTION; WELLS,"Disproportionate Permeability Reduction (DPR) is often used as a water-shutoff treatment in production wells when conventional solutions such as mechanical isolations are difficult to perform. Although this property has been well documented by different investigators, the performance of DPR treatments in field applications has varied between success and failure without understandable reasons. This work investigated the DPR performance in different scenarios to see when, where and at which conditions DPR treatments can give better results. Numerical simulation methods were used to simulate different scenarios happening in oil and gas fields such as five-spot pattern system and linear-system, with different number of layers, with and without crossflow. The possibility of using DPR treatment in hydraulically-fractured reservoirs was also investigated since many reports indicated that there is an increase in the water production for some oil and gas reservoirs after being hydraulically-fractured. Moreover, the physical reasoning behind the variations in the DPR performance for different scenarios has been extensively discussed. The results explored that the DPR performance was excellent in both of water-cut reduction and oil-recovery improvement when the flow regime was viscous dominated (viscous-gravity number < 0.1). On the other hand, when the flow regime was gravity dominated (viscous-gravity number > 10), the effective period of DPR treatment was a short-term remedy. Secondly, when the high-K layer is existed at the lower-zone of oil or gas reservoir, the reservoir would be a good candidate for the DPR treatment as compared with the reservoirs that have the high-K layer located at the upper zone. Furthermore, selecting the correct time to perform DPR treatments generally could have a significant role to mitigate water production. Finally, the dimensions of the treated fracture are the key components to get a successful DPR-treatment in the hydraulically fractured reservoirs.",5,5,0
Fracture,Hydraulic Fracture,"Olatunji, Kayode; Zhang, Jin; Wang, Dongmei",Effect of the rock dimension on surfactant imbibition rate in the Middle Member of Bakken: Creating a model for frac design,Oil recovery; Cores; Length; Surface areas; Imbibition; Model; Frac design,SHALE; WETTABILITY,"As an unconventional energy resource, the Bakken Formation has long been considered an important source rock for oil in the Williston Basin. The naturally fractured Bakken Formation consists of thin shale and silty carbonate sequences, capable of producing oil at economic rates when completed using hydraulically fractured horizontal wells. However, because of its low permeability and oil-wet characters, the primary recovery values are still low. As part of our effort to assess the potential for imbibition to recover oil from tight rocks, we performed spontaneous imbibition experiments using brine and surfactant for different dimensions of cores from the Middle Member of the Bakken Formation in North Dakota. The effect of length of the core on imbibition rate in the cores was measured for brine and surfactants. The purpose of this study is to create a model which can be basis for development of design of hydraulic fracturing of the formation. These cores from Bakken were silt stone, limestone, and shale interlayers in lithology. To the point of scaling the dimension of the core from laboratory to a field application, the large area of fluid contact will promote higher imbibition rate and faster oil recovery from the rock. Although oil recovery was low during brine imbibition into the oil-wet cores, alkali/surfactant solution recovered approximately 30-45% of the oil based on the laboratory results. We found higher oil recovery factor was achieved from surfactant imbibition more than just used brine. As would be expected, a given level oil recovery was reached faster in shorter cores than in longer cores in same diameters. The shorter core has a larger ratio of surface area to volume. A model which describes the relationship between Peak Oil recovery and surface areas for cores was derived.",5,5,1
Fracture,Hydraulic Fracture,"Liu, Wenzheng; Zeng, Qingdong; Yao, Jun",Numerical simulation of elasto-plastic hydraulic fracture propagation in deep reservoir coupled with temperature field,Deep reservoir; Hydraulic fracturing; Elasto-plasticity; Heat transfer; Cohesive zone model; Embedded discrete fracture model,FLUID-DRIVEN FRACTURES; MEDIA; ROCK,"With the increasing demand of oil and gas resource, the development of deep reservoir has become an inevitable trend. To investigate the coupled effects of rock elasto-plastic deformation, fluid flow and heat transfer in the process of hydraulic fracturing of deep reservoir, the mathematical model of elasto-plastic hydraulic fracture propagation is established based on cohesive zone model (CZM) and embedded discrete fracture model (EDFM). The constitutive equation incorporating thermal stress is derived by using Drucker-Prager yield condition and the associated flow law. Fluid flow in the fracture is modeled with lubrication theory. The thermal non-equilibrium theory is employed to describe the heat exchange between rock matrix and fluid in the fracture based on EDFM. The CZM is used as fracture propagation criterion. The rock deformation equation is solved by finite element method. The temperature field and fluid flow in the fracture are discretized by finite volume method. Due to the non-linearity of flow equation, the iterative method is used to solve the coupled problem of stress, pressure and temperature fields. A Triangular-PEBI (Perpendicular Bisector) dual mesh system is presented for numerical implementation. The numerical model is validated against with analytical solution and other methods in the literature. The results show the significance of accounting for elasto-plastic deformation and heat transfer when simulating hydraulic fracture propagation in deep reservoir.",5,5,5
Fracture,Hydraulic Fracture,"Wang, Fei; Pan, Ziqing; Zhang, Shicheng",Coupled thermo-hydro-chemical modeling of fracturing-fluid leakoff in hydraulically fractured shale gas reservoirs,Shale gas; Hydraulic fracturing; Water leakoff; Thermo-hydro-chemical coupling; Numerical simulation,PART I; BEHAVIOR; OIL; PRESSURE; OSMOSIS; FLOW; COAL,"Once the low-temperature, high-pressure and low-salinity water contacts the shale matrix through the hydraulic fractures during the treatment of hydraulic fracturing, both mass and energy transfer occur due to the significant temperature, pressure, saturation and salinity gradients. Although, many leakoff models have been published, none of the models coupled the transient fluid flow modeling with heat transfer and chemical-potential equilibrium phenomena. In this paper, a coupled thermo-hydro-chemical (THC) model based on the derivation of non-isothermal chemical-potential equations from Gibbs' free energy is presented to simulate fluid/heat flow behaviors during the leakoff process of hydraulic fracturing. The THC model takes into account a two-phase flow and a triple-porosity medium, which includes hydraulic fractures, organic and inorganic shale matrix. The simulation of fluid flow and leakoff with the THC model accounts for all the important mass and heat transfer processes occurring in fractured shale system, including fluid transport driven by convection, adsorption and diffusion, and heat transport driven by thermal convection and conductivity. The dynamic temperature, pressure, saturation and salt concentration profiles within fractures and shale matrix are calculated, revealing a multi-field coupled invasion region of fracturing-fluids during the treatment of hydraulic fracturing. In sensitivity analyses, cases with different initial reservoir temperature, pressure, saturation and brine salinity are considered. The impacts of the temperature, pressure, saturation and salinity gradients between the shale formation and the pumped fluids on the well injection and leakoff volumes during the treatment of hydraulic fracturing are investigated. Results show that although hydraulic pressure is the most factor which affects the fracturing-fluid leakoff behavior, the combination of chemical-osmosis, thermal-osmosis and capillarity still has a non-negligible influence on the fracturing-fluid leakoff. This study provides a better understanding of the mass and heat transport mechanism of water-based fracturing-fluids in shale gas reservoirs.",5,5,8
Fracture,Hydraulic Fracture,"Shan, Liqun; Guo, Boyun; Weng, Dingwei; Liu, Zhe; Chu, Henry",Posteriori assessment of fracture propagation in refractured vertical oil wells by pressure transient analysis,Refracturing; Oil; Wells; Fractures; Propagation; Assessment,,"Oil companies have realized that refracturing old wells is the more budget-friendly way to achieve cash flow than drilling and completing new wells in the down turn of the energy industry. But it has been seen that the refracturing technology does not always work equally well in all reservoir conditions. It is desirable to have a quantitative method for assessment of well refracturing design and operations. An analytical transient flow model was derived in this study to estimate the orthogonality between the old and new hydraulic fractures after refracturing. Pressure transient data from seven wells refractured in an oilfield in the southwestern China was analyzed with the model. The model implies that orthogonal fractures created in well refracturing treatments induce orthogonal reservoir linear flow in the stimulated reservoir volume. This fracture configuration can be identified by the unit slope of pressure derivative in the log-log diagnosis plot. The angle between fractures initiated from wellbore can be estimated using pressure transient data analysis technique with a log-log diagnostic plot, with extreme situations that merged or parallel fractures will show a half slope and orthogonal fractures will show a unit slope. Case studies of data from 7 wells show that orthogonal fractures were created in 3 wells, merging or parallel fractures were created in 1 well, and fractures with non-right angles were created in 3 wells. The actual well productivity data for the 7 wells are basically consistent with the expected trend implied by the estimated fracture configurations with an exception of one well. The reason is not clear and needs further investigations. More production data from refractured wells are required to further validate the technique.",6,6,0
Fracture,Hydraulic Fracture,"Wu, Rui; Deng, Jingen; Liu, Wei; Mao, Shaowen; Sun, Jin; Yan, Min; Li, Ming; Li, Yao",Numerical investigation of fluid injection into poorly consolidated geomaterial considering shear dilation and compaction,Fluid injection; Poorly consolidated geomaterial; Poroelastoplasticity; Cohesive zone model; Shear dilation; Compaction failure,CAM-CLAY PLASTICITY; HYDRAULIC FRACTURE PROBLEM; BOUNDING SURFACE MODEL; IMPLICIT INTEGRATION; LABORATORY EXPERIMENTS; UNCONSOLIDATED-SAND; SOIL; STRESS; FLOW; SIMULATION,"We present a fully coupled poroelastoplastic finite element model to simulate micro-fracture evolution, cornpaction failure and tensile fracture propagation during fluid injection into poorly consolidated geomaterial. The model includes shear dilation, strain hardening and fracture process zone with permeability evolution. We investigated the effects of geomechanics (stress anisotropy) and fluid injection (fluid rheology) on rock deformation and fracture behavior. Results indicate that fluid rheology dominate the rock failure. Pore pressure increase and water wedge effect can cause two kinds of shear dilation which are prior to tensile failure. The effect of compaction is significant to tensile fracture geometries, which differ from those under elastic and poroelastic conditions. The difference between shear band and compaction zone is the transition of fracture regime from the leak-off dominated to the storage dominated governed by fluid injection.",6,6,1
Fracture,Hydraulic Fracture,"Wang, Fei; Pan, Ziqing; Zhang, Yichi; Zhang, Shicheng",Simulation of coupled hydro-mechanical-chemical phenomena in hydraulically fractured gas shale during fracturing-fluid flowback,Fracturing-fluid flowback; Shale gas reservoirs; Hydro-mechanical-chemical model; Fracture closure; Chemical osmosis,PART I; IMBIBITION; PRESSURE; BEHAVIOR; BRINE; WELLS; COAL; OIL,"Fracturing-fluid flowback in hydraulically fractured gas shale is a complicated transport behavior involving hydrodynamic (H), mechanical (M) and chemical (C) processes. Although, many flowback models have been published, none of the models flly coupled the transient fluid flow modeling with chemical-potential equilibrium and fracture closure phenomena. In this paper, a coupled hydro-mechanical-chemical (HMC) model based on hydrodynamics, linear-elastic fracture mechanics, and chemical-potential equations is presented to simulate the fracturing-fluid flowback behavior in hydraulically fractured gas shale. The HMC model takes into account a gas-liquid two-phase flow and a triple-porosity medium, which includes primary hydraulic fractures, secondary induced fractures and shale matrix. The flowback simulation with the HMC model accounts for all the important processes in fractured shale system, including (1) water transport driven by hydraulic, capillary and osmotic convections, (2) gas transport induced by both hydraulic pressure driven convection and adsorption, and (3) fracture closure considered as an elastic deformation. The fluid transport, coupled with rock deformation, are described by a set of partial differential equations. The semi-implicit finite-difference method is used to solve these equations. The evolution of pressure, saturation, salinity and aperture profiles of hydraulic fractures, induced fractures and matrix is calculated, revealing the multi-field coupled flowback behavior in fractured gas shale. The sensitivity analysis is also performed to investigate the physiochemical properties of shale on the water load recovery and gas production rate during the fracturing-fluid flowback. The results indicate that the capillarity has the most effect followed by chemical osmosis and induced fracture closure. The sub-irreducible water saturation has the weakest effect. Moreover, the matrix-related physiochemical parameters cause opposite influences on water load recovery and gas production rate. While, the influence of induced fracture-related parameters on both water load recovery and gas production rate is consistent. Results from this study are expected to explain which is the predominant mechanism for fracturing-fluid retention and the inherent relationship between fracturing-fluid flowback and gas production for different initial physiochemical properties of shale.",6,6,12
Fracture,Hydraulic Fracture,"Zeng, Yan; Ning, Zhengfu; Wang, Qing; Sun, Hongliang; Huang, Liang; Ye, Hongtao",Gas transport in self-affine rough microchannels of shale gas reservoir,Shale; Roughness effect; Triple-effect permeability model; Lattice Boltzmann method; Permeability,LATTICE BOLTZMANN METHOD; FLUID-FLOW; SURFACE-ROUGHNESS; POISEUILLE NUMBER; PRESSURE-DROP; SICHUAN BASIN; FRACTURE; SIMULATION; MODEL; MICRO,"The matrix of shale gas reservoirs is always characterized by rough surfaces and the roughness of the topography significantly influences the gas flow characteristics. However, most existing models are based on smooth surface. Moreover, the roughness effect leads to a complex velocity distribution and can influence the apparent permeability through its own transport mechanism. In this study, a generalized lattice Boltzmann method with nonequilibrium extrapolation boundary conditions was developed to simulate the rarefied shale gas flow through nanochannels with rough surface. Fractal geometry was introduced to model the rough surface, and the roughness was characterized by two parameters, namely, relative roughness height and fractal dimension. Triple-effect permeability estimation model was adopted to calculate the apparent permeability accounting for multiple roughness characteristics including surface tortuosity, hydraulic tortuosity, and local roughness. Effects of fractal dimension, relative roughness, and tortuosity on velocity distribution were investigated. The effect of pressure and roughness characteristic parameters on the apparent permeability at different Knudsen numbers was also studied. The results showed that the influence of fractal dimension and relative roughness on the permeability was affected by the rarefaction effect. The roughness effect on gas flow behavior became more evident when associated with the enhanced rarefaction effect. Moreover, relative roughness was found to play a significant role in determining the permeability in the transient flow regime.",7,8,1
Fracture,Hydraulic Fracture,"Kim, Jihoon; Um, Evan Schankee; Moridis, George J.",Integrated simulation of vertical fracture propagation induced by water injection and its borehole electromagnetic responses in shale gas systems,Hydraulic fracturing; Shale gas; Electromagnetic geophysics; Coupled flow and geomechanics,HYDRAULIC-FRACTURE; POROSITY MATERIALS; RESERVOIR; FLOW; GEOMECHANICS; TOMOGRAPHY; FERROFLUID,"We analyze fracture propagation induced by hydraulic fracturing with water injection and examine their detectability with crosswell electromagnetic (EM) geophysical methods. For rigorous 3D coupled flow-geomechanical modeling, we employ a numerical method that can model failure by tensile and shear stresses, dynamic nonlinear permeability, dual continuum approach, and thermo-poro-mechanical effects. From numerical simulation, we find that the fracture propagation is not the same as propagation of the water front, because fracturing is governed by geomechanics whereas water saturation is determined by multiphase flow. At early times, the water front is almost identical to the fracture tip, suggesting that the fracture is mostly filled with the injected water. However, at late times, movement of the water front is retarded compared to fracture propagation, yielding a significant gap between the water front and the fracture top, filled with reservoir gas. During fracture propagation, the coupled flow-geomechanical models are transformed via a rock-physics model into electrical conductivity models. We employ a full 3D finite-element EM geophysical simulator to evaluate the sensitivity of the crosswell EM method to fracture propagation. It is shown that anomalous distribution of electrical conductivity is closely related to the injected water saturation, but not closely related to newly created unsaturated fractures. Our numerical modeling experiments demonstrate that the crosswell EM method can be highly sensitive to electrical conductivity changes that directly indicate the migration pathways of the injected fluid. Accordingly, the EM method can serve as an effective monitoring tool for monitoring the injected fluids during hydraulic fracturing operations.",7,7,2
Fracture,Hydraulic Fracture,"Guo, Chaohua; Li, Qianyao; Wei, Mingzhen","Pore structure characteristics of marine Silurian shales in the Sichuan Basin, China: Insights to reserve assessment and production design",Silurian shale; Pore structure; SEM-Imaging; Mineralogy analysis; Over-mature,ORGANIC-RICH SHALES; SOUTHERN SICHUAN; GAS-STORAGE; NORTHERN GERMANY; LONGMAXI SHALE; LOWER TOARCIAN; CLASSIFICATION; PERMEABILITY; HAYNESVILLE; MARCELLUS,"Due to shortage of conventional resources, tight/shale oil/gas reservoirs have become increasingly important in balancing the energy consumption in China. As the most important shale reservoirs in China, marine Silurian shales in the Sichuan Basin have received intensive investigation during recent years in the area of pore structure characterization and reserve assessment. However, no work has been conducted to compare the China shale plays with other mature shale plays in the North America using multiple experimental methods based on the mineralogy analysis and organic geochemistry. In this paper, pore structure, formation porosity, total organic carbon ( TOC), thermal maturity, and mineralogy of 36 samples in Longmaxi shale and 7 samples in Qiongzhusi shale have been investigated using multiple experimental methods. FIB-SEM imaging results show that Longmaxi shale gas reservoir include primary pores, residual intergranular pores, dissolution pores, and intergranular pores. The majority of the pores are distributed in residual intergranular pores, secondary dissolution pores, and intercrystalline pores, but less in primary intergranular pores. X-ray diffraction analysis shows that the clay minerals of Longmaxi shale reservoir mainly consist of illite and kaolinite, then followed by chlorite. The content of kaolinite is from 7.2% to 16.87%, and the average is 12.21%. The content of illite is from 8.03% to 26.8%, with the average of 16.1%. TOC tests show that most of the samples have their TOC more than 0.5%, which means Longmaxi formation has a potential to produce shale gas. Clay minerals mainly include quartz, K-feldspar, calcite, dolomite, anorthose, and pyrite. The quartz has the highest content value, followed by calcite, which are 29% and 22% average respectively. The content of pyrite and anorthose are less than 10%. The average content of brittle minerals of Longmaxi formation samples is 66% (> 50%), which is suitable for hydraulic fracturing. Thermal maturity tests show that Vitrinite reflectance of each sample is more than 2.0%, which indicates that it is high enough to generate shale gas in the formation. Comparing with other mature shale plays, the Longmaxi and Qiongzhusi shale plays have lower porosity and lower TOC than that of the U.S. shale plays, and the quartz content and thermal maturity are similar. The Qiongzhusi shale and Longmaxi shale are over-mature ( Ro> 2.5%) compared with U.S. shale plays. The results of this study will contribute to the formation characteristics understanding and reserve assessment of China shale plays. Also, it will facilitate the development of suitable and efficient production plan for China shale plays.",7,7,3
Fracture,Hydraulic Fracture,"Zhao, Jinzhou; Chen, Pengfei; Liu, Youquan; Mao, Jincheng",Development of an LPG fracturing fluid with improved temperature stability,Unconventional; Liquefied petroleum gas; Fracturing fluid; Crosslinking agent; Optimization,,"Continued exploitation of unconventional reservoirs using conventional hydraulic fracturing fluid technologies requires large volumes of water, which may lead to water resource shortage and environmental pollution problems. To mitigate these issues, we have developed a waterless fracturing fluid system, an LPG (Liquefied Petroleum Gas) fracturing fluid, which exhibits excellent rheological properties, at high temperatures. In order to develop this high-performance LPG fracturing fluid, two series of metal cross-linkers (aluminum cross-linkers and iron cross-linkers) were formulated. Crosslinking performance was examined via visual observation at room temperature and by rheological testing at raised temperatures. After optimizing the crosslinker formulation, the breaking performance and the regain permeability of the new LPG fracturing fluid were also examined. The new LPG fracturing fluid breaks almost completely at 90 degrees C and achieves an average regain permeability of 96.97% even at 25 degrees C, suggesting low damage in the field applications. A fracturing fluid with such good performance can satisfy the requirements of unconventional reservoir operations. Also, as far as we know, it is the first time that all of the important characteristics of an LPG fracturing fluid are reported.",7,7,8
Fracture,Hydraulic Fracture,"Liu, Guoqing; Ehlig-Economides, Christine",Practical considerations for diagnostic fracture injection test (DFIT) analysis,DFIT; Fracture closure; Hydraulic fracture design; Natural fracture; Pressure falloff analysis,,"The diagnostic fracture injection test (DFIT) provides a way to estimate parameters critical to hydraulic fracture design. Existing published models for before-closure and after-closure behaviors rely on assumptions, and failure to honor important realities leads to parameter estimation errors that could degrade hydraulic fracturing design. This paper is to illustrate an accurate way to estimate parameters from the DFIT data, and then discuss how these parameters should be used in the hydraulic fracture design, and at last offer an alternative DFIT design approach. Two fundamental concepts underlying the proposed methodology are the material balance before fracture closure and the diffusive flow in the formation after closure. Before closure analysis must correctly address abnormal leakoff behaviors and near well friction losses. Likewise, accurate permeability and pore pressure estimation requires correct accounting for the leakoff rate into the formation. Strict attention to material balance yields estimations for instantaneous shut-in pressure (ISIP) and perforation and tortuosity friction losses that may, in turn, avoid apparent very high net pressure and stress shadowing. This work also underscores the importance of understanding surface and downhole volumes and rates both in the DFIT design and in the analysis. Further, for the DFIT case with pressure dependent leakoff (PDL), the fracture design for the subsequent hydraulic fracturing treatment should use the apparent leakoff rate associated with the first closure trend instead of the leakoff rate associated with the last closure trend derived from a normal leakoff model. Two successive DFITs in the same perforation, the first treated with low injection rate and small volume and then the second with high rate and large volume, are proved to be a good practice to obtain reliable estimation of formation properties. This paper demonstrates that DFIT parameters have often been misused. With the proposed methodology, the interpretation will be more accurate and reliable for formation evaluation and hydraulic fracture design.",8,10,0
Fracture,Hydraulic Fracture,"Raef, Abdelmoneam E.; Kamari, Arash; Totten, Matthew; Harris, Dustin; Janssen, Kale; Lambert, Michael","The dynamic elastic and mineralogical Brittleness of Woodford shale of the Anadarko Basin: Ultrasonic P-wave and S-wave velocities, XRD-Mineralogy and predictive models",Shale; Brittleness index; Elastic properties; Mineralogy; Hydraulic fracturing,OKLAHOMA; VISCOSITY; SYSTEMS; ROCKS,"The recent advances in drilling and hydraulic fracturing technology rendered the Woodford shale of the Anadarko basin a prolific resource play producing gas and liquid hydrocarbons. Among the challenges facing improved economics, there is variable production from one well to another as well as from a completion stage to another due to the variability in facture gradient or brittleness index (BI) and the kerogen content. This investigation relies on laboratory ultrasonic P-wave and S-wave velocity in Woodford core samples to estimate BI based on the estimated elastic moduli. We modified a literature mineralogical brittleness index equation in order to take into account additional iron-rich minerals like pyrite, hematite, and iron oxides that are present in the Woodford shales, and also investigated the impact of total organic content (TOC) on the mineralogical brittleness index. Furthermore, a number of new reliable equations based on different elastic properties have been introduced in this study for the evaluation of the elastic BI, which is of significant importance in designing hydraulic fracturing in shale and tight reservoirs. In another panel of our study, the sensitivities of both mineralogical makeup of Woodford shale and elastic properties calculated -including density, acoustic impedance, Poisson's ratio, Young's modules, Lame's parameters-to the elastic brittleness index are examined. It was indicated that they have a positive effect on the prediction and can be employed in the respective predictive methods for the estimation of elastic BI. However, the analysis demonstrated that TOC has no considerable effect on mineral BI, at least in Woodford sample studied. A comparison between these newly developed predictive equations and the most commonly used methods for the prediction of elastic brittleness index available in the literature demonstrates that the new equations have a better performance in terms of both accuracy and simplicity. On comparing the BI prediction equation, with highest prediction quality ""Method 1"", that was developed based on ultrasonic elastic moduli with a corresponding equation based on sonic well-logs elastic moduli, Method1 was proven applicable to estimating BI based sonic frequency elastic moduli.",8,9,1
Fracture,Hydraulic Fracture,"Shen, Jian; Qin, Yong; Li, Yepeng; Yang, Yanhui; Ju, Wei; Yang, Chunli; Wang, Geoff","In situ stress field in the FZ Block of Qinshui Basin, China: Implications for the permeability and coalbed methane production",In situ stress; High-rank coal; Coalbed methane; Permeability; Gas and water production; Qinshui basin,EASTERN ORDOS BASIN; SHANXI PROVINCE; ORIENTATION; EXPLORATION; MAGNITUDE; RESERVOIR; PART; AREA; GEOMECHANICS; FRACTURES,"In situ stress affects reservoir permeability and stimulation, and thus coalbed methane (CBM) recovery. In this study, the in situ stress field measured from 238 CBM wells in the FZ Block of Qinshui Basin, China, was investigated. The vertical stress, horizontal maximum and minimum principal stress are 5.92-20.08 MPa, 8.03-41.75 MPa, and 5.38-21.24 MPa, respectively. The in situ stress magnitudes increase with burial depth of the coal seams. The FZ Block is dominated by reverse and strike-slip faulting stress regimes. Most of reverse fault stress regimes appear within burial depth less than 500 m, whereas normal and strike faulting stress regimes are deeper than 500 m. The relation between the coefficient of lateral stress and burial depth shows that shallow strata are characterized by horizontal stresses, whereas deep strata are generally hydrostatic pressures that approximately equal to the principal stresses. Low gas and high water production are associated with vertical hydraulic fractures, wherein the horizontal minimum principal stress is the minimum stress. High gas and low water production are associated with horizontal hydraulic fractures, wherein the vertical stress is the minimum stress. This results are attributed to the enhanced permeability of the coal seam and the communication with overlying or underlying aquifers because the minimum stress varies between vertical and horizontal minimum stress. The orientation of the horizontal maximum principal stress is -NEE-NE and is locally distorted by faults, which can be used to optimize the drilling, completion, and stimulation of CBM wells in the study area.",8,10,1
Fracture,Hydraulic Fracture,"Shovkun, Igor; Espinoza, D. Nicolas",Geomechanical implications of dissolution of mineralized natural fractures in shale formations,Stimulated reservoir volume; Shear failure; Mineral dissolution; Hydraulic fracturing; Acidizing,BARNETT SHALE; GAS-PRODUCTION; POROUS-MEDIA; PERMEABILITY; ROCK; BASIN; FLOW; NETWORKS; MODEL; COAL,"Organic shale reservoirs accommodate large amounts of hydrocarbons in extremely tight rock matrix. Slick water hydraulic fracturing and proppant placement is the most spread stimulating technology for this type of reservoirs. Some shale formations contain a fair amount of easily-dissolvable carbonates, which prompts shale acidizing as a potential method to increase reservoir permeability. Carbonates in shale formations can be present as a part of rock matrix or can be localized in natural fractures - so-called mineral veins. Previous studies investigated the effects of chemical dissolution within the matrix, implying that acidizing can etch the rock, open new conduits for flow, and increase fracture permeability after closure. This study rather focuses on the reservoir-scale geomechanical implications of chemical dissolution of mineral filling in natural fractures. We use a combination of elasto-plastic analytical methods, analogous thermo-elastic numerical solutions, and experimental results to elucidate the impact of veins dissolution on in-situ stresses. Analytical, numerical, and experimental results indicate that mineral dissolution of localized carbonate fractures leads to changes of local in-situ stresses. The direction of stress relaxation strongly depends on the orientation of mineralized fractures. Dissolution of near-vertical mineralized fractures contributes the most to decreases of effective horizontal stress and reduce stress shadow effects in multistage hydraulic fracture completions. Mineral dissolution, similar to pore pressure depletion or thermal cooling/heating, can increase stress anisotropy, which can reactivate critically-oriented natural fractures. In-situ stress chemical manipulation can be used advantageously to enlarge the stimulated reservoir volume.",8,9,1
Fracture,Hydraulic Fracture,"Chen, Ming; Zhang, Shicheng; Ma, Xinfang; Zhou, Tong; Zou, Yushi",A semi-analytical model for predicting fluid partitioning among multiple hydraulic fractures from a horizontal well,Multi-cluster fracturing; Semi-analytical method; Homogeneous growth; Interaction stress; Perforation friction,PERFORATION CLUSTERS; NETWORK PROPAGATION; NATURAL FRACTURES; SIMULATION; GROWTH; XFEM; ROCK; RESERVOIRS; FLOW,"Multiple fracture growth during multi-cluster fracturing of a horizontal well is closely dependent on fluid partitioning. However, whether injected fluid can uniformly flux into multiple fractures during fracturing remains uncertain. In this study, a semi-analytical model was proposed to simulate fluid rate distribution in multiple fractures. Multi-fracture interaction stresses in the model are solved by a detailed approximation of the elastic solution for a pressurized fracture, which are integrated with rock deformation equations to calculate the multi-fracture width. The semi-analytical model was validated with a well-recognized fully coupled hydraulic fracture simulator. The semi-analytical model can efficiently optimize perforation parameters for multi-cluster fracturing of a horizontal well. Sensitivity analysis was conducted by using the model, and simulation results show that perforation friction and interaction stress are two key factors that determine fluid partitioning among multiple fractures. When interaction stress dominates the flow pressure drop in multiple fractures, fluid partitioning among multiple fractures is uneven due to heterogeneous interaction stresses among multiple fractures; otherwise, fluid partitioning is evenly distributed. Decreasing the total number or diameter of perforation holes can promote uniform multi-fracture growth and fluid partitioning. Homogenous fluid partitioning can be achieved by decreasing the perforation number of exterior fractures, whereas increasing the perforation number of interior fractures minimally affects uniform fluid partitioning among multiple fractures.",8,8,2
Fracture,Hydraulic Fracture,"Li, Linkai; Jiang, Hanqiao; Li, Junjian; Wu, Keliu; Meng, Fanle; Xu, Qilu; Chen, Zhangxin",An analysis of stochastic discrete fracture networks on shale gas recovery,Shale gas recovery; Stochastic fracture networks; Fractal; Fracture intersection; Percolation; Fracture connectivity,FLOW BEHAVIOR; CONNECTIVITY; SIMULATION; MODEL; RESERVOIRS; WELLS,"Complex fracture networks are created by hydraulic fracturing in shale gas reservoirs. The well performance is largely affected by the geometrical properties of fracture networks. It is difficult to estimate well performance because a large number of parameters are used for characterization of a fracture network. In this study, only two parameters are screened to estimate the shale gas recovery by the method of design of experiments. Synthetic fracture networks are generated based on the stochastic theory to represent the secondary fractures in the hydraulic fracture network. Two numerical experiments are designed to correlate the fracture network properties to gas recovery estimated by a commercial software. Various fracture network parameters derived from the analyses of fracture intersection, fractal and percolation are screened to correlate the gas recovery. In terms of the internal structure of a fracture network, a dimensionless parameter called the effective fracture density is proposed to estimate shale gas recovery. It is a combination of the number of fractures, fracture length and orientation. In terms of the boundary of a fracture network, the shale gas recovery is determined by the number of intersection points between the primary fractures and secondary fractures (NIPS). The shale gas recovery predicted by the two parameters (the NIPS and the dimensionless fracture density) is accurate compared with that calculated by the commercial software, which provides us a practical method to estimate the gas recovery by eliminating the number of parameters used for fracture network properties.",8,10,2
Fracture,Hydraulic Fracture,"Peng, Shujun; Zhang, Zhennan; Mou, Jianye; Zhao, Bing; Liu, Zhiyuan; Ghassemi, Ahmad",Hydraulic fracture simulation with hydro-mechanical coupled discretized virtual internal bond,Hydraulic fracture; Fluid flow; Lattice model; Numerical simulation; Discretized virtual internal bond,CRACK-GROWTH; NATURAL FRACTURE; PROPAGATION; CONCRETE; MODEL; ROCK; MASS,"The discrete virtual internal bond (DVIB) is a newly developed lattice model, which considers material to consist of bond cells. Through DVIB, both the 3D continuous seepage and mechanical process are reduced to the 1D discrete bond problem. The micro bond functions as both the fluid channel and the mechanical connection between particles. With the calibrated micro hydro-mechanical parameters, the DVIB can simulate the seepage and mechanical behaviors accurately based on a common set of lattice. To model the fractured medium, a fracture is allowed to run through a bond cell, which makes it possible to embed massive fracture into the background meshing scheme. To consider the hydro-mechanical coupling process, the coupling equations are built up, with which the hydro-mechanical coupling process can be well simulated. This method unifies the hydraulic and mechanical process on the micro bond level, providing a micro-macro hydraulic fracture simulation method for the complex reservoir.",8,8,4
Fracture,Hydraulic Fracture,"Damani, A.; Sondergeld, C. H.; Rai, C. S.",Experimental investigation of in situ and injection fluid effect on hydraulic fracture mechanism using acoustic emission in Tennessee sandstone,Hydraulic fracturing mechanism; Laboratory hydraulic fracturing; Acoustic emission; Microseismic; SRV; Fluid effect,VISCOSITY; ROCK,"Hydraulic fracture propagation and associated rock failure mechanism is dependent on multiple factors including the reservoir pore fluid and its interaction with the rock and the fracturing fluid. This dependence of rock failure on in situ pore fluid could affect the stimulated volume and could manifest itself in the hydraulic fracturing diagnostics such as treatment pressure and microseismic. Therefore, it would be beneficial to an engineer designing, planning or interpreting a fracturing treatment to be aware of expected differences in hydraulic fracture responses in formations having different reservoir fluids, i.e. fracturing a gas or oil bearing formation. We investigate this effect by way of laboratory hydraulic fracturing experiments on triaxially stressed samples of Tennessee sandstone. The acoustic response during rock failure was monitored using 16 P-wave transducers and the waveforms were acquired using a continuous acoustic monitoring system. The effects of pore pressure, water weakening and viscosity of the injection fluids on hydraulic fracture propagation and associated damage are investigated using six experiments on dry, brine saturated and dodecane saturated Tennessee sandstone, fractured with either water (1 cP) or oil (50 cP). Significant rock weakening was observed in fluid saturated samples (breakdown pressures exhibited a reduction of 15-40% from dry state breakdown pressures); the presence of more polar fluid (water) in the pore space resulted in more weakening (800-900 psi lower breakdown pressures when water saturated vs. dodecane saturated). The effect of injection fluid viscosity is observed to be suppressed for fluid saturated samples as breakdown pressures for samples which were saturated with either fluid (brine and dodecane) were observed to be almost same. Acoustic event distributions, continuous stream monitoring, failure mechanisms and permeability measurements on fractured cores all seem to suggest a more complex fracture network in dry rock and more conventional tensile type failure in brine saturated rock. Continuous acoustic stream energy variation with time offers insight into the induced fracture complexity and should be used along with microseismic cloud distributions to assess the stimulated reservoir volume.",8,9,4
Fracture,Stress,"Chen, Yuanhang; Yu, Mengjiao; Takach, Nicholas",Modeling and analysis of coupled thermal-hydrologic-mechanical processes during lost circulation,Wellbore stability; Lost circulation; Numerical simulation; Heat transfer; Geomechanics; Coupled processes,WELLBORE STABILITY; SIMULATION; BOREHOLE; FLUIDS; FLOW,"Wellbore stability remains as one of the major challenges to drilling engineers. Results of recent survey showed about one third of non-productive time of drilling operation is classified as borehole problem, where a significant part is attributed to borehole instability. The thermal regime of a formation in the vicinity of a wellbore affects the stability of the well significantly during drilling operations, especially in High pressure High Temperature (HPHT) wells. This paper describes how the thermal behavior of a tubular-wellbore-reservoir system is altered during mud loss, as well as its consequent impact on near-wellbore state of stresses and critical mud weights. A fully coupled three dimensional thermal-poro-elastic model, integrated with a transient tubular-wellbore-reservoir heat flow model, is developed to evaluate near-wellbore stresses and pore pressure redistribution during mud loss. The forced convective heat transfer coefficients in both conduits-drillpipe and annulus-are rigorously determined as a function of local flow and fluid properties. The results reveal that continuous mud loss destabilizes the wellbore as the pressure window shifts considerably over time. Critical mud weights for both tensile and compressive failures decrease during mud loss over the entire length of the wellbore, in addition to the point of loss. During severe losses, the fracture gradient at the bottom of the well can decrease by over 1 ppg within the first hour. This can intensify the existing fracturing condition and allow the development of new fractures at other locations, which leads to further losses as time progresses. This model enables prediction of a more realistic operating window during lost circulation by taking additional thermally-induced effects into account. In addition, failure indexes during mud loss considering P-rho-T coupling effect on a compressible mud column in the annulus are investigated with the proposed model. During drilling operations, especially Managed Pressure Drilling (MPD) and offshore applications with moderate to severe mud loss, the operation window should be modified by taking mud loss-induced thermal stresses into account. The mud type, wellbore geometry, circulation rate, and other parameters affect the magnitude of shift in critical mud weight during mud loss, hence evaluations should be based on specific cases.",0,0,1
Fracture,Stress,"Karatela, Ehtesham; Taheri, Abbas",Localized stress field modelling around fractures using three-dimensional discrete element method,Stress; Fractures; Borehole stability; Stress tensor,IN-SITU STRESSES; PERTH BASIN; BOREHOLE STABILITY; AUSTRALIA; ORIENTATION; ROCKS; FAULT,"Understanding of field stress condition in fractured rock mass is required to investigate stability of underground excavations. To analyze stress perturbation in fractured rock mass, a regional model is generated using a DEM based code, 3DEC. Three major steep faults were considered in the model. The regional model then was used to estimate stresses on the boundaries of smaller descriptive model termed as the base model. Stresses were observed to vary in magnitude at the intersection of discontinuity sets and stress drop was observed at the discontinuity. In addition, stress tensors in the model were observed to rotate parallel to the discontinuity. A vertical borehole in base model revealed that high stresses concentrated along discontinuities may result in forming yield zones around the borehole. Furthermore, the base mode was subjected to strength and stress anisotropy analysis. Effect of stress anisotropy on stress perturbation was significant, whereas, stress values slightly changed by strength anisotropy. In both cases, due to the effect of discontinuities the induced stress field was non-linear and fluctuating. Effect of stress anisotropy on stress perturbation found to be more significant for the maximum principal stress as compare with the minimum principal stress.",1,1,2
Fracture,Stress,"Osiptsov, A. A.; Boronin, S. A.; Zilonova, E. M.; Desroches, J.",Managed Saffman-Taylor instability during overflush in hydraulic fracturing,Hele-Shaw cell; Hydraulic fracturing; Saffman-Taylor instability; Yield stress; Bingham fluid; Proppant transport; Fingering; Slumping; Shale gas fracturing; Fracture,YIELD-STRESS FLUIDS; HELE-SHAW CELL; NEWTONIAN SLURRY; SUSPENSION FLOW; DISPLACEMENT; PLACEMENT; MECHANICS; MODEL,"Overflushing is a common practice in multistage completions of horizontal wells in unconventional formations. It consists in displacing the suspension by a thin fluid, away from the wellbore and into the fracture. It can, however, overly displace proppant and leave a significant portion of the fracture unsupported near the wellbore, or trigger gravity slumping, again leaving unpropped area near the wellbore. That unpropped area can then close during production, damaging the performance of the fracture. A novel modeling approach was investigated to gain insight into the overflush process and determine secure bounds for maintaining the fracture performance. From a fluid mechanics viewpoint, overflushing is the displacement of a Hershel-Bulkley fluid by a power law fluid in a Hele-Shaw cell, leading to Saffman-Taylor instability at the fluids interface. Whereas most hydraulic fracturing simulators use power-law rheology model, we used a novel numerical approach accounting for the yield-stress behavior of the slurry. Using the lubrication approximation, we derived a model, which includes transport equations for fluid volume fractions and a nonlinear elliptic equation for pressure with mixed-type boundary conditions. Validation was previously performed against three sets of experiments in Hele-Shaw cells, comprising gravitational slumping and displacement of fluids with fingering. Based on fracture mechanics, we analyzed how large a portion of the fracture may be left unsupported before it is severely pinched during drawdown. A parametric study was performed on the displacement of the yield-stress slurry by the overflushing fluid. Qualitatively, when fingers of the overflushing fluid can be created at the overflush/slurry interface, large slurry pillars are preserved in the near-wellbore area, which may keep the fracture open. Three main scenarios of fluids distribution are identified and classified in terms of the oveflush fluid-to-slurry viscosity ratio.: (i) the slumping-dominated regime, where light clean overflush fluid goes on top of sedimenting heavy proppant-laden suspension (xi greater than or similar to 0.1), (ii) an intermediate scenario of slumping combined with fingering (xi similar to 0.01), and, finally, (iii) a pure fingering-dominated scenario, when the slurry viscosity is high (xi < 10(-3)). The third scenario minimizes the geomechanical risks of overflushing by providing tiny fingers that are unlikely to be pinched out during fracture closure.",2,2,0
Fracture,Stress,"Jadoon, Quaid Khan; Roberts, Eric M.; Henderson, Robert A.; Blenkinsop, Thomas G.; Wust, Raphael A. J.","Mineralogical variability of the Permian Roseneath and Murteree Shales from the Cooper Basin, Australia: Implications for shale properties and hydrocarbon extraction",Shale gas; Roseneath; Murteree; Brittleness; Plasticity; Cooper Basin,SOIL; MODEL; CLAY,"Brittleness and plasticity indices in hydrocarbon reservoirs are calculated to understand how rocks behave under stress, and for assessing the fracturing performance of clay-rich shale reservoirs and assessing borehole stability. Evaluating shale plasticity/brittleness requires careful analysis of clay mineral composition in target shales and the development of fracking strategies for optimal shale stimulation. Here we report on the mineralogical variability of two Permian lacustrine shale units, the Roseneath and Murteree shales in the Cooper Basin, Australia, that are considered to have potential as unconventional hydrocarbon producers. The study involved a combination of X-ray diffraction, scanning electron microscopy and petrophysical modelling of the Roseneath and Murteree shales in order to obtain a better understanding of the compositions and microfabrics of these two units. This is part of a larger investigation of the shale gas potential of these two units in the Cooper Basin, and the results presented here may ultimately lead to improved reservoir stimulation techniques in both units. Core data has been integrated with wireline logging data to better identify brittle and plastic zones within the Roseneath and Murteree shales. Mineralogical analysis shows that both units are composed mainly of detrital quartz and clay/mica minerals with siderite cement. The clay mineral composition is dominated by illite/mica, and kaolinite in both units. However, based on the relative mineralogical differences between the two units, the Murteree Shale has more favourable brittle properties than the Roseneath Shale, and is considered to be more amenable to hydraulic fracturing for gas exploitation. However, the Roseneath Shale also has potential for gas stimulation, especially in intervals where siderite cement is prevalent.",2,3,1
Fracture,Stress,"Hu, Jinghong; Chen, Zhangxin; Liu, Pengcheng; Liu, Hui",A comprehensive model for dynamic characteristic curves considering sulfur deposition in sour carbonate fractured gas reservoirs,Sulfur deposition; Stress sensitivity; Fractured carbonate gas reservoir; Finite differences; Characteristic curve,HYDROGEN-SULFIDE; SOLUBILITY; BEHAVIOR; FLOW; PERFORMANCE; WELLS,"Calculating sulfur deposition is a key issue in developing sour gas reservoirs, where sulfur solubility plays an important role. However, prediction of sulfur solubility is a difficult problem due to the toxic of H2S. In this work, an analytical model for dual porosity media considering the influence of sulfur deposition was proposed. The Douglas-Jones predictor-corrector method is used to calculate a relationship between time and pressure, which can avoid solving the system of nonlinear equations. The effects of sulfur deposition on well performance were analyzed and some dynamic characteristic curves for predicting sulfur deposition were provided. The results show that the fastest pressure drop appears near the wellbore, which is the primary damage zone for elemental sulfur precipitation and deposition. Flow parameters and storage ratio play the significant influences on the sulfur saturation curve shape. In addition, the reduction of flow parameters and storage ratio lead to the increase of sulfur saturation and decrease of permeability, resulting in the damage of sour gas formation. The advantage of this approach is that it can be used to describe a characteristic curve without considering the sulfur solubility issue. This paper provides a novel method to analyze the impacts of sulfur deposition on well performances in sour carbonate fractured gas reservoirs.",2,3,10
Fracture,Stress,"Norouzi, Peyman; Baghbanan, Alireza; Hashemolhosseini, Hamid",Effect of coupled triaxial stress-perforation on fracture mechanism and acoustic wave velocity of limestone,Perforation; Triaxial stress; P-Wave velocity; Fracture pattern; In-situ stresses,FORMATION DAMAGE; P-WAVE; TAGUCHI; PERMEABILITY; PENETRATION; EVOLUTION; GRANITE; ROCKS,"Perforation with shaped charges establishes the hydraulic communication between cased wellbore and reservoir. Higher DoP(1) is one of the most important goals of perforation. Performance of a perforation is greatly influenced by confining pressure, which was mostly anisotropic, around the target. Therefore, it is necessary to consider the triaxial confining pressure on the target to achieve the actual results. In this study, a new triaxial perforation machine designed and constructed to investigate the effect of anisotropic in-situ stress on the DoP and failure pattern of limestone targets. The number of tests was optimized by Taguchi's method and ANOVA(2) was used to determine the cross effect of the different combination of applied in-situ stresses on DoP. The ultrasonic P-wave velocity was measured before and after perforation under different conditions of anisotropic loading. The results show that the Measured DoP is more controlled by the off plane stresses (stresses normal to shooting axis) than the stress in the direction of penetration. The created fractures by perforation are more oriented along the maximum horizontal stress, which is less propagated around a hole with increasing the maximum to the minimum off plane stress ratio. The measured p-wave velocity showed that V-P increases along the perforation hole from the beginning of the hole toward the block boundaries. It was found the loading conditions control the V-P values along the shooting axis. In anisotropic loading mode, the velocity of P-waves in direction of the maximum stress was greater than minimum horizontal stress. In the isotropic loading condition, V-P values were same along the direction perpendicular to the firing axis.",3,4,1
Fracture,Stress,"Zhao, Hongbo; Li, Zhen; Zhu, Changxing; Ru, Zhongliang",Reliability analysis models for hydraulic fracturing,Hydraulic fracturing; Uncertainty; Reliability analysis; First order reliability method,PRINCIPAL STRESS; ELEMENT-METHOD; FLUID LAG; PROPAGATION; SIMULATION; ALGORITHM; DESIGN; SPREADSHEET; XFEM,"For many decades, hydraulic fracturing has been the technique most commonly used in the oil and gas industry to increase the productivity of low permeability reservoirs. However, much uncertainty remains when applying this technique, which can influence performance. It has proved difficult, for example, to evaluate the uncertainties inherent in traditional deterministic hydraulic fracturing models using classic analytical and numerical methods. Thus, in this study, we adapted reliability analysis to evaluate the performance of hydraulic fracturing including the length, width, and nature of a fracture when considering uncertainty. Random variables are assumed to follow a normal distribution, and the first-order reliability method (FORM) was used to calculate a reliability index for hydraulic fracturing based on Khristianovic-Geertsma-de Klerk (KGD) and Perkins-Kern-Nordgren (PKN) models. Reliability indexes obtained under different conditions show excellent agreement with Monte Carlo simulations, and indicate that use of this method provides an efficient and effective scientific approach for the uncertainty analysis of hydraulic fracturing. We also investigate and discuss the influence of elastic mechanical parameters of rock formations as well as in situ stress as random variables affecting the performance of hydraulic fracturing alongside various other factors that can influence this process, including rock tensile strength, injection rate and time. This analysis provides quantitative insights into the uncertainties that underlie hydraulic fracturing models and enables the identification of potentially influencing factors to reduce performance uncertainties. The results also show reliability analysis provides an appropriate solution for evaluation of uncertainty and can further improve the performance of hydraulic fracturing.",4,4,0
Fracture,Stress,"Dutta, Jayanta; Kumar, Ashutosh; Bhardwaj, Nitin; Gunasekaran, Karthikeyan; Mohammed, Sajid","Production induced faulting risk assessment in a depleted reservoir: A case study from deepwater Krishna-Godavari basin, India",Deepwater depleted reservoir; Risk assessment; Production induced faulting; Slip tendency; Dilation tendency; Secondary fractures re-activation,IN-SITU STRESS; FLUID-FLOW; PORE PRESSURE; REACTIVATION; FIELD,"In a producing field, the fluid conduit nature of faults could initiate due to changes in the stress state within the reservoir. It has large impacts on different aspects (seal integrity, casing shear, mud loss during drilling, reservoir permeability, and induced earthquakes) of the field performance. In order to optimize the future drilling campaign and field management strategy, production induced faulting risk assessment was performed to evaluate the fault behavior in a depleted reservoir, where the reservoir pressure has decreased by 40% from its pre-production pressure. The risk assessment was done through (i) identifying the critically stressed fracture/fault in the pre-production stage, (ii) assesses the risk of production induced new fractures/faults generation & reactivation of existing faults, and (iii) risk ranking of faults within the reservoir. The assessment model was based on the relationship between failure mode and fluid flow with change in stresses on the fault planes due to reservoir pressure depletion. The model was built through integrating different data, such as, reservoir fault mapping, core data, drilling data, production data, and geomechanical modelling. The analysis revealed that all the faults at the pre-production stage were not critically stressed and therefore, were closed. Production induced new fractures/faults are neither generated nor existing faults re-activated till the current depleted reservoir condition in the study field. Risk ranking based on the slip and dilation tendency analysis suggests that because of the depletion fault slip tendency has not increased much and risk of fault slip is on the lower side. But, the dilation tendency has increased for all the faults which makes these faults more prone to extensional/tensile failure than shear failure. Furthermore, the analysis suggests that the severe mud loss events encountered in the post-production wells were due to re-activation of existing secondary fractures at the fault intersection depths during drilling.",5,5,3
Fracture,Stress,"Liu, Wenzheng; Zeng, Qingdong; Yao, Jun",Numerical simulation of elasto-plastic hydraulic fracture propagation in deep reservoir coupled with temperature field,Deep reservoir; Hydraulic fracturing; Elasto-plasticity; Heat transfer; Cohesive zone model; Embedded discrete fracture model,FLUID-DRIVEN FRACTURES; MEDIA; ROCK,"With the increasing demand of oil and gas resource, the development of deep reservoir has become an inevitable trend. To investigate the coupled effects of rock elasto-plastic deformation, fluid flow and heat transfer in the process of hydraulic fracturing of deep reservoir, the mathematical model of elasto-plastic hydraulic fracture propagation is established based on cohesive zone model (CZM) and embedded discrete fracture model (EDFM). The constitutive equation incorporating thermal stress is derived by using Drucker-Prager yield condition and the associated flow law. Fluid flow in the fracture is modeled with lubrication theory. The thermal non-equilibrium theory is employed to describe the heat exchange between rock matrix and fluid in the fracture based on EDFM. The CZM is used as fracture propagation criterion. The rock deformation equation is solved by finite element method. The temperature field and fluid flow in the fracture are discretized by finite volume method. Due to the non-linearity of flow equation, the iterative method is used to solve the coupled problem of stress, pressure and temperature fields. A Triangular-PEBI (Perpendicular Bisector) dual mesh system is presented for numerical implementation. The numerical model is validated against with analytical solution and other methods in the literature. The results show the significance of accounting for elasto-plastic deformation and heat transfer when simulating hydraulic fracture propagation in deep reservoir.",5,5,5
Fracture,Stress,"Wu, Rui; Deng, Jingen; Liu, Wei; Mao, Shaowen; Sun, Jin; Yan, Min; Li, Ming; Li, Yao",Numerical investigation of fluid injection into poorly consolidated geomaterial considering shear dilation and compaction,Fluid injection; Poorly consolidated geomaterial; Poroelastoplasticity; Cohesive zone model; Shear dilation; Compaction failure,CAM-CLAY PLASTICITY; HYDRAULIC FRACTURE PROBLEM; BOUNDING SURFACE MODEL; IMPLICIT INTEGRATION; LABORATORY EXPERIMENTS; UNCONSOLIDATED-SAND; SOIL; STRESS; FLOW; SIMULATION,"We present a fully coupled poroelastoplastic finite element model to simulate micro-fracture evolution, cornpaction failure and tensile fracture propagation during fluid injection into poorly consolidated geomaterial. The model includes shear dilation, strain hardening and fracture process zone with permeability evolution. We investigated the effects of geomechanics (stress anisotropy) and fluid injection (fluid rheology) on rock deformation and fracture behavior. Results indicate that fluid rheology dominate the rock failure. Pore pressure increase and water wedge effect can cause two kinds of shear dilation which are prior to tensile failure. The effect of compaction is significant to tensile fracture geometries, which differ from those under elastic and poroelastic conditions. The difference between shear band and compaction zone is the transition of fracture regime from the leak-off dominated to the storage dominated governed by fluid injection.",6,6,1
Fracture,Stress,"Bui, Binh T.; Tutuncu, Azra N.",Modeling the swelling of shale matrix in unconventional reservoirs,Shale swelling; Coupled modeling; Unconventional reservoirs; Dual-porosity model; Water injection; Mass transport,,"The imbibition of the injection water into shale matrix may result in shale swelling affecting oil recovery from the rock matrix and the transport properties of the fractures. The expansion of rock due to the swelling of shale matrix compresses the pore space in the rock matrix and the surrounding fractures. This reduces fracture and matrix porosity and permeability. The reduction of matrix pore space can reduce the rate of oil recovered from the rock matrix. On the other hand, it also forces the oil out of the matrix pore space increasing oil recovery. However, this effect has not been evaluated and integrated in reservoir modeling. This study presents a coupled fluid flow and geomechanics model for modeling shale swelling to quantitatively investigate the effect of swelling on transport properties of rock matrix and fractures. The main objective is to quantitatively determine the effect of shale swelling on the oil recovery from the rock matrix. A numerical solution is presented to solve the coupled equations simultaneously for the phase pressure, fluid saturation, stress, and strain. We show that the mechanical properties of the rock matrix vary significantly as the result of water imbibition. The reduction of the fracture and matrix permeability and porosity due to swelling is considerable. This results in the reduction of more than 50% of the oil recovered from shale matrix. Hence, shale swelling should be prevented in any water injection operations.",6,6,1
Fracture,Stress,"Zhao, Junlong; Tang, Dazhen; Qin, Yong; Xu, Hao","Experimental study on structural models of coal macrolithotypes and its well logging responses in the Hancheng area, Ordos Basin, China",Coal macrolitotype; Structural model; Pore and fracture; Advanced well logging; Hancheng,PORE-STRUCTURE CHARACTERIZATION; SCANNING-ELECTRON-MICROSCOPY; SOUTHERN QINSHUI BASIN; METHANE RESERVOIRS; JHARIA COALFIELD; EASTERN MARGIN; SURFACE-AREA; GAS CONTENT; PERMEABILITY; SEAMS,"Coal macrolithotype (bright, semi-bright, semi-dull, and dull coals) controls the heterogeneity of coal physical properties in the coalbed methane (CBM) reservoir. However, few scholars carried out the work aiming at the compositional-based macrolithotype analysis of coal reservoirs. In this work, the Hancheng area, Ordos Basin, China, was taken as an example to understand the macrolithotype difference, establish the structural models of macrolithotypes, and then evaluate the responses of advanced well loggings (the natural gamma-ray spectroscopy (NGS), formation microresistivity image (FMI), and cross-dipole array acoustic (XMAC) loggings). Results show that, from the bright to dull coal, the coal density, ash yield, and mineral content increase while the vitrinite content and pore-fracture development degree decrease gradually. The dull and semi-dull coals usually are found in touch with the mudstone (roof, floor, and parting) while the bright or semi-bright coal occurs as an interlayer between them. In the structural models of macrolithotypes for the CBM reservoir, the fracture model couples the artificial and macrofractures controlled by the tectonic stress field as well as the microfracture mainly restricted by the coal macrolithotypes; the pore model shows multilevel pores with gradually decreasing pore size, namely the protogenetic (plant tissue and intergranular pores) and secondary (gas and intermolecular pores) pores; and the pore-fracture relation model is characterized by the multilevel communication between the pores and fractures. Of all the three advanced logging responses of macrolithotypes, the NGS and XMAC show a good consistency with the natural gamma (GR) and interval transit time (AC) loggings since the former was derived from the latter essentially, respectively. But using FMI to identify macrolithotypes is error-prone due to the strong coal heterogeneity around the wellhole. From the bright to dull coal and mudstone, the values of thorium, kalium, uranium elements and GR (or GR without uranium) increase while those of AC including the longitudinal, transverse, and Stoneley waves decrease gradually.",7,8,0
Fracture,Stress,"Kim, Jihoon; Um, Evan Schankee; Moridis, George J.",Integrated simulation of vertical fracture propagation induced by water injection and its borehole electromagnetic responses in shale gas systems,Hydraulic fracturing; Shale gas; Electromagnetic geophysics; Coupled flow and geomechanics,HYDRAULIC-FRACTURE; POROSITY MATERIALS; RESERVOIR; FLOW; GEOMECHANICS; TOMOGRAPHY; FERROFLUID,"We analyze fracture propagation induced by hydraulic fracturing with water injection and examine their detectability with crosswell electromagnetic (EM) geophysical methods. For rigorous 3D coupled flow-geomechanical modeling, we employ a numerical method that can model failure by tensile and shear stresses, dynamic nonlinear permeability, dual continuum approach, and thermo-poro-mechanical effects. From numerical simulation, we find that the fracture propagation is not the same as propagation of the water front, because fracturing is governed by geomechanics whereas water saturation is determined by multiphase flow. At early times, the water front is almost identical to the fracture tip, suggesting that the fracture is mostly filled with the injected water. However, at late times, movement of the water front is retarded compared to fracture propagation, yielding a significant gap between the water front and the fracture top, filled with reservoir gas. During fracture propagation, the coupled flow-geomechanical models are transformed via a rock-physics model into electrical conductivity models. We employ a full 3D finite-element EM geophysical simulator to evaluate the sensitivity of the crosswell EM method to fracture propagation. It is shown that anomalous distribution of electrical conductivity is closely related to the injected water saturation, but not closely related to newly created unsaturated fractures. Our numerical modeling experiments demonstrate that the crosswell EM method can be highly sensitive to electrical conductivity changes that directly indicate the migration pathways of the injected fluid. Accordingly, the EM method can serve as an effective monitoring tool for monitoring the injected fluids during hydraulic fracturing operations.",7,7,2
Fracture,Stress,"Liu, Yuetian; Yu, Peng; Ding, Zupeng",Research on stress-sensitivity of fractured porous media,Oil and gas reservoir; Zero-stress model; High dip fracture; Fracture aperture; Fracture permeability,PERMEABILITY; COMPRESSIBILITY; DEFORMATION; BEHAVIOR; POROSITY; WHOLE,"Stress sensitivity parameters of a fracture are often tested under compression on both sides of the fractured medium, which is considered as an elastic solid. However, the elastic solid assumption will fail when two fracture surfaces, if applied to tensile stresses, are out of contact. In such cases, effective stress in the fracture is zero and the change of fracture aperture is not determined by the fracture itself, but by the deformation of the matrix and the overall deformation of the fractured region. This paper proposed a zero-stress model that is applicable after the failure of elastic fracture model as described above. The model analyzes the deformation mechanism of fractures and derives a new equation that can be used to describe the aperture and permeability behavior of a fractured medium under the condition of zero stress. The model is derived for different geometric shapes of fractured region under hydrostatic pressures. The model equations can be used to calculate aperture and permeability changes caused by the production of oil and gas from a reservoir as well as the injection of water or gases for EOR. Sensitivity analysis of the model found that both shape factor of the fractured region and elastic modulus of the surrounding rocks have a significant impact on the outcome of the aperture and permeability forecast as a function of changing pore pressure. The permeability model can also be used in reservoir engineering analysis and reservoir numerical simulation. The new model is joined with the traditional elastic model to better describe the deformation process of fractures.",7,7,3
Fracture,Stress,"Liu, Guoqing; Ehlig-Economides, Christine",Practical considerations for diagnostic fracture injection test (DFIT) analysis,DFIT; Fracture closure; Hydraulic fracture design; Natural fracture; Pressure falloff analysis,,"The diagnostic fracture injection test (DFIT) provides a way to estimate parameters critical to hydraulic fracture design. Existing published models for before-closure and after-closure behaviors rely on assumptions, and failure to honor important realities leads to parameter estimation errors that could degrade hydraulic fracturing design. This paper is to illustrate an accurate way to estimate parameters from the DFIT data, and then discuss how these parameters should be used in the hydraulic fracture design, and at last offer an alternative DFIT design approach. Two fundamental concepts underlying the proposed methodology are the material balance before fracture closure and the diffusive flow in the formation after closure. Before closure analysis must correctly address abnormal leakoff behaviors and near well friction losses. Likewise, accurate permeability and pore pressure estimation requires correct accounting for the leakoff rate into the formation. Strict attention to material balance yields estimations for instantaneous shut-in pressure (ISIP) and perforation and tortuosity friction losses that may, in turn, avoid apparent very high net pressure and stress shadowing. This work also underscores the importance of understanding surface and downhole volumes and rates both in the DFIT design and in the analysis. Further, for the DFIT case with pressure dependent leakoff (PDL), the fracture design for the subsequent hydraulic fracturing treatment should use the apparent leakoff rate associated with the first closure trend instead of the leakoff rate associated with the last closure trend derived from a normal leakoff model. Two successive DFITs in the same perforation, the first treated with low injection rate and small volume and then the second with high rate and large volume, are proved to be a good practice to obtain reliable estimation of formation properties. This paper demonstrates that DFIT parameters have often been misused. With the proposed methodology, the interpretation will be more accurate and reliable for formation evaluation and hydraulic fracture design.",8,10,0
Fracture,Stress,"Qi, Dexuan; Li, Lijuan; Jiao, Yongshu",The stress state around an elliptical borehole in anisotropy medium,Borehole stability; Elliptical borehole; Stress state; Anisotropic elasticity; Complex variable method; Analytical solution,WELLBORE STABILITY; FAILURE; ROCKS,"Under the assumption of generalized plane strain condition, this paper presents an analytical solution for stresses near an inclined elliptical wellbore drilled in anisotropic formation based on the linear theory of anisotropic elasticity and complex variable method. The solution is suitable for calculating the stresses around an elliptical borehole drilled with any inclination and orientation angles in a linear elastic, continuous, homogeneous and general anisotropic medium. The solution for the stresses can also show the effects of the liquid pressure exerted by drilling mud, the ratio and the direction of the in-situ stresses. For engineering utilization the transformation of compliance matrix for the transversely isotropic medium is formulated. An example is calculated and shown by contours of stress components around an inclined elliptical wellbore in a transversely isotropic formation. The stress contours can be utilized to some extent to predict the location, the range, the depth and even the outlines of fractured or collapsed well wall. Then a range of parametric analysis is carried out on the impacts of borehole inclination, orientation and ellipticity on the first principal stress and maximum shearing stress. The results indicate that for various boreholes with different degree of formation anisotropy the algebraic values of the first principal stress and maximum shearing stress go down gradually with the increase of borehole inclination, and these two stresses vary in the pattern of half a sinusoidal wave with the variation of orientation angles. Furthermore, the stresses go up with the increase of ellipticity. The solution presented in this paper might supply a more realistic technique for assessing the stability of borehole and optimizing the well path in anisotropic medium.",8,8,1
Fracture,Stress,"Shen, Jian; Qin, Yong; Li, Yepeng; Yang, Yanhui; Ju, Wei; Yang, Chunli; Wang, Geoff","In situ stress field in the FZ Block of Qinshui Basin, China: Implications for the permeability and coalbed methane production",In situ stress; High-rank coal; Coalbed methane; Permeability; Gas and water production; Qinshui basin,EASTERN ORDOS BASIN; SHANXI PROVINCE; ORIENTATION; EXPLORATION; MAGNITUDE; RESERVOIR; PART; AREA; GEOMECHANICS; FRACTURES,"In situ stress affects reservoir permeability and stimulation, and thus coalbed methane (CBM) recovery. In this study, the in situ stress field measured from 238 CBM wells in the FZ Block of Qinshui Basin, China, was investigated. The vertical stress, horizontal maximum and minimum principal stress are 5.92-20.08 MPa, 8.03-41.75 MPa, and 5.38-21.24 MPa, respectively. The in situ stress magnitudes increase with burial depth of the coal seams. The FZ Block is dominated by reverse and strike-slip faulting stress regimes. Most of reverse fault stress regimes appear within burial depth less than 500 m, whereas normal and strike faulting stress regimes are deeper than 500 m. The relation between the coefficient of lateral stress and burial depth shows that shallow strata are characterized by horizontal stresses, whereas deep strata are generally hydrostatic pressures that approximately equal to the principal stresses. Low gas and high water production are associated with vertical hydraulic fractures, wherein the horizontal minimum principal stress is the minimum stress. High gas and low water production are associated with horizontal hydraulic fractures, wherein the vertical stress is the minimum stress. This results are attributed to the enhanced permeability of the coal seam and the communication with overlying or underlying aquifers because the minimum stress varies between vertical and horizontal minimum stress. The orientation of the horizontal maximum principal stress is -NEE-NE and is locally distorted by faults, which can be used to optimize the drilling, completion, and stimulation of CBM wells in the study area.",8,10,1
Fracture,Stress,"Shovkun, Igor; Espinoza, D. Nicolas",Geomechanical implications of dissolution of mineralized natural fractures in shale formations,Stimulated reservoir volume; Shear failure; Mineral dissolution; Hydraulic fracturing; Acidizing,BARNETT SHALE; GAS-PRODUCTION; POROUS-MEDIA; PERMEABILITY; ROCK; BASIN; FLOW; NETWORKS; MODEL; COAL,"Organic shale reservoirs accommodate large amounts of hydrocarbons in extremely tight rock matrix. Slick water hydraulic fracturing and proppant placement is the most spread stimulating technology for this type of reservoirs. Some shale formations contain a fair amount of easily-dissolvable carbonates, which prompts shale acidizing as a potential method to increase reservoir permeability. Carbonates in shale formations can be present as a part of rock matrix or can be localized in natural fractures - so-called mineral veins. Previous studies investigated the effects of chemical dissolution within the matrix, implying that acidizing can etch the rock, open new conduits for flow, and increase fracture permeability after closure. This study rather focuses on the reservoir-scale geomechanical implications of chemical dissolution of mineral filling in natural fractures. We use a combination of elasto-plastic analytical methods, analogous thermo-elastic numerical solutions, and experimental results to elucidate the impact of veins dissolution on in-situ stresses. Analytical, numerical, and experimental results indicate that mineral dissolution of localized carbonate fractures leads to changes of local in-situ stresses. The direction of stress relaxation strongly depends on the orientation of mineralized fractures. Dissolution of near-vertical mineralized fractures contributes the most to decreases of effective horizontal stress and reduce stress shadow effects in multistage hydraulic fracture completions. Mineral dissolution, similar to pore pressure depletion or thermal cooling/heating, can increase stress anisotropy, which can reactivate critically-oriented natural fractures. In-situ stress chemical manipulation can be used advantageously to enlarge the stimulated reservoir volume.",8,9,1
Fracture,Stress,"Chen, Ming; Zhang, Shicheng; Ma, Xinfang; Zhou, Tong; Zou, Yushi",A semi-analytical model for predicting fluid partitioning among multiple hydraulic fractures from a horizontal well,Multi-cluster fracturing; Semi-analytical method; Homogeneous growth; Interaction stress; Perforation friction,PERFORATION CLUSTERS; NETWORK PROPAGATION; NATURAL FRACTURES; SIMULATION; GROWTH; XFEM; ROCK; RESERVOIRS; FLOW,"Multiple fracture growth during multi-cluster fracturing of a horizontal well is closely dependent on fluid partitioning. However, whether injected fluid can uniformly flux into multiple fractures during fracturing remains uncertain. In this study, a semi-analytical model was proposed to simulate fluid rate distribution in multiple fractures. Multi-fracture interaction stresses in the model are solved by a detailed approximation of the elastic solution for a pressurized fracture, which are integrated with rock deformation equations to calculate the multi-fracture width. The semi-analytical model was validated with a well-recognized fully coupled hydraulic fracture simulator. The semi-analytical model can efficiently optimize perforation parameters for multi-cluster fracturing of a horizontal well. Sensitivity analysis was conducted by using the model, and simulation results show that perforation friction and interaction stress are two key factors that determine fluid partitioning among multiple fractures. When interaction stress dominates the flow pressure drop in multiple fractures, fluid partitioning among multiple fractures is uneven due to heterogeneous interaction stresses among multiple fractures; otherwise, fluid partitioning is evenly distributed. Decreasing the total number or diameter of perforation holes can promote uniform multi-fracture growth and fluid partitioning. Homogenous fluid partitioning can be achieved by decreasing the perforation number of exterior fractures, whereas increasing the perforation number of interior fractures minimally affects uniform fluid partitioning among multiple fractures.",8,8,2
Fracture,Stress,"Yi, Sophie S.; Sharma, Mukul M.",A new method to calculate slurry distribution among multiple fractures during fracturing and refracturing,Fluid partitioning; Slurry distribution; Simulation of multi-fracture stimulation; Plug-and-perf stages; Re-fracturing,,"An accurate calculation of slurry distribution among multiple perforation clusters is necessary for all multifracture simulators. The slurry distribution was solved by applying the Newton-Raphson Method in the past. This method requires a numerical evaluation of the Jacobian matrix and can be unstable in some cases. In this paper, we propose a new approach to calculate slurry distribution among multiple fractures, the Resistance Method. This new approach is computationally efficient, requires no Jacobian matrix calculation, and has been proved to converge locally at least linearly. The Resistance Method is derived by reforming the mass conservation and pressure continuity equations for multiple fractures into a system of nonlinear fixed-point iteration equations. In the new equation system, the fracture resistance is defined as the pressure drop per unit flow rate. And the injected slurry is distributed among multiple fractures in inverse proportion to the resistance of each fracture. This new slurry distribution method has been applied to several different fracture models. The convergence of this new slurry distribution method has been analyzed with the map contraction theory. In this paper, we show three example applications of the Resistance Method. First, the Resistance Method is implemented with an analytical PKN model, with direct comparison made with the Newton-Raphson method. Simulation results show that both methods solve the slurry distribution accurately, but we show that the Resistance Method can be more computationally efficient than the Newton-Raphson Method. Second, the Resistance Method is used to obtain the proppant distribution in multiple clusters with particle transport efficiency curves implemented implicitly. It is shown that the proppant distribution among multiple clusters can be quite different from the fluid distribution. Due to inertial effects, proppant tends to accumulate towards the toe side clusters and causes pre-mature screen-out, resulting in a heel-biased treatment. Third, the Resistance Method is used in a refracturing example problem. A synthetic refracturing treatment with 50 existing fractures, 49 new clusters and about 15 h' treatment time was simulated. The results show that the refrac treatment is heel biased with the 20 heel side clusters receiving most of the treatment and that both existing fractures and new perforations propagate during refracturing. In such simulations extending over long periods of injection and with a large number of perforation clusters it is important to have a very efficient solver to obtain the fluid and proppant distribution in a reasonable computational time frame. In this work, we developed a new method to calculate slurry distribution among multiple clusters with applications to fracturing and refracturing treatments. This new method can be integrated with any fracture model. The main advantages of this new approach include: 1) simple implementation, 2) no numerical evaluation of the Jacobian matrix, 3) computationally efficiency, and 4) easy integration of slurry distribution, proppant transport, stress shadow effects and multiple fracture propagation.",8,9,3
Fracture,Stress,"Damani, A.; Sondergeld, C. H.; Rai, C. S.",Experimental investigation of in situ and injection fluid effect on hydraulic fracture mechanism using acoustic emission in Tennessee sandstone,Hydraulic fracturing mechanism; Laboratory hydraulic fracturing; Acoustic emission; Microseismic; SRV; Fluid effect,VISCOSITY; ROCK,"Hydraulic fracture propagation and associated rock failure mechanism is dependent on multiple factors including the reservoir pore fluid and its interaction with the rock and the fracturing fluid. This dependence of rock failure on in situ pore fluid could affect the stimulated volume and could manifest itself in the hydraulic fracturing diagnostics such as treatment pressure and microseismic. Therefore, it would be beneficial to an engineer designing, planning or interpreting a fracturing treatment to be aware of expected differences in hydraulic fracture responses in formations having different reservoir fluids, i.e. fracturing a gas or oil bearing formation. We investigate this effect by way of laboratory hydraulic fracturing experiments on triaxially stressed samples of Tennessee sandstone. The acoustic response during rock failure was monitored using 16 P-wave transducers and the waveforms were acquired using a continuous acoustic monitoring system. The effects of pore pressure, water weakening and viscosity of the injection fluids on hydraulic fracture propagation and associated damage are investigated using six experiments on dry, brine saturated and dodecane saturated Tennessee sandstone, fractured with either water (1 cP) or oil (50 cP). Significant rock weakening was observed in fluid saturated samples (breakdown pressures exhibited a reduction of 15-40% from dry state breakdown pressures); the presence of more polar fluid (water) in the pore space resulted in more weakening (800-900 psi lower breakdown pressures when water saturated vs. dodecane saturated). The effect of injection fluid viscosity is observed to be suppressed for fluid saturated samples as breakdown pressures for samples which were saturated with either fluid (brine and dodecane) were observed to be almost same. Acoustic event distributions, continuous stream monitoring, failure mechanisms and permeability measurements on fractured cores all seem to suggest a more complex fracture network in dry rock and more conventional tensile type failure in brine saturated rock. Continuous acoustic stream energy variation with time offers insight into the induced fracture complexity and should be used along with microseismic cloud distributions to assess the stimulated reservoir volume.",8,9,4
Fracture,Distribution,"Osiptsov, A. A.; Boronin, S. A.; Zilonova, E. M.; Desroches, J.",Managed Saffman-Taylor instability during overflush in hydraulic fracturing,Hele-Shaw cell; Hydraulic fracturing; Saffman-Taylor instability; Yield stress; Bingham fluid; Proppant transport; Fingering; Slumping; Shale gas fracturing; Fracture,YIELD-STRESS FLUIDS; HELE-SHAW CELL; NEWTONIAN SLURRY; SUSPENSION FLOW; DISPLACEMENT; PLACEMENT; MECHANICS; MODEL,"Overflushing is a common practice in multistage completions of horizontal wells in unconventional formations. It consists in displacing the suspension by a thin fluid, away from the wellbore and into the fracture. It can, however, overly displace proppant and leave a significant portion of the fracture unsupported near the wellbore, or trigger gravity slumping, again leaving unpropped area near the wellbore. That unpropped area can then close during production, damaging the performance of the fracture. A novel modeling approach was investigated to gain insight into the overflush process and determine secure bounds for maintaining the fracture performance. From a fluid mechanics viewpoint, overflushing is the displacement of a Hershel-Bulkley fluid by a power law fluid in a Hele-Shaw cell, leading to Saffman-Taylor instability at the fluids interface. Whereas most hydraulic fracturing simulators use power-law rheology model, we used a novel numerical approach accounting for the yield-stress behavior of the slurry. Using the lubrication approximation, we derived a model, which includes transport equations for fluid volume fractions and a nonlinear elliptic equation for pressure with mixed-type boundary conditions. Validation was previously performed against three sets of experiments in Hele-Shaw cells, comprising gravitational slumping and displacement of fluids with fingering. Based on fracture mechanics, we analyzed how large a portion of the fracture may be left unsupported before it is severely pinched during drawdown. A parametric study was performed on the displacement of the yield-stress slurry by the overflushing fluid. Qualitatively, when fingers of the overflushing fluid can be created at the overflush/slurry interface, large slurry pillars are preserved in the near-wellbore area, which may keep the fracture open. Three main scenarios of fluids distribution are identified and classified in terms of the oveflush fluid-to-slurry viscosity ratio.: (i) the slumping-dominated regime, where light clean overflush fluid goes on top of sedimenting heavy proppant-laden suspension (xi greater than or similar to 0.1), (ii) an intermediate scenario of slumping combined with fingering (xi similar to 0.01), and, finally, (iii) a pure fingering-dominated scenario, when the slurry viscosity is high (xi < 10(-3)). The third scenario minimizes the geomechanical risks of overflushing by providing tiny fingers that are unlikely to be pinched out during fracture closure.",2,2,0
Fracture,Distribution,"Wang, Yong; Hou, Jirui; Tang, Yong; Song, Zhaojie; You, Zhenjiang",Application of modified Dykstra-Parsons method to natural bottom-water drive in non-communicating fractured-vuggy reservoir,Fractured-vuggy reservoir; Natural bottom-water drive; Dykstra-Parsons method; Gravity number,DISPLACEMENT,"Universal existence of the filled vug and fracture in carbonate fractured-vuggy reservoir upgrades the complexity of fluid flow as the coexistence of free flow and porous flow. The highly discrete distribution of fracture and vug makes it possible to apply Dykstra-Parsons method in this kind of medium. A modification of Dykstra-Parsons method is proposed to depict the displacement in fracture-vug system, which consists of multiple non-communicating fracture-vug units with each containing fracture, fills, and vug. The displacement front advance equation is derived piecewise corresponding to the position of the front in fracture, fills, and unfilled vug of one unit. The solution to this equation for every fracture-vug unit is used to estimate the production dynamics of the fracture-vug system, including the fractional oil recovery, the water cut, the injected pore volume, and the injectivity ratio. A calculating example with log-normal distribution for fracture aperture is involved to make the sensitivity analysis of gravity number, viscosity ratio, fills properties, and variation of the fracture aperture. In terms of increased oil recovery, decreased water cut, and delayed water breakthrough, it was found that a better performance reached in the condition of weak heterogeneity of fracture, large gravity number, and lower oil//water viscosity ratio; the fills with low permeability and high filling degree is favorable when all vugs are filled identically.",3,3,2
Fracture,Distribution,"Tandon, Saurabh; Heidari, Zoya; Aderibigbe, Aderonke; Shi, Jingyu; Fuss-Dezelic, Tihana",A new method for mechanical damage characterization in proppant packs using nuclear magnetic resonance measurements,Mechanical damage; Proppant packs; Nuclear magnetic resonance; Measurements; Pore-size distribution; Fines,HYDRAULIC CONDUCTIVITY; NMR RELAXATION; POROSITY; FLUIDS,"Proppant performance can significantly affect the success of hydraulic fracturing treatments and production in unconventional plays. Performance of proppants can decrease rapidly by mechanical damage. Quantifying the impact of mechanical damage on proppant performance can be challenging either in the laboratory or in-situ condition. This paper introduces a new method based on Nuclear Magnetic Resonance (NMR) Transverse relaxation (T-2) measurements to characterize pore-size distribution in proppant packs. Quantifying the pore-size distribution in proppant packs enables enhanced evaluation of porosity and conductivity of proppant packs and possible mechanical damage to the packs. The objectives of this paper are (a) to evaluate the performance of this new NMR-based method for characterizing pore structure of the proppant packs, and (b) to isolate and quantify the mechanical damage in proppant packs due to generating of fines in the laboratory using this new NMR-based method. First, we prepared proppant pack test samples in three categories including (a) different types of proppants with different surface relaxivity, (b) mixture of proppants with different sizes, and (c) proppants undergone different levels of mechanical damage. We measured NMR response in proppant packs and quantified the impacts of proppant type, size, and mechanical damage on NMR T-2 distribution. Next, we used the fractional packing model to quantify the efficiency of packing of proppant mixture and to quantify the changes in porosity of proppant packs caused by variation in size and fraction of fines. Finally, we used Kozeny-Carman (KC) equation and modified Schlumberger Doll Research (SDR) equation to correlate the variation in T-2 distribution to the decrease in proppant pack permeability. Results showed that NMR T-2 distribution is sensitive to pore-size distribution in the proppant packs. The variable pore-size distribution was either a consequence of having a mixture of proppants with different sizes or different levels of mechanical damage. The impacts of fines on the pore-size distribution of the proppant packs was measureable, which is promising for the successful application of the introduced method for time-lapse quantification of generated fines. We also observed a measurable sensitivity of T-2 distribution to mechanical damage in the proppant packs, which enables quantifying the level of damage in proppants through quantifying pore structure in the proppant packs. The NMR T-2 measurements were, however, sensitive to the presence of paramagnetic materials such as iron in proppants. This sensitivity was more significant in cases where paramagnetic materials were distributed on the proppant surface. The proposed method is considered as an indirect measurement of pore structure and could potentially provide a quantitative assessment of the proppant pack conductivity both in the lab-scale and in-situ conditions. Improved assessment of proppant conductivity can help in enhancing the design and execution of fracture treatments for successful development of unconventional plays.",4,4,0
Fracture,Distribution,"Zhao, Hongbo; Li, Zhen; Zhu, Changxing; Ru, Zhongliang",Reliability analysis models for hydraulic fracturing,Hydraulic fracturing; Uncertainty; Reliability analysis; First order reliability method,PRINCIPAL STRESS; ELEMENT-METHOD; FLUID LAG; PROPAGATION; SIMULATION; ALGORITHM; DESIGN; SPREADSHEET; XFEM,"For many decades, hydraulic fracturing has been the technique most commonly used in the oil and gas industry to increase the productivity of low permeability reservoirs. However, much uncertainty remains when applying this technique, which can influence performance. It has proved difficult, for example, to evaluate the uncertainties inherent in traditional deterministic hydraulic fracturing models using classic analytical and numerical methods. Thus, in this study, we adapted reliability analysis to evaluate the performance of hydraulic fracturing including the length, width, and nature of a fracture when considering uncertainty. Random variables are assumed to follow a normal distribution, and the first-order reliability method (FORM) was used to calculate a reliability index for hydraulic fracturing based on Khristianovic-Geertsma-de Klerk (KGD) and Perkins-Kern-Nordgren (PKN) models. Reliability indexes obtained under different conditions show excellent agreement with Monte Carlo simulations, and indicate that use of this method provides an efficient and effective scientific approach for the uncertainty analysis of hydraulic fracturing. We also investigate and discuss the influence of elastic mechanical parameters of rock formations as well as in situ stress as random variables affecting the performance of hydraulic fracturing alongside various other factors that can influence this process, including rock tensile strength, injection rate and time. This analysis provides quantitative insights into the uncertainties that underlie hydraulic fracturing models and enables the identification of potentially influencing factors to reduce performance uncertainties. The results also show reliability analysis provides an appropriate solution for evaluation of uncertainty and can further improve the performance of hydraulic fracturing.",4,4,0
Fracture,Distribution,"Ou, Chenghua; Li, Chaochun; Huang, Siyuan; Lu, Wentao; Sheng, James J.; Xiong, Hongli",Three-dimensional discrete network modeling of structural fractures based on the geometric restoration of structure surface: Methodology and its application,Structural fractures; 3D discrete network model; Visualized characterization; Core description; Structure surface restoration; Fractured reservoir,GAS-RESERVOIRS; SHALE; FAULT; OUTCROP; BASIN; FIELD; PERMEABILITY; KINEMATICS; ANTICLINE; OIL,"Structural fractures are widely developed in the oil and gas fractured reservoirs. However, it is difficult to characterize structural fractures accurately in three-dimensional (3D) space by using: core description method; logging interpretation method; tectonic curvature method; stochastic simulation method; or seismic description method. Based on the theory of fault-related folds and stochastic simulation, a method for constructing 3D structural fracture models relying on the geometric restoration of the structure surface was developed. The structural surface geometrical restoration technique was applied to establish the structural fracture development index model. The core description results were utilized to construct the structural fracture group mode and the fracture intensity model for each fracture group. In addition, the fracture development intensity model was developed and used as the main input to construct the 3D discrete network structural fracture model based on the spatial restriction to the structural fracture development index model. This model achieves 3D visualized modeling for each group of structural fractures and their attribute characteristics. A case study was performed by applying this proposed method to a Jiaoshiba shale gas field in the braided fold belt of eastern Sichuan Basin, where a discrete network model of structural fractures with high and low angle was established. This discrete network model reconstructed the distribution, development scale, extension direction and cutting relationship of structural fractures in 3D space. The modeling results not only provide a discrete structural fractures network model for simulating the production of the Jiaoshiba shale gas field, but also provide a new method for developing a discrete structural fractures network model for sandstone reservoir, carbonate reservoir and shale reservoir.",4,5,4
Fracture,Distribution,"Abbasi, Fayyaz-Ur-Rehman; Ali, Aamir; Alves, Tiago M.; Rehman, Khaista",The accuracy of AVA approximations in isotropic media assessed via synthetic numerical experiments: Implications for the determination of porosity,Seismic amplitude vs. angle; Rock physics modelling; Non-interacting approach; Bayesian approach; Metropolis algorithm; Pre-stack seismic inversion,REFLECTION COEFFICIENTS; FRACTURED RESERVOIRS; BAYESIAN-ESTIMATION; SEISMIC INVERSION; GAS; AMPLITUDE; PERMEABILITY; UNCERTAINTY; ANISOTROPY; STIFFNESS,"Analyses of seismic amplitude vs. angle are widely used to estimate hydrocarbon reservoir properties. This paper investigates the accuracy of existing approximations based on the Zoeppritz equation, using synthetic numerical experiments that correlate P-wave reflectivity in isotropic media with reservoir porosity. An effective medium non-interacting approach (NIA) in rock physics modelling was used to compute the properties of fluid-saturated (water + gas) reservoir, which were then used in seismic modelling. In parallel, a Bayesian approach was used to estimate reservoir porosities from angle-dependent reflection coefficients and seismic amplitudes. A Maximum a posteriori solution of the Bayesian approach was also utilised to obtain an inverted porosity distribution in the reservoir model. The results of our forward models are important as they suggest that most of the approximations deviate from the exact Zoeppritz solutions with increasing angles of incidence of seismic waves. The results from the Bayesian inversion show that the Ruger and Bortfeld approximations agree with the exact Zoeppritz solutions to accurately estimate reservoir porosity. All the other approximations, except for Smith's, underestimate reservoir porosity and should be used in pre-stack inversion with caution. Smith's and Fatti's approximations failed to estimate reservoir porosity because of associated uncertainties.",5,5,1
Fracture,Distribution,"Liang, Bo; Lan, Hui-qing; Lin, Nan",Diffusion simulation and safety assessment of oil leaked in the ground,Oil; Leak Multi-phase flow in porous media; Diffusion; Test; Safety assessment,ASSESSING NAPL CONTAMINATION; MULTIPHASE FLOW MODEL; POROUS-MEDIA; GRAVITY CURRENTS; RISK-ASSESSMENT; FRACTURED MEDIA; PERSPECTIVE; SITE,"Oil leaked in the ground causes pollution of land and groundwater, and even leads to an explosion. Therefore, it is significant to make a research on safety assessment of diffusion of oil in the ground after oil leakage accident happened. Taken a perforation-caused leakage accident of oil in buried piping in China as an example, the computational fluid dynamics method of multiphase flow in porous media was used to determine the distribution of leaked oil in the ground in this paper. Then, an onsite drilling test was carried put and it's found that the simulation of distribution of leaked oil agreed with the test result. Finally, on the base of the simulation results, fuzzy synthetic evaluation method was carried out and hazardous areas of oil leaked in the ground were put forward.",5,6,2
Fracture,Distribution,"Zhou, Fengde; Shields, Daren; Tyson, Stephen; Esterle, Joan","Comparison of sequential indicator simulation, object modelling and multiple-point statistics in reproducing channel geometries and continuity in 2D with two different spaced conditional datasets",Sequential indicator simulation; Object modelling; Multiple-point statistics; Channel geometry and continuity; Amazon river,RESERVOIR; CONNECTIVITY; RECONSTRUCTION; VARIOGRAM; PROGRAM; OUTCROP; BASIN,"Fluvial sediments with multi-scale channels are difficult to model using classical two-point statistical methods, e. g. sequential indicator simulation (SIS) or object-based modelling (ObjM). Multiple-point statistics (MPS) has been used to generate facies, fracture and porosity distributions based on pattern statistics derived from training datasets. However, the ability of these three methods to reproduce channel geometry and continuity is not clear, especially when using differently spaced conditional data. This paper presents a case study to compare the application of these three methods in reproducing channels from a section of Amazon River based on two differently spaced conditional data sets. Results show that: the reproduction accuracy is similar between MPS and SIS; MPS provides the most connected channel facies (or most channel continuity) as compared to SIS and ObjM; and using a hand-drawn facies based on the sampling points yield a similar accuracy to that achieved by using the reality facies distribution as the training image. Finally, we conclude that the application of MPS does not significantly increase the reproduction accuracy when compared to SIS channel models; however, MPS can generate realistic models with respect to channel geometry and continuity.",6,7,0
Fracture,Distribution,"Pan, Xinpeng; Zhang, Guangzhi",Estimation of fluid indicator and dry fracture compliances using azimuthal seismic reflection data in a gas-saturated fractured reservoir,Amplitude variation with offset and azimuth (AVOA) inversion; Fluid and fracture characteristics; Gassmann's anisotropic poroelasticity; Bayesian inversion,ANISOTROPIC MEDIA; ELASTIC-WAVES; PARAMETERS; COEFFICIENTS; RECONSTRUCTION; SUBSTITUTION; VELOCITIES; INVERSION; SYMMETRY; MODELS,"Amplitude variation with offset and azimuth (AVOA) inversion is a powerful tool used to predict the fluid and fracture information by utilizing the observable seismic reflection amplitudes. Understanding the effect of in situ fluid and fracture characteristics on seismic response is significant in a fractured reservoir. Our goal is to demonstrate an AVOA inversion approach to utilize the observable azimuthal seismic reflection data to predict the fluid and fracture properties in a gas-saturated fractured reservoir. Starting from Gassmann's anisotropic poroelasticity theory and the linear-slip model, we first derive a linearized PP-wave reflection coefficient in terms of fluid, rigidity, density, and dry fracture compliance parameters based on the scattering function and perturbations in dry stiffness matrix of a horizontal transversely isotropic (HTI) rock containing a system of aligned vertical fractures. The derived equation builds a linearized relationship between the characteristics of fluid and fracture and the seismic response of azimuthal seismic reflection amplitudes. Incorporating the convolution model and Bayesian inversion, we propose a feasible Bayesian AVOA inversion method to estimate the fluid and fracture parameters directly. Cauchy and Gaussian probability distribution are used for the a priori information of model parameters and the likelihood function, respectively, and the nonlinear iteratively reweighted least squares (IRLS) strategy is finally utilized to solve the maximum a posteriori solutions of model parameters. The synthetic examples containing a moderate noise demonstrate the feasibility of inversion method, and the real data illustrates the inversion stabilities of fluid and fracture parameters in a gas-saturated fractured reservoir.",6,7,1
Fracture,Distribution,"Freire Soares, Andreia Silveira; Costa Marques, Monica Regina; Calcada, Luis Americo; Borges Filho, Moacyr Nogueira; de Oliveira Petkowicz, Carmem Lucia",Interaction of blockers on drilling fluids rheology and its effects on sealing of fractures and prevention of filtrate invasion,Drilling fluids; Lost circulation and loss control material,XANTHAN GUM; PARTICLE-SIZE; FLOCCULATION; BENTONITE; WATER; MONTMORILLONITE; PERFORMANCE; POLYMERS; CHARGE,"Drilling fluids from oil wells play an important role in the drilling operations, including cleaning and maintaining well stability, as well as cooling and lubricating the drill bit. Invasion of fluid in the rock formation, through natural or induced fractures, can compromise the entire well. In this work we evaluated the effect of combination of viscosifiers xanthan gum (XG), carboxymethylcellulose (CMC), Hydroxypropylstarch (HPS) and bentonite in the interaction with lost circulation materials diatomaceous earth (DE) and hydrogel (HG). The main objective was to obtain a product with adequate rheological properties showing viscoelastic behavior and minimizing loss of fluid to the wellbore. Tests of X-ray diffraction (XRD) and zeta potential were performed to analyze the interactions between the particles present in the fluids. With rheological tests we studied the effects of the addition of different components on the fluid rheology. XRD technique showed that the bentonite deflocculated only in polymer suspensions with DE. The results of zeta potential suggest that only the fluid with Hydroxypropylstarch and HG was completely flocculated and unstable, showed through particle sizes distribution tests. The gel modulus (G') and viscous modulus (G '') of the fluids were affected by the interaction of bentonite layers with lost circulation materials particles, with significant increase of G' with the addition of HG to the suspension. There was a decrease of viscosity due to agglomeration of HG and DE particles, an increase of G' can be observed as well. Among all the fluids, the suspension of CMC and bentonite showed better affinity with the HG lost circulation material, presenting thermal stability and a wide range of particle size, essential property to avoid the loss of fluid through the fractures and pores of the rock formation.",6,6,2
Fracture,Distribution,"Zeng, Yan; Ning, Zhengfu; Wang, Qing; Sun, Hongliang; Huang, Liang; Ye, Hongtao",Gas transport in self-affine rough microchannels of shale gas reservoir,Shale; Roughness effect; Triple-effect permeability model; Lattice Boltzmann method; Permeability,LATTICE BOLTZMANN METHOD; FLUID-FLOW; SURFACE-ROUGHNESS; POISEUILLE NUMBER; PRESSURE-DROP; SICHUAN BASIN; FRACTURE; SIMULATION; MODEL; MICRO,"The matrix of shale gas reservoirs is always characterized by rough surfaces and the roughness of the topography significantly influences the gas flow characteristics. However, most existing models are based on smooth surface. Moreover, the roughness effect leads to a complex velocity distribution and can influence the apparent permeability through its own transport mechanism. In this study, a generalized lattice Boltzmann method with nonequilibrium extrapolation boundary conditions was developed to simulate the rarefied shale gas flow through nanochannels with rough surface. Fractal geometry was introduced to model the rough surface, and the roughness was characterized by two parameters, namely, relative roughness height and fractal dimension. Triple-effect permeability estimation model was adopted to calculate the apparent permeability accounting for multiple roughness characteristics including surface tortuosity, hydraulic tortuosity, and local roughness. Effects of fractal dimension, relative roughness, and tortuosity on velocity distribution were investigated. The effect of pressure and roughness characteristic parameters on the apparent permeability at different Knudsen numbers was also studied. The results showed that the influence of fractal dimension and relative roughness on the permeability was affected by the rarefaction effect. The roughness effect on gas flow behavior became more evident when associated with the enhanced rarefaction effect. Moreover, relative roughness was found to play a significant role in determining the permeability in the transient flow regime.",7,8,1
Fracture,Distribution,"Kim, Jihoon; Um, Evan Schankee; Moridis, George J.",Integrated simulation of vertical fracture propagation induced by water injection and its borehole electromagnetic responses in shale gas systems,Hydraulic fracturing; Shale gas; Electromagnetic geophysics; Coupled flow and geomechanics,HYDRAULIC-FRACTURE; POROSITY MATERIALS; RESERVOIR; FLOW; GEOMECHANICS; TOMOGRAPHY; FERROFLUID,"We analyze fracture propagation induced by hydraulic fracturing with water injection and examine their detectability with crosswell electromagnetic (EM) geophysical methods. For rigorous 3D coupled flow-geomechanical modeling, we employ a numerical method that can model failure by tensile and shear stresses, dynamic nonlinear permeability, dual continuum approach, and thermo-poro-mechanical effects. From numerical simulation, we find that the fracture propagation is not the same as propagation of the water front, because fracturing is governed by geomechanics whereas water saturation is determined by multiphase flow. At early times, the water front is almost identical to the fracture tip, suggesting that the fracture is mostly filled with the injected water. However, at late times, movement of the water front is retarded compared to fracture propagation, yielding a significant gap between the water front and the fracture top, filled with reservoir gas. During fracture propagation, the coupled flow-geomechanical models are transformed via a rock-physics model into electrical conductivity models. We employ a full 3D finite-element EM geophysical simulator to evaluate the sensitivity of the crosswell EM method to fracture propagation. It is shown that anomalous distribution of electrical conductivity is closely related to the injected water saturation, but not closely related to newly created unsaturated fractures. Our numerical modeling experiments demonstrate that the crosswell EM method can be highly sensitive to electrical conductivity changes that directly indicate the migration pathways of the injected fluid. Accordingly, the EM method can serve as an effective monitoring tool for monitoring the injected fluids during hydraulic fracturing operations.",7,7,2
Fracture,Distribution,"Zeng, Qinglu; Lu, Wenzhong; Zhang, Ronghu; Zhao, Jilong; Ren, Ping; Wang, Bo","LIDAR-based fracture characterization and controlling factors analysis: An outcrop case from Kuqa Depression, NW China",LIDAR; Fracture; Development characterization; Controlling factors; Kuqa Depression,THRUST BELT; EXAMPLE; MODELS; RESERVOIRS; SANDSTONE; GEOLOGY,"Fracture is of primary importance to the natural gas production capacity from many tight sandstone reservoirs in the Kuqa foreland basin, NW China, but the orientation, size and plane porosity of the fractures in the subsurface is difficult to measure directly. Terrestrial light detection and ranging (LIDAR) surveys can offer factual information of outcrop-based research efforts to characterize fracture development laws and controlling factors. In this paper, utilizing a multi-level covering, we obtain the three dimensional (3D) point cloud data from a LIDAR survey launched at a typical outcrop. Matching with high-resolution digital photos and artificial measured information, the 3-D positions of natural fractures are extracted strictly in the data volume section. Furthermore, the fracture and reservoir model can be founded based on the systematic sampling and laboratory analysis, while a variety of accurate facture parameters can be obtained. It is founded that three groups of shear fractures are mainly developed in two periods with large inclination, short trace length and small spacing of normal distribution. Its patterns has provided a literal distribution of penetrating fracture zone and interlayer fracture zone with a single and a double set of advantage orientation respectively. It turned out that the fracture development scale is controlled by lithology, layer thickness, maximum principle paleostress and rock composition with a good exponential relationship. Our work could provide a workflow linking outcrop fracture observations to the 3D model of subsurface fracture prediction and extend modeling capability in other outcrop studies.",7,9,2
Fracture,Distribution,"Guo, Chaohua; Li, Qianyao; Wei, Mingzhen","Pore structure characteristics of marine Silurian shales in the Sichuan Basin, China: Insights to reserve assessment and production design",Silurian shale; Pore structure; SEM-Imaging; Mineralogy analysis; Over-mature,ORGANIC-RICH SHALES; SOUTHERN SICHUAN; GAS-STORAGE; NORTHERN GERMANY; LONGMAXI SHALE; LOWER TOARCIAN; CLASSIFICATION; PERMEABILITY; HAYNESVILLE; MARCELLUS,"Due to shortage of conventional resources, tight/shale oil/gas reservoirs have become increasingly important in balancing the energy consumption in China. As the most important shale reservoirs in China, marine Silurian shales in the Sichuan Basin have received intensive investigation during recent years in the area of pore structure characterization and reserve assessment. However, no work has been conducted to compare the China shale plays with other mature shale plays in the North America using multiple experimental methods based on the mineralogy analysis and organic geochemistry. In this paper, pore structure, formation porosity, total organic carbon ( TOC), thermal maturity, and mineralogy of 36 samples in Longmaxi shale and 7 samples in Qiongzhusi shale have been investigated using multiple experimental methods. FIB-SEM imaging results show that Longmaxi shale gas reservoir include primary pores, residual intergranular pores, dissolution pores, and intergranular pores. The majority of the pores are distributed in residual intergranular pores, secondary dissolution pores, and intercrystalline pores, but less in primary intergranular pores. X-ray diffraction analysis shows that the clay minerals of Longmaxi shale reservoir mainly consist of illite and kaolinite, then followed by chlorite. The content of kaolinite is from 7.2% to 16.87%, and the average is 12.21%. The content of illite is from 8.03% to 26.8%, with the average of 16.1%. TOC tests show that most of the samples have their TOC more than 0.5%, which means Longmaxi formation has a potential to produce shale gas. Clay minerals mainly include quartz, K-feldspar, calcite, dolomite, anorthose, and pyrite. The quartz has the highest content value, followed by calcite, which are 29% and 22% average respectively. The content of pyrite and anorthose are less than 10%. The average content of brittle minerals of Longmaxi formation samples is 66% (> 50%), which is suitable for hydraulic fracturing. Thermal maturity tests show that Vitrinite reflectance of each sample is more than 2.0%, which indicates that it is high enough to generate shale gas in the formation. Comparing with other mature shale plays, the Longmaxi and Qiongzhusi shale plays have lower porosity and lower TOC than that of the U.S. shale plays, and the quartz content and thermal maturity are similar. The Qiongzhusi shale and Longmaxi shale are over-mature ( Ro> 2.5%) compared with U.S. shale plays. The results of this study will contribute to the formation characteristics understanding and reserve assessment of China shale plays. Also, it will facilitate the development of suitable and efficient production plan for China shale plays.",7,7,3
Fracture,Distribution,"Paes de Godoi, Felipe Augusto; Scheid, Claudia Miriam; Bernardo, Leticia Siqueira; de Oliveira, Beatriz Rosas; Borges Filho, Moacyr Nogueira; Calcada, Luis Americo",Study of the pressure drop and the flow of loss circulation material suspensions in a physical simulator of fractures,Fractures sealing; Flow of suspensions; Calcium carbonate; Particulate system,,"The loss of fluid to the rock formation is one of the main problems encountered in oil well drilling operations. To mitigate this problem, particulate materials responsible for sealing fractures or for strengthening the well are used. The main objective of this work is to study the flow of Non-Newtonian suspensions through fractures, the pressure drop associated with this flow and the process of sealing fractures using particulate materials suspensions. The flow through fracture of Non-Newtonian suspensions was studied using an apparatus that allowed these fluids to flow through three different artificial fractures with widths of 2 mm, 5 mm and 10 mm and an average 1 cm depth. The suspensions were prepared by mixing water, viscosifying polymer and particulate materials based on laminar calcium carbonate. The particulate materials used are called fine and medium because they have different particle size distributions. The characterization of the solutions and suspensions was carried out from the rheological tests and the determination of the densities and the particle size distributions. The influence of factors such as flow rate, concentration and particle size distributions on the flow of the suspensions through fractures and its sealing capabilities were evaluated. The suspensions of the fine material particles were able to seal only the 2 mm fracture. The suspension composed of the particles of the medium material proved efficient in sealing the three fractures. A mathematical methodology was proposed with the objective of correlating the pressure drop and the flow rate of suspensions in fractures.",7,7,3
Fracture,Distribution,"Dong, Kai; Zhu, Ding; Hill, A. Daniel",Mechanism of wormholing and its optimal conditions: A fundamental explanation,Wormholing mechanism; Carbonate acidizing; Optimal conditions; Pore growth function; Pore scale,POROUS-MEDIA,"Acid stimulation is commonly used in carbonate reservoirs, which can be either matrix acidizing or acid fracturing. In both treatments, wormholes can form. In matrix acidizing, wormholing is favorable because the damaged region can be bypassed. In acid fracturing, wormholing is not desired because it can increase fluid loss, which can limit conductive fracture length. Three major processes are involved for wormholing: convection, diffusion and surface reaction. A thorough understanding of these processes is necessary for engineering design. In this paper, we fundamentally explore wormholing mechanisms starting from pore growth. A wormhole forms when larger pores grow in cross-sectional area at a rate that greatly exceeds the growth rate of smaller pores due to surface reaction. This happens when pore growth follows a particular mechanism, which is discussed in this paper. We developed a model to predict wormhole growth behavior. The model uses the mode-size pore in a pore size distribution - the pore size that appears most frequently in a distribution - to predict the growth of the pore. By controlling the acid velocity inside of it, we can make larger pores grow much faster than other smaller pores, thus reaching the most favorable condition for wormholing. This also results in a balance between overall acid/rock reaction and acid flow. By understanding the wormholing mechanism, engineers can select proper treatment fluids and pumping rate for acid stimulation design.",8,9,0
Fracture,Distribution,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Fracture,Distribution,"Chen, Ming; Zhang, Shicheng; Ma, Xinfang; Zhou, Tong; Zou, Yushi",A semi-analytical model for predicting fluid partitioning among multiple hydraulic fractures from a horizontal well,Multi-cluster fracturing; Semi-analytical method; Homogeneous growth; Interaction stress; Perforation friction,PERFORATION CLUSTERS; NETWORK PROPAGATION; NATURAL FRACTURES; SIMULATION; GROWTH; XFEM; ROCK; RESERVOIRS; FLOW,"Multiple fracture growth during multi-cluster fracturing of a horizontal well is closely dependent on fluid partitioning. However, whether injected fluid can uniformly flux into multiple fractures during fracturing remains uncertain. In this study, a semi-analytical model was proposed to simulate fluid rate distribution in multiple fractures. Multi-fracture interaction stresses in the model are solved by a detailed approximation of the elastic solution for a pressurized fracture, which are integrated with rock deformation equations to calculate the multi-fracture width. The semi-analytical model was validated with a well-recognized fully coupled hydraulic fracture simulator. The semi-analytical model can efficiently optimize perforation parameters for multi-cluster fracturing of a horizontal well. Sensitivity analysis was conducted by using the model, and simulation results show that perforation friction and interaction stress are two key factors that determine fluid partitioning among multiple fractures. When interaction stress dominates the flow pressure drop in multiple fractures, fluid partitioning among multiple fractures is uneven due to heterogeneous interaction stresses among multiple fractures; otherwise, fluid partitioning is evenly distributed. Decreasing the total number or diameter of perforation holes can promote uniform multi-fracture growth and fluid partitioning. Homogenous fluid partitioning can be achieved by decreasing the perforation number of exterior fractures, whereas increasing the perforation number of interior fractures minimally affects uniform fluid partitioning among multiple fractures.",8,8,2
Fracture,Distribution,"Yi, Sophie S.; Sharma, Mukul M.",A new method to calculate slurry distribution among multiple fractures during fracturing and refracturing,Fluid partitioning; Slurry distribution; Simulation of multi-fracture stimulation; Plug-and-perf stages; Re-fracturing,,"An accurate calculation of slurry distribution among multiple perforation clusters is necessary for all multifracture simulators. The slurry distribution was solved by applying the Newton-Raphson Method in the past. This method requires a numerical evaluation of the Jacobian matrix and can be unstable in some cases. In this paper, we propose a new approach to calculate slurry distribution among multiple fractures, the Resistance Method. This new approach is computationally efficient, requires no Jacobian matrix calculation, and has been proved to converge locally at least linearly. The Resistance Method is derived by reforming the mass conservation and pressure continuity equations for multiple fractures into a system of nonlinear fixed-point iteration equations. In the new equation system, the fracture resistance is defined as the pressure drop per unit flow rate. And the injected slurry is distributed among multiple fractures in inverse proportion to the resistance of each fracture. This new slurry distribution method has been applied to several different fracture models. The convergence of this new slurry distribution method has been analyzed with the map contraction theory. In this paper, we show three example applications of the Resistance Method. First, the Resistance Method is implemented with an analytical PKN model, with direct comparison made with the Newton-Raphson method. Simulation results show that both methods solve the slurry distribution accurately, but we show that the Resistance Method can be more computationally efficient than the Newton-Raphson Method. Second, the Resistance Method is used to obtain the proppant distribution in multiple clusters with particle transport efficiency curves implemented implicitly. It is shown that the proppant distribution among multiple clusters can be quite different from the fluid distribution. Due to inertial effects, proppant tends to accumulate towards the toe side clusters and causes pre-mature screen-out, resulting in a heel-biased treatment. Third, the Resistance Method is used in a refracturing example problem. A synthetic refracturing treatment with 50 existing fractures, 49 new clusters and about 15 h' treatment time was simulated. The results show that the refrac treatment is heel biased with the 20 heel side clusters receiving most of the treatment and that both existing fractures and new perforations propagate during refracturing. In such simulations extending over long periods of injection and with a large number of perforation clusters it is important to have a very efficient solver to obtain the fluid and proppant distribution in a reasonable computational time frame. In this work, we developed a new method to calculate slurry distribution among multiple clusters with applications to fracturing and refracturing treatments. This new method can be integrated with any fracture model. The main advantages of this new approach include: 1) simple implementation, 2) no numerical evaluation of the Jacobian matrix, 3) computationally efficiency, and 4) easy integration of slurry distribution, proppant transport, stress shadow effects and multiple fracture propagation.",8,9,3
Fracture,Distribution,"Damani, A.; Sondergeld, C. H.; Rai, C. S.",Experimental investigation of in situ and injection fluid effect on hydraulic fracture mechanism using acoustic emission in Tennessee sandstone,Hydraulic fracturing mechanism; Laboratory hydraulic fracturing; Acoustic emission; Microseismic; SRV; Fluid effect,VISCOSITY; ROCK,"Hydraulic fracture propagation and associated rock failure mechanism is dependent on multiple factors including the reservoir pore fluid and its interaction with the rock and the fracturing fluid. This dependence of rock failure on in situ pore fluid could affect the stimulated volume and could manifest itself in the hydraulic fracturing diagnostics such as treatment pressure and microseismic. Therefore, it would be beneficial to an engineer designing, planning or interpreting a fracturing treatment to be aware of expected differences in hydraulic fracture responses in formations having different reservoir fluids, i.e. fracturing a gas or oil bearing formation. We investigate this effect by way of laboratory hydraulic fracturing experiments on triaxially stressed samples of Tennessee sandstone. The acoustic response during rock failure was monitored using 16 P-wave transducers and the waveforms were acquired using a continuous acoustic monitoring system. The effects of pore pressure, water weakening and viscosity of the injection fluids on hydraulic fracture propagation and associated damage are investigated using six experiments on dry, brine saturated and dodecane saturated Tennessee sandstone, fractured with either water (1 cP) or oil (50 cP). Significant rock weakening was observed in fluid saturated samples (breakdown pressures exhibited a reduction of 15-40% from dry state breakdown pressures); the presence of more polar fluid (water) in the pore space resulted in more weakening (800-900 psi lower breakdown pressures when water saturated vs. dodecane saturated). The effect of injection fluid viscosity is observed to be suppressed for fluid saturated samples as breakdown pressures for samples which were saturated with either fluid (brine and dodecane) were observed to be almost same. Acoustic event distributions, continuous stream monitoring, failure mechanisms and permeability measurements on fractured cores all seem to suggest a more complex fracture network in dry rock and more conventional tensile type failure in brine saturated rock. Continuous acoustic stream energy variation with time offers insight into the induced fracture complexity and should be used along with microseismic cloud distributions to assess the stimulated reservoir volume.",8,9,4
Fracture,Shale Gas,"Thompson, Leslie G.",Modeling the effects of fracture interference using a spectral gas reservoir simulator,Fracture interference; Numerical modeling; Horizontal well; Shale gas; Unconventional reservoir,,"Economic success in the Cana Woodford shale play in Western Oklahoma has been largely due to field development using vertically fractured long horizontal laterals. In progressing from the field delineation phase, where sections are held by single well, to the field development phase, where multiple new wells are added to a previously produced section, many of the pre-existing ""parent"" wells suffer significant reduction in productivity as a result of interference from fracturing operations in the neighboring ""infill"" wells. We hypothesized that the change in the parent well's productivity was due to changes in fracture conductivity and/or changes in effective fracture length. In order to investigate the validity of our hypothesis, we developed a novel high-resolution spectral gas reservoir simulator to determine whether we could mimic the observed production behavior in the field. In particular, we wanted a simulator that would be immune to spatial truncation errors associated with finite difference schemes, and which would allow us to clearly examine interaction between nanodarcy reservoir matrix and high permeability narrow fractures; in addition, we needed the ability to alter fracture permeability with time to simulate the hypothesized effects of fracture interference. This paper details development of the spectral simulator and demonstrates that changes in fracture conductivity and length due to the interference event can account for observed productivity changes. We qualitatively compare simulator data to observed field data and show that changes in well productivity due to fracture interference can be explained by alteration of fracture half length and/or fracture conductivity.",2,2,0
Fracture,Shale Gas,"Osiptsov, A. A.; Boronin, S. A.; Zilonova, E. M.; Desroches, J.",Managed Saffman-Taylor instability during overflush in hydraulic fracturing,Hele-Shaw cell; Hydraulic fracturing; Saffman-Taylor instability; Yield stress; Bingham fluid; Proppant transport; Fingering; Slumping; Shale gas fracturing; Fracture,YIELD-STRESS FLUIDS; HELE-SHAW CELL; NEWTONIAN SLURRY; SUSPENSION FLOW; DISPLACEMENT; PLACEMENT; MECHANICS; MODEL,"Overflushing is a common practice in multistage completions of horizontal wells in unconventional formations. It consists in displacing the suspension by a thin fluid, away from the wellbore and into the fracture. It can, however, overly displace proppant and leave a significant portion of the fracture unsupported near the wellbore, or trigger gravity slumping, again leaving unpropped area near the wellbore. That unpropped area can then close during production, damaging the performance of the fracture. A novel modeling approach was investigated to gain insight into the overflush process and determine secure bounds for maintaining the fracture performance. From a fluid mechanics viewpoint, overflushing is the displacement of a Hershel-Bulkley fluid by a power law fluid in a Hele-Shaw cell, leading to Saffman-Taylor instability at the fluids interface. Whereas most hydraulic fracturing simulators use power-law rheology model, we used a novel numerical approach accounting for the yield-stress behavior of the slurry. Using the lubrication approximation, we derived a model, which includes transport equations for fluid volume fractions and a nonlinear elliptic equation for pressure with mixed-type boundary conditions. Validation was previously performed against three sets of experiments in Hele-Shaw cells, comprising gravitational slumping and displacement of fluids with fingering. Based on fracture mechanics, we analyzed how large a portion of the fracture may be left unsupported before it is severely pinched during drawdown. A parametric study was performed on the displacement of the yield-stress slurry by the overflushing fluid. Qualitatively, when fingers of the overflushing fluid can be created at the overflush/slurry interface, large slurry pillars are preserved in the near-wellbore area, which may keep the fracture open. Three main scenarios of fluids distribution are identified and classified in terms of the oveflush fluid-to-slurry viscosity ratio.: (i) the slumping-dominated regime, where light clean overflush fluid goes on top of sedimenting heavy proppant-laden suspension (xi greater than or similar to 0.1), (ii) an intermediate scenario of slumping combined with fingering (xi similar to 0.01), and, finally, (iii) a pure fingering-dominated scenario, when the slurry viscosity is high (xi < 10(-3)). The third scenario minimizes the geomechanical risks of overflushing by providing tiny fingers that are unlikely to be pinched out during fracture closure.",2,2,0
Fracture,Shale Gas,"Jadoon, Quaid Khan; Roberts, Eric M.; Henderson, Robert A.; Blenkinsop, Thomas G.; Wust, Raphael A. J.","Mineralogical variability of the Permian Roseneath and Murteree Shales from the Cooper Basin, Australia: Implications for shale properties and hydrocarbon extraction",Shale gas; Roseneath; Murteree; Brittleness; Plasticity; Cooper Basin,SOIL; MODEL; CLAY,"Brittleness and plasticity indices in hydrocarbon reservoirs are calculated to understand how rocks behave under stress, and for assessing the fracturing performance of clay-rich shale reservoirs and assessing borehole stability. Evaluating shale plasticity/brittleness requires careful analysis of clay mineral composition in target shales and the development of fracking strategies for optimal shale stimulation. Here we report on the mineralogical variability of two Permian lacustrine shale units, the Roseneath and Murteree shales in the Cooper Basin, Australia, that are considered to have potential as unconventional hydrocarbon producers. The study involved a combination of X-ray diffraction, scanning electron microscopy and petrophysical modelling of the Roseneath and Murteree shales in order to obtain a better understanding of the compositions and microfabrics of these two units. This is part of a larger investigation of the shale gas potential of these two units in the Cooper Basin, and the results presented here may ultimately lead to improved reservoir stimulation techniques in both units. Core data has been integrated with wireline logging data to better identify brittle and plastic zones within the Roseneath and Murteree shales. Mineralogical analysis shows that both units are composed mainly of detrital quartz and clay/mica minerals with siderite cement. The clay mineral composition is dominated by illite/mica, and kaolinite in both units. However, based on the relative mineralogical differences between the two units, the Murteree Shale has more favourable brittle properties than the Roseneath Shale, and is considered to be more amenable to hydraulic fracturing for gas exploitation. However, the Roseneath Shale also has potential for gas stimulation, especially in intervals where siderite cement is prevalent.",2,3,1
Fracture,Shale Gas,"Ou, Chenghua; Li, Chaochun; Huang, Siyuan; Lu, Wentao; Sheng, James J.; Xiong, Hongli",Three-dimensional discrete network modeling of structural fractures based on the geometric restoration of structure surface: Methodology and its application,Structural fractures; 3D discrete network model; Visualized characterization; Core description; Structure surface restoration; Fractured reservoir,GAS-RESERVOIRS; SHALE; FAULT; OUTCROP; BASIN; FIELD; PERMEABILITY; KINEMATICS; ANTICLINE; OIL,"Structural fractures are widely developed in the oil and gas fractured reservoirs. However, it is difficult to characterize structural fractures accurately in three-dimensional (3D) space by using: core description method; logging interpretation method; tectonic curvature method; stochastic simulation method; or seismic description method. Based on the theory of fault-related folds and stochastic simulation, a method for constructing 3D structural fracture models relying on the geometric restoration of the structure surface was developed. The structural surface geometrical restoration technique was applied to establish the structural fracture development index model. The core description results were utilized to construct the structural fracture group mode and the fracture intensity model for each fracture group. In addition, the fracture development intensity model was developed and used as the main input to construct the 3D discrete network structural fracture model based on the spatial restriction to the structural fracture development index model. This model achieves 3D visualized modeling for each group of structural fractures and their attribute characteristics. A case study was performed by applying this proposed method to a Jiaoshiba shale gas field in the braided fold belt of eastern Sichuan Basin, where a discrete network model of structural fractures with high and low angle was established. This discrete network model reconstructed the distribution, development scale, extension direction and cutting relationship of structural fractures in 3D space. The modeling results not only provide a discrete structural fractures network model for simulating the production of the Jiaoshiba shale gas field, but also provide a new method for developing a discrete structural fractures network model for sandstone reservoir, carbonate reservoir and shale reservoir.",4,5,4
Fracture,Shale Gas,"Wang, Fei; Pan, Ziqing; Zhang, Shicheng",Coupled thermo-hydro-chemical modeling of fracturing-fluid leakoff in hydraulically fractured shale gas reservoirs,Shale gas; Hydraulic fracturing; Water leakoff; Thermo-hydro-chemical coupling; Numerical simulation,PART I; BEHAVIOR; OIL; PRESSURE; OSMOSIS; FLOW; COAL,"Once the low-temperature, high-pressure and low-salinity water contacts the shale matrix through the hydraulic fractures during the treatment of hydraulic fracturing, both mass and energy transfer occur due to the significant temperature, pressure, saturation and salinity gradients. Although, many leakoff models have been published, none of the models coupled the transient fluid flow modeling with heat transfer and chemical-potential equilibrium phenomena. In this paper, a coupled thermo-hydro-chemical (THC) model based on the derivation of non-isothermal chemical-potential equations from Gibbs' free energy is presented to simulate fluid/heat flow behaviors during the leakoff process of hydraulic fracturing. The THC model takes into account a two-phase flow and a triple-porosity medium, which includes hydraulic fractures, organic and inorganic shale matrix. The simulation of fluid flow and leakoff with the THC model accounts for all the important mass and heat transfer processes occurring in fractured shale system, including fluid transport driven by convection, adsorption and diffusion, and heat transport driven by thermal convection and conductivity. The dynamic temperature, pressure, saturation and salt concentration profiles within fractures and shale matrix are calculated, revealing a multi-field coupled invasion region of fracturing-fluids during the treatment of hydraulic fracturing. In sensitivity analyses, cases with different initial reservoir temperature, pressure, saturation and brine salinity are considered. The impacts of the temperature, pressure, saturation and salinity gradients between the shale formation and the pumped fluids on the well injection and leakoff volumes during the treatment of hydraulic fracturing are investigated. Results show that although hydraulic pressure is the most factor which affects the fracturing-fluid leakoff behavior, the combination of chemical-osmosis, thermal-osmosis and capillarity still has a non-negligible influence on the fracturing-fluid leakoff. This study provides a better understanding of the mass and heat transport mechanism of water-based fracturing-fluids in shale gas reservoirs.",5,5,8
Fracture,Shale Gas,"Luo, Xiangrong; Ren, Xiaojuan; Wang, Shuzhong; Li, Xiaoxiao; Ma, Huanhuan; Liu, Yuyan",Experimental study on convection heat-transfer characteristics of BCG-CO2 fracturing fluid,BCG-CO2 fracturing fluid; Heat transfer; Foam quality; Shear rate,THERMAL-CONDUCTIVITY; LAMINAR-FLOW,"A BCG-CO2 fracturing fluid system is especially suitable for shale gas stimulation because it has many advantages, including minimizing water consumption, reducing damage to the formation, and recovering more rapidly and efficiently. A major objective of this experimental study is to ascertain the convection heat-transfer characteristics of a BCG-CO2 fracturing fluid system. A high-parameter foam fracturing fluid test system was adopted in this study. The measurement of convection heat transfer is based on the double-wall heat-transfer theory. Through experimental research, the correlations for BCG-CO2 fracturing fluid convection heat transfer have been obtained under different foam qualities. The average error of the fitting formula for all experimental data is 10.7%. The results indicate that the convection heat-transfer coefficient decreases with increasing temperature, with an average decrease of about 10%. The convection heat-transfer coefficient shows a decreasing trend with increasing foam quality. There is a linear relationship between the convection heat-transfer coefficient and shear rate, and the shear rate has the most pronounced effect on convection heat-transfer characteristics. The results of this study can be used to calculate heat-transfer parameters to determine the temperature field of BCG-CO2 fracturing fluid flow in fracturing design, and they are significant for the engineering application of BCG-CO2 fracturing fluid.",6,8,2
Fracture,Shale Gas,"Zhao, Lin; Jiang, Hanqiao; Zhang, Shaoqing; Yang, Hanxu; Sun, Fengrui; Qiao, Yan; Zhao, Lijun; Chen, Wenbin; Li, Junjian",Modeling vertical well in field-scale discrete fracture-matrix model using a practical pseudo inner-boundary model,Discrete fracture-matrix model; Vertical fractured well; Well model; Mesh generation; Transmissibility evaluation,NUMERICAL RESERVOIR SIMULATION; EQUIVALENT WELLBLOCK RADIUS; SHALE GAS; HORIZONTAL WELLS; BLOCK PRESSURES; MESH GENERATOR; GRIDS; MATLAB; FLOW; PERMEABILITY,"The discrete fracture-matrix model (DFM) technique has contributed to the rapid development of fracture modeling. In terms of vertical well modeling, however, the current well models fail to handle the field-scale DFM utilization. In this study, a pseudo inner-boundary model is presented tailored to this problem. Specifically, the modeling methodology consists of mesh generation and transmissibility evaluation. Regarding the mesh generation, the model handles the 2-D triangular-gridded matrix and 1-D edge-gridded fracture. The strict geometric analogy to generate triangles for the wellbore is abandoned, instead, the wellbore is approximated by a source/sink point and returns to a circular geometry when evaluating the transmissibility. The treatment sheds the limitation of triangle size and proves to boost the generation efficiency. Regarding the transmissibility evaluation, the derived formulations apply the radial/linear approximation for flow in matrix/fracture well-gridblock, and various conditions are considered, including gridblock geometry (triangle and rectangle), flow state (steady-state, unsteady-state and pseudosteady-state) and well completion (fully penetrating well and partially penetrating well). In addition, the compatibility with the star-delta transformation is discussed. By refining the well-gridblock into several sub-triangles, the formulations could be rapidly implemented to non-triangle-based DFM (e. g. PEBI, Cartesian). The model performance is demonstrated in eight validation cases. The model is shown to provide results in close agreement with those of reference in cases where the direct comparisons are performed.",6,6,4
Fracture,Shale Gas,"Dai, Caili; Sun, Xin; Sun, Yongpeng; Zhao, Mingwei; Du, Mingyong; Zou, Chenwei; Guan, Baoshan",The effect of supercritical CO2 fracturing fluid retention-induced permeability alteration of tight oil reservoir,Permeability alteration; SC-CO2 fracturing fluid; Adsorption; Trapping; Tight oil reservoir,INVESTIGATE FORMATION-DAMAGE; SHALE GAS; PERFORMANCE; OPTIMIZATION; INJECTIVITY; SILICA,"Supercritical CO2 (SC-CO2), as a non-aqueous material of fracturing fluid, receives widely attention in the development of unconventional reservoirs. In this study, permeability regain (K-rg) was introduced to characterize the permeability alteration on tight cores by SC-CO2 fracturing fluid. Meanwhile, scanning electron microscope (SEM), microscope system, nuclear magnetic resonance (NMR) were used to reveal the mechanisms of permeability alteration at different scales. The results showed that the composition of SC-CO2 fracturing fluid, fluid filter loss, and reservoir permeability were all responsible for permeability alteration. With the increasing thickener contents and filter loss of fracturing fluid, core permeability regains turned to be declined. Comparatively, tight cores which consist of more micro-nanometer sized pores were more likely to receive more formation damage of permeability, as well. The retention of thickener in microchannels (micro pores) were confirmed to be the main mechanisms on permeability alteration.",6,7,4
Fracture,Shale Gas,"Wang, Fei; Pan, Ziqing; Zhang, Yichi; Zhang, Shicheng",Simulation of coupled hydro-mechanical-chemical phenomena in hydraulically fractured gas shale during fracturing-fluid flowback,Fracturing-fluid flowback; Shale gas reservoirs; Hydro-mechanical-chemical model; Fracture closure; Chemical osmosis,PART I; IMBIBITION; PRESSURE; BEHAVIOR; BRINE; WELLS; COAL; OIL,"Fracturing-fluid flowback in hydraulically fractured gas shale is a complicated transport behavior involving hydrodynamic (H), mechanical (M) and chemical (C) processes. Although, many flowback models have been published, none of the models flly coupled the transient fluid flow modeling with chemical-potential equilibrium and fracture closure phenomena. In this paper, a coupled hydro-mechanical-chemical (HMC) model based on hydrodynamics, linear-elastic fracture mechanics, and chemical-potential equations is presented to simulate the fracturing-fluid flowback behavior in hydraulically fractured gas shale. The HMC model takes into account a gas-liquid two-phase flow and a triple-porosity medium, which includes primary hydraulic fractures, secondary induced fractures and shale matrix. The flowback simulation with the HMC model accounts for all the important processes in fractured shale system, including (1) water transport driven by hydraulic, capillary and osmotic convections, (2) gas transport induced by both hydraulic pressure driven convection and adsorption, and (3) fracture closure considered as an elastic deformation. The fluid transport, coupled with rock deformation, are described by a set of partial differential equations. The semi-implicit finite-difference method is used to solve these equations. The evolution of pressure, saturation, salinity and aperture profiles of hydraulic fractures, induced fractures and matrix is calculated, revealing the multi-field coupled flowback behavior in fractured gas shale. The sensitivity analysis is also performed to investigate the physiochemical properties of shale on the water load recovery and gas production rate during the fracturing-fluid flowback. The results indicate that the capillarity has the most effect followed by chemical osmosis and induced fracture closure. The sub-irreducible water saturation has the weakest effect. Moreover, the matrix-related physiochemical parameters cause opposite influences on water load recovery and gas production rate. While, the influence of induced fracture-related parameters on both water load recovery and gas production rate is consistent. Results from this study are expected to explain which is the predominant mechanism for fracturing-fluid retention and the inherent relationship between fracturing-fluid flowback and gas production for different initial physiochemical properties of shale.",6,6,12
Fracture,Shale Gas,"Thompson, Leslie G.",Horizontal well fracture interference - Semi-analytical modeling and rate prediction,Fracture interference; Analytical modeling; Horizontal well; Shale gas; Unconventional reservoir,,"A semi-analytical superposition model for analyzing pressure and rate data from wells where production characteristics were altered because of interference from nearby fracture operations is presented. In previous work (Thompson (2017)), specialized numerical simulations showed that these production changes could be explained by changes to the total fracture half-length and fracture permeability; in turn, these parameters alter the completion's linear flow parameter, root kA, (which we loosely refer to here as the well's linear ""flow capacity"") and ""skin"" pseudopressure drop (i.e., steady-state unit rate pseudopressure drop between the matrix and the wellbore). Superposition equations that govern fracture interference events under the assumption of linear flow to the fracture system are presented. The model is semi-analytical since no account is taken of variable gas compressibility effects in the superposition equation. Application of the technique allows quantification of interference-induced changes to both flow capacity, (root kA) and skin pressure drop. By inverting the model, a method of predicting the well's production performance post-interference, given the changes to flow capacity and skin and a bottom-hole pressure production schedule, is developed. The predicted rate schedule is valid as long as the well remains in linear flow. The validity of the model is illustrated by applying it both to synthetic and a field production data. Based on the synthetic data, it is demonstrated that the superposition model can accurately describe changes to flow capacity and skin, and that the obtained model parameters can be used to reproduce the model rates given imposed bottom hole pressures. The method is applied to a field example where an interference event occurred, and demonstrates very good agreement between model predicted rates and observed field data.",7,7,0
Fracture,Shale Gas,"Zeng, Yan; Ning, Zhengfu; Wang, Qing; Sun, Hongliang; Huang, Liang; Ye, Hongtao",Gas transport in self-affine rough microchannels of shale gas reservoir,Shale; Roughness effect; Triple-effect permeability model; Lattice Boltzmann method; Permeability,LATTICE BOLTZMANN METHOD; FLUID-FLOW; SURFACE-ROUGHNESS; POISEUILLE NUMBER; PRESSURE-DROP; SICHUAN BASIN; FRACTURE; SIMULATION; MODEL; MICRO,"The matrix of shale gas reservoirs is always characterized by rough surfaces and the roughness of the topography significantly influences the gas flow characteristics. However, most existing models are based on smooth surface. Moreover, the roughness effect leads to a complex velocity distribution and can influence the apparent permeability through its own transport mechanism. In this study, a generalized lattice Boltzmann method with nonequilibrium extrapolation boundary conditions was developed to simulate the rarefied shale gas flow through nanochannels with rough surface. Fractal geometry was introduced to model the rough surface, and the roughness was characterized by two parameters, namely, relative roughness height and fractal dimension. Triple-effect permeability estimation model was adopted to calculate the apparent permeability accounting for multiple roughness characteristics including surface tortuosity, hydraulic tortuosity, and local roughness. Effects of fractal dimension, relative roughness, and tortuosity on velocity distribution were investigated. The effect of pressure and roughness characteristic parameters on the apparent permeability at different Knudsen numbers was also studied. The results showed that the influence of fractal dimension and relative roughness on the permeability was affected by the rarefaction effect. The roughness effect on gas flow behavior became more evident when associated with the enhanced rarefaction effect. Moreover, relative roughness was found to play a significant role in determining the permeability in the transient flow regime.",7,8,1
Fracture,Shale Gas,"Kim, Jihoon; Um, Evan Schankee; Moridis, George J.",Integrated simulation of vertical fracture propagation induced by water injection and its borehole electromagnetic responses in shale gas systems,Hydraulic fracturing; Shale gas; Electromagnetic geophysics; Coupled flow and geomechanics,HYDRAULIC-FRACTURE; POROSITY MATERIALS; RESERVOIR; FLOW; GEOMECHANICS; TOMOGRAPHY; FERROFLUID,"We analyze fracture propagation induced by hydraulic fracturing with water injection and examine their detectability with crosswell electromagnetic (EM) geophysical methods. For rigorous 3D coupled flow-geomechanical modeling, we employ a numerical method that can model failure by tensile and shear stresses, dynamic nonlinear permeability, dual continuum approach, and thermo-poro-mechanical effects. From numerical simulation, we find that the fracture propagation is not the same as propagation of the water front, because fracturing is governed by geomechanics whereas water saturation is determined by multiphase flow. At early times, the water front is almost identical to the fracture tip, suggesting that the fracture is mostly filled with the injected water. However, at late times, movement of the water front is retarded compared to fracture propagation, yielding a significant gap between the water front and the fracture top, filled with reservoir gas. During fracture propagation, the coupled flow-geomechanical models are transformed via a rock-physics model into electrical conductivity models. We employ a full 3D finite-element EM geophysical simulator to evaluate the sensitivity of the crosswell EM method to fracture propagation. It is shown that anomalous distribution of electrical conductivity is closely related to the injected water saturation, but not closely related to newly created unsaturated fractures. Our numerical modeling experiments demonstrate that the crosswell EM method can be highly sensitive to electrical conductivity changes that directly indicate the migration pathways of the injected fluid. Accordingly, the EM method can serve as an effective monitoring tool for monitoring the injected fluids during hydraulic fracturing operations.",7,7,2
Fracture,Shale Gas,"Guo, Chaohua; Li, Qianyao; Wei, Mingzhen","Pore structure characteristics of marine Silurian shales in the Sichuan Basin, China: Insights to reserve assessment and production design",Silurian shale; Pore structure; SEM-Imaging; Mineralogy analysis; Over-mature,ORGANIC-RICH SHALES; SOUTHERN SICHUAN; GAS-STORAGE; NORTHERN GERMANY; LONGMAXI SHALE; LOWER TOARCIAN; CLASSIFICATION; PERMEABILITY; HAYNESVILLE; MARCELLUS,"Due to shortage of conventional resources, tight/shale oil/gas reservoirs have become increasingly important in balancing the energy consumption in China. As the most important shale reservoirs in China, marine Silurian shales in the Sichuan Basin have received intensive investigation during recent years in the area of pore structure characterization and reserve assessment. However, no work has been conducted to compare the China shale plays with other mature shale plays in the North America using multiple experimental methods based on the mineralogy analysis and organic geochemistry. In this paper, pore structure, formation porosity, total organic carbon ( TOC), thermal maturity, and mineralogy of 36 samples in Longmaxi shale and 7 samples in Qiongzhusi shale have been investigated using multiple experimental methods. FIB-SEM imaging results show that Longmaxi shale gas reservoir include primary pores, residual intergranular pores, dissolution pores, and intergranular pores. The majority of the pores are distributed in residual intergranular pores, secondary dissolution pores, and intercrystalline pores, but less in primary intergranular pores. X-ray diffraction analysis shows that the clay minerals of Longmaxi shale reservoir mainly consist of illite and kaolinite, then followed by chlorite. The content of kaolinite is from 7.2% to 16.87%, and the average is 12.21%. The content of illite is from 8.03% to 26.8%, with the average of 16.1%. TOC tests show that most of the samples have their TOC more than 0.5%, which means Longmaxi formation has a potential to produce shale gas. Clay minerals mainly include quartz, K-feldspar, calcite, dolomite, anorthose, and pyrite. The quartz has the highest content value, followed by calcite, which are 29% and 22% average respectively. The content of pyrite and anorthose are less than 10%. The average content of brittle minerals of Longmaxi formation samples is 66% (> 50%), which is suitable for hydraulic fracturing. Thermal maturity tests show that Vitrinite reflectance of each sample is more than 2.0%, which indicates that it is high enough to generate shale gas in the formation. Comparing with other mature shale plays, the Longmaxi and Qiongzhusi shale plays have lower porosity and lower TOC than that of the U.S. shale plays, and the quartz content and thermal maturity are similar. The Qiongzhusi shale and Longmaxi shale are over-mature ( Ro> 2.5%) compared with U.S. shale plays. The results of this study will contribute to the formation characteristics understanding and reserve assessment of China shale plays. Also, it will facilitate the development of suitable and efficient production plan for China shale plays.",7,7,3
Fracture,Shale Gas,"Raef, Abdelmoneam E.; Kamari, Arash; Totten, Matthew; Harris, Dustin; Janssen, Kale; Lambert, Michael","The dynamic elastic and mineralogical Brittleness of Woodford shale of the Anadarko Basin: Ultrasonic P-wave and S-wave velocities, XRD-Mineralogy and predictive models",Shale; Brittleness index; Elastic properties; Mineralogy; Hydraulic fracturing,OKLAHOMA; VISCOSITY; SYSTEMS; ROCKS,"The recent advances in drilling and hydraulic fracturing technology rendered the Woodford shale of the Anadarko basin a prolific resource play producing gas and liquid hydrocarbons. Among the challenges facing improved economics, there is variable production from one well to another as well as from a completion stage to another due to the variability in facture gradient or brittleness index (BI) and the kerogen content. This investigation relies on laboratory ultrasonic P-wave and S-wave velocity in Woodford core samples to estimate BI based on the estimated elastic moduli. We modified a literature mineralogical brittleness index equation in order to take into account additional iron-rich minerals like pyrite, hematite, and iron oxides that are present in the Woodford shales, and also investigated the impact of total organic content (TOC) on the mineralogical brittleness index. Furthermore, a number of new reliable equations based on different elastic properties have been introduced in this study for the evaluation of the elastic BI, which is of significant importance in designing hydraulic fracturing in shale and tight reservoirs. In another panel of our study, the sensitivities of both mineralogical makeup of Woodford shale and elastic properties calculated -including density, acoustic impedance, Poisson's ratio, Young's modules, Lame's parameters-to the elastic brittleness index are examined. It was indicated that they have a positive effect on the prediction and can be employed in the respective predictive methods for the estimation of elastic BI. However, the analysis demonstrated that TOC has no considerable effect on mineral BI, at least in Woodford sample studied. A comparison between these newly developed predictive equations and the most commonly used methods for the prediction of elastic brittleness index available in the literature demonstrates that the new equations have a better performance in terms of both accuracy and simplicity. On comparing the BI prediction equation, with highest prediction quality ""Method 1"", that was developed based on ultrasonic elastic moduli with a corresponding equation based on sonic well-logs elastic moduli, Method1 was proven applicable to estimating BI based sonic frequency elastic moduli.",8,9,1
Fracture,Shale Gas,"Li, Linkai; Jiang, Hanqiao; Li, Junjian; Wu, Keliu; Meng, Fanle; Xu, Qilu; Chen, Zhangxin",An analysis of stochastic discrete fracture networks on shale gas recovery,Shale gas recovery; Stochastic fracture networks; Fractal; Fracture intersection; Percolation; Fracture connectivity,FLOW BEHAVIOR; CONNECTIVITY; SIMULATION; MODEL; RESERVOIRS; WELLS,"Complex fracture networks are created by hydraulic fracturing in shale gas reservoirs. The well performance is largely affected by the geometrical properties of fracture networks. It is difficult to estimate well performance because a large number of parameters are used for characterization of a fracture network. In this study, only two parameters are screened to estimate the shale gas recovery by the method of design of experiments. Synthetic fracture networks are generated based on the stochastic theory to represent the secondary fractures in the hydraulic fracture network. Two numerical experiments are designed to correlate the fracture network properties to gas recovery estimated by a commercial software. Various fracture network parameters derived from the analyses of fracture intersection, fractal and percolation are screened to correlate the gas recovery. In terms of the internal structure of a fracture network, a dimensionless parameter called the effective fracture density is proposed to estimate shale gas recovery. It is a combination of the number of fractures, fracture length and orientation. In terms of the boundary of a fracture network, the shale gas recovery is determined by the number of intersection points between the primary fractures and secondary fractures (NIPS). The shale gas recovery predicted by the two parameters (the NIPS and the dimensionless fracture density) is accurate compared with that calculated by the commercial software, which provides us a practical method to estimate the gas recovery by eliminating the number of parameters used for fracture network properties.",8,10,2
Fracture,Shale Gas,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun; Alsaba, Mortadha",Lessons learned from IOR pilots in Bakken formation by using numerical simulation,CO2-EOR in shale oil reservoirs; CO2-EOR huff-n-puff operations; Unconventional EOR methods; Improved oil recovery,RESERVOIRS,"Bakken is the most productive formation among unconventional plays in North America. This formation has about 7.4 billion barrels of recoverable oil. However, the primary oil recovery is still low as 5-10%. Miscible natural gas and carbon dioxide (CO2) might be the most two potential strategies to improve oil recovery in such a complex play. In this study, some of the IOR pilots which have been conducted in Montana, North Dakota, and South Saskatchewan have been presented. The performance results of these pilots in US-Bakken versus Canadian-Bakken have been compared. Moreover, the reasons behind the successful IOR pilots in Canadian-Bakken versus US-Bakken have been discussed. Then, numerical simulation models have been constructed to mimic the results of some pilots. Two different compositional models have been built for oils of two different formations. Furthermore, two different models, single porosity model and dual permeability model have been created to match the performance of some pilots. Implementation of molecular diffusion mechanism has been conducted in both of single porosity and dual permeability model. Finally, the continuous miscible gases injection versus huff-n-puff protocols have been compared and investigated. The results showed that the performance of natural gases generally over-performed the CO2 injection technique's in Bakken formation. Although the diffusion flow is dominant in these types of reservoirs, the diffusivity of the injected CO2 into formation oil is slow due to the fact that CO2 has large molecules as compared with the small pore throats of these porous media. Accordingly, miscible CO2-EOR might not be beneficial in huff-n-puff operations as in continuous flooding process. However, the success of natural gases based EOR does not have that strong functionality of molar diffusivity. Therefore, their performance was much better than CO2 performance in the field scale of these tight formations. Furthermore, the numerical simulation of this study concluded that the spacing between the production wells and injection wells should be minimized, for the continuous flooding process of miscible-gases EOR, to enhance their performance. Although the permeability of Canadian-Bakken has a permeability of 1-2 order higher than the permeability of US-Bakken, the pilots' spacing between injectors and producers in Canadian Bakken is interestingly much shorter than that for US-Bakken, which might be the reason behind the EOR success in Canadian Bakken. Finally, the activatiown process of the highly intensive natural fractures might be the key to enhance the diffusivity of CO2-EOR. Otherwise, natural gases are highly recommended to be the most potential EOR in these types of reservoirs. This study explains how the diffusion mechanism affects the performance of different miscible gases to improve oil recovery in these plays since they are more complex and very different from conventional formations. Also, it suggests that CO2 flooding process would be a good practice to overcome the limitations of CO2-diffusion rate in these reservoirs if the conformance problems are wisely controlled.",8,8,4
Fracture,Fracture Networks,"Wang, Xin; Guo, Chaohua; He, Sheng; Jiang, Zeyun; Ma, Yongjie",Improved skeleton extraction method considering surface feature of natural micro fractures in unconventional shale/tight reservoirs,Digital core; Natural micro fractures; Skeleton model; Pore-fracture system; Morphological operation,COMPUTED-TOMOGRAPHY; NETWORK MODELS; PORE-SCALE; TOPOLOGY; FLOW; IMAGES; ALGORITHM; SHALE,"Massive micro fractures (MFs) developed in the ultra-tight formations (such as shale/tight reservoirs), which provide preferential channels for the fluids flow. Accurate characterization of such pore-fracture systems and suitable pore network models are the fundamentals of pore structure characterization and micro scale flow simulation. Conventional medial axis (MA) skeleton extraction method cannot preserve the fracture surface feature and connectivity information, which is not suitable for accurate pore scale simulation for these porous media with MFs. In this paper, a new skeleton model was proposed to distinguish MFs from pore space via extraction of surface points set of MFs. In the procedure of points set extraction, we improved the classic ""MA based"" shrink method to ""medial surface (MS) based"" method for the MFs characterization through introducing a new set of skeleton points (i.e., surface points and edge points of the micro fractures). The former describes their apertures and the latter is used for collecting connectivity information and determining the extension ranges of the MFs. Comparison of connectivity index, fracture length, Euclidean distance showed enhanced effectiveness and accuracy of the proposed method. The proposed method was applied in four ideal models and one field shale core sample. Results show that the proposed skeleton model can show more comprehensible forms of the real connected junction instead of the conventional ideal model. The extracted skeleton can also satisfy demands of the traditional skeleton extraction model and preserve the topology of the original pore-fracture space. This work proposed a more accurate method for pore-scale modeling in cores with natural MFs, and potentially applicable for pore scale flow simulations for tight/shale reservoirs.",0,0,4
Fracture,Fracture Networks,"Li, Binglin; Su, Yuliang; Zhan, Shiyuan; Yao, Wei; Hu, Yangming; Wang, Wendong",Temporal scale analysis of two phase flow in fractured well,Fractured well; Two phase flow; Temporal scale analysis; Time lag effect,CAPACITANCE-RESISTANCE MODEL; SHALE RESERVOIRS; PERMEABILITY; PROPAGATION; SIMULATION; BEHAVIOR; VOLUME; FIELD,"Two phase flow between two fractures commonly exists around fractured wells. Due to the fracture network, the flow velocity is extremely variable in different regions and it can be described by the temporal scale analysis. The flow velocity also changes with time during the change in water saturation, but these changes cannot be captured by the conventional temporal scale analysis. The temporal scales are obtained based on a principal equation, so it is difficult to accurately estimate the formation properties and to determine the exploitation scheme. In this study, the two phase flow model between two fractures has been proposed for the temporal scale description. The impact of reservoir heterogeneity on the temporal scales is considered in the model. Due to the tortuous flow channel shape between the fractures, the flow pressure affects the fluid flow afterwards. This is explained by the time lag effect in the model. The temporal scales are obtained by using finite element method and Laplace transformation at all time points with these considerations. Moreover, the well is soaked intermittently. The soaking duration is chosen based on temporal scales, and then discussed in terms of efficiency and recovery factor. The results showed that the water saturation profile position is reflected by the temporal scales, the flow resistance and the flow velocity are represented by their zero status response contributions, while the initial flow pressure is described by their zero input contribution. The highest zero status response contribution is different for different properties. Moreover, the time lag effect promotes the initial pressure fluctuation, and also upscales the fluid flow in tortuous channels. Finally, the soaking duration is an approximation of the time required to reduce the fracture flow pressure.",1,1,0
Fracture,Fracture Networks,"Song, Suihong; Hou, Jiagen; Sun, Shuang; Li, Yongqiang; Wang, Xixin; Dou, Luxing; Liu, Yuming; Kang, Qiangqiang; Huang, Shengyu",Local optimization of DFN by integrating tracer data based on improved simulated annealing,Discrete fracture network; Inter-well connection; Objective function; Weighted perturbation,FRACTURE NETWORKS,"Precise discrete fracture network (DFN) is very significant for fractured reservoirs due to its considerable power to help understand the complex nature of reservoir, predict production response, and create a development plan. Typically, many types of static data, including seismic, wellbore, outcrop, geomechanical, and geostatistical data, are integrated to construct a DFN. A potential problem is the mismatching of inter-well connection between DFN and field dynamic data. Therefore, a local optimization method is proposed in this paper to improve DFN for precise inter-well connections using field tracer data based on an improved simulated annealing algorithm. The proposed method is validated with two field case examples by largely improving the performance of numerical simulation. The results of optimization are also reasonable from the perspective of geostatistics and geomechanics. Optimization has a minimum effect on the original fracture density model. Additionally, the percentage of fractures to be updated in each perturbation of the proposed method decides the speed and precision level of the optimization. The improved simulated annealing algorithm can also be widely used for other optimization problems.",1,1,4
Fracture,Fracture Networks,"Ou, Chenghua; Li, Chaochun; Huang, Siyuan; Lu, Wentao; Sheng, James J.; Xiong, Hongli",Three-dimensional discrete network modeling of structural fractures based on the geometric restoration of structure surface: Methodology and its application,Structural fractures; 3D discrete network model; Visualized characterization; Core description; Structure surface restoration; Fractured reservoir,GAS-RESERVOIRS; SHALE; FAULT; OUTCROP; BASIN; FIELD; PERMEABILITY; KINEMATICS; ANTICLINE; OIL,"Structural fractures are widely developed in the oil and gas fractured reservoirs. However, it is difficult to characterize structural fractures accurately in three-dimensional (3D) space by using: core description method; logging interpretation method; tectonic curvature method; stochastic simulation method; or seismic description method. Based on the theory of fault-related folds and stochastic simulation, a method for constructing 3D structural fracture models relying on the geometric restoration of the structure surface was developed. The structural surface geometrical restoration technique was applied to establish the structural fracture development index model. The core description results were utilized to construct the structural fracture group mode and the fracture intensity model for each fracture group. In addition, the fracture development intensity model was developed and used as the main input to construct the 3D discrete network structural fracture model based on the spatial restriction to the structural fracture development index model. This model achieves 3D visualized modeling for each group of structural fractures and their attribute characteristics. A case study was performed by applying this proposed method to a Jiaoshiba shale gas field in the braided fold belt of eastern Sichuan Basin, where a discrete network model of structural fractures with high and low angle was established. This discrete network model reconstructed the distribution, development scale, extension direction and cutting relationship of structural fractures in 3D space. The modeling results not only provide a discrete structural fractures network model for simulating the production of the Jiaoshiba shale gas field, but also provide a new method for developing a discrete structural fractures network model for sandstone reservoir, carbonate reservoir and shale reservoir.",4,5,4
Fracture,Fracture Networks,"Tian, Feng; Du, Xiaokang; Wang, Xiaodong; Xu, Wenli",Rate decline analysis for finite conductivity vertical fractured gas wells produced under a variable inner boundary condition,Finite vertical fractured gas wells; Variable inner boundary condition; Two-stage performance; Initial rate; Limiting bottom-hole pressure,PRESSURE-TRANSIENT ANALYSIS; TIGHT OIL-RESERVOIRS; NON-DARCY-FLOW; PRODUCTION SIMULATION; SEMIANALYTICAL MODEL; HORIZONTAL WELLS; PERFORMANCE; NETWORKS; BEHAVIOR; PERMEABILITY,"This paper presents a new approximate semi-analytical method for predicting performance of a finite conductivity vertical fractured gas well produced at a variable production system. The proposed solution is based on the gas diffusivity equation with a variable inner boundary condition. The variable inner boundary condition in this study represents that the type of the inner boundary conditions changes from constant rate to constant pressure during the production time. The calculations of the two-stage performance for a finite vertical fractured gas well are accomplished. The two-stage performance is influenced by the limiting bottom-hole pressure, the initial rate and the fracture conductivity. A high initial rate reduces the extents of both the constant-rate period and the total production life. However, the initial rate has no effect on the cumulative gas production when the production period is sufficiently long. Moreover, the initial rate may be appropriately adjusted to achieve the optimum cumulative gas production in a specific production period. The cumulative gas production can be effectively improved by establishing a lower limiting bottom-hole pressure. The higher the fracture conductivity is, the longer the constant rate period elapses, and the shorter the constant pressure period remains. A higher fracture conductivity is helpful to achieve a larger cumulative gas production in a shorter production period. Thus, the operation can be optimized by setting a low limiting bottom-hole pressure, a suitable initial rate and fracture conductivity. The proposed method may be applied to other typical well performance prediction in a variable production system.",5,5,1
Fracture,Fracture Networks,"Fang, Wenchao; Liu, Chuanxi; Li, Junjian; Jiang, Hanqiao; Pu, Jun; Gu, Hao; Qin, Xuejie","A discrete modeling framework for reservoirs with complex fractured media: Theory, validation and case studies",Discrete model; Control-volume finite-difference; Automatic differentiation; Differentiation operator; Fractured reservoir,MULTIPHASE FLOW SIMULATIONS; WELL-BLOCK PRESSURES; NUMERICAL-SIMULATION; FINITE-ELEMENT; AUTOMATIC DIFFERENTIATION; NETWORKS; OIL,"An unstructured discrete fracture model (UDFM) is developed in this study to simulate the two-dimensional fluid flow in the complex fractured tight oil reservoirs. The model applies a control-volume finite-difference (CVFD) discretization scheme with the two-point flux-approximation (TPFA) to evaluate the transmissibility list. Discretization process of the mathematical model is greatly simplified by three differential operators that are defined to represent the expressions of divergence, gradient and average as their original forms, and thus, enable rapid prototyping of the numerical model. The discretized equation system is solved by a modified Newton's method, in which the Jacobian matrix is computed by the automatic differentiation (AD) technique. Our model is validated with the simulation results obtained by the commercial reservoir simulator, Eclipse. To test the model's potential in field-scale application, we implement it in five large-scale complex fractured systems that are radial domains with a uniform diameter of 1000 m but different fracture densities: 382/km(2), 509/km(2), 636/km(2), 764/km(2) and 1018/km(2). Simulation results not only indicate the robustness of our model in simulating complex fractured systems but also highlight the significant effects of fracture network configuration and fracture density on the development features of fractured tight oil reservoirs.",7,8,2
Fracture,Fracture Networks,"Li, Junjian; Yang, Hanxu; Qiao, Yan; Fan, Zhen; Chen, Wenbin; Jiang, Hanqiao",Laboratory evaluations of fiber-based treatment for in-depth profile control,Profile control; Plugging effect; In-depth mobility; Dynamic plugging mechanism; Fiber,POLYMER MICROSPHERES; PHENOLIC RESIN; OPTIMIZATION; GEL,"Inspired by the successful implementation in acid fracturing, a fiber-loaded suspension system was designed to investigate inlet injectivity, in-depth mobility and overall plugging effect in unconsolidated high permeability sandpacks. In this paper, a series of experiments were conducted to screen suitable fiber suspension, including additives selection and dynamic plugging tests. Results showed that the formulation of 0.02 wt% citric acid +0.1 wt% YC regulator +0.1 wt% sodium tetraborate +0.12 wt% HPG displayed satisfactory dispersity. Sandpacks equipped with three pressure gauges to detect pressure changes were used for physical experiments. Four parameters (fiber length, fiber concentration, injection rate and permeability) that influenced the plugging efficiency were under discussion. The results revealed that relatively slow injection helped stabilize inlet pressure below upper limit. Three pressures increased in sequence during the subsequent water flooding, indicating that fibers moved forward with permeability reduction in sandpacks. The pressure dropped down but maintained at a high level after the operation finished. By comparison, 0.3 wt% 1000 mu m-long fiber injected at the rate of 1 mL/min was found to achieve the best performance under the permeability of 4000-7000mD. And the more serious the heterogeneity was, the more significant the diversion ability of the high permeability layer was. Noticeably, the fluctuations were observed in pressure curves, which was further interpreted by the dynamic plugging mechanism of fiber in four transport processes: ""migration-capture-redirection-recapture"". With unique slender shape, fibers were flexible enough to bridge and create a compact three-dimensional network structure along the flow direction. Due to high plugging strength and strong penetrability, the new fiber suspension system proves its potential to be an environmentally-friendly candidate in the selection of in-depth diverting agents. The evaluation and mechanism analysis may provide guidance for the operation design of profile control.",7,7,3
Fracture,Fracture Networks,"Shovkun, Igor; Espinoza, D. Nicolas",Geomechanical implications of dissolution of mineralized natural fractures in shale formations,Stimulated reservoir volume; Shear failure; Mineral dissolution; Hydraulic fracturing; Acidizing,BARNETT SHALE; GAS-PRODUCTION; POROUS-MEDIA; PERMEABILITY; ROCK; BASIN; FLOW; NETWORKS; MODEL; COAL,"Organic shale reservoirs accommodate large amounts of hydrocarbons in extremely tight rock matrix. Slick water hydraulic fracturing and proppant placement is the most spread stimulating technology for this type of reservoirs. Some shale formations contain a fair amount of easily-dissolvable carbonates, which prompts shale acidizing as a potential method to increase reservoir permeability. Carbonates in shale formations can be present as a part of rock matrix or can be localized in natural fractures - so-called mineral veins. Previous studies investigated the effects of chemical dissolution within the matrix, implying that acidizing can etch the rock, open new conduits for flow, and increase fracture permeability after closure. This study rather focuses on the reservoir-scale geomechanical implications of chemical dissolution of mineral filling in natural fractures. We use a combination of elasto-plastic analytical methods, analogous thermo-elastic numerical solutions, and experimental results to elucidate the impact of veins dissolution on in-situ stresses. Analytical, numerical, and experimental results indicate that mineral dissolution of localized carbonate fractures leads to changes of local in-situ stresses. The direction of stress relaxation strongly depends on the orientation of mineralized fractures. Dissolution of near-vertical mineralized fractures contributes the most to decreases of effective horizontal stress and reduce stress shadow effects in multistage hydraulic fracture completions. Mineral dissolution, similar to pore pressure depletion or thermal cooling/heating, can increase stress anisotropy, which can reactivate critically-oriented natural fractures. In-situ stress chemical manipulation can be used advantageously to enlarge the stimulated reservoir volume.",8,9,1
Fracture,Fracture Networks,"Chen, Ming; Zhang, Shicheng; Ma, Xinfang; Zhou, Tong; Zou, Yushi",A semi-analytical model for predicting fluid partitioning among multiple hydraulic fractures from a horizontal well,Multi-cluster fracturing; Semi-analytical method; Homogeneous growth; Interaction stress; Perforation friction,PERFORATION CLUSTERS; NETWORK PROPAGATION; NATURAL FRACTURES; SIMULATION; GROWTH; XFEM; ROCK; RESERVOIRS; FLOW,"Multiple fracture growth during multi-cluster fracturing of a horizontal well is closely dependent on fluid partitioning. However, whether injected fluid can uniformly flux into multiple fractures during fracturing remains uncertain. In this study, a semi-analytical model was proposed to simulate fluid rate distribution in multiple fractures. Multi-fracture interaction stresses in the model are solved by a detailed approximation of the elastic solution for a pressurized fracture, which are integrated with rock deformation equations to calculate the multi-fracture width. The semi-analytical model was validated with a well-recognized fully coupled hydraulic fracture simulator. The semi-analytical model can efficiently optimize perforation parameters for multi-cluster fracturing of a horizontal well. Sensitivity analysis was conducted by using the model, and simulation results show that perforation friction and interaction stress are two key factors that determine fluid partitioning among multiple fractures. When interaction stress dominates the flow pressure drop in multiple fractures, fluid partitioning among multiple fractures is uneven due to heterogeneous interaction stresses among multiple fractures; otherwise, fluid partitioning is evenly distributed. Decreasing the total number or diameter of perforation holes can promote uniform multi-fracture growth and fluid partitioning. Homogenous fluid partitioning can be achieved by decreasing the perforation number of exterior fractures, whereas increasing the perforation number of interior fractures minimally affects uniform fluid partitioning among multiple fractures.",8,8,2
Fracture,Fracture Networks,"Li, Linkai; Jiang, Hanqiao; Li, Junjian; Wu, Keliu; Meng, Fanle; Xu, Qilu; Chen, Zhangxin",An analysis of stochastic discrete fracture networks on shale gas recovery,Shale gas recovery; Stochastic fracture networks; Fractal; Fracture intersection; Percolation; Fracture connectivity,FLOW BEHAVIOR; CONNECTIVITY; SIMULATION; MODEL; RESERVOIRS; WELLS,"Complex fracture networks are created by hydraulic fracturing in shale gas reservoirs. The well performance is largely affected by the geometrical properties of fracture networks. It is difficult to estimate well performance because a large number of parameters are used for characterization of a fracture network. In this study, only two parameters are screened to estimate the shale gas recovery by the method of design of experiments. Synthetic fracture networks are generated based on the stochastic theory to represent the secondary fractures in the hydraulic fracture network. Two numerical experiments are designed to correlate the fracture network properties to gas recovery estimated by a commercial software. Various fracture network parameters derived from the analyses of fracture intersection, fractal and percolation are screened to correlate the gas recovery. In terms of the internal structure of a fracture network, a dimensionless parameter called the effective fracture density is proposed to estimate shale gas recovery. It is a combination of the number of fractures, fracture length and orientation. In terms of the boundary of a fracture network, the shale gas recovery is determined by the number of intersection points between the primary fractures and secondary fractures (NIPS). The shale gas recovery predicted by the two parameters (the NIPS and the dimensionless fracture density) is accurate compared with that calculated by the commercial software, which provides us a practical method to estimate the gas recovery by eliminating the number of parameters used for fracture network properties.",8,10,2
Fracture,Fracture Networks,"Damani, A.; Sondergeld, C. H.; Rai, C. S.",Experimental investigation of in situ and injection fluid effect on hydraulic fracture mechanism using acoustic emission in Tennessee sandstone,Hydraulic fracturing mechanism; Laboratory hydraulic fracturing; Acoustic emission; Microseismic; SRV; Fluid effect,VISCOSITY; ROCK,"Hydraulic fracture propagation and associated rock failure mechanism is dependent on multiple factors including the reservoir pore fluid and its interaction with the rock and the fracturing fluid. This dependence of rock failure on in situ pore fluid could affect the stimulated volume and could manifest itself in the hydraulic fracturing diagnostics such as treatment pressure and microseismic. Therefore, it would be beneficial to an engineer designing, planning or interpreting a fracturing treatment to be aware of expected differences in hydraulic fracture responses in formations having different reservoir fluids, i.e. fracturing a gas or oil bearing formation. We investigate this effect by way of laboratory hydraulic fracturing experiments on triaxially stressed samples of Tennessee sandstone. The acoustic response during rock failure was monitored using 16 P-wave transducers and the waveforms were acquired using a continuous acoustic monitoring system. The effects of pore pressure, water weakening and viscosity of the injection fluids on hydraulic fracture propagation and associated damage are investigated using six experiments on dry, brine saturated and dodecane saturated Tennessee sandstone, fractured with either water (1 cP) or oil (50 cP). Significant rock weakening was observed in fluid saturated samples (breakdown pressures exhibited a reduction of 15-40% from dry state breakdown pressures); the presence of more polar fluid (water) in the pore space resulted in more weakening (800-900 psi lower breakdown pressures when water saturated vs. dodecane saturated). The effect of injection fluid viscosity is observed to be suppressed for fluid saturated samples as breakdown pressures for samples which were saturated with either fluid (brine and dodecane) were observed to be almost same. Acoustic event distributions, continuous stream monitoring, failure mechanisms and permeability measurements on fractured cores all seem to suggest a more complex fracture network in dry rock and more conventional tensile type failure in brine saturated rock. Continuous acoustic stream energy variation with time offers insight into the induced fracture complexity and should be used along with microseismic cloud distributions to assess the stimulated reservoir volume.",8,9,4
Fracture,Fracture Networks,"Chen, Zhiming; Liao, Xinwei; Yu, Wei; Zhao, Xiaoliang",Transient flow analysis in flowback period for shale reservoirs with complex fracture networks,Shale reservoirs; Production performance; Two-phase flow; Flowback; Fracture networks,MODELING 2-PHASE FLOWBACK; TIGHT OIL-RESERVOIRS; HORIZONTAL WELLS; SEMIANALYTICAL MODEL; GAS-WELLS; UNCONVENTIONAL RESERVOIRS; PRODUCTION SIMULATION; PERFORMANCE; BEHAVIOR,"Model developments for transient analysis of fractured horizontal wells have gained tremendous attention in shale reservoirs, especially, during the flowback period. However, the existing models so far have rarely considered two-phase flow and complex fracture networks. To improve this situation, in this work, we present a comprehensively semianalytical two-phase flow model. Two fluids simultaneously flow in the matrix and fracture networks. By iteratively correcting the relative permeability to the phases, we incorporate the two-phase flow into fracture model. Complex fracture networks with arbitrary geometries are described and the fluid flow interplays at fracture intersections are eliminated by mass balance equation. The model solution is obtained by using Laplace transform inversion, and it is verified by performing a case study with numerical simulators. Our results show that there exist two distinct flow regimes: fluid feed and pseudo-boundary dominated flow (PBDF), which is generated by the permeability contrast between fracture networks and matrix. We also investigate the impacts of some key reservoir and fracture properties on the characteristics of the two-phase productivity index. Results indicate that the two-phase productivity index increases with an increase in initial water saturation. Furthermore, it is found that during the PBDF, different fracture-network parameters have various constant productivity indexes, providing an efficient tool to characterize the fracture networks. Based on that, we apply the model to estimate the fracture networks of a well in CJ formation from China with flowback data and micro seismic data, which provides an efficient technique to estimate the fracture parameters during the flowback period.",8,8,5
Fracture,Carbonate,"Phan, T. N.; Gogri, M. P.; Kabir, C. S.; Reza, Z. A.",Exploring safe disposal of CO2 and wastewater in saline aquifers,Safe disposal of CO2 & wastewater; In saline aquifers; Use of injection diagnostic tool; Assessment of injected pore volume; Probabilistic modeling approach,STORAGE EFFICIENCY; SOLUBILITY,"Process safety has taken the spotlight in recent years for both carbon sequestration and wastewater disposal operations. We present a systematic approach to monitoring injection-well performance in saline aquifers for both wastewater disposal and CO2 injection with required well surveillance and injection data. Uncertainty assessment formed the cornerstone of understanding the fundamental variables impacting the injection performance with numerical modeling. Among the variables studied, aquifer heterogeneity and injection parameters, rock compressibility, and fracture gradient have a significant influence on total cumulative injection and safe-volume injection. The modified-Hall analysis turned out to be the critical diagnostic tool for identifying the abnormal injection behavior and real-time disposal process for both fluids. We estimated the safe pore-volume injection for disposal of wastewater and CO2 to be 1.6% and 1.5%, respectively, in saline aquifers at 80% probability. Of the CO2 trapping mechanisms studied here, critical gas saturation turned out to be the most dominant in residual trapping mechanism, whereas porosity and brine salinity appeared dominant in solubility trapping mechanism.",1,1,3
Fracture,Carbonate,"Hu, Jinghong; Chen, Zhangxin; Liu, Pengcheng; Liu, Hui",A comprehensive model for dynamic characteristic curves considering sulfur deposition in sour carbonate fractured gas reservoirs,Sulfur deposition; Stress sensitivity; Fractured carbonate gas reservoir; Finite differences; Characteristic curve,HYDROGEN-SULFIDE; SOLUBILITY; BEHAVIOR; FLOW; PERFORMANCE; WELLS,"Calculating sulfur deposition is a key issue in developing sour gas reservoirs, where sulfur solubility plays an important role. However, prediction of sulfur solubility is a difficult problem due to the toxic of H2S. In this work, an analytical model for dual porosity media considering the influence of sulfur deposition was proposed. The Douglas-Jones predictor-corrector method is used to calculate a relationship between time and pressure, which can avoid solving the system of nonlinear equations. The effects of sulfur deposition on well performance were analyzed and some dynamic characteristic curves for predicting sulfur deposition were provided. The results show that the fastest pressure drop appears near the wellbore, which is the primary damage zone for elemental sulfur precipitation and deposition. Flow parameters and storage ratio play the significant influences on the sulfur saturation curve shape. In addition, the reduction of flow parameters and storage ratio lead to the increase of sulfur saturation and decrease of permeability, resulting in the damage of sour gas formation. The advantage of this approach is that it can be used to describe a characteristic curve without considering the sulfur solubility issue. This paper provides a novel method to analyze the impacts of sulfur deposition on well performances in sour carbonate fractured gas reservoirs.",2,3,10
Fracture,Carbonate,"Wang, Yong; Hou, Jirui; Tang, Yong; Song, Zhaojie; You, Zhenjiang",Application of modified Dykstra-Parsons method to natural bottom-water drive in non-communicating fractured-vuggy reservoir,Fractured-vuggy reservoir; Natural bottom-water drive; Dykstra-Parsons method; Gravity number,DISPLACEMENT,"Universal existence of the filled vug and fracture in carbonate fractured-vuggy reservoir upgrades the complexity of fluid flow as the coexistence of free flow and porous flow. The highly discrete distribution of fracture and vug makes it possible to apply Dykstra-Parsons method in this kind of medium. A modification of Dykstra-Parsons method is proposed to depict the displacement in fracture-vug system, which consists of multiple non-communicating fracture-vug units with each containing fracture, fills, and vug. The displacement front advance equation is derived piecewise corresponding to the position of the front in fracture, fills, and unfilled vug of one unit. The solution to this equation for every fracture-vug unit is used to estimate the production dynamics of the fracture-vug system, including the fractional oil recovery, the water cut, the injected pore volume, and the injectivity ratio. A calculating example with log-normal distribution for fracture aperture is involved to make the sensitivity analysis of gravity number, viscosity ratio, fills properties, and variation of the fracture aperture. In terms of increased oil recovery, decreased water cut, and delayed water breakthrough, it was found that a better performance reached in the condition of weak heterogeneity of fracture, large gravity number, and lower oil//water viscosity ratio; the fills with low permeability and high filling degree is favorable when all vugs are filled identically.",3,3,2
Fracture,Carbonate,"Ou, Chenghua; Li, Chaochun; Huang, Siyuan; Lu, Wentao; Sheng, James J.; Xiong, Hongli",Three-dimensional discrete network modeling of structural fractures based on the geometric restoration of structure surface: Methodology and its application,Structural fractures; 3D discrete network model; Visualized characterization; Core description; Structure surface restoration; Fractured reservoir,GAS-RESERVOIRS; SHALE; FAULT; OUTCROP; BASIN; FIELD; PERMEABILITY; KINEMATICS; ANTICLINE; OIL,"Structural fractures are widely developed in the oil and gas fractured reservoirs. However, it is difficult to characterize structural fractures accurately in three-dimensional (3D) space by using: core description method; logging interpretation method; tectonic curvature method; stochastic simulation method; or seismic description method. Based on the theory of fault-related folds and stochastic simulation, a method for constructing 3D structural fracture models relying on the geometric restoration of the structure surface was developed. The structural surface geometrical restoration technique was applied to establish the structural fracture development index model. The core description results were utilized to construct the structural fracture group mode and the fracture intensity model for each fracture group. In addition, the fracture development intensity model was developed and used as the main input to construct the 3D discrete network structural fracture model based on the spatial restriction to the structural fracture development index model. This model achieves 3D visualized modeling for each group of structural fractures and their attribute characteristics. A case study was performed by applying this proposed method to a Jiaoshiba shale gas field in the braided fold belt of eastern Sichuan Basin, where a discrete network model of structural fractures with high and low angle was established. This discrete network model reconstructed the distribution, development scale, extension direction and cutting relationship of structural fractures in 3D space. The modeling results not only provide a discrete structural fractures network model for simulating the production of the Jiaoshiba shale gas field, but also provide a new method for developing a discrete structural fractures network model for sandstone reservoir, carbonate reservoir and shale reservoir.",4,5,4
Fracture,Carbonate,"Olatunji, Kayode; Zhang, Jin; Wang, Dongmei",Effect of the rock dimension on surfactant imbibition rate in the Middle Member of Bakken: Creating a model for frac design,Oil recovery; Cores; Length; Surface areas; Imbibition; Model; Frac design,SHALE; WETTABILITY,"As an unconventional energy resource, the Bakken Formation has long been considered an important source rock for oil in the Williston Basin. The naturally fractured Bakken Formation consists of thin shale and silty carbonate sequences, capable of producing oil at economic rates when completed using hydraulically fractured horizontal wells. However, because of its low permeability and oil-wet characters, the primary recovery values are still low. As part of our effort to assess the potential for imbibition to recover oil from tight rocks, we performed spontaneous imbibition experiments using brine and surfactant for different dimensions of cores from the Middle Member of the Bakken Formation in North Dakota. The effect of length of the core on imbibition rate in the cores was measured for brine and surfactants. The purpose of this study is to create a model which can be basis for development of design of hydraulic fracturing of the formation. These cores from Bakken were silt stone, limestone, and shale interlayers in lithology. To the point of scaling the dimension of the core from laboratory to a field application, the large area of fluid contact will promote higher imbibition rate and faster oil recovery from the rock. Although oil recovery was low during brine imbibition into the oil-wet cores, alkali/surfactant solution recovered approximately 30-45% of the oil based on the laboratory results. We found higher oil recovery factor was achieved from surfactant imbibition more than just used brine. As would be expected, a given level oil recovery was reached faster in shorter cores than in longer cores in same diameters. The shorter core has a larger ratio of surface area to volume. A model which describes the relationship between Peak Oil recovery and surface areas for cores was derived.",5,5,1
Fracture,Carbonate,"Leyva-Gomez, H.; Babadagli, Tayfun",Efficiency of heavy-oil/bitumen recovery from fractured carbonates by hot-solvent injection,Injection parameters optimization; Heavy oil; Hot solvent; Fractured carbonate reservoirs; Oil dilution,RESERVOIRS SOS-FR; OIL-RECOVERY; BITUMEN RECOVERY; ASPHALTENE DEPOSITION; VAPOR EXTRACTION; AIDED PROCESS; STEAM; SIMULATION; SANDS; PILOT,"This paper presents an extensive analysis of three different solvents injected through two different rock types under dynamic conditions, at elevated temperatures, to recover heavy-oil/bitumen from fractured carbonates. The main idea was to identify the optimal temperatures needed for maximal recovery by hot solvent injection for a wide range of solvents. We also considered the optimal conditions for effective solvent retrieval for the economics of this type recovery approach. In order to represent a wide range of carbon number solvents, heptane and naphtha were injected at atmospheric pressure and temperatures ranging from 70 to 120 degrees C and 21.5-100 degrees C, respectively. Propane was injected at a pressure of 1483-1511 kPa and a temperature ranging from 22 to 60 degrees C to be in the liquid phase. Indiana limestone (outcrop) and vuggy naturally fractured carbonate samples (outcrop core samples from a producing formation in Mexico) were selected as core samples. Hot solvent was injected continuously through artificially fractured cores followed by hot water (or steam injection) phase for solvent retrieval. The optimal temperatures for heavy oil recovery and solvent retrieval, in the subsequent hot water injection, for each kind of rock sample and type of solvent were determined. The results revealed that heavy oil recovery increase with the solvent carbon number used. Also, it was observed that when the temperature is higher than the saturation value for the given pressure curve, the recovery decreases and the lightest component of the heavy oil are dragged by the gas stream.",5,5,1
Fracture,Carbonate,"Zhan, Mingming; Li, Zhao","The lithofacies and reservoir characteristics of the fine-grained sedimentary rocks of the Permian Lucaogou Formation at the northern foot of Bogda Mountains, Junggar Basin (NW China)",Lithofacies characteristics; Reservoir space types; Fine-grained sedimentary rocks; Lucaogou Formation; Junggar Basin,TIGHT OIL-RESERVOIR; ORGANIC-RICH SHALE; JIMUSAER SAG; JIMSAR SAG; SOUTHERN MARGIN; SICHUAN BASIN; NORTHWEST CHINA; SANGONGHE AREA; BARNETT SHALE; PORE-THROAT,"The northern foot of Bogda Mountains in Junggar Basin, Northwest China hosts thick organic-rich fine-grained sedimentary rocks in the Permian Lucaogou Formation consisting of the lower member and upper member. The lithofacies and reservoir characteristics of the fine-grained sedimentary rocks of Lucaogou Formation here are investigated. Analytical results show that the major lithofacies of lower member and upper member are carbonate fine-grained sedimentary rocks and felsic fine-grained sedimentary rocks, respectively. The study areas were the deep lake environments with weak hydrodynamic energy, and the distance from source areas is long, the terrestrial clastics input is low during the deposition of lower member period. However, the study areas were the semi-deep lake environments with strong hydrodynamic energy, the distance from source areas is short and the terrestrial clastics input is high during the deposition of upper member period. The reservoir space types of Lucaogou Formation can be divided into the effective pore reservoir space (primary intergranular pore, intercrystalline pore and dissolved pore), effective fracture resrvoir space (structure fracture, lamellation fracture and abnormal pressure fracture) and ineffective reservoir space (intracrystalline pore and organic pore), respectively. Dissolved pore, structure fracture, lamellation fracture and abnormal pressure fracture are the major effective reservoir space types of No. 1 tight oil layer. Furthermore, the major effective reservoir space types of No. 2 tight oil layer are primary intergranular pore, intercdrystalline pore, lamellation fractures and structure fracture. However, the major effective reservoir space types of No. 3 tight oil layer are structure fracture and lamellation fracture.",6,7,1
Fracture,Carbonate,"Aljehani, Abdulrahman S.; Da Wang, Ying; Rahman, Sheikh S.",An innovative approach to relative permeability estimation of naturally fractured carbonate rocks,Fracture roughness; Discrete fracture flow; Multiphase flow; Relative permeability; Capillary pressure,2-PHASE FLOW; CAPILLARY-PRESSURE; MULTIPHASE-FLOW; SMOOTH,"This paper presents an innovative numerical procedure for flow simulation and estimation of relative permeability of naturally fractured carbonate rocks by history matching laboratory derived multi-phase production data. The multi-phase flow simulator accounts for flow in discrete fractures with variable asperities. These discrete fractures are characterised by the fracture surface topography which is imaged with the use of surface laser scanning and micro computed tomography (mu-CT). Next, the production data for naturally fractured carbonate samples (matrix and fracture permeability), samples with no fracture (matrix permeability only) and samples with fracture only (near zero matrix permeability) for unsteady state conditions are obtained. Forward simulation performed by coupling both the matrix and fracture relative permeability to estimate production for a porous fractured system. This is validated by comparing to the laboratory obtained production data. This has allowed us to validate the proposed numerical procedure and subsequently history match the experimental production data for the porous fractured system to obtain overall porous fractured relative permeability curves. Results of this study show that there exists a strong discontinuity of phase saturation. It was also observed that Corey's parameters are best suited for history matching of the production data through porous matrix, and cubic parameters are best suited for fracture.",7,7,3
Fracture,Carbonate,"Guo, Chaohua; Li, Qianyao; Wei, Mingzhen","Pore structure characteristics of marine Silurian shales in the Sichuan Basin, China: Insights to reserve assessment and production design",Silurian shale; Pore structure; SEM-Imaging; Mineralogy analysis; Over-mature,ORGANIC-RICH SHALES; SOUTHERN SICHUAN; GAS-STORAGE; NORTHERN GERMANY; LONGMAXI SHALE; LOWER TOARCIAN; CLASSIFICATION; PERMEABILITY; HAYNESVILLE; MARCELLUS,"Due to shortage of conventional resources, tight/shale oil/gas reservoirs have become increasingly important in balancing the energy consumption in China. As the most important shale reservoirs in China, marine Silurian shales in the Sichuan Basin have received intensive investigation during recent years in the area of pore structure characterization and reserve assessment. However, no work has been conducted to compare the China shale plays with other mature shale plays in the North America using multiple experimental methods based on the mineralogy analysis and organic geochemistry. In this paper, pore structure, formation porosity, total organic carbon ( TOC), thermal maturity, and mineralogy of 36 samples in Longmaxi shale and 7 samples in Qiongzhusi shale have been investigated using multiple experimental methods. FIB-SEM imaging results show that Longmaxi shale gas reservoir include primary pores, residual intergranular pores, dissolution pores, and intergranular pores. The majority of the pores are distributed in residual intergranular pores, secondary dissolution pores, and intercrystalline pores, but less in primary intergranular pores. X-ray diffraction analysis shows that the clay minerals of Longmaxi shale reservoir mainly consist of illite and kaolinite, then followed by chlorite. The content of kaolinite is from 7.2% to 16.87%, and the average is 12.21%. The content of illite is from 8.03% to 26.8%, with the average of 16.1%. TOC tests show that most of the samples have their TOC more than 0.5%, which means Longmaxi formation has a potential to produce shale gas. Clay minerals mainly include quartz, K-feldspar, calcite, dolomite, anorthose, and pyrite. The quartz has the highest content value, followed by calcite, which are 29% and 22% average respectively. The content of pyrite and anorthose are less than 10%. The average content of brittle minerals of Longmaxi formation samples is 66% (> 50%), which is suitable for hydraulic fracturing. Thermal maturity tests show that Vitrinite reflectance of each sample is more than 2.0%, which indicates that it is high enough to generate shale gas in the formation. Comparing with other mature shale plays, the Longmaxi and Qiongzhusi shale plays have lower porosity and lower TOC than that of the U.S. shale plays, and the quartz content and thermal maturity are similar. The Qiongzhusi shale and Longmaxi shale are over-mature ( Ro> 2.5%) compared with U.S. shale plays. The results of this study will contribute to the formation characteristics understanding and reserve assessment of China shale plays. Also, it will facilitate the development of suitable and efficient production plan for China shale plays.",7,7,3
Fracture,Carbonate,"Paes de Godoi, Felipe Augusto; Scheid, Claudia Miriam; Bernardo, Leticia Siqueira; de Oliveira, Beatriz Rosas; Borges Filho, Moacyr Nogueira; Calcada, Luis Americo",Study of the pressure drop and the flow of loss circulation material suspensions in a physical simulator of fractures,Fractures sealing; Flow of suspensions; Calcium carbonate; Particulate system,,"The loss of fluid to the rock formation is one of the main problems encountered in oil well drilling operations. To mitigate this problem, particulate materials responsible for sealing fractures or for strengthening the well are used. The main objective of this work is to study the flow of Non-Newtonian suspensions through fractures, the pressure drop associated with this flow and the process of sealing fractures using particulate materials suspensions. The flow through fracture of Non-Newtonian suspensions was studied using an apparatus that allowed these fluids to flow through three different artificial fractures with widths of 2 mm, 5 mm and 10 mm and an average 1 cm depth. The suspensions were prepared by mixing water, viscosifying polymer and particulate materials based on laminar calcium carbonate. The particulate materials used are called fine and medium because they have different particle size distributions. The characterization of the solutions and suspensions was carried out from the rheological tests and the determination of the densities and the particle size distributions. The influence of factors such as flow rate, concentration and particle size distributions on the flow of the suspensions through fractures and its sealing capabilities were evaluated. The suspensions of the fine material particles were able to seal only the 2 mm fracture. The suspension composed of the particles of the medium material proved efficient in sealing the three fractures. A mathematical methodology was proposed with the objective of correlating the pressure drop and the flow rate of suspensions in fractures.",7,7,3
Fracture,Carbonate,"Dong, Kai; Zhu, Ding; Hill, A. Daniel",Mechanism of wormholing and its optimal conditions: A fundamental explanation,Wormholing mechanism; Carbonate acidizing; Optimal conditions; Pore growth function; Pore scale,POROUS-MEDIA,"Acid stimulation is commonly used in carbonate reservoirs, which can be either matrix acidizing or acid fracturing. In both treatments, wormholes can form. In matrix acidizing, wormholing is favorable because the damaged region can be bypassed. In acid fracturing, wormholing is not desired because it can increase fluid loss, which can limit conductive fracture length. Three major processes are involved for wormholing: convection, diffusion and surface reaction. A thorough understanding of these processes is necessary for engineering design. In this paper, we fundamentally explore wormholing mechanisms starting from pore growth. A wormhole forms when larger pores grow in cross-sectional area at a rate that greatly exceeds the growth rate of smaller pores due to surface reaction. This happens when pore growth follows a particular mechanism, which is discussed in this paper. We developed a model to predict wormhole growth behavior. The model uses the mode-size pore in a pore size distribution - the pore size that appears most frequently in a distribution - to predict the growth of the pore. By controlling the acid velocity inside of it, we can make larger pores grow much faster than other smaller pores, thus reaching the most favorable condition for wormholing. This also results in a balance between overall acid/rock reaction and acid flow. By understanding the wormholing mechanism, engineers can select proper treatment fluids and pumping rate for acid stimulation design.",8,9,0
Fracture,Carbonate,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Fracture,Carbonate,"Shovkun, Igor; Espinoza, D. Nicolas",Geomechanical implications of dissolution of mineralized natural fractures in shale formations,Stimulated reservoir volume; Shear failure; Mineral dissolution; Hydraulic fracturing; Acidizing,BARNETT SHALE; GAS-PRODUCTION; POROUS-MEDIA; PERMEABILITY; ROCK; BASIN; FLOW; NETWORKS; MODEL; COAL,"Organic shale reservoirs accommodate large amounts of hydrocarbons in extremely tight rock matrix. Slick water hydraulic fracturing and proppant placement is the most spread stimulating technology for this type of reservoirs. Some shale formations contain a fair amount of easily-dissolvable carbonates, which prompts shale acidizing as a potential method to increase reservoir permeability. Carbonates in shale formations can be present as a part of rock matrix or can be localized in natural fractures - so-called mineral veins. Previous studies investigated the effects of chemical dissolution within the matrix, implying that acidizing can etch the rock, open new conduits for flow, and increase fracture permeability after closure. This study rather focuses on the reservoir-scale geomechanical implications of chemical dissolution of mineral filling in natural fractures. We use a combination of elasto-plastic analytical methods, analogous thermo-elastic numerical solutions, and experimental results to elucidate the impact of veins dissolution on in-situ stresses. Analytical, numerical, and experimental results indicate that mineral dissolution of localized carbonate fractures leads to changes of local in-situ stresses. The direction of stress relaxation strongly depends on the orientation of mineralized fractures. Dissolution of near-vertical mineralized fractures contributes the most to decreases of effective horizontal stress and reduce stress shadow effects in multistage hydraulic fracture completions. Mineral dissolution, similar to pore pressure depletion or thermal cooling/heating, can increase stress anisotropy, which can reactivate critically-oriented natural fractures. In-situ stress chemical manipulation can be used advantageously to enlarge the stimulated reservoir volume.",8,9,1
Fracture,Carbonate,"Kathel, P.; Mohanty, K. K.",Dynamic surfactant-aided imbibition in fractured oil-wet carbonates,Wettability alteration; Imbibition; Gravity drainage; Fractured reservoirs; Carbonate rocks,WETTABILITY ALTERATION; GRAVITY DRAINAGE; RECOVERY; RESERVOIRS; WATER; TEMPERATURE,"Numerous studies based on static imbibition experiments at lab scale have established surfactant-aided imbibition as an improved oil recovery process for fractured oil-wet carbonate reservoirs. However, predicting performance at larger scales and at dynamic conditions (fluid flow through fracture) remains a challenge. In this study, experiments are performed on Estaillades Limestone and Texas Cream Limestone outcrop cores with varying height and diameter with permeability in the range of 8 mD to 150 mD to address this challenge. It is observed that dynamic imbibition process recovers oil faster than static imbibition. Imbibition experiments performed on cores with varying height and diameter show that oil recovery decreases with increasing diameter and height. A 3D fine grid mechanistic simulator was used to perform lab scale validation and analyze recovery mechanism. Numerically simulated velocity and saturation profiles demonstrated the recovery mechanism to be gravity dominated flow. A new scaling function is proposed for surfactant aided gravity dominated processes. Data with same boundary conditions, rock, fluids and varying dimensions can be correlated with the scaling function at early times with no fitting parameters involved. A good correlation is obtained with the data indicating the effectiveness of the scaling function. The scaling is applicable to both static as well as dynamic imbibition.",8,8,3
Fracture,Carbonate,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun; Alsaba, Mortadha",Lessons learned from IOR pilots in Bakken formation by using numerical simulation,CO2-EOR in shale oil reservoirs; CO2-EOR huff-n-puff operations; Unconventional EOR methods; Improved oil recovery,RESERVOIRS,"Bakken is the most productive formation among unconventional plays in North America. This formation has about 7.4 billion barrels of recoverable oil. However, the primary oil recovery is still low as 5-10%. Miscible natural gas and carbon dioxide (CO2) might be the most two potential strategies to improve oil recovery in such a complex play. In this study, some of the IOR pilots which have been conducted in Montana, North Dakota, and South Saskatchewan have been presented. The performance results of these pilots in US-Bakken versus Canadian-Bakken have been compared. Moreover, the reasons behind the successful IOR pilots in Canadian-Bakken versus US-Bakken have been discussed. Then, numerical simulation models have been constructed to mimic the results of some pilots. Two different compositional models have been built for oils of two different formations. Furthermore, two different models, single porosity model and dual permeability model have been created to match the performance of some pilots. Implementation of molecular diffusion mechanism has been conducted in both of single porosity and dual permeability model. Finally, the continuous miscible gases injection versus huff-n-puff protocols have been compared and investigated. The results showed that the performance of natural gases generally over-performed the CO2 injection technique's in Bakken formation. Although the diffusion flow is dominant in these types of reservoirs, the diffusivity of the injected CO2 into formation oil is slow due to the fact that CO2 has large molecules as compared with the small pore throats of these porous media. Accordingly, miscible CO2-EOR might not be beneficial in huff-n-puff operations as in continuous flooding process. However, the success of natural gases based EOR does not have that strong functionality of molar diffusivity. Therefore, their performance was much better than CO2 performance in the field scale of these tight formations. Furthermore, the numerical simulation of this study concluded that the spacing between the production wells and injection wells should be minimized, for the continuous flooding process of miscible-gases EOR, to enhance their performance. Although the permeability of Canadian-Bakken has a permeability of 1-2 order higher than the permeability of US-Bakken, the pilots' spacing between injectors and producers in Canadian Bakken is interestingly much shorter than that for US-Bakken, which might be the reason behind the EOR success in Canadian Bakken. Finally, the activatiown process of the highly intensive natural fractures might be the key to enhance the diffusivity of CO2-EOR. Otherwise, natural gases are highly recommended to be the most potential EOR in these types of reservoirs. This study explains how the diffusion mechanism affects the performance of different miscible gases to improve oil recovery in these plays since they are more complex and very different from conventional formations. Also, it suggests that CO2 flooding process would be a good practice to overcome the limitations of CO2-diffusion rate in these reservoirs if the conformance problems are wisely controlled.",8,8,4
Fracture,Horizontal Wells,"Thompson, Leslie G.",Modeling the effects of fracture interference using a spectral gas reservoir simulator,Fracture interference; Numerical modeling; Horizontal well; Shale gas; Unconventional reservoir,,"Economic success in the Cana Woodford shale play in Western Oklahoma has been largely due to field development using vertically fractured long horizontal laterals. In progressing from the field delineation phase, where sections are held by single well, to the field development phase, where multiple new wells are added to a previously produced section, many of the pre-existing ""parent"" wells suffer significant reduction in productivity as a result of interference from fracturing operations in the neighboring ""infill"" wells. We hypothesized that the change in the parent well's productivity was due to changes in fracture conductivity and/or changes in effective fracture length. In order to investigate the validity of our hypothesis, we developed a novel high-resolution spectral gas reservoir simulator to determine whether we could mimic the observed production behavior in the field. In particular, we wanted a simulator that would be immune to spatial truncation errors associated with finite difference schemes, and which would allow us to clearly examine interaction between nanodarcy reservoir matrix and high permeability narrow fractures; in addition, we needed the ability to alter fracture permeability with time to simulate the hypothesized effects of fracture interference. This paper details development of the spectral simulator and demonstrates that changes in fracture conductivity and length due to the interference event can account for observed productivity changes. We qualitatively compare simulator data to observed field data and show that changes in well productivity due to fracture interference can be explained by alteration of fracture half length and/or fracture conductivity.",2,2,0
Fracture,Horizontal Wells,"Osiptsov, A. A.; Boronin, S. A.; Zilonova, E. M.; Desroches, J.",Managed Saffman-Taylor instability during overflush in hydraulic fracturing,Hele-Shaw cell; Hydraulic fracturing; Saffman-Taylor instability; Yield stress; Bingham fluid; Proppant transport; Fingering; Slumping; Shale gas fracturing; Fracture,YIELD-STRESS FLUIDS; HELE-SHAW CELL; NEWTONIAN SLURRY; SUSPENSION FLOW; DISPLACEMENT; PLACEMENT; MECHANICS; MODEL,"Overflushing is a common practice in multistage completions of horizontal wells in unconventional formations. It consists in displacing the suspension by a thin fluid, away from the wellbore and into the fracture. It can, however, overly displace proppant and leave a significant portion of the fracture unsupported near the wellbore, or trigger gravity slumping, again leaving unpropped area near the wellbore. That unpropped area can then close during production, damaging the performance of the fracture. A novel modeling approach was investigated to gain insight into the overflush process and determine secure bounds for maintaining the fracture performance. From a fluid mechanics viewpoint, overflushing is the displacement of a Hershel-Bulkley fluid by a power law fluid in a Hele-Shaw cell, leading to Saffman-Taylor instability at the fluids interface. Whereas most hydraulic fracturing simulators use power-law rheology model, we used a novel numerical approach accounting for the yield-stress behavior of the slurry. Using the lubrication approximation, we derived a model, which includes transport equations for fluid volume fractions and a nonlinear elliptic equation for pressure with mixed-type boundary conditions. Validation was previously performed against three sets of experiments in Hele-Shaw cells, comprising gravitational slumping and displacement of fluids with fingering. Based on fracture mechanics, we analyzed how large a portion of the fracture may be left unsupported before it is severely pinched during drawdown. A parametric study was performed on the displacement of the yield-stress slurry by the overflushing fluid. Qualitatively, when fingers of the overflushing fluid can be created at the overflush/slurry interface, large slurry pillars are preserved in the near-wellbore area, which may keep the fracture open. Three main scenarios of fluids distribution are identified and classified in terms of the oveflush fluid-to-slurry viscosity ratio.: (i) the slumping-dominated regime, where light clean overflush fluid goes on top of sedimenting heavy proppant-laden suspension (xi greater than or similar to 0.1), (ii) an intermediate scenario of slumping combined with fingering (xi similar to 0.01), and, finally, (iii) a pure fingering-dominated scenario, when the slurry viscosity is high (xi < 10(-3)). The third scenario minimizes the geomechanical risks of overflushing by providing tiny fingers that are unlikely to be pinched out during fracture closure.",2,2,0
Fracture,Horizontal Wells,"Luo, Hongwen; Li, Haitao; Wang, Junchao; Su, Chao; Li, Ying; Zhu, Xiaoping",A fuzzy system of candidate completion methods selection for multi-fractured horizontal wells in tight oil reservoirs,Fuzzy evaluation system; Optimal selection; Completion methods; Fractured horizontal well; Tight oil reservoir,ARTIFICIAL NEURAL-NETWORKS; REAL-TIME PREDICTION; MULTILATERAL WELLS; GAS-RESERVOIRS,"Multi-stage fracturing technique has been widely applied to tight oil/gas reservoirs. However, there still exists challenges to select the most applicable and economical well completion methods (WCMs) for a multi-stage fractured horizontal well (MFHW) in a tight oil reservoir. And, the theoretical methods used to select the best WCM for a particular MFHW are not fully investigated. At present, the existing models and methods are basically applied to conventional horizontal wells and the application of relevant models or methods in tight oil reservoirs are rarely involved. In this study, a comprehensive fuzzy evaluation system is developed to help engineers performing the optimal selection of WCMs for MFHWs in tight oil reservoirs. Firstly, the wellbore stability analysis is carried out to obtain the critical drawdown pressure which determines the availability of open-hole WCMs. Subsequently, a fuzzy evaluation model is proposed to preliminarily find out several potentially available WCMs for the target MFHW. The problems caused by non-quantification and fuzziness of effect factors are solved by membership functions. Then, on the basis of production decline analysis and the initial productivity prediction using a semi-analytical productivity model, the cumulative production in the future for the target MFHW using different candidate WCMs (fuzzy evaluation results) are predicted respectively. And an economic evaluation model is proposed to identify the most economic candidate WCM based on the cumulative production estimation results. Finally, the recommendation of the optimized WCM is performed with considering the obtained critical drawdown. With the help of the developed corresponding software, the proposed fuzzy system is applied along with two field applications in a tight oil reservoir. The results of optimal selection of WCMs for those two filed cases are validated by the field practices.",2,2,1
Fracture,Horizontal Wells,"Tian, Feng; Du, Xiaokang; Wang, Xiaodong; Xu, Wenli",Rate decline analysis for finite conductivity vertical fractured gas wells produced under a variable inner boundary condition,Finite vertical fractured gas wells; Variable inner boundary condition; Two-stage performance; Initial rate; Limiting bottom-hole pressure,PRESSURE-TRANSIENT ANALYSIS; TIGHT OIL-RESERVOIRS; NON-DARCY-FLOW; PRODUCTION SIMULATION; SEMIANALYTICAL MODEL; HORIZONTAL WELLS; PERFORMANCE; NETWORKS; BEHAVIOR; PERMEABILITY,"This paper presents a new approximate semi-analytical method for predicting performance of a finite conductivity vertical fractured gas well produced at a variable production system. The proposed solution is based on the gas diffusivity equation with a variable inner boundary condition. The variable inner boundary condition in this study represents that the type of the inner boundary conditions changes from constant rate to constant pressure during the production time. The calculations of the two-stage performance for a finite vertical fractured gas well are accomplished. The two-stage performance is influenced by the limiting bottom-hole pressure, the initial rate and the fracture conductivity. A high initial rate reduces the extents of both the constant-rate period and the total production life. However, the initial rate has no effect on the cumulative gas production when the production period is sufficiently long. Moreover, the initial rate may be appropriately adjusted to achieve the optimum cumulative gas production in a specific production period. The cumulative gas production can be effectively improved by establishing a lower limiting bottom-hole pressure. The higher the fracture conductivity is, the longer the constant rate period elapses, and the shorter the constant pressure period remains. A higher fracture conductivity is helpful to achieve a larger cumulative gas production in a shorter production period. Thus, the operation can be optimized by setting a low limiting bottom-hole pressure, a suitable initial rate and fracture conductivity. The proposed method may be applied to other typical well performance prediction in a variable production system.",5,5,1
Fracture,Horizontal Wells,"Olatunji, Kayode; Zhang, Jin; Wang, Dongmei",Effect of the rock dimension on surfactant imbibition rate in the Middle Member of Bakken: Creating a model for frac design,Oil recovery; Cores; Length; Surface areas; Imbibition; Model; Frac design,SHALE; WETTABILITY,"As an unconventional energy resource, the Bakken Formation has long been considered an important source rock for oil in the Williston Basin. The naturally fractured Bakken Formation consists of thin shale and silty carbonate sequences, capable of producing oil at economic rates when completed using hydraulically fractured horizontal wells. However, because of its low permeability and oil-wet characters, the primary recovery values are still low. As part of our effort to assess the potential for imbibition to recover oil from tight rocks, we performed spontaneous imbibition experiments using brine and surfactant for different dimensions of cores from the Middle Member of the Bakken Formation in North Dakota. The effect of length of the core on imbibition rate in the cores was measured for brine and surfactants. The purpose of this study is to create a model which can be basis for development of design of hydraulic fracturing of the formation. These cores from Bakken were silt stone, limestone, and shale interlayers in lithology. To the point of scaling the dimension of the core from laboratory to a field application, the large area of fluid contact will promote higher imbibition rate and faster oil recovery from the rock. Although oil recovery was low during brine imbibition into the oil-wet cores, alkali/surfactant solution recovered approximately 30-45% of the oil based on the laboratory results. We found higher oil recovery factor was achieved from surfactant imbibition more than just used brine. As would be expected, a given level oil recovery was reached faster in shorter cores than in longer cores in same diameters. The shorter core has a larger ratio of surface area to volume. A model which describes the relationship between Peak Oil recovery and surface areas for cores was derived.",5,5,1
Fracture,Horizontal Wells,"MoradiDowlatabad, Mojtaba; Jamiolahmady, Mahmoud",New approach for predicting multiple fractured horizontal wells performance in tight reservoirs,Productivity index (PI); Multiple fractured horizontal wells (MFHWs); Tight reservoirs; Unconventional reservoirs; Pseudo-steady state (PSS); Symbolic regression,PRODUCTIVITY; DARCY,"Multiple fractured horizontal wells (MFHWs) are considered as the most effective stimulation technique to improve recovery from low permeability reservoirs particularly tight and shale assets. Understanding of the complex flow behaviour and predicting Productivity Index (PI) of these wells are vital for exploitation of unconventional reservoirs. The analytical or semi analytical models previously proposed for their PI calculations cannot accurately describe the flow behaviour around MFHWs mainly due to lack of capturing the complexity of the flow especially the fracture-to-fracture interference effects. Many of them are also too complex and/or not general enough limiting their use. The fine grid three-dimensional (3D) simulation approach is also costly and cumbersome. In this work, we followed a new approach to develop a new equation that can predict MFHWs performance under pseudo-steady state (PSS) flow conditions in tight reservoirs. A programming code, producing the include files, was coupled with a fine grid 3D commercial reservoir simulator to generate a large data bank. For these simulations, the pertinent parameters (matrix permeability, the number of fractures and fracture permeability, spacing, width, length and conductivity) were varied over wide practical ranges based on the Latin Hypercube sampling method. The individual impact of the parameters on PI, as the output variable, was evaluated by a statistical analysis technique under different prevailing conditions. It is shown, for instance, that increasing the fracture width and permeability does not result in a significant monotonic increase in PI while changing fracture length, spacing and numbers influence PI greatly. A new equation is then proposed that relates MFHWs-PI to a limited number of parameters by applying symbolic regression technique. Here, the total productivity index of MFHWs is related to the PI of the horizontal well with a single fracture, the number of fractures and dimensionless fracture spacing. The cross-validation results show that the proposed equation is general, reliable and simple for prediction purposes because it benefits from limited and appropriate dimensionless numbers with good values of fitting indices. This study expands our understanding of flow behaviour in tight reservoirs and provides an invaluable engineering tool that can facilitate simulation of flow around MFHWs, their optimum design and their well performance prediction.",6,6,1
Fracture,Horizontal Wells,"Zhao, Lin; Jiang, Hanqiao; Zhang, Shaoqing; Yang, Hanxu; Sun, Fengrui; Qiao, Yan; Zhao, Lijun; Chen, Wenbin; Li, Junjian",Modeling vertical well in field-scale discrete fracture-matrix model using a practical pseudo inner-boundary model,Discrete fracture-matrix model; Vertical fractured well; Well model; Mesh generation; Transmissibility evaluation,NUMERICAL RESERVOIR SIMULATION; EQUIVALENT WELLBLOCK RADIUS; SHALE GAS; HORIZONTAL WELLS; BLOCK PRESSURES; MESH GENERATOR; GRIDS; MATLAB; FLOW; PERMEABILITY,"The discrete fracture-matrix model (DFM) technique has contributed to the rapid development of fracture modeling. In terms of vertical well modeling, however, the current well models fail to handle the field-scale DFM utilization. In this study, a pseudo inner-boundary model is presented tailored to this problem. Specifically, the modeling methodology consists of mesh generation and transmissibility evaluation. Regarding the mesh generation, the model handles the 2-D triangular-gridded matrix and 1-D edge-gridded fracture. The strict geometric analogy to generate triangles for the wellbore is abandoned, instead, the wellbore is approximated by a source/sink point and returns to a circular geometry when evaluating the transmissibility. The treatment sheds the limitation of triangle size and proves to boost the generation efficiency. Regarding the transmissibility evaluation, the derived formulations apply the radial/linear approximation for flow in matrix/fracture well-gridblock, and various conditions are considered, including gridblock geometry (triangle and rectangle), flow state (steady-state, unsteady-state and pseudosteady-state) and well completion (fully penetrating well and partially penetrating well). In addition, the compatibility with the star-delta transformation is discussed. By refining the well-gridblock into several sub-triangles, the formulations could be rapidly implemented to non-triangle-based DFM (e. g. PEBI, Cartesian). The model performance is demonstrated in eight validation cases. The model is shown to provide results in close agreement with those of reference in cases where the direct comparisons are performed.",6,6,4
Fracture,Horizontal Wells,"Thompson, Leslie G.",Horizontal well fracture interference - Semi-analytical modeling and rate prediction,Fracture interference; Analytical modeling; Horizontal well; Shale gas; Unconventional reservoir,,"A semi-analytical superposition model for analyzing pressure and rate data from wells where production characteristics were altered because of interference from nearby fracture operations is presented. In previous work (Thompson (2017)), specialized numerical simulations showed that these production changes could be explained by changes to the total fracture half-length and fracture permeability; in turn, these parameters alter the completion's linear flow parameter, root kA, (which we loosely refer to here as the well's linear ""flow capacity"") and ""skin"" pseudopressure drop (i.e., steady-state unit rate pseudopressure drop between the matrix and the wellbore). Superposition equations that govern fracture interference events under the assumption of linear flow to the fracture system are presented. The model is semi-analytical since no account is taken of variable gas compressibility effects in the superposition equation. Application of the technique allows quantification of interference-induced changes to both flow capacity, (root kA) and skin pressure drop. By inverting the model, a method of predicting the well's production performance post-interference, given the changes to flow capacity and skin and a bottom-hole pressure production schedule, is developed. The predicted rate schedule is valid as long as the well remains in linear flow. The validity of the model is illustrated by applying it both to synthetic and a field production data. Based on the synthetic data, it is demonstrated that the superposition model can accurately describe changes to flow capacity and skin, and that the obtained model parameters can be used to reproduce the model rates given imposed bottom hole pressures. The method is applied to a field example where an interference event occurred, and demonstrates very good agreement between model predicted rates and observed field data.",7,7,0
Fracture,Horizontal Wells,"Shen, Jian; Qin, Yong; Li, Yepeng; Yang, Yanhui; Ju, Wei; Yang, Chunli; Wang, Geoff","In situ stress field in the FZ Block of Qinshui Basin, China: Implications for the permeability and coalbed methane production",In situ stress; High-rank coal; Coalbed methane; Permeability; Gas and water production; Qinshui basin,EASTERN ORDOS BASIN; SHANXI PROVINCE; ORIENTATION; EXPLORATION; MAGNITUDE; RESERVOIR; PART; AREA; GEOMECHANICS; FRACTURES,"In situ stress affects reservoir permeability and stimulation, and thus coalbed methane (CBM) recovery. In this study, the in situ stress field measured from 238 CBM wells in the FZ Block of Qinshui Basin, China, was investigated. The vertical stress, horizontal maximum and minimum principal stress are 5.92-20.08 MPa, 8.03-41.75 MPa, and 5.38-21.24 MPa, respectively. The in situ stress magnitudes increase with burial depth of the coal seams. The FZ Block is dominated by reverse and strike-slip faulting stress regimes. Most of reverse fault stress regimes appear within burial depth less than 500 m, whereas normal and strike faulting stress regimes are deeper than 500 m. The relation between the coefficient of lateral stress and burial depth shows that shallow strata are characterized by horizontal stresses, whereas deep strata are generally hydrostatic pressures that approximately equal to the principal stresses. Low gas and high water production are associated with vertical hydraulic fractures, wherein the horizontal minimum principal stress is the minimum stress. High gas and low water production are associated with horizontal hydraulic fractures, wherein the vertical stress is the minimum stress. This results are attributed to the enhanced permeability of the coal seam and the communication with overlying or underlying aquifers because the minimum stress varies between vertical and horizontal minimum stress. The orientation of the horizontal maximum principal stress is -NEE-NE and is locally distorted by faults, which can be used to optimize the drilling, completion, and stimulation of CBM wells in the study area.",8,10,1
Fracture,Horizontal Wells,"Chen, Ming; Zhang, Shicheng; Ma, Xinfang; Zhou, Tong; Zou, Yushi",A semi-analytical model for predicting fluid partitioning among multiple hydraulic fractures from a horizontal well,Multi-cluster fracturing; Semi-analytical method; Homogeneous growth; Interaction stress; Perforation friction,PERFORATION CLUSTERS; NETWORK PROPAGATION; NATURAL FRACTURES; SIMULATION; GROWTH; XFEM; ROCK; RESERVOIRS; FLOW,"Multiple fracture growth during multi-cluster fracturing of a horizontal well is closely dependent on fluid partitioning. However, whether injected fluid can uniformly flux into multiple fractures during fracturing remains uncertain. In this study, a semi-analytical model was proposed to simulate fluid rate distribution in multiple fractures. Multi-fracture interaction stresses in the model are solved by a detailed approximation of the elastic solution for a pressurized fracture, which are integrated with rock deformation equations to calculate the multi-fracture width. The semi-analytical model was validated with a well-recognized fully coupled hydraulic fracture simulator. The semi-analytical model can efficiently optimize perforation parameters for multi-cluster fracturing of a horizontal well. Sensitivity analysis was conducted by using the model, and simulation results show that perforation friction and interaction stress are two key factors that determine fluid partitioning among multiple fractures. When interaction stress dominates the flow pressure drop in multiple fractures, fluid partitioning among multiple fractures is uneven due to heterogeneous interaction stresses among multiple fractures; otherwise, fluid partitioning is evenly distributed. Decreasing the total number or diameter of perforation holes can promote uniform multi-fracture growth and fluid partitioning. Homogenous fluid partitioning can be achieved by decreasing the perforation number of exterior fractures, whereas increasing the perforation number of interior fractures minimally affects uniform fluid partitioning among multiple fractures.",8,8,2
Fracture,Horizontal Wells,"Chen, Zhiming; Liao, Xinwei; Yu, Wei; Zhao, Xiaoliang",Transient flow analysis in flowback period for shale reservoirs with complex fracture networks,Shale reservoirs; Production performance; Two-phase flow; Flowback; Fracture networks,MODELING 2-PHASE FLOWBACK; TIGHT OIL-RESERVOIRS; HORIZONTAL WELLS; SEMIANALYTICAL MODEL; GAS-WELLS; UNCONVENTIONAL RESERVOIRS; PRODUCTION SIMULATION; PERFORMANCE; BEHAVIOR,"Model developments for transient analysis of fractured horizontal wells have gained tremendous attention in shale reservoirs, especially, during the flowback period. However, the existing models so far have rarely considered two-phase flow and complex fracture networks. To improve this situation, in this work, we present a comprehensively semianalytical two-phase flow model. Two fluids simultaneously flow in the matrix and fracture networks. By iteratively correcting the relative permeability to the phases, we incorporate the two-phase flow into fracture model. Complex fracture networks with arbitrary geometries are described and the fluid flow interplays at fracture intersections are eliminated by mass balance equation. The model solution is obtained by using Laplace transform inversion, and it is verified by performing a case study with numerical simulators. Our results show that there exist two distinct flow regimes: fluid feed and pseudo-boundary dominated flow (PBDF), which is generated by the permeability contrast between fracture networks and matrix. We also investigate the impacts of some key reservoir and fracture properties on the characteristics of the two-phase productivity index. Results indicate that the two-phase productivity index increases with an increase in initial water saturation. Furthermore, it is found that during the PBDF, different fracture-network parameters have various constant productivity indexes, providing an efficient tool to characterize the fracture networks. Based on that, we apply the model to estimate the fracture networks of a well in CJ formation from China with flowback data and micro seismic data, which provides an efficient technique to estimate the fracture parameters during the flowback period.",8,8,5
Fracture,Horizontal Wells,"Ren, Junjie; Guo, Ping",Analytical method for transient flow rate with the effect of the quadratic gradient term,Transient flow rate; Transient pressure; Quadratic gradient term; Material balance; Horizontal well,FRACTURED HORIZONTAL WELLS; SHALE GAS-RESERVOIRS; NEW-TYPE CURVES; PVT PROPERTIES; VOLUME FACTOR; CRUDE OILS; MODEL; BEHAVIOR; COMPRESSIBILITY; PERFORMANCE,"Owing to neglecting the quadratic gradient term (QGT) in the governing equation, the conventional method proposed by van Everdingen and Hurst [Trans. AIME, 1949, 186, 305-324] for obtaining the transient flow rate is inconsistent with material balance and may lead to errors in the prediction of the flow rate for the wells producing at a constant bottomhole pressure. This paper extends the conventional method to consider the effect of the QGT. If the pressure solution in Laplace space under the constant-rate-production condition is known, the flow-rate solution in Laplace space under the constant-pressure-production condition including the effect of the QGT can be determined by the proposed method. Flow-rate solutions for horizontal wells in reservoirs with different lateral outer boundaries under the constant-pressure-production condition are obtained by the proposed method and the conventional method, respectively. The difference between the flow-rate solutions with and without the effect of the QGT is qualitatively and quantitatively analyzed. The proposed method for obtaining the transient flow rate is consistent with material balance, and thus it can be used to obtain more accurate transient flow rate.",9,9,0
Fracture,Oil-recovery,"Moosavi, Seyedeh Robab; Vaferi, Behzad; Wood, David A.",Applying orthogonal collocation for rapid and reliable solutions of transient flow in naturally fractured reservoirs,Naturally fractured reservoir; Pseudo-steady state; Orthogonal collocation method; Parametric analyses; Pressure transient response,DIFFUSIVITY EQUATION; PRESSURE RESPONSE; ELEMENT SOLUTION; WELL; SIMULATION,"Naturally fractured reservoirs (NFR) contain a significant portion of the worldwide oil and gas reserves. Pressure transient analysis is the most well-established methodology for characterizing these heterogeneous reservoirs based upon well-test data. Pressure transient responses (PTR) of oil and gas reservoirs to various production/injection scenarios is widely used for forecasting and optimizing their production performance and ultimate resource recoveries. In this study, orthogonal collocation (OC) which is a straightforward and very efficient approximate approach for solving differential equations is employed as a novel approach to simulate the PTR of NFRs. The governing equations describe fluid flow in NFR for pseudo-steady state conditions. Constant production rate from a wellbore and circular no-flow are employed as an inner and outer boundary conditions, respectively. The results of OC are verified with exact analytical solutions using the Laplace transform. Thereafter, the effects of three parameters (storativity ratio, interporosity flow coefficient, and radial distance of the outer boundary from the wellbore) are studied using pressure-derivative plots. Employing the superposition theorem, the pressure response of NFR to the multi-rate production from the wellbore is calculated. The results indicate that this approximate approach can predict the pressure transient response of NFRs with an acceptable accuracy, i.e., absolute average relative deviation (AARD) of 0.16%. The equations can be adapted to deal with other flow conditions, boundary conditions and fracture stimulated reservoirs. The proposed method provides a straightforward, faster and more accurate solution in comparison with other methods commonly used. As the OC method is simpler to execute than analytical solutions (e.g. Laplace Transform), it is easier to modify and expand for addressing more complex reservoir scenarios. Likewise, the numerical methods (e.g. finite difference and finite elements) commonly applied to model fractured reservoirs involve significantly more time-consuming calculations, making them more cumbersome to use in reservoir simulations than the proposed orthogonal collocation method.",3,4,0
Fracture,Oil-recovery,"Wang, Yong; Hou, Jirui; Tang, Yong; Song, Zhaojie; You, Zhenjiang",Application of modified Dykstra-Parsons method to natural bottom-water drive in non-communicating fractured-vuggy reservoir,Fractured-vuggy reservoir; Natural bottom-water drive; Dykstra-Parsons method; Gravity number,DISPLACEMENT,"Universal existence of the filled vug and fracture in carbonate fractured-vuggy reservoir upgrades the complexity of fluid flow as the coexistence of free flow and porous flow. The highly discrete distribution of fracture and vug makes it possible to apply Dykstra-Parsons method in this kind of medium. A modification of Dykstra-Parsons method is proposed to depict the displacement in fracture-vug system, which consists of multiple non-communicating fracture-vug units with each containing fracture, fills, and vug. The displacement front advance equation is derived piecewise corresponding to the position of the front in fracture, fills, and unfilled vug of one unit. The solution to this equation for every fracture-vug unit is used to estimate the production dynamics of the fracture-vug system, including the fractional oil recovery, the water cut, the injected pore volume, and the injectivity ratio. A calculating example with log-normal distribution for fracture aperture is involved to make the sensitivity analysis of gravity number, viscosity ratio, fills properties, and variation of the fracture aperture. In terms of increased oil recovery, decreased water cut, and delayed water breakthrough, it was found that a better performance reached in the condition of weak heterogeneity of fracture, large gravity number, and lower oil//water viscosity ratio; the fills with low permeability and high filling degree is favorable when all vugs are filled identically.",3,3,2
Fracture,Oil-recovery,"van Santvoort, Joris; Golombok, Michael",Improved recovery from fractured oil reservoirs,Fracture permeability; Fluid loss; Breakthrough; Viscoelastic surfactants,VISCOELASTIC SURFACTANTS; MICELLAR-SOLUTION; RHEOLOGY; FLOW; PERFORMANCE; DIVERSION; BEHAVIOR,"Fluid loss through natural fractures in oil reservoirs can be overcome using flow induced viscoelastic surfactant (FIVES) solutions. Single phase tests show higher flow resistance in fractures compared to matrix. This reduces the fluid lost through the fracture. During decane displacement, the amount of fluid lost through the fracture is lowered due to this increased local flow resistance. Improved recovery is obtained and the pore volume injected at break-through is reduced from 2.5 PV to ca. 1.0 PV. These results translate to a prolonged economic lifespan of a fractured heterogeneous reservoir and a significant reduction in post-processing costs.",3,3,2
Fracture,Oil-recovery,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun; Almansour, Abdullah",Numerical simulation study to understand the performance of RPM gels in water-shutoff treatments,,DISPROPORTIONATE PERMEABILITY REDUCTION; WELLS,"Disproportionate Permeability Reduction (DPR) is often used as a water-shutoff treatment in production wells when conventional solutions such as mechanical isolations are difficult to perform. Although this property has been well documented by different investigators, the performance of DPR treatments in field applications has varied between success and failure without understandable reasons. This work investigated the DPR performance in different scenarios to see when, where and at which conditions DPR treatments can give better results. Numerical simulation methods were used to simulate different scenarios happening in oil and gas fields such as five-spot pattern system and linear-system, with different number of layers, with and without crossflow. The possibility of using DPR treatment in hydraulically-fractured reservoirs was also investigated since many reports indicated that there is an increase in the water production for some oil and gas reservoirs after being hydraulically-fractured. Moreover, the physical reasoning behind the variations in the DPR performance for different scenarios has been extensively discussed. The results explored that the DPR performance was excellent in both of water-cut reduction and oil-recovery improvement when the flow regime was viscous dominated (viscous-gravity number < 0.1). On the other hand, when the flow regime was gravity dominated (viscous-gravity number > 10), the effective period of DPR treatment was a short-term remedy. Secondly, when the high-K layer is existed at the lower-zone of oil or gas reservoir, the reservoir would be a good candidate for the DPR treatment as compared with the reservoirs that have the high-K layer located at the upper zone. Furthermore, selecting the correct time to perform DPR treatments generally could have a significant role to mitigate water production. Finally, the dimensions of the treated fracture are the key components to get a successful DPR-treatment in the hydraulically fractured reservoirs.",5,5,0
Fracture,Oil-recovery,"Olatunji, Kayode; Zhang, Jin; Wang, Dongmei",Effect of the rock dimension on surfactant imbibition rate in the Middle Member of Bakken: Creating a model for frac design,Oil recovery; Cores; Length; Surface areas; Imbibition; Model; Frac design,SHALE; WETTABILITY,"As an unconventional energy resource, the Bakken Formation has long been considered an important source rock for oil in the Williston Basin. The naturally fractured Bakken Formation consists of thin shale and silty carbonate sequences, capable of producing oil at economic rates when completed using hydraulically fractured horizontal wells. However, because of its low permeability and oil-wet characters, the primary recovery values are still low. As part of our effort to assess the potential for imbibition to recover oil from tight rocks, we performed spontaneous imbibition experiments using brine and surfactant for different dimensions of cores from the Middle Member of the Bakken Formation in North Dakota. The effect of length of the core on imbibition rate in the cores was measured for brine and surfactants. The purpose of this study is to create a model which can be basis for development of design of hydraulic fracturing of the formation. These cores from Bakken were silt stone, limestone, and shale interlayers in lithology. To the point of scaling the dimension of the core from laboratory to a field application, the large area of fluid contact will promote higher imbibition rate and faster oil recovery from the rock. Although oil recovery was low during brine imbibition into the oil-wet cores, alkali/surfactant solution recovered approximately 30-45% of the oil based on the laboratory results. We found higher oil recovery factor was achieved from surfactant imbibition more than just used brine. As would be expected, a given level oil recovery was reached faster in shorter cores than in longer cores in same diameters. The shorter core has a larger ratio of surface area to volume. A model which describes the relationship between Peak Oil recovery and surface areas for cores was derived.",5,5,1
Fracture,Oil-recovery,"Leyva-Gomez, H.; Babadagli, Tayfun",Efficiency of heavy-oil/bitumen recovery from fractured carbonates by hot-solvent injection,Injection parameters optimization; Heavy oil; Hot solvent; Fractured carbonate reservoirs; Oil dilution,RESERVOIRS SOS-FR; OIL-RECOVERY; BITUMEN RECOVERY; ASPHALTENE DEPOSITION; VAPOR EXTRACTION; AIDED PROCESS; STEAM; SIMULATION; SANDS; PILOT,"This paper presents an extensive analysis of three different solvents injected through two different rock types under dynamic conditions, at elevated temperatures, to recover heavy-oil/bitumen from fractured carbonates. The main idea was to identify the optimal temperatures needed for maximal recovery by hot solvent injection for a wide range of solvents. We also considered the optimal conditions for effective solvent retrieval for the economics of this type recovery approach. In order to represent a wide range of carbon number solvents, heptane and naphtha were injected at atmospheric pressure and temperatures ranging from 70 to 120 degrees C and 21.5-100 degrees C, respectively. Propane was injected at a pressure of 1483-1511 kPa and a temperature ranging from 22 to 60 degrees C to be in the liquid phase. Indiana limestone (outcrop) and vuggy naturally fractured carbonate samples (outcrop core samples from a producing formation in Mexico) were selected as core samples. Hot solvent was injected continuously through artificially fractured cores followed by hot water (or steam injection) phase for solvent retrieval. The optimal temperatures for heavy oil recovery and solvent retrieval, in the subsequent hot water injection, for each kind of rock sample and type of solvent were determined. The results revealed that heavy oil recovery increase with the solvent carbon number used. Also, it was observed that when the temperature is higher than the saturation value for the given pressure curve, the recovery decreases and the lightest component of the heavy oil are dragged by the gas stream.",5,5,1
Fracture,Oil-recovery,"Bui, Binh T.; Tutuncu, Azra N.",Modeling the swelling of shale matrix in unconventional reservoirs,Shale swelling; Coupled modeling; Unconventional reservoirs; Dual-porosity model; Water injection; Mass transport,,"The imbibition of the injection water into shale matrix may result in shale swelling affecting oil recovery from the rock matrix and the transport properties of the fractures. The expansion of rock due to the swelling of shale matrix compresses the pore space in the rock matrix and the surrounding fractures. This reduces fracture and matrix porosity and permeability. The reduction of matrix pore space can reduce the rate of oil recovered from the rock matrix. On the other hand, it also forces the oil out of the matrix pore space increasing oil recovery. However, this effect has not been evaluated and integrated in reservoir modeling. This study presents a coupled fluid flow and geomechanics model for modeling shale swelling to quantitatively investigate the effect of swelling on transport properties of rock matrix and fractures. The main objective is to quantitatively determine the effect of shale swelling on the oil recovery from the rock matrix. A numerical solution is presented to solve the coupled equations simultaneously for the phase pressure, fluid saturation, stress, and strain. We show that the mechanical properties of the rock matrix vary significantly as the result of water imbibition. The reduction of the fracture and matrix permeability and porosity due to swelling is considerable. This results in the reduction of more than 50% of the oil recovered from shale matrix. Hence, shale swelling should be prevented in any water injection operations.",6,6,1
Fracture,Oil-recovery,"Wang, Fei; Pan, Ziqing; Zhang, Yichi; Zhang, Shicheng",Simulation of coupled hydro-mechanical-chemical phenomena in hydraulically fractured gas shale during fracturing-fluid flowback,Fracturing-fluid flowback; Shale gas reservoirs; Hydro-mechanical-chemical model; Fracture closure; Chemical osmosis,PART I; IMBIBITION; PRESSURE; BEHAVIOR; BRINE; WELLS; COAL; OIL,"Fracturing-fluid flowback in hydraulically fractured gas shale is a complicated transport behavior involving hydrodynamic (H), mechanical (M) and chemical (C) processes. Although, many flowback models have been published, none of the models flly coupled the transient fluid flow modeling with chemical-potential equilibrium and fracture closure phenomena. In this paper, a coupled hydro-mechanical-chemical (HMC) model based on hydrodynamics, linear-elastic fracture mechanics, and chemical-potential equations is presented to simulate the fracturing-fluid flowback behavior in hydraulically fractured gas shale. The HMC model takes into account a gas-liquid two-phase flow and a triple-porosity medium, which includes primary hydraulic fractures, secondary induced fractures and shale matrix. The flowback simulation with the HMC model accounts for all the important processes in fractured shale system, including (1) water transport driven by hydraulic, capillary and osmotic convections, (2) gas transport induced by both hydraulic pressure driven convection and adsorption, and (3) fracture closure considered as an elastic deformation. The fluid transport, coupled with rock deformation, are described by a set of partial differential equations. The semi-implicit finite-difference method is used to solve these equations. The evolution of pressure, saturation, salinity and aperture profiles of hydraulic fractures, induced fractures and matrix is calculated, revealing the multi-field coupled flowback behavior in fractured gas shale. The sensitivity analysis is also performed to investigate the physiochemical properties of shale on the water load recovery and gas production rate during the fracturing-fluid flowback. The results indicate that the capillarity has the most effect followed by chemical osmosis and induced fracture closure. The sub-irreducible water saturation has the weakest effect. Moreover, the matrix-related physiochemical parameters cause opposite influences on water load recovery and gas production rate. While, the influence of induced fracture-related parameters on both water load recovery and gas production rate is consistent. Results from this study are expected to explain which is the predominant mechanism for fracturing-fluid retention and the inherent relationship between fracturing-fluid flowback and gas production for different initial physiochemical properties of shale.",6,6,12
Fracture,Oil-recovery,"Wu, Fei-peng; Liu, Jing; Wei, Xue-mei; Pu, Chun-sheng",A study on oxygen consumption mechanism of air-foam flooding in low-temperature oil reservoir,Low temperature and permeability oil reservoir; Air injection; Oxygen consumption mechanism; Oxygen consumption rate; Field test,AQUEOUS-SOLUTION; POLYMER GELS; OXIDATION; POLYACRYLAMIDE; INJECTION; DEGRADATION; SOLUBILITY; KINETICS; STABILITY; GAS,"Air flooding/air-foam flooding recovery technology has been attracting attention in oilfield development. The key point to the application of this technology is to ensure that the oxygen injected with the air can be fully dissipated inside the reservoir to lower the explosion risk in production wells and reduce the oxidation of the pipeline. It is generally believed that the oxygen and crude oil can react more in low-temperature-oxidation (LTO) reactions above 80 degrees C. As a large amount of oxygen would be spontaneously consumed at this temperature, this technology is mainly used in reservoirs where the temperature is greater than 80 degrees C. In the fractured low-permeability reservoir of China's Yanchang oilfield, where the reservoir temperature is only approximately 30 degrees C, a wide range of crude oil LTO would not be triggered theoretically. However, we found that the oxygen content of the associated gas in the gas channeling wells is significantly lower than that in the air. This phenomenon suggests that, there are other factors that could consume oxygen apart from the LTO reaction. To verify this assumption, an oxygen dissipation core flooding experiment at 30 degrees C and 80 degrees C was carried out to evaluate the oxygen consumption at different temperatures. At the same time, in order to determine the main controlling factors and dissipation mechanisms of oxygen dissipation, theoretical analyses and experimental studies were carried out from the aspects of reductive mineral oxidation reaction in the rock surface and formation water, the physical absorption of the micropore and the dissolution of the reservoir fluid. The results show that at the same experimental conditions, the oxygen consumption at 30 degrees C is 38.14% lower than that at 80 degrees C. The oxygen consumption factors in the low-temperature reservoir mainly include the chemical reactions between the oxygen and reducing minerals, dissolution and retention of formation water and oil, adsorption of Van der Waals forces in the reservoir and physical electronic adsorption of the hydrogen-sulfur bonds and carbon-sulfur bonds. In Chang 6 Reservoir of Ganguyi oilfield, formation water could theoretically consume 56 mg/L (1.75 mmol/L) oxygen through dissolved Fe2+. The dissolution by formation water could absorb 11.85 mmol/L oxygen (experimental value). The dissolution by oil could absorb 69.25 mmol/L oxygen (experimental test value), and the oxygen physical adsorption rate of rock pore surface was 1.26 mmol/L. Together with the pilot test data, the results show that the LTO reaction of the stratum crude oil barely occurs in the reservoir at low temperature (30 degrees C). However, a large amount of oxygen dissipation could still be achieved. This study demonstrates that air-foam flooding could break the applicable limit temperature and could also be applied in low-temperature reservoirs.",7,7,1
Fracture,Oil-recovery,"Song, Zhaojie; Bai, Baojun; Zhang, Hao",Preformed particle gel propagation and dehydration through semi-transparent fractures and their effect on water flow,Enhanced oil recovery; Preformed particle gel; Open fracture; Dehydration behavior; Conformance improvement,CONFORMANCE-CONTROL; HYDROLYZED POLYACRYLAMIDE; PERFORMANCE; TRANSPORT; INJECTION; MODELS,"Polymer gels have been widely applied to plug high permeability streaks or fractures, and to improve sweep efficiency of chase waterfloods. This work constructed semi-transparent fracture models to investigate gel propagation and dehydration behaviors using preformed particle gel (PPG) in open fractures. Roubidoux sandstone slabs were used in the models because they could better model the roughness of fractures and PPG dehydration in a real fracture system, which was rarely reported in earlier studies. Injection rate, fracture width, particle size, brine and gel concentration were taken into account to understand their effects on particle gel extrusion. Experimental results showed PPG propagated like a piston along a fracture when the fracture width was smaller than or similar to the particle size; and gravity will dominate the PPG movement when the fracture width was larger than the particle size. PPG dehydration decreased with the increasing gel injection rate, fracture width, and brine concentration used to prepare PPG. Higher PPG injection rates and lower injection rates for chase waterfloods are recommended to improve the sweep efficiency in the matrix. This study could provide an insight into the particular PPG gel treatment for conformance improvement.",7,7,1
Fracture,Oil-recovery,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Fracture,Oil-recovery,"Abolhosseini, Pejman; Khosravi, Maryam; Rostami, Behzad; Masoudi, Mohammad",Influence of Thermal Marangoni convection on the recovery of bypassed oil during immiscible injection,Injection into fracture; Marangoni flow; Benard-Marangoni convection; Immiscible injection,INTERFACIAL-TENSION; MASS-TRANSFER; FLUID; FLOW; MATRIX,"Several phenomena could recover the bypassed oil in matrixes and low permeable areas, among them; Marangoni is the most unfamiliar one in fluid flow model. This mechanism triggers a convective flow from low interfacial tension point to a high interfacial tension point because of variation in solvent concentration, temperature or electrical charge. In this study, experimental and analytical tools have been utilized to investigate the effect of thermal Marangoni flux on the enhancement of oil recovery during immiscible injection in a matrix-fracture system. Results of non-isothermal experiments have been compared with isothermal (as the zero level of Marangoni) to study the presence of Marangoni flow and its direction respect to the fracture location. Results show that not only the Marangoni flux does exist and has significant impact on the recovery of bypassed oil but also, its magnitude is proportional to the absolute value of temperature gradient in phases interface.",8,8,2
Fracture,Oil-recovery,"Kathel, P.; Mohanty, K. K.",Dynamic surfactant-aided imbibition in fractured oil-wet carbonates,Wettability alteration; Imbibition; Gravity drainage; Fractured reservoirs; Carbonate rocks,WETTABILITY ALTERATION; GRAVITY DRAINAGE; RECOVERY; RESERVOIRS; WATER; TEMPERATURE,"Numerous studies based on static imbibition experiments at lab scale have established surfactant-aided imbibition as an improved oil recovery process for fractured oil-wet carbonate reservoirs. However, predicting performance at larger scales and at dynamic conditions (fluid flow through fracture) remains a challenge. In this study, experiments are performed on Estaillades Limestone and Texas Cream Limestone outcrop cores with varying height and diameter with permeability in the range of 8 mD to 150 mD to address this challenge. It is observed that dynamic imbibition process recovers oil faster than static imbibition. Imbibition experiments performed on cores with varying height and diameter show that oil recovery decreases with increasing diameter and height. A 3D fine grid mechanistic simulator was used to perform lab scale validation and analyze recovery mechanism. Numerically simulated velocity and saturation profiles demonstrated the recovery mechanism to be gravity dominated flow. A new scaling function is proposed for surfactant aided gravity dominated processes. Data with same boundary conditions, rock, fluids and varying dimensions can be correlated with the scaling function at early times with no fitting parameters involved. A good correlation is obtained with the data indicating the effectiveness of the scaling function. The scaling is applicable to both static as well as dynamic imbibition.",8,8,3
Fracture,Oil-recovery,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun; Alsaba, Mortadha",Lessons learned from IOR pilots in Bakken formation by using numerical simulation,CO2-EOR in shale oil reservoirs; CO2-EOR huff-n-puff operations; Unconventional EOR methods; Improved oil recovery,RESERVOIRS,"Bakken is the most productive formation among unconventional plays in North America. This formation has about 7.4 billion barrels of recoverable oil. However, the primary oil recovery is still low as 5-10%. Miscible natural gas and carbon dioxide (CO2) might be the most two potential strategies to improve oil recovery in such a complex play. In this study, some of the IOR pilots which have been conducted in Montana, North Dakota, and South Saskatchewan have been presented. The performance results of these pilots in US-Bakken versus Canadian-Bakken have been compared. Moreover, the reasons behind the successful IOR pilots in Canadian-Bakken versus US-Bakken have been discussed. Then, numerical simulation models have been constructed to mimic the results of some pilots. Two different compositional models have been built for oils of two different formations. Furthermore, two different models, single porosity model and dual permeability model have been created to match the performance of some pilots. Implementation of molecular diffusion mechanism has been conducted in both of single porosity and dual permeability model. Finally, the continuous miscible gases injection versus huff-n-puff protocols have been compared and investigated. The results showed that the performance of natural gases generally over-performed the CO2 injection technique's in Bakken formation. Although the diffusion flow is dominant in these types of reservoirs, the diffusivity of the injected CO2 into formation oil is slow due to the fact that CO2 has large molecules as compared with the small pore throats of these porous media. Accordingly, miscible CO2-EOR might not be beneficial in huff-n-puff operations as in continuous flooding process. However, the success of natural gases based EOR does not have that strong functionality of molar diffusivity. Therefore, their performance was much better than CO2 performance in the field scale of these tight formations. Furthermore, the numerical simulation of this study concluded that the spacing between the production wells and injection wells should be minimized, for the continuous flooding process of miscible-gases EOR, to enhance their performance. Although the permeability of Canadian-Bakken has a permeability of 1-2 order higher than the permeability of US-Bakken, the pilots' spacing between injectors and producers in Canadian Bakken is interestingly much shorter than that for US-Bakken, which might be the reason behind the EOR success in Canadian Bakken. Finally, the activatiown process of the highly intensive natural fractures might be the key to enhance the diffusivity of CO2-EOR. Otherwise, natural gases are highly recommended to be the most potential EOR in these types of reservoirs. This study explains how the diffusion mechanism affects the performance of different miscible gases to improve oil recovery in these plays since they are more complex and very different from conventional formations. Also, it suggests that CO2 flooding process would be a good practice to overcome the limitations of CO2-diffusion rate in these reservoirs if the conformance problems are wisely controlled.",8,8,4
Fracture,Size,"Tandon, Saurabh; Heidari, Zoya; Aderibigbe, Aderonke; Shi, Jingyu; Fuss-Dezelic, Tihana",A new method for mechanical damage characterization in proppant packs using nuclear magnetic resonance measurements,Mechanical damage; Proppant packs; Nuclear magnetic resonance; Measurements; Pore-size distribution; Fines,HYDRAULIC CONDUCTIVITY; NMR RELAXATION; POROSITY; FLUIDS,"Proppant performance can significantly affect the success of hydraulic fracturing treatments and production in unconventional plays. Performance of proppants can decrease rapidly by mechanical damage. Quantifying the impact of mechanical damage on proppant performance can be challenging either in the laboratory or in-situ condition. This paper introduces a new method based on Nuclear Magnetic Resonance (NMR) Transverse relaxation (T-2) measurements to characterize pore-size distribution in proppant packs. Quantifying the pore-size distribution in proppant packs enables enhanced evaluation of porosity and conductivity of proppant packs and possible mechanical damage to the packs. The objectives of this paper are (a) to evaluate the performance of this new NMR-based method for characterizing pore structure of the proppant packs, and (b) to isolate and quantify the mechanical damage in proppant packs due to generating of fines in the laboratory using this new NMR-based method. First, we prepared proppant pack test samples in three categories including (a) different types of proppants with different surface relaxivity, (b) mixture of proppants with different sizes, and (c) proppants undergone different levels of mechanical damage. We measured NMR response in proppant packs and quantified the impacts of proppant type, size, and mechanical damage on NMR T-2 distribution. Next, we used the fractional packing model to quantify the efficiency of packing of proppant mixture and to quantify the changes in porosity of proppant packs caused by variation in size and fraction of fines. Finally, we used Kozeny-Carman (KC) equation and modified Schlumberger Doll Research (SDR) equation to correlate the variation in T-2 distribution to the decrease in proppant pack permeability. Results showed that NMR T-2 distribution is sensitive to pore-size distribution in the proppant packs. The variable pore-size distribution was either a consequence of having a mixture of proppants with different sizes or different levels of mechanical damage. The impacts of fines on the pore-size distribution of the proppant packs was measureable, which is promising for the successful application of the introduced method for time-lapse quantification of generated fines. We also observed a measurable sensitivity of T-2 distribution to mechanical damage in the proppant packs, which enables quantifying the level of damage in proppants through quantifying pore structure in the proppant packs. The NMR T-2 measurements were, however, sensitive to the presence of paramagnetic materials such as iron in proppants. This sensitivity was more significant in cases where paramagnetic materials were distributed on the proppant surface. The proposed method is considered as an indirect measurement of pore structure and could potentially provide a quantitative assessment of the proppant pack conductivity both in the lab-scale and in-situ conditions. Improved assessment of proppant conductivity can help in enhancing the design and execution of fracture treatments for successful development of unconventional plays.",4,4,0
Fracture,Size,"Mousavi, E.; Cheshomi, A.; Ashtari, M.",Estimating elasticity modulus and uniaxial compressive strength of sandstone using indentation test,UCS; Elasticity modulus; Indentation test; Critical transition force (CTF); Indentation modulus (IM),LOAD TEST; ROCK,"Elastic modulus (E) and uniaxial compressive strength (UCS) are very important engineering parameters that is required for many engineering projects. In some projects such as well drilling for oil production, deep underground tunnels in crushed zone, due to the depth of the well and fractures of rocks, there are some problems for obtained standard core samples. In this situations various methods have been developed for determining UCS and E using drilling cutting. Indentation test is one of these methods, in this method, an indenter penetrates into the stabilized samples in the surrounding material and then Critical Transition Force (CTF) and Indentation modulus (IM) determine. In the present study in order to developing the application of indentation testing for sandstone, and investigate the effect of particles size, shape and thickness, 14 sandstone blocks were collected from different formations in Iran and their physical characteristics, UCS and, E were measured using standard methods. After crushing the blocks and preparing 600 particles with dimensions of 3x3x3 mm(3), 5x5x3 mm(3), 5x5x5 mm(3), 5x5x8 mm(3), and 8x8x8 mm(3) and irregular shape particles with a thickness of 5 mm, indentation tests were performed on each particle and CTF and IM were calculated for each particle separately. According to the tests carried out some empirical relationships were proposed between UCS CTF (with R-2 >= 0.86) and E - IM (with R-2 >= 0.73) for different shapes and dimensions. Due to the differences in the dimensions of the produced particles, investigating the effect of surface and thickness of particle on the CTF and the IM revealed that the particle's surface had a considerable effect on the CTF and IM; however, the effect of thickness was negligible. Using the dimensionless surface parameter (S and Si), some empirical relationships between UCS - CTF/S (with R-2 >= 0.80) and E - IM/Si (with R-2 >= 0.77) were proposed for predicting UCS and E of sandstone particles with different shapes and dimensions. The accuracy of these relations was validated by performing standard uniaxial and indentation tests on 4 sandstone blocks and comparing measured UCS and E with those predicted using these relations. This comparison showed there is a good correlation between measured and predicted values. The proposed equations in this study were compared with results of previous studies. The relationship proposed in the present study to predict sandstone UCS has a similar accuracy with those proposed in by other researchers.",4,5,2
Fracture,Size,"Freire Soares, Andreia Silveira; Costa Marques, Monica Regina; Calcada, Luis Americo; Borges Filho, Moacyr Nogueira; de Oliveira Petkowicz, Carmem Lucia",Interaction of blockers on drilling fluids rheology and its effects on sealing of fractures and prevention of filtrate invasion,Drilling fluids; Lost circulation and loss control material,XANTHAN GUM; PARTICLE-SIZE; FLOCCULATION; BENTONITE; WATER; MONTMORILLONITE; PERFORMANCE; POLYMERS; CHARGE,"Drilling fluids from oil wells play an important role in the drilling operations, including cleaning and maintaining well stability, as well as cooling and lubricating the drill bit. Invasion of fluid in the rock formation, through natural or induced fractures, can compromise the entire well. In this work we evaluated the effect of combination of viscosifiers xanthan gum (XG), carboxymethylcellulose (CMC), Hydroxypropylstarch (HPS) and bentonite in the interaction with lost circulation materials diatomaceous earth (DE) and hydrogel (HG). The main objective was to obtain a product with adequate rheological properties showing viscoelastic behavior and minimizing loss of fluid to the wellbore. Tests of X-ray diffraction (XRD) and zeta potential were performed to analyze the interactions between the particles present in the fluids. With rheological tests we studied the effects of the addition of different components on the fluid rheology. XRD technique showed that the bentonite deflocculated only in polymer suspensions with DE. The results of zeta potential suggest that only the fluid with Hydroxypropylstarch and HG was completely flocculated and unstable, showed through particle sizes distribution tests. The gel modulus (G') and viscous modulus (G '') of the fluids were affected by the interaction of bentonite layers with lost circulation materials particles, with significant increase of G' with the addition of HG to the suspension. There was a decrease of viscosity due to agglomeration of HG and DE particles, an increase of G' can be observed as well. Among all the fluids, the suspension of CMC and bentonite showed better affinity with the HG lost circulation material, presenting thermal stability and a wide range of particle size, essential property to avoid the loss of fluid through the fractures and pores of the rock formation.",6,6,2
Fracture,Size,"Zhao, Lin; Jiang, Hanqiao; Zhang, Shaoqing; Yang, Hanxu; Sun, Fengrui; Qiao, Yan; Zhao, Lijun; Chen, Wenbin; Li, Junjian",Modeling vertical well in field-scale discrete fracture-matrix model using a practical pseudo inner-boundary model,Discrete fracture-matrix model; Vertical fractured well; Well model; Mesh generation; Transmissibility evaluation,NUMERICAL RESERVOIR SIMULATION; EQUIVALENT WELLBLOCK RADIUS; SHALE GAS; HORIZONTAL WELLS; BLOCK PRESSURES; MESH GENERATOR; GRIDS; MATLAB; FLOW; PERMEABILITY,"The discrete fracture-matrix model (DFM) technique has contributed to the rapid development of fracture modeling. In terms of vertical well modeling, however, the current well models fail to handle the field-scale DFM utilization. In this study, a pseudo inner-boundary model is presented tailored to this problem. Specifically, the modeling methodology consists of mesh generation and transmissibility evaluation. Regarding the mesh generation, the model handles the 2-D triangular-gridded matrix and 1-D edge-gridded fracture. The strict geometric analogy to generate triangles for the wellbore is abandoned, instead, the wellbore is approximated by a source/sink point and returns to a circular geometry when evaluating the transmissibility. The treatment sheds the limitation of triangle size and proves to boost the generation efficiency. Regarding the transmissibility evaluation, the derived formulations apply the radial/linear approximation for flow in matrix/fracture well-gridblock, and various conditions are considered, including gridblock geometry (triangle and rectangle), flow state (steady-state, unsteady-state and pseudosteady-state) and well completion (fully penetrating well and partially penetrating well). In addition, the compatibility with the star-delta transformation is discussed. By refining the well-gridblock into several sub-triangles, the formulations could be rapidly implemented to non-triangle-based DFM (e. g. PEBI, Cartesian). The model performance is demonstrated in eight validation cases. The model is shown to provide results in close agreement with those of reference in cases where the direct comparisons are performed.",6,6,4
Fracture,Size,"Zhao, Junlong; Tang, Dazhen; Qin, Yong; Xu, Hao","Experimental study on structural models of coal macrolithotypes and its well logging responses in the Hancheng area, Ordos Basin, China",Coal macrolitotype; Structural model; Pore and fracture; Advanced well logging; Hancheng,PORE-STRUCTURE CHARACTERIZATION; SCANNING-ELECTRON-MICROSCOPY; SOUTHERN QINSHUI BASIN; METHANE RESERVOIRS; JHARIA COALFIELD; EASTERN MARGIN; SURFACE-AREA; GAS CONTENT; PERMEABILITY; SEAMS,"Coal macrolithotype (bright, semi-bright, semi-dull, and dull coals) controls the heterogeneity of coal physical properties in the coalbed methane (CBM) reservoir. However, few scholars carried out the work aiming at the compositional-based macrolithotype analysis of coal reservoirs. In this work, the Hancheng area, Ordos Basin, China, was taken as an example to understand the macrolithotype difference, establish the structural models of macrolithotypes, and then evaluate the responses of advanced well loggings (the natural gamma-ray spectroscopy (NGS), formation microresistivity image (FMI), and cross-dipole array acoustic (XMAC) loggings). Results show that, from the bright to dull coal, the coal density, ash yield, and mineral content increase while the vitrinite content and pore-fracture development degree decrease gradually. The dull and semi-dull coals usually are found in touch with the mudstone (roof, floor, and parting) while the bright or semi-bright coal occurs as an interlayer between them. In the structural models of macrolithotypes for the CBM reservoir, the fracture model couples the artificial and macrofractures controlled by the tectonic stress field as well as the microfracture mainly restricted by the coal macrolithotypes; the pore model shows multilevel pores with gradually decreasing pore size, namely the protogenetic (plant tissue and intergranular pores) and secondary (gas and intermolecular pores) pores; and the pore-fracture relation model is characterized by the multilevel communication between the pores and fractures. Of all the three advanced logging responses of macrolithotypes, the NGS and XMAC show a good consistency with the natural gamma (GR) and interval transit time (AC) loggings since the former was derived from the latter essentially, respectively. But using FMI to identify macrolithotypes is error-prone due to the strong coal heterogeneity around the wellhole. From the bright to dull coal and mudstone, the values of thorium, kalium, uranium elements and GR (or GR without uranium) increase while those of AC including the longitudinal, transverse, and Stoneley waves decrease gradually.",7,8,0
Fracture,Size,"Song, Zhaojie; Bai, Baojun; Zhang, Hao",Preformed particle gel propagation and dehydration through semi-transparent fractures and their effect on water flow,Enhanced oil recovery; Preformed particle gel; Open fracture; Dehydration behavior; Conformance improvement,CONFORMANCE-CONTROL; HYDROLYZED POLYACRYLAMIDE; PERFORMANCE; TRANSPORT; INJECTION; MODELS,"Polymer gels have been widely applied to plug high permeability streaks or fractures, and to improve sweep efficiency of chase waterfloods. This work constructed semi-transparent fracture models to investigate gel propagation and dehydration behaviors using preformed particle gel (PPG) in open fractures. Roubidoux sandstone slabs were used in the models because they could better model the roughness of fractures and PPG dehydration in a real fracture system, which was rarely reported in earlier studies. Injection rate, fracture width, particle size, brine and gel concentration were taken into account to understand their effects on particle gel extrusion. Experimental results showed PPG propagated like a piston along a fracture when the fracture width was smaller than or similar to the particle size; and gravity will dominate the PPG movement when the fracture width was larger than the particle size. PPG dehydration decreased with the increasing gel injection rate, fracture width, and brine concentration used to prepare PPG. Higher PPG injection rates and lower injection rates for chase waterfloods are recommended to improve the sweep efficiency in the matrix. This study could provide an insight into the particular PPG gel treatment for conformance improvement.",7,7,1
Fracture,Size,"Zeng, Qinglu; Lu, Wenzhong; Zhang, Ronghu; Zhao, Jilong; Ren, Ping; Wang, Bo","LIDAR-based fracture characterization and controlling factors analysis: An outcrop case from Kuqa Depression, NW China",LIDAR; Fracture; Development characterization; Controlling factors; Kuqa Depression,THRUST BELT; EXAMPLE; MODELS; RESERVOIRS; SANDSTONE; GEOLOGY,"Fracture is of primary importance to the natural gas production capacity from many tight sandstone reservoirs in the Kuqa foreland basin, NW China, but the orientation, size and plane porosity of the fractures in the subsurface is difficult to measure directly. Terrestrial light detection and ranging (LIDAR) surveys can offer factual information of outcrop-based research efforts to characterize fracture development laws and controlling factors. In this paper, utilizing a multi-level covering, we obtain the three dimensional (3D) point cloud data from a LIDAR survey launched at a typical outcrop. Matching with high-resolution digital photos and artificial measured information, the 3-D positions of natural fractures are extracted strictly in the data volume section. Furthermore, the fracture and reservoir model can be founded based on the systematic sampling and laboratory analysis, while a variety of accurate facture parameters can be obtained. It is founded that three groups of shear fractures are mainly developed in two periods with large inclination, short trace length and small spacing of normal distribution. Its patterns has provided a literal distribution of penetrating fracture zone and interlayer fracture zone with a single and a double set of advantage orientation respectively. It turned out that the fracture development scale is controlled by lithology, layer thickness, maximum principle paleostress and rock composition with a good exponential relationship. Our work could provide a workflow linking outcrop fracture observations to the 3D model of subsurface fracture prediction and extend modeling capability in other outcrop studies.",7,9,2
Fracture,Size,"Paes de Godoi, Felipe Augusto; Scheid, Claudia Miriam; Bernardo, Leticia Siqueira; de Oliveira, Beatriz Rosas; Borges Filho, Moacyr Nogueira; Calcada, Luis Americo",Study of the pressure drop and the flow of loss circulation material suspensions in a physical simulator of fractures,Fractures sealing; Flow of suspensions; Calcium carbonate; Particulate system,,"The loss of fluid to the rock formation is one of the main problems encountered in oil well drilling operations. To mitigate this problem, particulate materials responsible for sealing fractures or for strengthening the well are used. The main objective of this work is to study the flow of Non-Newtonian suspensions through fractures, the pressure drop associated with this flow and the process of sealing fractures using particulate materials suspensions. The flow through fracture of Non-Newtonian suspensions was studied using an apparatus that allowed these fluids to flow through three different artificial fractures with widths of 2 mm, 5 mm and 10 mm and an average 1 cm depth. The suspensions were prepared by mixing water, viscosifying polymer and particulate materials based on laminar calcium carbonate. The particulate materials used are called fine and medium because they have different particle size distributions. The characterization of the solutions and suspensions was carried out from the rheological tests and the determination of the densities and the particle size distributions. The influence of factors such as flow rate, concentration and particle size distributions on the flow of the suspensions through fractures and its sealing capabilities were evaluated. The suspensions of the fine material particles were able to seal only the 2 mm fracture. The suspension composed of the particles of the medium material proved efficient in sealing the three fractures. A mathematical methodology was proposed with the objective of correlating the pressure drop and the flow rate of suspensions in fractures.",7,7,3
Fracture,Size,"Dong, Kai; Zhu, Ding; Hill, A. Daniel",Mechanism of wormholing and its optimal conditions: A fundamental explanation,Wormholing mechanism; Carbonate acidizing; Optimal conditions; Pore growth function; Pore scale,POROUS-MEDIA,"Acid stimulation is commonly used in carbonate reservoirs, which can be either matrix acidizing or acid fracturing. In both treatments, wormholes can form. In matrix acidizing, wormholing is favorable because the damaged region can be bypassed. In acid fracturing, wormholing is not desired because it can increase fluid loss, which can limit conductive fracture length. Three major processes are involved for wormholing: convection, diffusion and surface reaction. A thorough understanding of these processes is necessary for engineering design. In this paper, we fundamentally explore wormholing mechanisms starting from pore growth. A wormhole forms when larger pores grow in cross-sectional area at a rate that greatly exceeds the growth rate of smaller pores due to surface reaction. This happens when pore growth follows a particular mechanism, which is discussed in this paper. We developed a model to predict wormhole growth behavior. The model uses the mode-size pore in a pore size distribution - the pore size that appears most frequently in a distribution - to predict the growth of the pore. By controlling the acid velocity inside of it, we can make larger pores grow much faster than other smaller pores, thus reaching the most favorable condition for wormholing. This also results in a balance between overall acid/rock reaction and acid flow. By understanding the wormholing mechanism, engineers can select proper treatment fluids and pumping rate for acid stimulation design.",8,9,0
Fracture,Size,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Fracture,Gravity,"Osiptsov, A. A.; Boronin, S. A.; Zilonova, E. M.; Desroches, J.",Managed Saffman-Taylor instability during overflush in hydraulic fracturing,Hele-Shaw cell; Hydraulic fracturing; Saffman-Taylor instability; Yield stress; Bingham fluid; Proppant transport; Fingering; Slumping; Shale gas fracturing; Fracture,YIELD-STRESS FLUIDS; HELE-SHAW CELL; NEWTONIAN SLURRY; SUSPENSION FLOW; DISPLACEMENT; PLACEMENT; MECHANICS; MODEL,"Overflushing is a common practice in multistage completions of horizontal wells in unconventional formations. It consists in displacing the suspension by a thin fluid, away from the wellbore and into the fracture. It can, however, overly displace proppant and leave a significant portion of the fracture unsupported near the wellbore, or trigger gravity slumping, again leaving unpropped area near the wellbore. That unpropped area can then close during production, damaging the performance of the fracture. A novel modeling approach was investigated to gain insight into the overflush process and determine secure bounds for maintaining the fracture performance. From a fluid mechanics viewpoint, overflushing is the displacement of a Hershel-Bulkley fluid by a power law fluid in a Hele-Shaw cell, leading to Saffman-Taylor instability at the fluids interface. Whereas most hydraulic fracturing simulators use power-law rheology model, we used a novel numerical approach accounting for the yield-stress behavior of the slurry. Using the lubrication approximation, we derived a model, which includes transport equations for fluid volume fractions and a nonlinear elliptic equation for pressure with mixed-type boundary conditions. Validation was previously performed against three sets of experiments in Hele-Shaw cells, comprising gravitational slumping and displacement of fluids with fingering. Based on fracture mechanics, we analyzed how large a portion of the fracture may be left unsupported before it is severely pinched during drawdown. A parametric study was performed on the displacement of the yield-stress slurry by the overflushing fluid. Qualitatively, when fingers of the overflushing fluid can be created at the overflush/slurry interface, large slurry pillars are preserved in the near-wellbore area, which may keep the fracture open. Three main scenarios of fluids distribution are identified and classified in terms of the oveflush fluid-to-slurry viscosity ratio.: (i) the slumping-dominated regime, where light clean overflush fluid goes on top of sedimenting heavy proppant-laden suspension (xi greater than or similar to 0.1), (ii) an intermediate scenario of slumping combined with fingering (xi similar to 0.01), and, finally, (iii) a pure fingering-dominated scenario, when the slurry viscosity is high (xi < 10(-3)). The third scenario minimizes the geomechanical risks of overflushing by providing tiny fingers that are unlikely to be pinched out during fracture closure.",2,2,0
Fracture,Gravity,"Xiao, Dong; Meng, Yingfeng; Li, Gao; Shu, Gang; Li, Shutao; Guo, Yuying",Development of a mathematical model and experimental validation of borehole instability due to gravity displacement during drilling in a fractured formation,Gravity displacement; Fracture formation; Drilling; Mathematical model; Model experiment,LOST CIRCULATION; WELL KICK,"Lost Circulation and overflow often occur concurrently in fracture formation due to gravity displacement, causing a downhole complexity, out of control for blowout, reservoir damage, well control difficulty, drilling cycle prolonging and cost overrun. There is still ongoing investigation and lack of basic theoretical understanding. In this paper, a mathematical model of gas-liquid gravity displacement is established and solved, as well as verified by model experiment. The results are used to develop a theoretical foundation that explains the phenomena, and a solution method is proposed for practical application.",3,5,0
Fracture,Gravity,"Wang, Yong; Hou, Jirui; Tang, Yong; Song, Zhaojie; You, Zhenjiang",Application of modified Dykstra-Parsons method to natural bottom-water drive in non-communicating fractured-vuggy reservoir,Fractured-vuggy reservoir; Natural bottom-water drive; Dykstra-Parsons method; Gravity number,DISPLACEMENT,"Universal existence of the filled vug and fracture in carbonate fractured-vuggy reservoir upgrades the complexity of fluid flow as the coexistence of free flow and porous flow. The highly discrete distribution of fracture and vug makes it possible to apply Dykstra-Parsons method in this kind of medium. A modification of Dykstra-Parsons method is proposed to depict the displacement in fracture-vug system, which consists of multiple non-communicating fracture-vug units with each containing fracture, fills, and vug. The displacement front advance equation is derived piecewise corresponding to the position of the front in fracture, fills, and unfilled vug of one unit. The solution to this equation for every fracture-vug unit is used to estimate the production dynamics of the fracture-vug system, including the fractional oil recovery, the water cut, the injected pore volume, and the injectivity ratio. A calculating example with log-normal distribution for fracture aperture is involved to make the sensitivity analysis of gravity number, viscosity ratio, fills properties, and variation of the fracture aperture. In terms of increased oil recovery, decreased water cut, and delayed water breakthrough, it was found that a better performance reached in the condition of weak heterogeneity of fracture, large gravity number, and lower oil//water viscosity ratio; the fills with low permeability and high filling degree is favorable when all vugs are filled identically.",3,3,2
Fracture,Gravity,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun; Almansour, Abdullah",Numerical simulation study to understand the performance of RPM gels in water-shutoff treatments,,DISPROPORTIONATE PERMEABILITY REDUCTION; WELLS,"Disproportionate Permeability Reduction (DPR) is often used as a water-shutoff treatment in production wells when conventional solutions such as mechanical isolations are difficult to perform. Although this property has been well documented by different investigators, the performance of DPR treatments in field applications has varied between success and failure without understandable reasons. This work investigated the DPR performance in different scenarios to see when, where and at which conditions DPR treatments can give better results. Numerical simulation methods were used to simulate different scenarios happening in oil and gas fields such as five-spot pattern system and linear-system, with different number of layers, with and without crossflow. The possibility of using DPR treatment in hydraulically-fractured reservoirs was also investigated since many reports indicated that there is an increase in the water production for some oil and gas reservoirs after being hydraulically-fractured. Moreover, the physical reasoning behind the variations in the DPR performance for different scenarios has been extensively discussed. The results explored that the DPR performance was excellent in both of water-cut reduction and oil-recovery improvement when the flow regime was viscous dominated (viscous-gravity number < 0.1). On the other hand, when the flow regime was gravity dominated (viscous-gravity number > 10), the effective period of DPR treatment was a short-term remedy. Secondly, when the high-K layer is existed at the lower-zone of oil or gas reservoir, the reservoir would be a good candidate for the DPR treatment as compared with the reservoirs that have the high-K layer located at the upper zone. Furthermore, selecting the correct time to perform DPR treatments generally could have a significant role to mitigate water production. Finally, the dimensions of the treated fracture are the key components to get a successful DPR-treatment in the hydraulically fractured reservoirs.",5,5,0
Fracture,Gravity,"Liang, Bo; Lan, Hui-qing; Lin, Nan",Diffusion simulation and safety assessment of oil leaked in the ground,Oil; Leak Multi-phase flow in porous media; Diffusion; Test; Safety assessment,ASSESSING NAPL CONTAMINATION; MULTIPHASE FLOW MODEL; POROUS-MEDIA; GRAVITY CURRENTS; RISK-ASSESSMENT; FRACTURED MEDIA; PERSPECTIVE; SITE,"Oil leaked in the ground causes pollution of land and groundwater, and even leads to an explosion. Therefore, it is significant to make a research on safety assessment of diffusion of oil in the ground after oil leakage accident happened. Taken a perforation-caused leakage accident of oil in buried piping in China as an example, the computational fluid dynamics method of multiphase flow in porous media was used to determine the distribution of leaked oil in the ground in this paper. Then, an onsite drilling test was carried put and it's found that the simulation of distribution of leaked oil agreed with the test result. Finally, on the base of the simulation results, fuzzy synthetic evaluation method was carried out and hazardous areas of oil leaked in the ground were put forward.",5,6,2
Fracture,Gravity,"Song, Zhaojie; Bai, Baojun; Zhang, Hao",Preformed particle gel propagation and dehydration through semi-transparent fractures and their effect on water flow,Enhanced oil recovery; Preformed particle gel; Open fracture; Dehydration behavior; Conformance improvement,CONFORMANCE-CONTROL; HYDROLYZED POLYACRYLAMIDE; PERFORMANCE; TRANSPORT; INJECTION; MODELS,"Polymer gels have been widely applied to plug high permeability streaks or fractures, and to improve sweep efficiency of chase waterfloods. This work constructed semi-transparent fracture models to investigate gel propagation and dehydration behaviors using preformed particle gel (PPG) in open fractures. Roubidoux sandstone slabs were used in the models because they could better model the roughness of fractures and PPG dehydration in a real fracture system, which was rarely reported in earlier studies. Injection rate, fracture width, particle size, brine and gel concentration were taken into account to understand their effects on particle gel extrusion. Experimental results showed PPG propagated like a piston along a fracture when the fracture width was smaller than or similar to the particle size; and gravity will dominate the PPG movement when the fracture width was larger than the particle size. PPG dehydration decreased with the increasing gel injection rate, fracture width, and brine concentration used to prepare PPG. Higher PPG injection rates and lower injection rates for chase waterfloods are recommended to improve the sweep efficiency in the matrix. This study could provide an insight into the particular PPG gel treatment for conformance improvement.",7,7,1
Fracture,Gravity,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Fracture,Gravity,"Kathel, P.; Mohanty, K. K.",Dynamic surfactant-aided imbibition in fractured oil-wet carbonates,Wettability alteration; Imbibition; Gravity drainage; Fractured reservoirs; Carbonate rocks,WETTABILITY ALTERATION; GRAVITY DRAINAGE; RECOVERY; RESERVOIRS; WATER; TEMPERATURE,"Numerous studies based on static imbibition experiments at lab scale have established surfactant-aided imbibition as an improved oil recovery process for fractured oil-wet carbonate reservoirs. However, predicting performance at larger scales and at dynamic conditions (fluid flow through fracture) remains a challenge. In this study, experiments are performed on Estaillades Limestone and Texas Cream Limestone outcrop cores with varying height and diameter with permeability in the range of 8 mD to 150 mD to address this challenge. It is observed that dynamic imbibition process recovers oil faster than static imbibition. Imbibition experiments performed on cores with varying height and diameter show that oil recovery decreases with increasing diameter and height. A 3D fine grid mechanistic simulator was used to perform lab scale validation and analyze recovery mechanism. Numerically simulated velocity and saturation profiles demonstrated the recovery mechanism to be gravity dominated flow. A new scaling function is proposed for surfactant aided gravity dominated processes. Data with same boundary conditions, rock, fluids and varying dimensions can be correlated with the scaling function at early times with no fitting parameters involved. A good correlation is obtained with the data indicating the effectiveness of the scaling function. The scaling is applicable to both static as well as dynamic imbibition.",8,8,3
Fracture,Degrees C,"Qi, Ning; Li, Boyang; Cai, Wenbin; Li, Xiaqing; Gao, Chengyuan",An optimal degrading agent formulation for detachable packing screens applicable for screenless sand control,Detachable packing screen; Degradation agent; Degradation degree; Degradation rate; Screenless sand control,DEGRADATION,"A new detachable packing screen used for sand control in oilfields has been designed. The key technology is to achieve rapid and effective downhole detachment of PLA-T (a polylactic acid material) tubing. An optimal formulation of the degradation agent was proposed considering the degradation degree and degradation rate of PLA-T materials. The temperature, salt and dilution tolerance of such degradation agent was evaluated under conditions simulating the in-situ reservoir environment. The degradation mechanism of the PLA-T was analyzed through scanning electron microscope (SEM) on the PLA-T surface during the reaction process. It is shown that the optimal formulation is that acetone: dimethylformamide: ethylenediamine ratio equals to 3: 2: 5. Under reservoir conditions with temperatures from 50 degrees C to 80 degrees C, water salinities from 10,000 mg/L to 100,000 mg/L and diluted concentrations from 70% to 90% of the original concentration, the degradation time of the PLA-T tubing ranges from 6 min to 92 min. This system maintains its excellent degradation capability under the complex downhole situation. The SEM tests show that the surface structure of the PLA-T changes gradually from the smooth surface, to cracks, then fractures, irregular fractures and finally the fracture-hole structure, and correspondingly the degradation rate of PLA-T first increases and then drops. The proposed high-efficiency degradation agent can achieve effective detachment of the downhole packing screen by rapidly degrading the PLA-T tubing, which enables screenless sand control of the unconsolidated sandstone reservoirs.",2,2,0
Fracture,Degrees C,"Leyva-Gomez, H.; Babadagli, Tayfun",Efficiency of heavy-oil/bitumen recovery from fractured carbonates by hot-solvent injection,Injection parameters optimization; Heavy oil; Hot solvent; Fractured carbonate reservoirs; Oil dilution,RESERVOIRS SOS-FR; OIL-RECOVERY; BITUMEN RECOVERY; ASPHALTENE DEPOSITION; VAPOR EXTRACTION; AIDED PROCESS; STEAM; SIMULATION; SANDS; PILOT,"This paper presents an extensive analysis of three different solvents injected through two different rock types under dynamic conditions, at elevated temperatures, to recover heavy-oil/bitumen from fractured carbonates. The main idea was to identify the optimal temperatures needed for maximal recovery by hot solvent injection for a wide range of solvents. We also considered the optimal conditions for effective solvent retrieval for the economics of this type recovery approach. In order to represent a wide range of carbon number solvents, heptane and naphtha were injected at atmospheric pressure and temperatures ranging from 70 to 120 degrees C and 21.5-100 degrees C, respectively. Propane was injected at a pressure of 1483-1511 kPa and a temperature ranging from 22 to 60 degrees C to be in the liquid phase. Indiana limestone (outcrop) and vuggy naturally fractured carbonate samples (outcrop core samples from a producing formation in Mexico) were selected as core samples. Hot solvent was injected continuously through artificially fractured cores followed by hot water (or steam injection) phase for solvent retrieval. The optimal temperatures for heavy oil recovery and solvent retrieval, in the subsequent hot water injection, for each kind of rock sample and type of solvent were determined. The results revealed that heavy oil recovery increase with the solvent carbon number used. Also, it was observed that when the temperature is higher than the saturation value for the given pressure curve, the recovery decreases and the lightest component of the heavy oil are dragged by the gas stream.",5,5,1
Fracture,Degrees C,"Wu, Fei-peng; Liu, Jing; Wei, Xue-mei; Pu, Chun-sheng",A study on oxygen consumption mechanism of air-foam flooding in low-temperature oil reservoir,Low temperature and permeability oil reservoir; Air injection; Oxygen consumption mechanism; Oxygen consumption rate; Field test,AQUEOUS-SOLUTION; POLYMER GELS; OXIDATION; POLYACRYLAMIDE; INJECTION; DEGRADATION; SOLUBILITY; KINETICS; STABILITY; GAS,"Air flooding/air-foam flooding recovery technology has been attracting attention in oilfield development. The key point to the application of this technology is to ensure that the oxygen injected with the air can be fully dissipated inside the reservoir to lower the explosion risk in production wells and reduce the oxidation of the pipeline. It is generally believed that the oxygen and crude oil can react more in low-temperature-oxidation (LTO) reactions above 80 degrees C. As a large amount of oxygen would be spontaneously consumed at this temperature, this technology is mainly used in reservoirs where the temperature is greater than 80 degrees C. In the fractured low-permeability reservoir of China's Yanchang oilfield, where the reservoir temperature is only approximately 30 degrees C, a wide range of crude oil LTO would not be triggered theoretically. However, we found that the oxygen content of the associated gas in the gas channeling wells is significantly lower than that in the air. This phenomenon suggests that, there are other factors that could consume oxygen apart from the LTO reaction. To verify this assumption, an oxygen dissipation core flooding experiment at 30 degrees C and 80 degrees C was carried out to evaluate the oxygen consumption at different temperatures. At the same time, in order to determine the main controlling factors and dissipation mechanisms of oxygen dissipation, theoretical analyses and experimental studies were carried out from the aspects of reductive mineral oxidation reaction in the rock surface and formation water, the physical absorption of the micropore and the dissolution of the reservoir fluid. The results show that at the same experimental conditions, the oxygen consumption at 30 degrees C is 38.14% lower than that at 80 degrees C. The oxygen consumption factors in the low-temperature reservoir mainly include the chemical reactions between the oxygen and reducing minerals, dissolution and retention of formation water and oil, adsorption of Van der Waals forces in the reservoir and physical electronic adsorption of the hydrogen-sulfur bonds and carbon-sulfur bonds. In Chang 6 Reservoir of Ganguyi oilfield, formation water could theoretically consume 56 mg/L (1.75 mmol/L) oxygen through dissolved Fe2+. The dissolution by formation water could absorb 11.85 mmol/L oxygen (experimental value). The dissolution by oil could absorb 69.25 mmol/L oxygen (experimental test value), and the oxygen physical adsorption rate of rock pore surface was 1.26 mmol/L. Together with the pilot test data, the results show that the LTO reaction of the stratum crude oil barely occurs in the reservoir at low temperature (30 degrees C). However, a large amount of oxygen dissipation could still be achieved. This study demonstrates that air-foam flooding could break the applicable limit temperature and could also be applied in low-temperature reservoirs.",7,7,1
Fracture,Degrees C,"Zhao, Jinzhou; Chen, Pengfei; Liu, Youquan; Mao, Jincheng",Development of an LPG fracturing fluid with improved temperature stability,Unconventional; Liquefied petroleum gas; Fracturing fluid; Crosslinking agent; Optimization,,"Continued exploitation of unconventional reservoirs using conventional hydraulic fracturing fluid technologies requires large volumes of water, which may lead to water resource shortage and environmental pollution problems. To mitigate these issues, we have developed a waterless fracturing fluid system, an LPG (Liquefied Petroleum Gas) fracturing fluid, which exhibits excellent rheological properties, at high temperatures. In order to develop this high-performance LPG fracturing fluid, two series of metal cross-linkers (aluminum cross-linkers and iron cross-linkers) were formulated. Crosslinking performance was examined via visual observation at room temperature and by rheological testing at raised temperatures. After optimizing the crosslinker formulation, the breaking performance and the regain permeability of the new LPG fracturing fluid were also examined. The new LPG fracturing fluid breaks almost completely at 90 degrees C and achieves an average regain permeability of 96.97% even at 25 degrees C, suggesting low damage in the field applications. A fracturing fluid with such good performance can satisfy the requirements of unconventional reservoir operations. Also, as far as we know, it is the first time that all of the important characteristics of an LPG fracturing fluid are reported.",7,7,8
Fracture,Degrees C,"Ghasemi, M.; Astutik, W.; Alavian, S. A.; Whitson, C. H.; Sigalas, L.; Olsen, D.; Suicmez, V. S.",Impact of pressure on tertiary-CO2 flooding in a fractured chalk reservoir,Outcrop chalk: sea-water flooding; Single-fracture/matrix system; Tertiary-CF at high pressure; Diffusion,INJECTION,"The purpose of this study is to present the numerical and experimental evaluation of tertiary-CO2 flooding (CF) at high operating pressure and temperature conditions. In this study, water flooding is followed by CO2 injection into an outcrop chalk core with a centralized fracture. Our validated numerical models reproduce the results of core flooding experiments. The experiments used an outcrop core which is vertically placed in the core-holder with the total length of 28 cm and the diameter of 12.3 cm. The axial ""fracture"" is represented by a centralized hole with the diameter of 2.2 cm. We utilize the Wood's Metal technique to initially saturate the chalk core with the North-Sea-Chalk-Field (NSCF) live oil. The core sample is aged to restore the original chalk wettability at the operating conditions. Then, the water flooding (WF) is performed by injecting brine from the bottom of the fracture and producing the oil from the top. After no additional produced oil is observed, the WF is stopped. A ""shut-in"" period follows, which allows preparing the rig for tertiary-CO2 flooding. CO2 is then injected from the top and the hydrocarbon streams are produced from the bottom of the fracture. The whole core flooding is operated at constant reservoir conditions of 300 bara and 110 degrees C, which is higher than the initial NSCF reservoir pressure (258 bara and 110 degrees C). This allows us to investigate the efficiency of the tertiary-CF at a higher operating pressure condition. We employ a compositional reservoir simulation with a developed equation of state (EOS) to model the experiment. An automated history matching procedure is developed to match the experimental results. The modeling workflow is capable of taking into account the significant vaporization effect observed during CF when the rich-CO2 enters the three-phase separator. We accurately model the WF experiment through tuning the oil-water capillary pressure and relative permeability data. The numerical model is capable of reproducing the CF lab results by employing the best match multi-component diffusion coefficients. Moreover, we successfully model the excessive water production during CO2 injection by taking into account the hysteresis effect in water-oil capillary pressure and relative permeability. Comparing these results with our previous work at lower reservoir pressure shows the positive effect of pressure on increasing the efficiency of the tertiary-CF in recovering more oil from a matrix-fracture system. Also, the tuned capillary pressure and relative permeability during WF indicate an active imbibition drive and a strongly water-wet system. Our findings are an important step towards modeling the tertiary-CO2 flooding in an actual fracture-chalk system.",8,8,2
Fracture,Degrees C,"Qiu, Liewei; Shen, Yiding; Wang, Chen",pH- and KCl-induced formation of worm-like micelle viscoelastic fluids based on a simple tertiary amine surfactant,pH-responsive surfactant; Micelle transition; Rheological behaviors; Acidic fracturing fluid,SMART USE; RHEOLOGY; SUSPENSIONS; PARTICLES; EMULSIONS; SHEAR,"To explore the application of pH-responsive surfactant, a pH-responsive N, N-dimethyl-erucamide-propylamine (DEAPA) self-assembly system was prepared and characterized. The rheological property and structural transformation of DEAPA molecular aggregations were comprehensively discussed with decreasing pH or increasing of Cl- concentration using rheology, dynamic light scattering (DLS), ultraviolet-visible (UV) spectrophotometry, and cryo-transmission electron microscopy (cryo-TEM). The properties of the DEAPA-KCl viscoelastic fluid used as the fracturing fluid were discussed in terms of the viscoelasticity, temperature-tolerance, and shear-tolerance, proppant suspension, and core permeability damage at pH 1.5. Results revealed that the microstructure of the DEAPA micelle first transformed from vesicles to spherical micelles, and finally changed to worm-like micelles when HCl solution was added. In addition, on increasing the KCl concentration, the system transforms from spherical micelles to worm-like micelles. When the Cl- concentration was increased to 0.50 mol/L (pH = 1.5), the storage modulus (G') of the DEAPA-KCl fluid became over 15 Pa and loss modulus (G '') was over 5 Pa, which suggests that elasticity is the predominant property of these worm-like micelles. Also, the viscosity of the DEAPAKCl fracturing fluid was constant at about 110 mPa s at 80 degrees C and shear rate of 170 s(-1). The settling velocity of the DEAPA-KCl fluid was lower than 0.004 mm/s at 60 degrees C, and the core permeability damage was 6.75%. Therefore, the DEAPA-KCl system is suitable for use as an acidic viscoelastic fracturing fluid.",8,8,8
Fracture,Lost Circulation,"Chen, Yuanhang; Yu, Mengjiao; Takach, Nicholas",Modeling and analysis of coupled thermal-hydrologic-mechanical processes during lost circulation,Wellbore stability; Lost circulation; Numerical simulation; Heat transfer; Geomechanics; Coupled processes,WELLBORE STABILITY; SIMULATION; BOREHOLE; FLUIDS; FLOW,"Wellbore stability remains as one of the major challenges to drilling engineers. Results of recent survey showed about one third of non-productive time of drilling operation is classified as borehole problem, where a significant part is attributed to borehole instability. The thermal regime of a formation in the vicinity of a wellbore affects the stability of the well significantly during drilling operations, especially in High pressure High Temperature (HPHT) wells. This paper describes how the thermal behavior of a tubular-wellbore-reservoir system is altered during mud loss, as well as its consequent impact on near-wellbore state of stresses and critical mud weights. A fully coupled three dimensional thermal-poro-elastic model, integrated with a transient tubular-wellbore-reservoir heat flow model, is developed to evaluate near-wellbore stresses and pore pressure redistribution during mud loss. The forced convective heat transfer coefficients in both conduits-drillpipe and annulus-are rigorously determined as a function of local flow and fluid properties. The results reveal that continuous mud loss destabilizes the wellbore as the pressure window shifts considerably over time. Critical mud weights for both tensile and compressive failures decrease during mud loss over the entire length of the wellbore, in addition to the point of loss. During severe losses, the fracture gradient at the bottom of the well can decrease by over 1 ppg within the first hour. This can intensify the existing fracturing condition and allow the development of new fractures at other locations, which leads to further losses as time progresses. This model enables prediction of a more realistic operating window during lost circulation by taking additional thermally-induced effects into account. In addition, failure indexes during mud loss considering P-rho-T coupling effect on a compressible mud column in the annulus are investigated with the proposed model. During drilling operations, especially Managed Pressure Drilling (MPD) and offshore applications with moderate to severe mud loss, the operation window should be modified by taking mud loss-induced thermal stresses into account. The mud type, wellbore geometry, circulation rate, and other parameters affect the magnitude of shift in critical mud weight during mud loss, hence evaluations should be based on specific cases.",0,0,1
Fracture,Lost Circulation,"Xiao, Dong; Meng, Yingfeng; Li, Gao; Shu, Gang; Li, Shutao; Guo, Yuying",Development of a mathematical model and experimental validation of borehole instability due to gravity displacement during drilling in a fractured formation,Gravity displacement; Fracture formation; Drilling; Mathematical model; Model experiment,LOST CIRCULATION; WELL KICK,"Lost Circulation and overflow often occur concurrently in fracture formation due to gravity displacement, causing a downhole complexity, out of control for blowout, reservoir damage, well control difficulty, drilling cycle prolonging and cost overrun. There is still ongoing investigation and lack of basic theoretical understanding. In this paper, a mathematical model of gas-liquid gravity displacement is established and solved, as well as verified by model experiment. The results are used to develop a theoretical foundation that explains the phenomena, and a solution method is proposed for practical application.",3,5,0
Fracture,Lost Circulation,"Freire Soares, Andreia Silveira; Costa Marques, Monica Regina; Calcada, Luis Americo; Borges Filho, Moacyr Nogueira; de Oliveira Petkowicz, Carmem Lucia",Interaction of blockers on drilling fluids rheology and its effects on sealing of fractures and prevention of filtrate invasion,Drilling fluids; Lost circulation and loss control material,XANTHAN GUM; PARTICLE-SIZE; FLOCCULATION; BENTONITE; WATER; MONTMORILLONITE; PERFORMANCE; POLYMERS; CHARGE,"Drilling fluids from oil wells play an important role in the drilling operations, including cleaning and maintaining well stability, as well as cooling and lubricating the drill bit. Invasion of fluid in the rock formation, through natural or induced fractures, can compromise the entire well. In this work we evaluated the effect of combination of viscosifiers xanthan gum (XG), carboxymethylcellulose (CMC), Hydroxypropylstarch (HPS) and bentonite in the interaction with lost circulation materials diatomaceous earth (DE) and hydrogel (HG). The main objective was to obtain a product with adequate rheological properties showing viscoelastic behavior and minimizing loss of fluid to the wellbore. Tests of X-ray diffraction (XRD) and zeta potential were performed to analyze the interactions between the particles present in the fluids. With rheological tests we studied the effects of the addition of different components on the fluid rheology. XRD technique showed that the bentonite deflocculated only in polymer suspensions with DE. The results of zeta potential suggest that only the fluid with Hydroxypropylstarch and HG was completely flocculated and unstable, showed through particle sizes distribution tests. The gel modulus (G') and viscous modulus (G '') of the fluids were affected by the interaction of bentonite layers with lost circulation materials particles, with significant increase of G' with the addition of HG to the suspension. There was a decrease of viscosity due to agglomeration of HG and DE particles, an increase of G' can be observed as well. Among all the fluids, the suspension of CMC and bentonite showed better affinity with the HG lost circulation material, presenting thermal stability and a wide range of particle size, essential property to avoid the loss of fluid through the fractures and pores of the rock formation.",6,6,2
Fracture,Lost Circulation,"Yang, Yuanguang; Yuan, Bin; Wang, Yongqing",Updated methodology for evaluating lost circulation control of cement slurry for double lost channels,Cementing; Fracture-pore lost channel; Bridging; Sealing coefficient,HIGH-TEMPERATURE; SYSTEMS,"This paper presents an evaluation method for evaluating the sealing capacity of cement slurry with lost circulation control for effective lost channel sealing during cementing operations. The method was developed based on a lost device and an evaluation model that we developed ourselves. This evaluation model includes three critical evaluation indexes: the loss time, loss weight, and maximum sealing pressure. In addition, it can be used to quantitatively evaluate the effective sealing capability of cement slurry with lost circulation control. This method is aimed at evaluating the sealing capacity of cement slurry as a way to investigate its applicability in designing effective treatments for the sealing of multiple lost channels. The results suggest the particle lost circulation materials (LCM) can improve the bridging capacity of fiber cement slurry. The loss capacity of a fracture-pore double lost channel is not equal to that of a fracture and a channel superposition. Moreover, the lost channel method can avoid an excessive or overly low evaluation of the sealing capacity of the cement slurry.",8,8,1
Fracture,Lost Circulation,"Vega, Marcia Peixoto; de Moraes Oliveira, Gabrielle Fontella; Fernandes, Lindoval Domiciano; Martins, Andre Leibsohn",Monitoring and control strategies to manage pressure fluctuations during oil well drilling,Kick; Circulation loss; Downhole pressure control; Decision making; Gain scheduling,LOST CIRCULATION; KICK DETECTION; MODEL; FLUID; DEEP; MUD; MITIGATION; PREDICTION; RESERVOIR; SYSTEM,"During drilling the mud flows through the drill string and exits through the choke valve. The mud density range has as constraints: pore pressure (minimum limit) and fracture pressure (maximum limit). In fact, annulus bottomhole (downhole) pressure needs to be higher than pore pressure, in order to prevent kick, and smaller than fracture pressure, for avoiding mud loss and formation damage. Experimental and simulation studies were implemented in order build a monitoring - diagnosing tool working together with a decision making routine based on an adaptive control scheme that employs gain scheduling. An experimental unit was built, presenting the most important characteristics of the drilling process. The transient nature of annulus bottomhole pressure is due to the process inherent disturbances: rheology, rate of penetration (ROP), kick and mud loss, which were all implemented at the experimental unit. The major objective of the present paper is using the experimental plant and a phenomenological model for implementing real time process automation, in order to assure drilling inside operational window, using in line measurements for flow and density disturbances under circulation loss and kick scenarios.",8,8,1
Fracture,Laplace Transformation,"Li, Binglin; Su, Yuliang; Zhan, Shiyuan; Yao, Wei; Hu, Yangming; Wang, Wendong",Temporal scale analysis of two phase flow in fractured well,Fractured well; Two phase flow; Temporal scale analysis; Time lag effect,CAPACITANCE-RESISTANCE MODEL; SHALE RESERVOIRS; PERMEABILITY; PROPAGATION; SIMULATION; BEHAVIOR; VOLUME; FIELD,"Two phase flow between two fractures commonly exists around fractured wells. Due to the fracture network, the flow velocity is extremely variable in different regions and it can be described by the temporal scale analysis. The flow velocity also changes with time during the change in water saturation, but these changes cannot be captured by the conventional temporal scale analysis. The temporal scales are obtained based on a principal equation, so it is difficult to accurately estimate the formation properties and to determine the exploitation scheme. In this study, the two phase flow model between two fractures has been proposed for the temporal scale description. The impact of reservoir heterogeneity on the temporal scales is considered in the model. Due to the tortuous flow channel shape between the fractures, the flow pressure affects the fluid flow afterwards. This is explained by the time lag effect in the model. The temporal scales are obtained by using finite element method and Laplace transformation at all time points with these considerations. Moreover, the well is soaked intermittently. The soaking duration is chosen based on temporal scales, and then discussed in terms of efficiency and recovery factor. The results showed that the water saturation profile position is reflected by the temporal scales, the flow resistance and the flow velocity are represented by their zero status response contributions, while the initial flow pressure is described by their zero input contribution. The highest zero status response contribution is different for different properties. Moreover, the time lag effect promotes the initial pressure fluctuation, and also upscales the fluid flow in tortuous channels. Finally, the soaking duration is an approximation of the time required to reduce the fracture flow pressure.",1,1,0
Fracture,Laplace Transformation,"Moosavi, Seyedeh Robab; Vaferi, Behzad; Wood, David A.",Applying orthogonal collocation for rapid and reliable solutions of transient flow in naturally fractured reservoirs,Naturally fractured reservoir; Pseudo-steady state; Orthogonal collocation method; Parametric analyses; Pressure transient response,DIFFUSIVITY EQUATION; PRESSURE RESPONSE; ELEMENT SOLUTION; WELL; SIMULATION,"Naturally fractured reservoirs (NFR) contain a significant portion of the worldwide oil and gas reserves. Pressure transient analysis is the most well-established methodology for characterizing these heterogeneous reservoirs based upon well-test data. Pressure transient responses (PTR) of oil and gas reservoirs to various production/injection scenarios is widely used for forecasting and optimizing their production performance and ultimate resource recoveries. In this study, orthogonal collocation (OC) which is a straightforward and very efficient approximate approach for solving differential equations is employed as a novel approach to simulate the PTR of NFRs. The governing equations describe fluid flow in NFR for pseudo-steady state conditions. Constant production rate from a wellbore and circular no-flow are employed as an inner and outer boundary conditions, respectively. The results of OC are verified with exact analytical solutions using the Laplace transform. Thereafter, the effects of three parameters (storativity ratio, interporosity flow coefficient, and radial distance of the outer boundary from the wellbore) are studied using pressure-derivative plots. Employing the superposition theorem, the pressure response of NFR to the multi-rate production from the wellbore is calculated. The results indicate that this approximate approach can predict the pressure transient response of NFRs with an acceptable accuracy, i.e., absolute average relative deviation (AARD) of 0.16%. The equations can be adapted to deal with other flow conditions, boundary conditions and fracture stimulated reservoirs. The proposed method provides a straightforward, faster and more accurate solution in comparison with other methods commonly used. As the OC method is simpler to execute than analytical solutions (e.g. Laplace Transform), it is easier to modify and expand for addressing more complex reservoir scenarios. Likewise, the numerical methods (e.g. finite difference and finite elements) commonly applied to model fractured reservoirs involve significantly more time-consuming calculations, making them more cumbersome to use in reservoir simulations than the proposed orthogonal collocation method.",3,4,0
Fracture,Laplace Transformation,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Fracture,Laplace Transformation,"Chen, Zhiming; Liao, Xinwei; Yu, Wei; Zhao, Xiaoliang",Transient flow analysis in flowback period for shale reservoirs with complex fracture networks,Shale reservoirs; Production performance; Two-phase flow; Flowback; Fracture networks,MODELING 2-PHASE FLOWBACK; TIGHT OIL-RESERVOIRS; HORIZONTAL WELLS; SEMIANALYTICAL MODEL; GAS-WELLS; UNCONVENTIONAL RESERVOIRS; PRODUCTION SIMULATION; PERFORMANCE; BEHAVIOR,"Model developments for transient analysis of fractured horizontal wells have gained tremendous attention in shale reservoirs, especially, during the flowback period. However, the existing models so far have rarely considered two-phase flow and complex fracture networks. To improve this situation, in this work, we present a comprehensively semianalytical two-phase flow model. Two fluids simultaneously flow in the matrix and fracture networks. By iteratively correcting the relative permeability to the phases, we incorporate the two-phase flow into fracture model. Complex fracture networks with arbitrary geometries are described and the fluid flow interplays at fracture intersections are eliminated by mass balance equation. The model solution is obtained by using Laplace transform inversion, and it is verified by performing a case study with numerical simulators. Our results show that there exist two distinct flow regimes: fluid feed and pseudo-boundary dominated flow (PBDF), which is generated by the permeability contrast between fracture networks and matrix. We also investigate the impacts of some key reservoir and fracture properties on the characteristics of the two-phase productivity index. Results indicate that the two-phase productivity index increases with an increase in initial water saturation. Furthermore, it is found that during the PBDF, different fracture-network parameters have various constant productivity indexes, providing an efficient tool to characterize the fracture networks. Based on that, we apply the model to estimate the fracture networks of a well in CJ formation from China with flowback data and micro seismic data, which provides an efficient technique to estimate the fracture parameters during the flowback period.",8,8,5
Fracture,Capillary Pressure,"Wang, Fei; Pan, Ziqing; Zhang, Yichi; Zhang, Shicheng",Simulation of coupled hydro-mechanical-chemical phenomena in hydraulically fractured gas shale during fracturing-fluid flowback,Fracturing-fluid flowback; Shale gas reservoirs; Hydro-mechanical-chemical model; Fracture closure; Chemical osmosis,PART I; IMBIBITION; PRESSURE; BEHAVIOR; BRINE; WELLS; COAL; OIL,"Fracturing-fluid flowback in hydraulically fractured gas shale is a complicated transport behavior involving hydrodynamic (H), mechanical (M) and chemical (C) processes. Although, many flowback models have been published, none of the models flly coupled the transient fluid flow modeling with chemical-potential equilibrium and fracture closure phenomena. In this paper, a coupled hydro-mechanical-chemical (HMC) model based on hydrodynamics, linear-elastic fracture mechanics, and chemical-potential equations is presented to simulate the fracturing-fluid flowback behavior in hydraulically fractured gas shale. The HMC model takes into account a gas-liquid two-phase flow and a triple-porosity medium, which includes primary hydraulic fractures, secondary induced fractures and shale matrix. The flowback simulation with the HMC model accounts for all the important processes in fractured shale system, including (1) water transport driven by hydraulic, capillary and osmotic convections, (2) gas transport induced by both hydraulic pressure driven convection and adsorption, and (3) fracture closure considered as an elastic deformation. The fluid transport, coupled with rock deformation, are described by a set of partial differential equations. The semi-implicit finite-difference method is used to solve these equations. The evolution of pressure, saturation, salinity and aperture profiles of hydraulic fractures, induced fractures and matrix is calculated, revealing the multi-field coupled flowback behavior in fractured gas shale. The sensitivity analysis is also performed to investigate the physiochemical properties of shale on the water load recovery and gas production rate during the fracturing-fluid flowback. The results indicate that the capillarity has the most effect followed by chemical osmosis and induced fracture closure. The sub-irreducible water saturation has the weakest effect. Moreover, the matrix-related physiochemical parameters cause opposite influences on water load recovery and gas production rate. While, the influence of induced fracture-related parameters on both water load recovery and gas production rate is consistent. Results from this study are expected to explain which is the predominant mechanism for fracturing-fluid retention and the inherent relationship between fracturing-fluid flowback and gas production for different initial physiochemical properties of shale.",6,6,12
Fracture,Capillary Pressure,"Aljehani, Abdulrahman S.; Da Wang, Ying; Rahman, Sheikh S.",An innovative approach to relative permeability estimation of naturally fractured carbonate rocks,Fracture roughness; Discrete fracture flow; Multiphase flow; Relative permeability; Capillary pressure,2-PHASE FLOW; CAPILLARY-PRESSURE; MULTIPHASE-FLOW; SMOOTH,"This paper presents an innovative numerical procedure for flow simulation and estimation of relative permeability of naturally fractured carbonate rocks by history matching laboratory derived multi-phase production data. The multi-phase flow simulator accounts for flow in discrete fractures with variable asperities. These discrete fractures are characterised by the fracture surface topography which is imaged with the use of surface laser scanning and micro computed tomography (mu-CT). Next, the production data for naturally fractured carbonate samples (matrix and fracture permeability), samples with no fracture (matrix permeability only) and samples with fracture only (near zero matrix permeability) for unsteady state conditions are obtained. Forward simulation performed by coupling both the matrix and fracture relative permeability to estimate production for a porous fractured system. This is validated by comparing to the laboratory obtained production data. This has allowed us to validate the proposed numerical procedure and subsequently history match the experimental production data for the porous fractured system to obtain overall porous fractured relative permeability curves. Results of this study show that there exists a strong discontinuity of phase saturation. It was also observed that Corey's parameters are best suited for history matching of the production data through porous matrix, and cubic parameters are best suited for fracture.",7,7,3
Fracture,Capillary Pressure,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Fracture,Capillary Pressure,"Ghasemi, M.; Astutik, W.; Alavian, S. A.; Whitson, C. H.; Sigalas, L.; Olsen, D.; Suicmez, V. S.",Impact of pressure on tertiary-CO2 flooding in a fractured chalk reservoir,Outcrop chalk: sea-water flooding; Single-fracture/matrix system; Tertiary-CF at high pressure; Diffusion,INJECTION,"The purpose of this study is to present the numerical and experimental evaluation of tertiary-CO2 flooding (CF) at high operating pressure and temperature conditions. In this study, water flooding is followed by CO2 injection into an outcrop chalk core with a centralized fracture. Our validated numerical models reproduce the results of core flooding experiments. The experiments used an outcrop core which is vertically placed in the core-holder with the total length of 28 cm and the diameter of 12.3 cm. The axial ""fracture"" is represented by a centralized hole with the diameter of 2.2 cm. We utilize the Wood's Metal technique to initially saturate the chalk core with the North-Sea-Chalk-Field (NSCF) live oil. The core sample is aged to restore the original chalk wettability at the operating conditions. Then, the water flooding (WF) is performed by injecting brine from the bottom of the fracture and producing the oil from the top. After no additional produced oil is observed, the WF is stopped. A ""shut-in"" period follows, which allows preparing the rig for tertiary-CO2 flooding. CO2 is then injected from the top and the hydrocarbon streams are produced from the bottom of the fracture. The whole core flooding is operated at constant reservoir conditions of 300 bara and 110 degrees C, which is higher than the initial NSCF reservoir pressure (258 bara and 110 degrees C). This allows us to investigate the efficiency of the tertiary-CF at a higher operating pressure condition. We employ a compositional reservoir simulation with a developed equation of state (EOS) to model the experiment. An automated history matching procedure is developed to match the experimental results. The modeling workflow is capable of taking into account the significant vaporization effect observed during CF when the rich-CO2 enters the three-phase separator. We accurately model the WF experiment through tuning the oil-water capillary pressure and relative permeability data. The numerical model is capable of reproducing the CF lab results by employing the best match multi-component diffusion coefficients. Moreover, we successfully model the excessive water production during CO2 injection by taking into account the hysteresis effect in water-oil capillary pressure and relative permeability. Comparing these results with our previous work at lower reservoir pressure shows the positive effect of pressure on increasing the efficiency of the tertiary-CF in recovering more oil from a matrix-fracture system. Also, the tuned capillary pressure and relative permeability during WF indicate an active imbibition drive and a strongly water-wet system. Our findings are an important step towards modeling the tertiary-CO2 flooding in an actual fracture-chalk system.",8,8,2
Oil Recovery,CO2,"Ma, Hongze; Yu, Gaoming; She, Yuehui; Gu, Yongan",A new hybrid production optimization algorithm for the combined CO2-cyclic solvent injection (CO2-CSI) and water/gas flooding in the post-CHOPS reservoirs,Well-control optimization; Steepest ascent-particle swarm optimization (SA-PSO); CO2-Cyclic solvent injection (CO2-CSI); CHOPS reservoir; Foamy-oil flow,PARTICLE SWARM OPTIMIZATION; HEAVY OIL PRODUCTION; RECOVERY; MODEL,"In this paper, a new hybrid production optimization algorithm, namely, the steepest ascent. particle swarm optimization (SA. PSO), is developed to optimize the combined CO2-cyclic solvent injection (CO2-CSI) and waterflooding (WF) or gasflooding (GF) in the post cold heavy oil production with sand (CHOPS) reservoirs. The field-scale CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF performances are predicted by upscaling the laboratory tests and using the numerical simulations with the considerations of the wormholes propagation and foamy-oil flow. The net present value (NPV) is chosen as an objective function and maximized by adjusting the well controls, such as the bottom-hole pressure (BHP) and water/gas injection rate. The efficacies of the following three optimization methods are evaluated and compared: the steepest ascent (SA) method, particle swarm optimization (PSO), and SA-PSO. It is found that the SA. PSO gives a higher global optimum NPV than the SA algorithm and requires fewer numerical simulation runs than the PSO. It combines the fast convergence of the SA algorithm and the global search of the PSO. It is also found that the CO2-CSI + GF has the highest NPV in the post-CHOPS reservoir among the three enhanced oil recovery (EOR) processes. For the CO2-CSI + GF, the gas injector should inject CO2 at the highest injection rate during the early cycles to displace the foamy oil but should be shut in during the late cycles to control the gas channeling. The optimum NPVs of the CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF are achieved when the BHPs of the producers are maintained at the lowest pressure. It is uneconomical to apply the WF immediately after the CO2-CSI due to the early water breakthrough.",1,1,3
Oil Recovery,CO2,"Golkari, Abdolah; Riazi, Masoud",Comparative study of oil spreading characteristics for water and carbonated water systems using live and dead oils,Carbonated water alternating CO2 injection; Oil swelling phenomena; Oil spreading coefficient (SC); Equilibrium interfacial tension (EIFT); Optimum conditions; Live crude oil,EQUILIBRIUM PHASE COMPOSITIONS; MINIMUM MISCIBILITY PRESSURE; INTERFACIAL-TENSION; CRUDE-OIL; 3-PHASE FLOW; DIOXIDE; CO2; DENSITIES; RESERVOIR; RECOVERY,"In order to investigate the potential of water alternating gas (WAG) and carbonated water alternating gas (CWAG) injection methods, a series of interfacial tension (IFT) experiments for the binary systems of brine/carbonated brine (CB), carbon dioxide (CO2) and live and dead crude oils were performed. The experiments done using the axisymmetric drop shape analysis (ADSA) technique at temperatures of 40 degrees C and 50 degrees C and different pressures up to 13.79 MPa. The IFT results are used to estimate and determine optimum value of spreading coefficient, which is known as a key enhanced oil recovery (EOR) parameter at the pore scale. The experimental results demonstrate that CB decreases the equilibrium IFT of crude oil compared to the brine at the same conditions (for example, the difference of IFT is 5.2 mN/m and 7.6 mN/m at temperature of 40 degrees C and pressures of 2.76 and 13.79 Mpa, respectively). The equilibrium IFT of the live oil-brine/CB system is greater than that of dead oil-brine/CB. The estimated SC shows that the presence of CO2 in the aqueous phase significantly affects the SC value. That is, it becomes positive for the dead/live oil-CB-CO2 system, and improve the performance of EOR process while it is negative for the dead/live oil-brine-CO2 system. The presence of CH4 gas in the oil phase reduces the SC values at different pressure conditions. Moreover, using the SC results are determined the optimum conditions during CWAG injection. Based on the observed results in the dead/live oil-CB systems, swelling phenomena of the dead oil drop be slightly lower than that of the live oil drop.",2,2,1
Oil Recovery,CO2,"Sedlar, Daria Karasalihovic; Vulin, Domagoj; Jukic, Lucija; Smajla, Ivan",Possibility of decreasing CO2 emissions from flaring on a mature oil field,CO2 emission; Gas flaring; Pressure depletion; economics of CO2 reduction,GREENHOUSE-GAS EMISSIONS; BUBBLE-GROWTH; STORAGE; ENERGY; UNCERTAINTY; RECOVERY; HYDROGEN; CAPTURE; BITUMEN,"Analysis of change in composition of flaring gas during the exploitation period of an oil reservoir has been performed to estimate possibilities for feasible reduction of CO2 emissions during hydrocarbon production. There are many projects regarding improvements of energy and flare efficiencies or possibilities for CO2 separation and storage, but none of them calculates emissions for different p-T conditions. Numerous oil fields do not have possibilities for transport of gas separated during oil production to final consumers due to technological or economic limitations. This paper deals with possibility of introducing small technological improvement like implementation of gas separator, which might lead to CO2 reduction at flare. First, it was necessary to calculate accurate oil production decline through lifetime of a reservoir, then pressure decline for a mature oil field was correlated. The payout period for such improvement, along with other economical parameters, has been calculated in economic analysis. It can be concluded that CO2 reduction is possible and economically feasible by introducing separator at oil production field.",3,3,3
Oil Recovery,CO2,"Ahmadi, Mohammad Ali; Chen, Zhangxing",Analytical approach for leakage characterization in carbon sequestration in a bounded deep saline aquifer,Analytical model; Leakage rate; Closed reservoir; Storage; Aquifer; Monitoring well,CO2 STORAGE CAPACITY; ENHANCED GAS RECOVERY; DIOXIDE SEQUESTRATION; ABANDONED WELLS; DEPLETED OIL; PRESSURE; FLOW; RESERVOIRS; INJECTION; BOREHOLES,"One of the promising methods in CO2 sequestration is CO2 injection into deep saline aquifers. A challenging question in CO2 storage in deep saline aquifers is how we can determine the leakage in a storage aquifer if its cap rock does not fully seal it. Among those approaches previously employed, leakage detection by monitoring pressure changes in a monitoring well has gained the most attention recently. In this study, we have developed a new analytical modeling method to monitor pressure changes in monitoring aquifers as a tool for leakage detection. Our developed analytical models are capable for bounded saline aquifers. To eliminate the effect of a size in our modeling, all the developed models are in dimensionless form. Pragmatic sensitivity analyses are performed to determine the effect of different parameters on a dimensionless leakage rate and a pressure change in a monitoring well and a pressure change in a storage aquifer due to both injection and leakage. Based on the results gained, the dimensionless pressure in the monitoring well depends on the well location and the thickness of the monitoring aquifer; however, it is independent of a leak location. The dimensionless pressure change in a storage aquifer highly depends on the dimensionless diffusivity coefficient and the thickness of the storage aquifer; however, it is independent of a leak location.",4,4,0
Oil Recovery,CO2,"Hassanpour, Sadegh; Malayeri, Mohammad Reza; Riazi, Masoud; Mousavi, Seyed Mahdi; Negahban, Zahra",On the impact of Co3O4 nanoparticles on interaction of heavy oil and brine mixtures,IFT; Brine solution; Asphaltene precipitation; EOR; Co3O4 nanoparticles,INTERFACIAL-TENSION; CRUDE-OIL; ASPHALTENE; SALINITY; TEMPERATURE; RECOVERY; PRESSURE; WATER; CO2; PRECIPITATION,"Among numerous EOR methods, the injection of brine with different salinities to oil reservoirs has gained attention where its performance would, in turn, depend on interfacial tension (IFT) of oil/brine mixture. The present study investigated the impact of Co3O4 nanoparticles with concentrations of 0.01, 0.1 and 1 wt% on IFT of brine solution (containing NaCl, KCl and CaCl2) and heavy crude oil system. The results confirmed that adding Co3O4 nanoparticles to water, compared to that without nanoparticles, reduced IFT at low (i.e. 0-5000 ppm) and high (i.e. greater than 5000 ppm) brine concentrations, although the propensity of IFT is different for various concentrations. Furthermore, the reduction of IFT for monovalent ions is greater than that for divalent ions. Properties such as high surface activity and higher surface to volume ratio of the Co3O4 nanoparticles should be accounted for profound adsorption of asphaltene onto the surface of nanoparticles. A high suspension of asphaltene at the brine/oil interface also avoided its precipitation in oil causing IFT to reduce in brine/crude mixtures with nanoparticles compared to that without nanoparticles. The extent of IFT reduction changed by using different concentrations of Co3O4 nanoparticles. For the oil/brine system attempted in this study, the optimum concentration of Co3O4 nanoparticles in term of IFT reduction was 0.1 wt%.",4,5,1
Oil Recovery,CO2,"Wang, Kongyang; Yan, Wei; Deng, Jingen; Tian, Hao; Li, Wenbo; Wang, Yangang; Wang, Luyao; Ye, Sutao",Experimental study on H2S and CO2 generation capacities of the Bohai bay heavy oil,Heavy oil; Thermal recovery; Pyrolysis; H2S and CO2 generation; Partial pressure,CYMBOPOGON FLEXUOSUS BIOFUEL; FIREFLOOD FIELD PROJECTS; DIESEL-ENGINE; EMISSION CHARACTERISTICS; RECOVERY STRATEGIES; GRAVITY DRAINAGE; BIODIESEL BLEND; PERFORMANCE; COMBUSTION; RESERVOIRS,"Thermal recovery is a conventional technology for heavy oil development. During thermal oil recovery the reservoir could generate H2S and CO2. They will potentially threat the safety of downhole tubing regarding the sweet or sour corrosion. In some Bohai heavy oil fields CO2 and H2S under thermal recovery conditions lead to some corrosion problems of the tubing and equipment. Therefore, to determine the corrosive gas generation capacity is crucial for anti-corrosion design of downhole tubing and casing. Heavy oil samples from Bohai, China were experimentally studied for their pyrolysis characteristics using high-temperature-high-pressure autoclaves. The gases were collected when autoclaves cooled down to the in situ formation temperature. Effects of temperature, water chemistry and core mineral on corrosive gas generation were investigated. The results show that total pressure increase significantly when temperature reached 250 degrees C-280 degrees C under the single heavy oil condition. The additional water facilitates the reaction process, after more SO42- added in the mimic formation water, higher H2S content is obtained. Under the condition of multiphase of oil, formation water and cores, both of the H2S and CO2 content increase obviously, and the cores' effect on CO2 is greater than H2S. Anti-corrosion design usually concerns only the highest corrosive gas concentration without further analysis. The highest concentration does not always correspond to the best corrosive gases generation capacities of heavy oil. Comprehensive analysis of both the total pressure of reaction process and the quality of the reaction heavy oil is carried out, then the corrosive gases volume per unit mass of heavy oil is calculated. These can determine the strongest corrosive formation environment and the maximum gases generation capacities of heavy oil.",4,4,3
Oil Recovery,CO2,"Zhao, Fenglan; Hao, Hongda; Lv, Guangzhong; Wang, Zhixing; Hou, Jirui; Wang, Peng; Zhang, Meng; Lu, Guoyong; Fu, Zhongfeng; Li, Wenfeng",Performance improvement of CO2 flooding using production controls in 3D areal heterogeneous models: Experimental and numerical simulations,Low permeability reservoir; CO2 flooding; Areal heterogeneity; Production control; Sweeping efficiency,ENHANCED OIL-RECOVERY; WATER-ALTERNATING-GAS; CARBON-DIOXIDE; FLOW; DISPLACEMENT; STORAGE; FLUID; FOAM,"CO2 flooding is a promising technology used to enhance oil recovery as it increases oil production and sequesters CO2 in low permeability oil reservoirs. However, the areal heterogeneity of a reservoir can seriously affect CO2 flooding efficiency. The importance of production control treatments (sweeping area regulation, differential production pressure control, and real-time producing regulation) are thus proposed to improve the performance of CO2 flooding in areal heterogeneous reservoirs. Three dimensional (3D) physical models and core-scale numerical models with areal heterogeneity and 5-spot patterns are designed using dimensionless scaling groups. Conventional CO2 flooding and CO2 production control flooding are conducted successively in the 3D models, and flooding efficiency is evaluated through oil recovery increments and changes in the displacement pressure drop curves. Mechanisms of CO2 performance improvement using production control treatments are also discussed through the analytical analysis of gas distribution and gas/oil mobility ratio. 3D experimental and numerical simulation results show that CO2 is displaced unevenly in the areal heterogeneous reservoir, leaving plenty of oil in the area of relatively low permeability. However, oil recovery of CO2 flooding in the areal heterogeneous reservoir can be doubled using production control treatments (sweeping area regulation, differential pressure control, or real-time producing regulation). The oil remaining in the area of relatively low permeability can be effectively displaced using sweeping area regulation, and both a larger sweeping area and a better CO2 flooding profile can be obtained using differential pressure control and real-time producing regulation. Through the analytical analysis of gas distribution and gas/oil mobility ratio, it is found that gas/oil mobility ratio is more sensitive to the areal heterogeneity, and real-time producing regulation has a powerful mobility control ability for CO2-EOR. Improvements in the performance of CO2 flooding using production control treatments provide a feasible technical strategy to treat with the areal heterogeneity and enhance the oil recovery for 5-spot well patterns in the areal heterogeneous reservoir.",4,4,5
Oil Recovery,CO2,"Vasquez Haro, Herberth Arturo; de Paula Gomes, Marcos Sebastiao; Rodrigues, Luis Glauber",Numerical analysis of carbon dioxide injection into a high permeability layer for CO2-EOR projects,Compositional simulation; Miscible flooding; Mobility; High permeability; Oil recovery factor; Carbon storage evaluation,ENHANCED OIL-RECOVERY; SCREENING CRITERIA; CO2 STORAGE; PORE-SCALE; WATER; CAPTURE; DESIGN; EOR,"Mature oilfields and aquifers are the most favorable targets for the CO2 sequestration projects. In this work, the purpose is to investigate an alternative approach in which at very early stage of the oil production, combines CO2-EOR and CO2 sequestration up to the depletion of the oilfield, and analyze the relationship between EOR and CCS projects. Responding to the oil industry needs, initially was designed to investigate the potential to increase the oil recovery factor and the extent to which mobility overlaps the miscibility in reservoirs with low and high permeability layers, a situation which is similar to the pre-salt reservoirs. The process of CO2 injection into oil reservoir is analyzed in different flooding scenarios that include: (i) continuous gas injection (CGI), (ii) constant water-alternating-gas (WAG) injection, and (iii) tapered WAG (TWAG) injection. Compositional numerical simulations were conducted to identify the good injection site in the reservoir and to optimize the injection strategies. Based on the observation, the results reveal that the oil recovery factor may be employed for indicating whoever overlaps, between mobility and miscibility, when a high permeability layer is present. A cradle-to-grave life cycle analysis was considered for estimating net CO2 emissions in each of the CO2-EOR operations. In regards to CCS, in the CGI, WAG and TWAG, simulation results indicate that the CO2 stored represents around 28.77%, 14.49% and 13.24% of the CO2 emissions, related to the oil produced due to the implementation of the EOR project, respectively.",4,5,6
Oil Recovery,CO2,"Fernandes, Bruno Ramon Batista; Marcondes, Francisco; Sepehrnoori, Kamy",Development of a fully implicit approach with intensive variables for compositional reservoir simulation,Compositional reservoir simulation; IMPEC; Fully implicit; Finite volume method; CO2 flooding,WELL-BLOCK PRESSURES; FINITE-VOLUME METHOD; UNSTRUCTURED GRIDS; CONJUNCTION; EQUATION; STATE; ALGORITHM; MODELS; FLOW,"Compositional reservoir simulators are important tools for application in enhanced oil recovery processes. These simulators solve partial differential equations arising from modeling fluid flow in permeable media. Various algorithms for the solution of such partial differential equations are available, which their application greatly impacts the computational performance of the simulators. In this work, a new fully implicit approach called PZS (pressure, overall composition, and water saturation) is proposed and implemented. The new formulation considers pressure, water saturation, and overall compositions as primary variables, reducing the number of unknowns by one when compared to other volume balance fully implicit formulations. The new approach is obtained by a variable change and elimination of a well known volume balance approach. The new approach is implemented in the UTOMPRS simulator that has been developed at The University of Texas at Austin for simulation of several multicomponent/multiphase recovery processes. The PZS formulation is compared to the volume balance based and IMPEC (Implicit Pressure Explicit Composition) formulations in UTCOMPRS. We observe that the PZS approach is, in general, faster than the other approaches tested.",5,5,0
Oil Recovery,CO2,"Zhu, Dongya; Meng, Qingqiang; Liu, Quanyou; Zhou, Bing; Jin, Zhijun; Hu, Wenxuan",Natural enhancement and mobility of oil reservoirs by supercritical CO2 and implication for vertical multi-trap CO2 geological storage,Supercritical CO2; Reservoir enhancement; Dawsonite; Geological storage; Huangqiao reservoir,RARE-EARTH-ELEMENT; CARBON-DIOXIDE; FLUID INCLUSIONS; SALINE AQUIFERS; BASIN; SEQUESTRATION; ACCUMULATION; GAS; RECOVERY; MODEL,"The accumulation and production of both deep mantle-derived CO2 and light oil were discovered in the Huangqiao reservoir, which is located in the Subei Basin, East China. The Huangqiao reservoir shows that both CO2 and oil are entrapped in and produced from vertical multi-traps. The effects of deep CO2 on the accumulation and production of oil under natural conditions and the implications for CO2 geological storage are investigated in detail. The fluid inclusions in quartz or calcite veins from the Silurian Fentou Formation (S(2-3)f), Permian Longtan Formation (P(2)l) and Triassic Qinglong Formation (T(1)q) have homogenization temperatures (Ths) that display peak ranges of 180 degrees C-190 degrees C, 170 degrees C-180 degrees C and 150 degrees C-160 degrees C, respectively. The Ths are higher than the formation temperatures. The calcite veins have light carbon and oxygen isotope compositions and have high Sr-87/Sr-86 ratios and positive Eu anomalies. These characteristics reveal the activities of deep CO2-rich hydrothermal fluids in the basin strata. The feldspar in the S(2-3)f and P(2)l sandstone reservoirs underwent significant dissolution because of the presence of CO2-rich fluids, forming of a large amount of secondary pores in the sandstone reservoirs and enhancing the reservoirs' physical properties. The measured porosity reaches 12.3%. CO2 in a supercritical state extracted or dissolved light petroleum components out of sedimentary rocks and then carried them towards reservoirs. Thus, CO2 and oil co-accumulated in the enhanced reservoirs, e.g. S(2-3)f, P(2)l and T(1)q. During drilling development, this supercritical CO2 naturally increased the mobility of oil, resulting in the co-production of highly pure CO2 and light oil. Based on the unique features of the Huangqiao CO2-oil reservoir, we propose a new CO2 geological storage model, namely, a vertical multi-trap geological storage model, which can either entrap large volumes of CO2 or lower the risk of long-term storage.",5,7,4
Oil Recovery,CO2,"Soh, Ye Ji; Babadagli, Tayfun",Use of air to improve the efficiency of foamy flow and reservoir pressurization in heavy oil recovery,Cyclic solvent injection; Post-CHOPS EOR; Methane and CO2; Air injection; Foamy oil corefloods,INJECTION; TEMPERATURE,"Primary recovery of heavy-oil is remarkably low due to high viscosity and low energy by solution gas exsolution to drive the oil. Gas injection to improve foamy flow and also to dilute the oil in such reservoirs has been proposed as a secondary recovery method. However, because of the high costs of injected gases, efforts are needed to optimize the process by selection of proper gas type (or gas combinations) and suitable injection scheme. To achieve this goal, an experimental procedure was followed with rigorous analyses of the output. A 1.5m long and 5 cm diameter sand-pack was first saturated with brine, which was replaced with dead oil. Then, gas solvents were injected to dead-oil containing core-holder until nearly reaching 500 psi followed by a two-day soaking period. Pressures all along the sand-pack were recorded with eight pressure transducers. Different combinations of various gas solvents (methane, CO2, and air) aiming to select the most competitive and economic formula were tested with a certain set of pressure depletion rates. The physics of the foamy oil flow for different solvent mixtures and depletion conditions were analyzed using pressure profiles acquired, recorded oil/gas data with time, and gas chromatography and SARA analyses of the produced gas and oil. Three huff-n-puff cycles were applied. Compared with other light hydrocarbon solvents and carbon dioxide, air has a significant advantage in terms of accessibility and lowered cost. Hence, attention was given to air mainly used to pressurize the system and increase oil viscosity due to oxidation process with an expectation of better foam quality when injected with other gases such as CO2 and methane. Methane (CH4) yielded the quickest response in terms of gas drive but, in the long run, CO2 was observed to be more effective technically. Air was observed to be effective if mixed with CO2 or methane from an economics point of view. To sum up the results, air Huff-n-Puff (HnP) followed by 2-cycles of CH4 HnP yielded 36.21% recovery, while air HnP followed by 2-cycles of CO2 HnP delivered 30.36% oil. When the gases are co-injected, air 50%-CO2 50% and air 50%-CH4 50% recovered 29.85% and 23.74% of total oil-in-place, respectively.",6,6,0
Oil Recovery,CO2,"Zhang, Kaiqiang; Jia, Na; Li, Songyan; Liu, Lirong",Nanoscale-extended correlation to calculate gas solvent minimum miscibility pressures in tight oil reservoirs,Minimum miscibility pressure; Nanoscale-extended correlation; Gas solvent; Tight oil reservoirs; Enhanced oil recovery,QUANTITATIVE TECHNICAL CRITERIA; INTERFACIAL-TENSION; GENETIC ALGORITHM; CONFINED FLUIDS; PHASE-BEHAVIOR; SLIM-TUBE; CO2; PREDICTION; SYSTEM; MMPS,"In this paper, a novel nanoscale-extended correlation is developed to calculate the minimum miscibility pressures (MMPs) for a wide range of dead and live tight oil-gas solvent systems in bulk phase and nanopores. First, experimentally, the slim-tube and coreflood tests as well as the vanishing interfacial tension (VIT) technique are conducted to measure the MMPs of three oil. gas systems. Second, the newly-developed correlation is proposed as a function of the reservoir temperature, molecular weight of C5+, mole fraction ratios of volatile components to intermediate components in oil and gas samples, and pore radius. Third, theoretically, the new correlation is analyzed on a basis of an oil. gas MMP database from this study and literature that covers 101 oil. gas MMP data for fifteen oil and thirteen gas samples at different reservoir temperatures in bulk phase and nanopores. A total of 40 commonly-used existing correlations are analyzed and reviewed. Compared to the seven existing correlations, the new correlation is found to provide the most accurate MMPs with an overall percentage average absolute deviation (AAD%) of 5.72% and maximum absolute deviation (MAD%) of 12.96% for different dead and live oil. pure CO2 systems in bulk phase. Moreover, for the different oil. pure and impure gas solvent systems, the new correlation leads to the best calculation accuracy of the MMPs with an overall AAD% of 4.70% and MAD% of 15.81% in comparison with the four existing correlations. More importantly, the new correlation is found to calculate the MMPs of different dead and live oil. pure and impure gas solvent systems in nanopores in an accurate, efficient, and physical correct manner. The overall AAD% and MAD% in terms of the MMP calculations in nanopores from the new correlation are determined to be 6.91% and 13.66%, respectively.",7,7,1
Oil Recovery,CO2,"Min, Baehyun; Sun, Alexander Y.; Wheeler, Mary F.; Jeong, Hoonyoung",Utilization of multiobjective optimization for pulse testing dataset from a CO2-EOR/sequestration field,Geological carbon storage; Leakage; Pulse testing; History matching; Multi-objective optimization,NONDOMINATED SORTING APPROACH; LEAKAGE DETECTION; SENSITIVITY-ANALYSIS; CO2 SEQUESTRATION; GENETIC ALGORITHM; RESERVOIR; FLOW; MODEL; PERFORMANCE; PRESSURE,"In a geological carbon storage project, leakage should be monitored to ensure safe long-term storage of injected CO2. Leakage can be detected early and cost-effectively by monitoring subsurface pressure. The uncertainty in geological models also needs to be sufficiently reduced to detect leakage based on pressure monitoring data. This study presents numerical results of field pulse testing experiments that are designed to detect leakage based on pressure monitoring data for periodical CO2 injection at a CO2 enhanced oil recovery field in Mississippi, USA. In the pulse test, sinusoidal pressure patterns are captured in transitional pressure data because CO2 injection and shut-in are repeated. The patterns are parameterized and history-matched efficiently in the frequency domain. Sensitivity analyses of pulse test parameters such as injection period and rate show that the frequency domain is more advantageous than the time domain for estimating leakage probability and well connectivity. We also conduct multi-objective history matching of pulse testing parameters in the frequency domain for reducing the uncertainty in geological models. This history matching reveals a clearer trade-off relationship between the matching qualities than conventional global-objective history matching, thereby being advantageous to yielding converged and diversified geological models for uncertainty quantification.",8,8,0
Oil Recovery,CO2,"Foroozesh, Jalal; Jamiolahmady, Mahmoud",The physics of CO2 transfer during carbonated water injection into oil reservoirs: From non-equilibrium core-scale physics to field-scale implication,Carbonated water injection (CWI); Mass transfer; Equilibrium CO2 storage; Core-scale; Reservoir-scale,NONAQUEOUS PHASE LIQUID; SATURATED SUBSURFACE SYSTEMS; MASS-TRANSFER RATES; POROUS-MEDIA; RECOVERY; STORAGE; GAS; DISSOLUTION; DISPLACEMENT; COEFFICIENTS,"CO2 can be dissolved into water to make carbonated water (CW). CW can be injected into oil reservoirs for enhanced oil recovery (EOR) and CO2 sequestration purposes. Carbonated water injection (CWI) technique is a cost-effective CO2 based injection strategy that needs less amount of CO2 as compared to other CO2-EOR techniques. We previously showed that for simulation of CWI coreflood experiments, the kinetics of CO2 transfer between the phases should be considered and we accordingly developed a non-equilibrium based two-phase compositional simulator. We also used the developed simulator to simulate some CWI coreflood experiments. This paper aims to explore the role of mass transfer during simulation of CWI process at field (large)-scale by analysing the data of core-scale simulations. To do so, the results of CWI core-scale simulations obtained from our non-equilibrium based simulator are benchmarked against the results from an equilibrium based simulator and a dimensionless number so-called equilibrium number (Ne) is introduced. It is shown that in a specific range of Ne values, the contact time of the oil and water phases inside the system is large enough that the CO2 can be distributed between the phases based on its equilibrium concentration. Contrary to core-scale simulation, it is concluded that mass transfer kinetics during large-scale simulation of CWI process is not important. Moreover, higher oil recovery factor and CO2 storage are predicted at large-scale (reservoir-scale) as compared to the core-scale's results. The findings of this paper can help to better understand the importance of mass transfer kinetics between the phases in porous media.",8,8,2
Oil Recovery,CO2,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun; Alsaba, Mortadha",Lessons learned from IOR pilots in Bakken formation by using numerical simulation,CO2-EOR in shale oil reservoirs; CO2-EOR huff-n-puff operations; Unconventional EOR methods; Improved oil recovery,RESERVOIRS,"Bakken is the most productive formation among unconventional plays in North America. This formation has about 7.4 billion barrels of recoverable oil. However, the primary oil recovery is still low as 5-10%. Miscible natural gas and carbon dioxide (CO2) might be the most two potential strategies to improve oil recovery in such a complex play. In this study, some of the IOR pilots which have been conducted in Montana, North Dakota, and South Saskatchewan have been presented. The performance results of these pilots in US-Bakken versus Canadian-Bakken have been compared. Moreover, the reasons behind the successful IOR pilots in Canadian-Bakken versus US-Bakken have been discussed. Then, numerical simulation models have been constructed to mimic the results of some pilots. Two different compositional models have been built for oils of two different formations. Furthermore, two different models, single porosity model and dual permeability model have been created to match the performance of some pilots. Implementation of molecular diffusion mechanism has been conducted in both of single porosity and dual permeability model. Finally, the continuous miscible gases injection versus huff-n-puff protocols have been compared and investigated. The results showed that the performance of natural gases generally over-performed the CO2 injection technique's in Bakken formation. Although the diffusion flow is dominant in these types of reservoirs, the diffusivity of the injected CO2 into formation oil is slow due to the fact that CO2 has large molecules as compared with the small pore throats of these porous media. Accordingly, miscible CO2-EOR might not be beneficial in huff-n-puff operations as in continuous flooding process. However, the success of natural gases based EOR does not have that strong functionality of molar diffusivity. Therefore, their performance was much better than CO2 performance in the field scale of these tight formations. Furthermore, the numerical simulation of this study concluded that the spacing between the production wells and injection wells should be minimized, for the continuous flooding process of miscible-gases EOR, to enhance their performance. Although the permeability of Canadian-Bakken has a permeability of 1-2 order higher than the permeability of US-Bakken, the pilots' spacing between injectors and producers in Canadian Bakken is interestingly much shorter than that for US-Bakken, which might be the reason behind the EOR success in Canadian Bakken. Finally, the activatiown process of the highly intensive natural fractures might be the key to enhance the diffusivity of CO2-EOR. Otherwise, natural gases are highly recommended to be the most potential EOR in these types of reservoirs. This study explains how the diffusion mechanism affects the performance of different miscible gases to improve oil recovery in these plays since they are more complex and very different from conventional formations. Also, it suggests that CO2 flooding process would be a good practice to overcome the limitations of CO2-diffusion rate in these reservoirs if the conformance problems are wisely controlled.",8,8,4
Oil Recovery,CO2,"Wei, Peng; Pu, Wanfen; Sun, Lin; Zhou, Wei; Ji, Xudong",Foam stabilized by alkyl polyglycoside and isoamyl alcohol for enhancing oil recovery in the low-permeable reservoir,APG foam; Isoamyl alcohol; Surface behavior; Foam stability; Low permeability,HIGH-SALINITY ENVIRONMENTS; AIR-WATER-INTERFACE; POROUS-MEDIA; HIGH-TEMPERATURE; CO2 FOAM; GAS TYPE; SURFACTANT; COALESCENCE; DRAINAGE; FILM,"Few studies have delved into the effect of low molecular alcohol on foam stability. This study firstly investigated the improvement in adsorption behavior and viscoelastic behavior at the surface of the APG solution in the presence of isoamyl alcohol, and then we observed that isoamyl alcohol could hinder the liquid drainage and retard the foam rupture by introducing the stabilization capacity (i.e., reducing the surface tension, increasing the surface viscoelasticity, creating the H-bond and providing the disjoining pressure). Afterwards, the addition of isoamyl alcohol can efficiently diminish the defoaming effect of crude oil and impose a considerable oil resistant in foam system. Finally, the flooding experiments were conducted in the tight formation. The results indicate that APG-alcohol foam presents a fine texture and reaches the maximum apparent viscosity at the transition foam quality of 0.67. As presented in the NMR experiment, APG-alcohol foam can efficiently displace the oil in pores with various sizes and substantially promote the EOR to 30.35%.",8,8,5
Oil Recovery,CO2,"Tayari, Farid; Blumsack, Seth; Johns, Russell T.; Tham, Suli; Ghosh, Soumyadeep",Techno-economic assessment of reservoir heterogeneity and permeability variation on economic value of enhanced oil recovery by gas and foam flooding,Techno-economic assessment; Enhanced oil recovery; Reservoir heterogeneity; Waterflood; Water alternating gas; Surfactant alternating gas,CO2,"This research introduces a detailed techno-economic model to estimate and evaluate the economics of enhanced oil recovery. The model categorizes the cost objects into three main modules: injection, production, and CO2 recycling. These modules are composed of a number of lower-level sub-modules that represent specific cost objects. The techno-economic model utilizes reservoir simulation inputs and results such as production rate and composition, injection fluid rate and composition, and bottomhole pressure to provide detailed costs and revenue of injection, production, and CO2 recycling, according to defined scenarios. Although the techno-economic model is a general model that can be applied to any EOR project, we illustrate it here to compare flooding scenarios for a modeled EOR project in Mississippi. Reservoir heterogeneity is the variation of petrophysical properties with space such as porosity, permeability, fluid saturation. This effect is explored for total of 81 cases considering different combinations of Dykstra-Parsons coefficient (VDP) and correlation length. For each case, 25 random realizations of the permeability field were generated and the results of realizations were averaged to provide a statistical representation of the cases. Simulations of three scenarios including Waterflood, Water Alternating Gas, and Surfactant Alternating Gas floods (using a foam model for SAG) were carried out for each realization. The results show that, under assumed cost structure and the selected foam model, on average, SAG is a better and more profitable injection scenario with an oil price of $40/bbl. The economic advantage of SAG, however, declines with greater permeability variation.",9,9,0
Oil Recovery,Water Flooding,"Zhang, Guowei; Yao, Guangqing; Li, Jiqing; Wu, Hua; Liu, Zhijun; Li, Desheng","A new experimental method for measuring the three-phase relative permeability of oil, gas, and water",Three-phase relative permeability; Saturation history; Archie equation; CT scan; Wettability,RESISTIVITY,"For tertiary oil recovery, the gas drive is often implemented after water flooding. The three-phase flow phenomenon of oil, gas, and water exists during the process of gas injection. The three-phase relative permeability should be measured to further study the flow characteristics of oil, gas, and water in porous media. In this work, the steady-state flow method is adopted to establish a combined experimental method based on the principle of relationship between resistivity and water saturation, and the principle of on-line CT scanning is used to measure the three-phase relative permeability. The relative permeability of oil, gas, and water is measured under different saturation histories, including the water alternating gas flooding, in which water saturation decreases, oil saturation decreases, and gas saturation increases, as well as gas alternating water flooding, in which water saturation increases, oil saturation decreases, and gas saturation decreases. The experimental results show that in a water-wet core, the relative permeability of water is a function of its own saturation, and its isoperms are straight lines. The relative permeability of oil and gas phase is affected by their saturation and other phase saturations. In an oil-wet core, the isoperms of oil, water, and gas are convex to the point of 100% their own saturation, which means the relative permeability of oil, gas and water depend on all the three phase saturations. The saturation histories influence the isoperms of the three phases differently. Compared with the two-phase flow, the three-phase flow is more complex. This new experiment provides an approach and theory for the study of three-phase seepage laws in the gas drive.",1,1,1
Oil Recovery,Water Flooding,"Ma, Hongze; Yu, Gaoming; She, Yuehui; Gu, Yongan",A new hybrid production optimization algorithm for the combined CO2-cyclic solvent injection (CO2-CSI) and water/gas flooding in the post-CHOPS reservoirs,Well-control optimization; Steepest ascent-particle swarm optimization (SA-PSO); CO2-Cyclic solvent injection (CO2-CSI); CHOPS reservoir; Foamy-oil flow,PARTICLE SWARM OPTIMIZATION; HEAVY OIL PRODUCTION; RECOVERY; MODEL,"In this paper, a new hybrid production optimization algorithm, namely, the steepest ascent. particle swarm optimization (SA. PSO), is developed to optimize the combined CO2-cyclic solvent injection (CO2-CSI) and waterflooding (WF) or gasflooding (GF) in the post cold heavy oil production with sand (CHOPS) reservoirs. The field-scale CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF performances are predicted by upscaling the laboratory tests and using the numerical simulations with the considerations of the wormholes propagation and foamy-oil flow. The net present value (NPV) is chosen as an objective function and maximized by adjusting the well controls, such as the bottom-hole pressure (BHP) and water/gas injection rate. The efficacies of the following three optimization methods are evaluated and compared: the steepest ascent (SA) method, particle swarm optimization (PSO), and SA-PSO. It is found that the SA. PSO gives a higher global optimum NPV than the SA algorithm and requires fewer numerical simulation runs than the PSO. It combines the fast convergence of the SA algorithm and the global search of the PSO. It is also found that the CO2-CSI + GF has the highest NPV in the post-CHOPS reservoir among the three enhanced oil recovery (EOR) processes. For the CO2-CSI + GF, the gas injector should inject CO2 at the highest injection rate during the early cycles to displace the foamy oil but should be shut in during the late cycles to control the gas channeling. The optimum NPVs of the CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF are achieved when the BHPs of the producers are maintained at the lowest pressure. It is uneconomical to apply the WF immediately after the CO2-CSI due to the early water breakthrough.",1,1,3
Oil Recovery,Water Flooding,"Katika, K.; Alam, M. M.; Alexeev, A.; Chakravarty, K. H.; Fosbol, P. L.; Revil, A.; Stenby, E.; Xiarchos, I.; Yousefi, A.; Fabricius, I. L.",Elasticity and electrical resistivity of chalk and greensand during water flooding with selective ions,Water flooding with selective ions; Greensand; Chalk; Wettability; Fines formation; Pore compressibility,WETTABILITY ALTERATION; OIL-RECOVERY; ROCK; FLUID; SALINITY; SEAWATER; IMPACT; FIELD; NMR; SANDSTONES,"Water flooding with selective ions has in some cases lead to increased oil recovery. We investigate the physical processes on a pore scale that are responsible for changes in petrophysical and mechanical properties of four oil-bearing chalk and four oil-bearing greensand samples caused by flooding with brines containing varying amounts of dissolved NaCl, Na2SO4, MgCl2 and MgSO4. Ultrasonic P-wave velocity and AC resistivity measurements were performed prior to, during and after flow through experiments in order to identify and quantify the processes related to water flooding with selective ions. Low field Nuclear Magnetic Resonance (NMR) spectrometry measurements were performed at full water saturation, at irreducible water saturation, after aging and after flooding. CT-scanning, X-ray diffraction (XRD), backscatter electron microscopy images (BSEM), mercury injection capillary pressure (MICP) curves and specific surface analysis (BET) reveal the mineralogy and texture of the rock samples before and after the injection. Low field NMR data indicates changes in the pore fluid distribution and wettability of chalk after aging of one of the samples. NMR data for other samples indicate that chalk is water-wet after flooding. Greensand remained mixed wet throughout the experiments. Electrical resistivity data are in agreement with this interpretation. The electrical resistivity data during flooding revealed that the formation brine is not fully replaced by the injected water in both chalk and greensand. Changes in the elasticity of chalk during flooding illustrate the softening effect of magnesium bearing brines as compared to the sodium bearing brines. The stiffness of greensand was not affected by water flooding with selective ions as determined from the elastic wave measurements. Precipitation of fines during flooding of chalk samples is indicated by an increase in specific surface area and a shift in the MICP to lower values but no fines were detected by NMR. No changes were observed for greensand samples.",3,3,0
Oil Recovery,Water Flooding,"Babadagli, Tayfun; Cao, Nahai",An experimental study to determine suitable injection strategies for water-alternating-solvent process in green and brownfields,Solvent injection optimization; Waterflooding; Water content; Injection sequence and slug size; Wettability,RECOVERY,"Considering more than 50% of oil is left on average after primary and secondary methods in conventional reservoirs, techniques to recover the remaining oil from these proven and mature reserves is critically important to meet the future energy demand. One of the ways to achieve this is to inject miscible solvents (usually gas), which is performed in the form of water-alternating gas rather than continuous injection of this type of expensive material. In this case, the process should be optimally designed for slug sizes and proper sequences of the solvent considering several controlling parameters including past history of waterflooding (water content) and wettability. We performed a set of experiments on vertically situated sand pack models saturated with 14cp oil. Heptane was selected as the solvent phase due to high miscibility conditions. Tests were started with waterflooding or solvent injection. Different slug sizes of solvent and water were tested on fully oil-saturated water, oil-wet samples, and samples with connate water (10 and 30%). The amounts of oil and solvent retrieved were monitored using refractometer. Using the collected data, the recovery rates and ultimate recoveries were comparatively analyzed. In addition to the technical feasibility, an economic analysis was performed considering the amount of solvent injected, oil and solvent recovered, and time for recovery. Starting the process with heptane was technically and economically feasible (pay-out time is shorter) in the short run for both the oil-and water-wet cases. This was especially true if the rock were oil-wet, which yielded faster recovery and higher ultimate recovery. Excessive water injection (up to the plateau level) preceding the solvent injection in the oil-wet case resulted in lower recovery factor whereas this design was very effective in the water-wet case. Therefore, the time to switch to solvent injection was critical in the oil-wet case and a short initial cycle of solvent injection followed by short waterflooding cycle is suggested. In the oil-wet case, initial waterflooding resulted in an inefficient process; while it yielded high ultimate recoveries, the process time was longer than other injection options. In the water-wet case, a greater amount of solvent was needed in the first cycle.",3,3,2
Oil Recovery,Water Flooding,"Babadagli, T.; Cao, N.",Can water-alternating-solvent injection be an option for efficient heavy-oil recovery?: An experimental analysis for different reservoir conditions,Heavy-oil recovery optimization; Solvent injection; WAG design; Injection sequence and slug size; Wettability,VAPOR EXTRACTION,"We performed a set of experiments on vertically situated sandpack models. Different slug sizes of water and solvent (heptane used in the experiments) were tested for 2000 cp heavy-oil. As a benchmark, tests were also performed for 14 cp light oil for comparative analysis. In addition to the technical feasibility, an economic analysis was performed considering the amount of solvent injected and oil and solvent recovered. Experiments were repeated for oil-wet systems. For both light and heavy oils, starting the process with the solvent was feasible in the short run technically and economically. If the process starts with water, excess amount of it occupies the largest pores and hinders solvent-oil interaction for mixing and oil displacement. This was true especially if the rock is oil-wet and oil is heavy, which yielded faster recovery and higher ultimate recovery than the water-wet case. The time for switching to solvent injection is more critical in the heavy-oil case as it is more sensitive to the amount of existing water in the system. As oil becomes heavier and if the rock is water-wet, starting the process with waterflooding is not suggested. In this case, more solvent needs to be injected in the first cycle compared to oil-wet systems. Due to partial miscibility and more gravity stable nature, solvent retrieval and sweep with water can be more effective in case of heavy-oil compared to light oil (fully miscible case) and, as a result, can be even more profitable. This is highly critical in exploitation of heavy-oil reservoirs if thermal options are limited and greenhouse gas emission is a concern.",4,4,3
Oil Recovery,Water Flooding,"Vasquez Haro, Herberth Arturo; de Paula Gomes, Marcos Sebastiao; Rodrigues, Luis Glauber",Numerical analysis of carbon dioxide injection into a high permeability layer for CO2-EOR projects,Compositional simulation; Miscible flooding; Mobility; High permeability; Oil recovery factor; Carbon storage evaluation,ENHANCED OIL-RECOVERY; SCREENING CRITERIA; CO2 STORAGE; PORE-SCALE; WATER; CAPTURE; DESIGN; EOR,"Mature oilfields and aquifers are the most favorable targets for the CO2 sequestration projects. In this work, the purpose is to investigate an alternative approach in which at very early stage of the oil production, combines CO2-EOR and CO2 sequestration up to the depletion of the oilfield, and analyze the relationship between EOR and CCS projects. Responding to the oil industry needs, initially was designed to investigate the potential to increase the oil recovery factor and the extent to which mobility overlaps the miscibility in reservoirs with low and high permeability layers, a situation which is similar to the pre-salt reservoirs. The process of CO2 injection into oil reservoir is analyzed in different flooding scenarios that include: (i) continuous gas injection (CGI), (ii) constant water-alternating-gas (WAG) injection, and (iii) tapered WAG (TWAG) injection. Compositional numerical simulations were conducted to identify the good injection site in the reservoir and to optimize the injection strategies. Based on the observation, the results reveal that the oil recovery factor may be employed for indicating whoever overlaps, between mobility and miscibility, when a high permeability layer is present. A cradle-to-grave life cycle analysis was considered for estimating net CO2 emissions in each of the CO2-EOR operations. In regards to CCS, in the CGI, WAG and TWAG, simulation results indicate that the CO2 stored represents around 28.77%, 14.49% and 13.24% of the CO2 emissions, related to the oil produced due to the implementation of the EOR project, respectively.",4,5,6
Oil Recovery,Water Flooding,"Fernandes, Bruno Ramon Batista; Marcondes, Francisco; Sepehrnoori, Kamy",Development of a fully implicit approach with intensive variables for compositional reservoir simulation,Compositional reservoir simulation; IMPEC; Fully implicit; Finite volume method; CO2 flooding,WELL-BLOCK PRESSURES; FINITE-VOLUME METHOD; UNSTRUCTURED GRIDS; CONJUNCTION; EQUATION; STATE; ALGORITHM; MODELS; FLOW,"Compositional reservoir simulators are important tools for application in enhanced oil recovery processes. These simulators solve partial differential equations arising from modeling fluid flow in permeable media. Various algorithms for the solution of such partial differential equations are available, which their application greatly impacts the computational performance of the simulators. In this work, a new fully implicit approach called PZS (pressure, overall composition, and water saturation) is proposed and implemented. The new formulation considers pressure, water saturation, and overall compositions as primary variables, reducing the number of unknowns by one when compared to other volume balance fully implicit formulations. The new approach is obtained by a variable change and elimination of a well known volume balance approach. The new approach is implemented in the UTOMPRS simulator that has been developed at The University of Texas at Austin for simulation of several multicomponent/multiphase recovery processes. The PZS formulation is compared to the volume balance based and IMPEC (Implicit Pressure Explicit Composition) formulations in UTCOMPRS. We observe that the PZS approach is, in general, faster than the other approaches tested.",5,5,0
Oil Recovery,Water Flooding,"Sivasankar, P.; Kumar, G. Suresh",Modelling the influence of interaction between injection and formation brine salinities on in-situ microbial enhanced oil recovery processes by coupling of multiple-ion exchange transport model with multiphase fluid flow and multi-species reactive transport models,Microbial enhanced oil recovery; Biosurfactant; Brine salinity; Ion exchange; Porous media; Modelling,SATURATED POROUS-MEDIA; BIOSURFACTANT PRODUCTION; PSEUDOMONAS-PUTIDA; NUMERICAL-SIMULATION; GROWTH; RESERVOIRS; WATER; PH; PERFORMANCE; SUBSURFACE,"Interaction between injection water (IW) and formation water (FW) salinities during microbial flooding critically influences the dynamics of in-situ Microbial Enhanced Oil Recovery (MEOR) processes. However, the lack in understanding of the influence of salinity interactions on MEOR processes had led to unreliable prediction of MEOR performance, and non-development of efficient strategies to improve the MEOR performance. Hence, analysing the influence of salinity interactions on MEOR processes would make the prediction of MEOR processes more realistic, and thereby, it could assist in development of suitable strategies to enhance the oil recovery. Thus, in the present study, a novel mathematical model has been developed by coupling the Multiple Ion (Na, Ca, Mg, Cl, SO4) Exchange (MIE) transport model with the MEOR model, and it has been solved numerically by finite volume technique. The MIE transport model simulates the resultant spatial and temporal salinity distribution within the reservoir due to the mixing of IW and FW salinities during microbial flooding. The MEOR model simulates the coupled multiphase fluid (water-oil) flow and multispecies (microbes-nutrients) reactive transport processes within the reservoir, and finally predicts the oil recovery due to microbial flooding. Subsequently, the influence of IW and FW at different salinities on MEOR processes has been investigated. The present numerical results were validated with the experimental and analytical results. The results clearly suggest that the in-situ FW salinity was completely altered to the externally injected IW salinity, and this IW salinity dictates the entire MEOR processes as against the conventionally assumed FW salinity. Further, it is revealed that lowering the IW salinity from 0.5M to 0.1M had recovered 4.5%-14% of Original Oil in Place (OOIP) higher than that of conventionally used IW (sea water) for microbial flooding. Moreover, the MEOR performance could be enhanced significantly in reservoirs with any initial FW salinity by adopting IW salinity closer to the salinity condition at which the microbial growth and biosurfactant production is maximum. Finally, the present work assists in the selection of suitable reservoir, microbes, and IW salinity for attaining maximum oil recovery by microbial flooding. Thus, the present work helps to enhance the performance of MEOR technique.",5,5,0
Oil Recovery,Water Flooding,"Lele, Pushan; Syed, Abdul Haseeb; Riordon, Jason; Mosavat, Nader; Guerrero, Adriana; Fadaei, Hossein; Sinton, David",Deformation of microdroplets in crude oil for rapid screening of enhanced oil recovery additives,EOR; Droplet deformation; Heavy oil; Interfacial tension; Alkaline flooding,INTERFACIAL-TENSION MEASUREMENT; MICROFLUIDICS-BASED MEASUREMENT; ASSISTED GRAVITY DRAINAGE; ON-A-CHIP; HEAVY OIL; IONIC-STRENGTH; SURFACTANT SOLUTIONS; BITUMEN EXTRACTION; SAGD PROCESSES; SYSTEMS,"We present a microfluidic method to rapidly screen enhanced oil recovery additives based on the deformation of aqueous microdroplets in oil. Conventional methods, such as the pendant drop method, are hindered by large fluid volumes that require several hours to thermally equilibrate between measurements. Here we demonstrate a complementary technology to conventional methods, by which additives can be rapidly screened to select the best candidates for further study. Our glass chip establishes thermal equilibrium (demonstrated at 80 degrees C) of undiluted, highly viscous, crude oil within seconds, and enables the rapid quantification of water-in-crude oil droplet deformation within minutes, at a reservoir-relevant scale. The influence of two alkaline additives, a surfactant and a salt in the injected water phase were quantified, demonstrating the applicability of our method to a variety of recovery strategies.",5,5,2
Oil Recovery,Water Flooding,"Lamas, Luis Fernando; Botechia, Vinicius Eduardo; Correia, Manuel Gomes; Schiozer, Denis Jose; Delshad, Mojdeh",Influence of polymer properties on selection of production strategy for a heavy oil field,Polymer flooding; Production strategy selection; Reservoir numerical simulation; Reservoir engineering; Chemical enhanced oil recovery; Reservoir management,,"Polymer flooding is an enhanced oil recovery method (EOR) where water-soluble polymer is added to the injection brine. This increases brine viscosity and reduces water mobility, aiming to increase volumetric sweep and thus oil recovery. Selection and development of a production strategy for oil field is a complex task. Polymer properties bring additional complexity to this process and it is important that each of them is properly treated and considered. This paper discusses the selection of production strategy considering different approaches: (1) water flooding, (2) ideal polymer (only viscosifying effect of polymer) and (3) polymer flooding, including separately four of the most influencing polymer properties i.e. retention, viscoelasticity, salinity and degradation. The analysis is extended to a probabilistic point of view, where scenarios were generated combining geological and polymer uncertainties. Selected production strategies are compared to quantify the impact of each property on field indicators. Comparisons were made in terms of net present value (NPV), produced oil, injected and produced water, oil recovery factor and polymer mass. Two different situations were considered: (1) to optimize considering each property since beginning (design thorn control variables, meaning development, and management stages) and (2) considering design variables (development stage) for ideal polymer, optimizing only control variables (management stage) for each property. The methodology is applied to a synthetic field, based on characteristics of an offshore field with high permeability (similar to 1 000 mD) and containing heavy and viscous oil (similar to 100 cP, 14 degrees API). Ranking the properties according to overall impact on the project NPV, it was found the impact of each variable in a descending order: degradation, salinity, viscoelasticity, and retention. Water and ideal polymer strategies limit indicators results, giving an idea of the performance of strategies. Considering the key polymer properties from the beginning of optimization process resulted in similar values in terms of NPV when compared with strategies that considered ideal polymer in the selection of project variables. Risk curves show that conclusions can be extended to a probabilistic point of view. The results allow a comprehensive understanding of the influence of each polymer property on selection of production strategy considering uncertainties. The results also show that it is possible to select a good strategy using Ideal polymer model. Finally, results show that strategies selected for water and for ideal polymer model act as lower and upper limits of performance for the field, giving valuable information to the decision maker, even before accurate data about polymer is available.",6,6,2
Oil Recovery,Water Flooding,"Sanni, Modiu; Al-Abbad, Mohammed; Kokal, Sunil; Dugstad, Oyvind; Hartvig, Sven; Huseby, Olaf",Pushing the envelope of residual oil measurement: A field case study of a new class of inter-well chemical tracers,Tracer; Residual oil saturation; Remaining oil saturation; Inter-well chemical tracer test; IOR/EOR; Field trial or case study,REMEDIATION PERFORMANCE,"The success of any improved oil recovery (IOR) project is largely dependent on how much oil is remaining to be mobilized within the targeted area of the partially depleted or mature reservoir. Partitioning tracers are generally used to measure residual oil saturation (Sor) or remaining oil saturation (ROS) in the near wellbore region via a single well chemical tracer test (SWCTT) or in an inter-well region via a partitioning inter-well tracer test (PITT). There is a limited repertoire of nonradioactive and environmentally friendly inter-well partitioning tracers for measuring ROS. A new class of environmentally friendly partitioning tracers was field tested, in a giant carbonate reservoir undergoing peripheral waterflood, for measuring ROS in inter-well regions in a depleted area. The new partitioning tracers were qualified via laboratory experiments and are deemed to be very stable at reservoir conditions (213 degrees F and a salinity range of 60-200 kppm). The field pilot was conducted concurrently with a set of non-partitioning inter-well chemical tracer test (IWCTT) to determine reservoir connectivity, water breakthrough times, and injector-to-producer pair communication in an area selected for an IOR/EOR field pilot. An elaborate sampling and analysis program was carried out over a period of 30 months. This paper reviews the complete design and implementation of the test, operational issues, and the analyses and interpretation of the results. The breakthrough times of the passive and partitioning tracers are reported, and inter-well connectivity between the paired and cross-paired injectors and producers are analyzed. The ROS measured by a majority of the novel tracers is comparable to the saturations obtained via SWCTT, core and log derived saturations. The combination of conventional IWCTT and the novel partitioning tracers via PITT has been very useful in analyzing well interconnectivity, understanding the reservoir dynamics and quantifying remaining oil saturation distribution in the reservoir. This has led to better reservoir description and an improved dynamic simulation model.",6,6,2
Oil Recovery,Water Flooding,"Wu, Fei-peng; Liu, Jing; Wei, Xue-mei; Pu, Chun-sheng",A study on oxygen consumption mechanism of air-foam flooding in low-temperature oil reservoir,Low temperature and permeability oil reservoir; Air injection; Oxygen consumption mechanism; Oxygen consumption rate; Field test,AQUEOUS-SOLUTION; POLYMER GELS; OXIDATION; POLYACRYLAMIDE; INJECTION; DEGRADATION; SOLUBILITY; KINETICS; STABILITY; GAS,"Air flooding/air-foam flooding recovery technology has been attracting attention in oilfield development. The key point to the application of this technology is to ensure that the oxygen injected with the air can be fully dissipated inside the reservoir to lower the explosion risk in production wells and reduce the oxidation of the pipeline. It is generally believed that the oxygen and crude oil can react more in low-temperature-oxidation (LTO) reactions above 80 degrees C. As a large amount of oxygen would be spontaneously consumed at this temperature, this technology is mainly used in reservoirs where the temperature is greater than 80 degrees C. In the fractured low-permeability reservoir of China's Yanchang oilfield, where the reservoir temperature is only approximately 30 degrees C, a wide range of crude oil LTO would not be triggered theoretically. However, we found that the oxygen content of the associated gas in the gas channeling wells is significantly lower than that in the air. This phenomenon suggests that, there are other factors that could consume oxygen apart from the LTO reaction. To verify this assumption, an oxygen dissipation core flooding experiment at 30 degrees C and 80 degrees C was carried out to evaluate the oxygen consumption at different temperatures. At the same time, in order to determine the main controlling factors and dissipation mechanisms of oxygen dissipation, theoretical analyses and experimental studies were carried out from the aspects of reductive mineral oxidation reaction in the rock surface and formation water, the physical absorption of the micropore and the dissolution of the reservoir fluid. The results show that at the same experimental conditions, the oxygen consumption at 30 degrees C is 38.14% lower than that at 80 degrees C. The oxygen consumption factors in the low-temperature reservoir mainly include the chemical reactions between the oxygen and reducing minerals, dissolution and retention of formation water and oil, adsorption of Van der Waals forces in the reservoir and physical electronic adsorption of the hydrogen-sulfur bonds and carbon-sulfur bonds. In Chang 6 Reservoir of Ganguyi oilfield, formation water could theoretically consume 56 mg/L (1.75 mmol/L) oxygen through dissolved Fe2+. The dissolution by formation water could absorb 11.85 mmol/L oxygen (experimental value). The dissolution by oil could absorb 69.25 mmol/L oxygen (experimental test value), and the oxygen physical adsorption rate of rock pore surface was 1.26 mmol/L. Together with the pilot test data, the results show that the LTO reaction of the stratum crude oil barely occurs in the reservoir at low temperature (30 degrees C). However, a large amount of oxygen dissipation could still be achieved. This study demonstrates that air-foam flooding could break the applicable limit temperature and could also be applied in low-temperature reservoirs.",7,7,1
Oil Recovery,Water Flooding,"Fang, Huijing; Xu, Huaimin; Wang, Zhenbiao; Jiang, Tongwen; Zhao, Yuyun; Li, Junjian","Formation mechanism of the Donghe Sandstone residual oil zone in the Tarim Basin, NW China",Residual oil zone; Structural adjustment; Microscopic occurrence state; Tarim basin,WATER-WET SANDSTONE; FIELD; SATURATION; RESERVOIRS; MORPHOLOGY; CONTACTS; STORAGE; MATS,"The residual oil zone (ROZ) with near-residual oil saturation is a naturally water-flooded interval adjacent to an oil-bearing reservoir. It has become a promising development target for the technical progress of enhanced oil recovery. The hydrocarbon show, bitumen distribution and grains containing oil inclusions all indicate the presence of ROZs in the Donghe Sandstone Member of the Tazhong4 and Hade Oilfields in the Tarim Basin. Analysis of the two ROZ examples reveals that a stable paleoreservoir and structural adjustment are significant elements of the ROZ-forming process. The ROZ of the Tazhong4 Oilfield is defined as a reactivated fault ROZ (RFROZ) lying between the paleo oil-water contact (OWC) and producing-OWC. Paleo-hydrocarbons leaked through the reactivated faults, and the current oil saturation has a positive proportion to baffle frequency. The ROZ in the paleo trap northwest of the current reservoir in the Hade Oilfield is defined as a migratory trap ROZ (MTROZ). Paleo-hydrocarbons migrated through connected sand bodies. The current oil saturation in the MTROZ has a positive proportion to baffle frequency and negative proportion to petrophysical properties. The microscopic occurrence state of the residual oil in ROZs was analyzed with direct computed tomography (CT) scanning. The displacement experiments coupled with CT scanning aimed to reveal the different occurrence states of the residual oil in the major stage of natural water flooding in the ROZ-forming process. In the microscopic view, the formation of both RFROZ and MTROZ is a process of clustered flow converting to discontinuous flow, and the clustered flow can be scattered to a larger extent in a high permeability zone. The ROZ development feasibility was preliminarily researched. Low-salinity water flooding after the displacement of the formation water in the etching model provided experimental corroboration for remobilizing the residual oil.",8,8,0
Oil Recovery,Water Flooding,"Zhong, Xun; Liu, Dexin; Shi, Xiaofei; Zhao, Hongtao; Pei, Chun; Zhu, Tongyu; Shao, Minglu; Zhang, Fang",Characteristics and functional mechanisms of clay-cement stabilized three-phase nitrogen foam for heavy oil reservoir,Heavy oil reservoir; Clay-cement three-phase foam; High stability; Water shutoff agent,HYDROPHOBIC NANOPARTICLES; DILATIONAL PROPERTIES; NANO-PARTICLES; AQUEOUS FOAMS; DEMULSIFIERS; RECOVERY; BUBBLES,"The large-scale application of two-phase foam flooding in heavy oil reservoirs was restricted due to the instability of foam itself. However, the developed clay-cement three-phase nitrogen foam can make up for the short broad effectively, which benefits from very good thermal stability, salt resistance, oil sensitivity and excellent plugging performance. In this paper, 8.0 wt% clay, 0.50 wt% cement particles and 1.0 wt% foaming agent were used to generate clay-cement nitrogen foam. The synergistic effects of clay/cement reaction products, particle adsorption layer and steric network contribute to a desirable protective sheath covered compact three-phase foam system with high stability and strength, the half-life of which was 42.0 min at 95 degrees C. Moreover, it became more stable when formation sands exist. Generally, clay-cement three-phase nitrogen foam has three kinds of plugging form owing to different formation permeability. In less permeable formations, most foam would separate into two parts, with particles stacking at the entry end and two-phase foam moving forward. While in formations with higher permeability, all foam would flow out directly without effective plugging. Only when it comes to the formations with proper permeability can this foam achieve impressive plugging strength under the effects of Jamin and particle plugging. In addition, the foaming formula can be modified by adjusting particle-surfactant concentrations to fit various formations. Therefore, it is a promising and widely applicable water shutoff agent for heavy oil reservoirs.",8,9,1
Oil Recovery,Water Flooding,"Alvarez, A. C.; Blom, T.; Lambert, W. J.; Bruining, J.; Marchesin, D.",Analytical and numerical validation of a model for flooding by saline carbonated water,Riemann problem; Waterflooding; Enhance oil recovery,EQUILIBRIUM PHASE COMPOSITIONS; VAPOR-LIQUID-EQUILIBRIA; HUCKEL LIMITING SLOPES; ACTIVITY-COEFFICIENT; RIEMANN PROBLEM; INTERFACIAL-TENSIONS; HYPERBOLIC SYSTEMS; DIOXIDE; SOLUBILITY; DENSITIES,"It has been shown experimentally in the literature that for clayey formations, oil with polar components and an aqueous phase with divalent ions, a secondary waterflood with low salinity water composition improves oil recovery by some 5-20%. Our focus is on a less well known mechanism, i.e. low salinity enhanced solvent (e.g. carbonated water) recovery, as low salinity enhances the aqueous solubility of carbon dioxide. Indeed, after injection the latter is transferred from the aqueous to oleic phase thus decreasing the oil concentration in the oleic phase and diluting the residual oil. To study this mechanism we formulate the conservation equations of total hydrogen, oxygen, chloride and decane. Therefore, we solve analytically and numerically these equations in 1-D in order to elucidate the effects of the injection of low salinity carbonated water into a reservoir containing oil equilibrated with high salinity carbonated water. We use PHREEQC (acronym of pH-REdox-Equilibrium C-program) to obtain the accurate equilibrium partition of neutral species that are soluble both in the oleic and the aqueous phase by application of the Krichevsky-Ilinskaya extension of Henry's law for solubility of gases in liquids. Using Gibbs phase rule it can be shown that the phase behavior only depends on the pH and the chloride concentration. The above mentioned equilibrium relations use Pitzer's activity coefficients to extend the validity up to 6M. We obtain the saturation, composition and the total Darcy velocity profiles. The significant new insight obtained is that by changing only the salinity in carbonated waterflooding the oil recovery can be enhanced.",8,8,2
Oil Recovery,Water Flooding,"Tayari, Farid; Blumsack, Seth; Johns, Russell T.; Tham, Suli; Ghosh, Soumyadeep",Techno-economic assessment of reservoir heterogeneity and permeability variation on economic value of enhanced oil recovery by gas and foam flooding,Techno-economic assessment; Enhanced oil recovery; Reservoir heterogeneity; Waterflood; Water alternating gas; Surfactant alternating gas,CO2,"This research introduces a detailed techno-economic model to estimate and evaluate the economics of enhanced oil recovery. The model categorizes the cost objects into three main modules: injection, production, and CO2 recycling. These modules are composed of a number of lower-level sub-modules that represent specific cost objects. The techno-economic model utilizes reservoir simulation inputs and results such as production rate and composition, injection fluid rate and composition, and bottomhole pressure to provide detailed costs and revenue of injection, production, and CO2 recycling, according to defined scenarios. Although the techno-economic model is a general model that can be applied to any EOR project, we illustrate it here to compare flooding scenarios for a modeled EOR project in Mississippi. Reservoir heterogeneity is the variation of petrophysical properties with space such as porosity, permeability, fluid saturation. This effect is explored for total of 81 cases considering different combinations of Dykstra-Parsons coefficient (VDP) and correlation length. For each case, 25 random realizations of the permeability field were generated and the results of realizations were averaged to provide a statistical representation of the cases. Simulations of three scenarios including Waterflood, Water Alternating Gas, and Surfactant Alternating Gas floods (using a foam model for SAG) were carried out for each realization. The results show that, under assumed cost structure and the selected foam model, on average, SAG is a better and more profitable injection scenario with an oil price of $40/bbl. The economic advantage of SAG, however, declines with greater permeability variation.",9,9,0
Oil Recovery,Degrees C,"Golkari, Abdolah; Riazi, Masoud",Comparative study of oil spreading characteristics for water and carbonated water systems using live and dead oils,Carbonated water alternating CO2 injection; Oil swelling phenomena; Oil spreading coefficient (SC); Equilibrium interfacial tension (EIFT); Optimum conditions; Live crude oil,EQUILIBRIUM PHASE COMPOSITIONS; MINIMUM MISCIBILITY PRESSURE; INTERFACIAL-TENSION; CRUDE-OIL; 3-PHASE FLOW; DIOXIDE; CO2; DENSITIES; RESERVOIR; RECOVERY,"In order to investigate the potential of water alternating gas (WAG) and carbonated water alternating gas (CWAG) injection methods, a series of interfacial tension (IFT) experiments for the binary systems of brine/carbonated brine (CB), carbon dioxide (CO2) and live and dead crude oils were performed. The experiments done using the axisymmetric drop shape analysis (ADSA) technique at temperatures of 40 degrees C and 50 degrees C and different pressures up to 13.79 MPa. The IFT results are used to estimate and determine optimum value of spreading coefficient, which is known as a key enhanced oil recovery (EOR) parameter at the pore scale. The experimental results demonstrate that CB decreases the equilibrium IFT of crude oil compared to the brine at the same conditions (for example, the difference of IFT is 5.2 mN/m and 7.6 mN/m at temperature of 40 degrees C and pressures of 2.76 and 13.79 Mpa, respectively). The equilibrium IFT of the live oil-brine/CB system is greater than that of dead oil-brine/CB. The estimated SC shows that the presence of CO2 in the aqueous phase significantly affects the SC value. That is, it becomes positive for the dead/live oil-CB-CO2 system, and improve the performance of EOR process while it is negative for the dead/live oil-brine-CO2 system. The presence of CH4 gas in the oil phase reduces the SC values at different pressure conditions. Moreover, using the SC results are determined the optimum conditions during CWAG injection. Based on the observed results in the dead/live oil-CB systems, swelling phenomena of the dead oil drop be slightly lower than that of the live oil drop.",2,2,1
Oil Recovery,Degrees C,"Wang, Kongyang; Yan, Wei; Deng, Jingen; Tian, Hao; Li, Wenbo; Wang, Yangang; Wang, Luyao; Ye, Sutao",Experimental study on H2S and CO2 generation capacities of the Bohai bay heavy oil,Heavy oil; Thermal recovery; Pyrolysis; H2S and CO2 generation; Partial pressure,CYMBOPOGON FLEXUOSUS BIOFUEL; FIREFLOOD FIELD PROJECTS; DIESEL-ENGINE; EMISSION CHARACTERISTICS; RECOVERY STRATEGIES; GRAVITY DRAINAGE; BIODIESEL BLEND; PERFORMANCE; COMBUSTION; RESERVOIRS,"Thermal recovery is a conventional technology for heavy oil development. During thermal oil recovery the reservoir could generate H2S and CO2. They will potentially threat the safety of downhole tubing regarding the sweet or sour corrosion. In some Bohai heavy oil fields CO2 and H2S under thermal recovery conditions lead to some corrosion problems of the tubing and equipment. Therefore, to determine the corrosive gas generation capacity is crucial for anti-corrosion design of downhole tubing and casing. Heavy oil samples from Bohai, China were experimentally studied for their pyrolysis characteristics using high-temperature-high-pressure autoclaves. The gases were collected when autoclaves cooled down to the in situ formation temperature. Effects of temperature, water chemistry and core mineral on corrosive gas generation were investigated. The results show that total pressure increase significantly when temperature reached 250 degrees C-280 degrees C under the single heavy oil condition. The additional water facilitates the reaction process, after more SO42- added in the mimic formation water, higher H2S content is obtained. Under the condition of multiphase of oil, formation water and cores, both of the H2S and CO2 content increase obviously, and the cores' effect on CO2 is greater than H2S. Anti-corrosion design usually concerns only the highest corrosive gas concentration without further analysis. The highest concentration does not always correspond to the best corrosive gases generation capacities of heavy oil. Comprehensive analysis of both the total pressure of reaction process and the quality of the reaction heavy oil is carried out, then the corrosive gases volume per unit mass of heavy oil is calculated. These can determine the strongest corrosive formation environment and the maximum gases generation capacities of heavy oil.",4,4,3
Oil Recovery,Degrees C,"Leyva-Gomez, H.; Babadagli, Tayfun",Efficiency of heavy-oil/bitumen recovery from fractured carbonates by hot-solvent injection,Injection parameters optimization; Heavy oil; Hot solvent; Fractured carbonate reservoirs; Oil dilution,RESERVOIRS SOS-FR; OIL-RECOVERY; BITUMEN RECOVERY; ASPHALTENE DEPOSITION; VAPOR EXTRACTION; AIDED PROCESS; STEAM; SIMULATION; SANDS; PILOT,"This paper presents an extensive analysis of three different solvents injected through two different rock types under dynamic conditions, at elevated temperatures, to recover heavy-oil/bitumen from fractured carbonates. The main idea was to identify the optimal temperatures needed for maximal recovery by hot solvent injection for a wide range of solvents. We also considered the optimal conditions for effective solvent retrieval for the economics of this type recovery approach. In order to represent a wide range of carbon number solvents, heptane and naphtha were injected at atmospheric pressure and temperatures ranging from 70 to 120 degrees C and 21.5-100 degrees C, respectively. Propane was injected at a pressure of 1483-1511 kPa and a temperature ranging from 22 to 60 degrees C to be in the liquid phase. Indiana limestone (outcrop) and vuggy naturally fractured carbonate samples (outcrop core samples from a producing formation in Mexico) were selected as core samples. Hot solvent was injected continuously through artificially fractured cores followed by hot water (or steam injection) phase for solvent retrieval. The optimal temperatures for heavy oil recovery and solvent retrieval, in the subsequent hot water injection, for each kind of rock sample and type of solvent were determined. The results revealed that heavy oil recovery increase with the solvent carbon number used. Also, it was observed that when the temperature is higher than the saturation value for the given pressure curve, the recovery decreases and the lightest component of the heavy oil are dragged by the gas stream.",5,5,1
Oil Recovery,Degrees C,"Lele, Pushan; Syed, Abdul Haseeb; Riordon, Jason; Mosavat, Nader; Guerrero, Adriana; Fadaei, Hossein; Sinton, David",Deformation of microdroplets in crude oil for rapid screening of enhanced oil recovery additives,EOR; Droplet deformation; Heavy oil; Interfacial tension; Alkaline flooding,INTERFACIAL-TENSION MEASUREMENT; MICROFLUIDICS-BASED MEASUREMENT; ASSISTED GRAVITY DRAINAGE; ON-A-CHIP; HEAVY OIL; IONIC-STRENGTH; SURFACTANT SOLUTIONS; BITUMEN EXTRACTION; SAGD PROCESSES; SYSTEMS,"We present a microfluidic method to rapidly screen enhanced oil recovery additives based on the deformation of aqueous microdroplets in oil. Conventional methods, such as the pendant drop method, are hindered by large fluid volumes that require several hours to thermally equilibrate between measurements. Here we demonstrate a complementary technology to conventional methods, by which additives can be rapidly screened to select the best candidates for further study. Our glass chip establishes thermal equilibrium (demonstrated at 80 degrees C) of undiluted, highly viscous, crude oil within seconds, and enables the rapid quantification of water-in-crude oil droplet deformation within minutes, at a reservoir-relevant scale. The influence of two alkaline additives, a surfactant and a salt in the injected water phase were quantified, demonstrating the applicability of our method to a variety of recovery strategies.",5,5,2
Oil Recovery,Degrees C,"Zhu, Dongya; Meng, Qingqiang; Liu, Quanyou; Zhou, Bing; Jin, Zhijun; Hu, Wenxuan",Natural enhancement and mobility of oil reservoirs by supercritical CO2 and implication for vertical multi-trap CO2 geological storage,Supercritical CO2; Reservoir enhancement; Dawsonite; Geological storage; Huangqiao reservoir,RARE-EARTH-ELEMENT; CARBON-DIOXIDE; FLUID INCLUSIONS; SALINE AQUIFERS; BASIN; SEQUESTRATION; ACCUMULATION; GAS; RECOVERY; MODEL,"The accumulation and production of both deep mantle-derived CO2 and light oil were discovered in the Huangqiao reservoir, which is located in the Subei Basin, East China. The Huangqiao reservoir shows that both CO2 and oil are entrapped in and produced from vertical multi-traps. The effects of deep CO2 on the accumulation and production of oil under natural conditions and the implications for CO2 geological storage are investigated in detail. The fluid inclusions in quartz or calcite veins from the Silurian Fentou Formation (S(2-3)f), Permian Longtan Formation (P(2)l) and Triassic Qinglong Formation (T(1)q) have homogenization temperatures (Ths) that display peak ranges of 180 degrees C-190 degrees C, 170 degrees C-180 degrees C and 150 degrees C-160 degrees C, respectively. The Ths are higher than the formation temperatures. The calcite veins have light carbon and oxygen isotope compositions and have high Sr-87/Sr-86 ratios and positive Eu anomalies. These characteristics reveal the activities of deep CO2-rich hydrothermal fluids in the basin strata. The feldspar in the S(2-3)f and P(2)l sandstone reservoirs underwent significant dissolution because of the presence of CO2-rich fluids, forming of a large amount of secondary pores in the sandstone reservoirs and enhancing the reservoirs' physical properties. The measured porosity reaches 12.3%. CO2 in a supercritical state extracted or dissolved light petroleum components out of sedimentary rocks and then carried them towards reservoirs. Thus, CO2 and oil co-accumulated in the enhanced reservoirs, e.g. S(2-3)f, P(2)l and T(1)q. During drilling development, this supercritical CO2 naturally increased the mobility of oil, resulting in the co-production of highly pure CO2 and light oil. Based on the unique features of the Huangqiao CO2-oil reservoir, we propose a new CO2 geological storage model, namely, a vertical multi-trap geological storage model, which can either entrap large volumes of CO2 or lower the risk of long-term storage.",5,7,4
Oil Recovery,Degrees C,"Yang, Shangyu; Han, Lihong; Feng, Chun; Wang, Hang; Feng, Yaorong; Wu, Xingru",Mechanical performance of casing in in-situ combustion thermal recovery,Casing performance; Heavy oil; In-situ combustion; Casing design; Steam flooding,OIL; WELLS,"In-situ combustion is often used to develop heavy oil as it has multiple advantages over alternative thermal methods. However, the wellbore integrity can be compromised if the casing is not properly designed or manufactured. Based on the fundamentals of heat transfer, a mathematical model with multiphysics is built to study the temperature and pressure distributions surrounding the wellbore during in-situ combustion. In laboratory, real casings and coupons with grades of N80, P110, and 3Cr110 were tested under high temperature to study their mechanical performances in the in-situ combustion recovery. From the modeling and laboratory testing results, we propose the casing design and manufacture protocols for thermal recovery of heavy oil. Field applications in Liaohe oil field, Du-66 Block, shows that the mechanical deterioration of P110 and 3Cr110 is less than that of N80 and the mechanical performance stability of 3Cr110 is better than others when the temperature is less than 600 degrees C. When the temperature is above 600 degrees C for more than 10 h, the mechanical performance of all casing grades declines quickly. Applying finite element analysis, we recommend a safety factor of 1.1 for designing casing at the temperatures of 250 degrees C,480 degrees C and 485 degrees C. The finding of this study provides fundamentals for the casing design and material selection for in-situ combustion recovery.",6,6,0
Oil Recovery,Degrees C,"Wu, Fei-peng; Liu, Jing; Wei, Xue-mei; Pu, Chun-sheng",A study on oxygen consumption mechanism of air-foam flooding in low-temperature oil reservoir,Low temperature and permeability oil reservoir; Air injection; Oxygen consumption mechanism; Oxygen consumption rate; Field test,AQUEOUS-SOLUTION; POLYMER GELS; OXIDATION; POLYACRYLAMIDE; INJECTION; DEGRADATION; SOLUBILITY; KINETICS; STABILITY; GAS,"Air flooding/air-foam flooding recovery technology has been attracting attention in oilfield development. The key point to the application of this technology is to ensure that the oxygen injected with the air can be fully dissipated inside the reservoir to lower the explosion risk in production wells and reduce the oxidation of the pipeline. It is generally believed that the oxygen and crude oil can react more in low-temperature-oxidation (LTO) reactions above 80 degrees C. As a large amount of oxygen would be spontaneously consumed at this temperature, this technology is mainly used in reservoirs where the temperature is greater than 80 degrees C. In the fractured low-permeability reservoir of China's Yanchang oilfield, where the reservoir temperature is only approximately 30 degrees C, a wide range of crude oil LTO would not be triggered theoretically. However, we found that the oxygen content of the associated gas in the gas channeling wells is significantly lower than that in the air. This phenomenon suggests that, there are other factors that could consume oxygen apart from the LTO reaction. To verify this assumption, an oxygen dissipation core flooding experiment at 30 degrees C and 80 degrees C was carried out to evaluate the oxygen consumption at different temperatures. At the same time, in order to determine the main controlling factors and dissipation mechanisms of oxygen dissipation, theoretical analyses and experimental studies were carried out from the aspects of reductive mineral oxidation reaction in the rock surface and formation water, the physical absorption of the micropore and the dissolution of the reservoir fluid. The results show that at the same experimental conditions, the oxygen consumption at 30 degrees C is 38.14% lower than that at 80 degrees C. The oxygen consumption factors in the low-temperature reservoir mainly include the chemical reactions between the oxygen and reducing minerals, dissolution and retention of formation water and oil, adsorption of Van der Waals forces in the reservoir and physical electronic adsorption of the hydrogen-sulfur bonds and carbon-sulfur bonds. In Chang 6 Reservoir of Ganguyi oilfield, formation water could theoretically consume 56 mg/L (1.75 mmol/L) oxygen through dissolved Fe2+. The dissolution by formation water could absorb 11.85 mmol/L oxygen (experimental value). The dissolution by oil could absorb 69.25 mmol/L oxygen (experimental test value), and the oxygen physical adsorption rate of rock pore surface was 1.26 mmol/L. Together with the pilot test data, the results show that the LTO reaction of the stratum crude oil barely occurs in the reservoir at low temperature (30 degrees C). However, a large amount of oxygen dissipation could still be achieved. This study demonstrates that air-foam flooding could break the applicable limit temperature and could also be applied in low-temperature reservoirs.",7,7,1
Oil Recovery,Degrees C,"Zhong, Xun; Liu, Dexin; Shi, Xiaofei; Zhao, Hongtao; Pei, Chun; Zhu, Tongyu; Shao, Minglu; Zhang, Fang",Characteristics and functional mechanisms of clay-cement stabilized three-phase nitrogen foam for heavy oil reservoir,Heavy oil reservoir; Clay-cement three-phase foam; High stability; Water shutoff agent,HYDROPHOBIC NANOPARTICLES; DILATIONAL PROPERTIES; NANO-PARTICLES; AQUEOUS FOAMS; DEMULSIFIERS; RECOVERY; BUBBLES,"The large-scale application of two-phase foam flooding in heavy oil reservoirs was restricted due to the instability of foam itself. However, the developed clay-cement three-phase nitrogen foam can make up for the short broad effectively, which benefits from very good thermal stability, salt resistance, oil sensitivity and excellent plugging performance. In this paper, 8.0 wt% clay, 0.50 wt% cement particles and 1.0 wt% foaming agent were used to generate clay-cement nitrogen foam. The synergistic effects of clay/cement reaction products, particle adsorption layer and steric network contribute to a desirable protective sheath covered compact three-phase foam system with high stability and strength, the half-life of which was 42.0 min at 95 degrees C. Moreover, it became more stable when formation sands exist. Generally, clay-cement three-phase nitrogen foam has three kinds of plugging form owing to different formation permeability. In less permeable formations, most foam would separate into two parts, with particles stacking at the entry end and two-phase foam moving forward. While in formations with higher permeability, all foam would flow out directly without effective plugging. Only when it comes to the formations with proper permeability can this foam achieve impressive plugging strength under the effects of Jamin and particle plugging. In addition, the foaming formula can be modified by adjusting particle-surfactant concentrations to fit various formations. Therefore, it is a promising and widely applicable water shutoff agent for heavy oil reservoirs.",8,9,1
Oil Recovery,Degrees C,"Sandengen, K.; Meldahl, M. M.; Gjersvold, B.; Molesworth, P.; Gaillard, N.; Braun, O.; Antignard, S.",Long term stability of ATBS type polymers for enhanced oil recovery,,C-13 NMR-SPECTROSCOPY; ELEVATED-TEMPERATURE; AQUEOUS-SOLUTION; HYDROLYSIS; POLYACRYLAMIDE; COPOLYMERS; OXYGEN; IRON,"In offshore enhanced oil recovery (EOR) applications polymer residence time within the reservoir could be many years. Long term stability (preservation of solution viscosity) within the anaerobic reservoir is a fundamental property of the polymer chemical and consequently highly important for choosing a proper product. For high temperature and/or high salinity reservoirs co-polymers of acrylamide (AM) and acrylamide tertiary butyl sulfonic acid (ATBS) have become common in the industry. The present work aimed at developing generic stability diagrams for such polymers dissolved in seawater (SW). Herein a two-step approach was attempted where stability versus ATBS content was measured at elevated temperature. Thereafter these data were extrapolated to lower temperature. To arrive at a sound extrapolation knowledge of hydrolysis kinetics for the two species, AM and ATBS, was needed. Aqueous solutions of AM-ATBS and AA-ATBS co-polymers were therefore stored at elevated temperature (82-140 degrees C) and progressive changes in microstructure followed by use of C-13 NMR spectroscopy. A steady increase in polymer stability with ATBS content was observed up to around 70 mol%. From 70 to 80 mol% the robustness sharply improved. A striking observation was that stability loss, defined as < 80% remaining viscosity, occurred before significant amounts of ATBS had reacted even at the highest ATBS contents. Acrylamide (AM) hydrolysis was found to be inhibited by the presence of ATBS. This reduced AM conversion rate was believed to be the main reason for increased stability. For the brines tested herein hydrolysis rate was virtually uninfluenced by hardness/salinity, while viscosity was largely impacted. Hence it was concluded that different viscosity loss in various brines stems from carboxylate complexation equilibria and not altered hydrolysis rates. Temperature extrapolation was found to fit a simple Arrhenius approach and it has been suggested that the function should be sound up to around 70 mol% ATBS. With this methodology, the current dataset enabled the construction of a stability diagram for ATBS polymers (0-70 mol% ATBS) dissolved in seawater.",8,8,1
Oil Recovery,Degrees C,"Liu, Pengcheng; Yuan, Zhe; Zhang, Shengfei; Xu, Zhenhua; Li, Xiuluan",Experimental study of the steam distillation mechanism during the steam injection process for heavy oil recovery,Heavy oil; Steam distillation; Distillation rate; Superheated steam; Degree of superheating,SIMULATION; SOLVENT; DRIVE; FIELD,"Steam distillation can effectively enhance heavy oil recovery during steam injection process in heavy oil reservoirs. However, the mechanism of steam distillation is complex, and the changes in oil properties during distillation remain unclear. In this study, three comparative steam distillation experiments were designed and conducted, including distillation processes employing saturated steam, steam superheated by 10 degrees C, and steam superheated by 40 degrees C. Heavy oil samples were derived from the Jin-1 Block in a typical heavy oilfield, in China. The density, viscosity, SARA fractions, and carbon number distribution of the residual oil were compared to those obtained before conducting steam distillation experiments. The steam distillation rates obtained with steam superheated by 40 degrees C, steam superheated by 10 degrees C, and saturated steam were 11.158%, 10.903% and 10.423%, respectively. The results indicate that the steam distillation rate of heavy oil increases significantly with increasing degree of superheating. During the steam distillation process, the density and viscosity of residual oil increase, the contents of saturated hydrocarbons and resin decrease, and the contents of aromatic hydrocarbons and asphaltenes increase. In addition, analysis of the distilled components indicates that lightweight components with smaller carbon numbers are removed firstly by steam distillation, followed by heavier components with larger carbon numbers. Moreover, all hydrocarbons with carbon numbers less than C-22 are removed from heavy oil in the distillation process, while the maximum carbon number of the distilled components was C-34. This study is favorable for understanding the changes in the properties of residual oil after distillation during the steam injection process for heavy oil recovery.",8,8,7
Oil Recovery,Matrix,"Gajo, Alessandro; Cecinato, Francesco; Loret, Benjamin",A computational framework for immiscible three-phase flow in deformable porous media,Immiscible fluids; Capillary pressures; Relative permeabilities; Gas injection; Imbibition; Finite element; Time marching scheme,SEMIDISCRETE FORMULATIONS; MULTIPHASE FLOW; MODEL; PERFORMANCE; TRANSPORT; FLUIDS,"Several soil decontamination processes and enhanced oil recovery techniques involve the co-existence of three immiscible fluids, such as water, a nonaqueous phase liquid and a gas. In this work, a computational framework based on the individual mass balance of each phase is developed, aimed at simulating three-phase flow in a deformable rock through the finite element method, without resorting to specific simplifications that are usually required by standard numerical schemes. Key ingredients of the model are: expression of the residual in terms of mass contents, consistent lumping of the storage terms in the residual and algorithmic (tangent) matrix, consistent integration rules, the use of a minimum relative permeability and a time marching scheme based on trapezoidal integration. Special convective boundary conditions are adopted for pressures to be consistent with the assumed rock wettability properties during co-current imbibition. The resulting numerical scheme can deal with arbitrary saturation and/or pressure boundary conditions. The model is tested by simulating gas injection tests, and both co- and counter-current water imbibition tests, in a deformable core. To assess the performance and robustness of the whole framework, sensitivity analyses are performed upon varying key constitutive, loading and numerical parameters.",2,2,0
Oil Recovery,Matrix,"van Santvoort, Joris; Golombok, Michael",Improved recovery from fractured oil reservoirs,Fracture permeability; Fluid loss; Breakthrough; Viscoelastic surfactants,VISCOELASTIC SURFACTANTS; MICELLAR-SOLUTION; RHEOLOGY; FLOW; PERFORMANCE; DIVERSION; BEHAVIOR,"Fluid loss through natural fractures in oil reservoirs can be overcome using flow induced viscoelastic surfactant (FIVES) solutions. Single phase tests show higher flow resistance in fractures compared to matrix. This reduces the fluid lost through the fracture. During decane displacement, the amount of fluid lost through the fracture is lowered due to this increased local flow resistance. Improved recovery is obtained and the pore volume injected at break-through is reduced from 2.5 PV to ca. 1.0 PV. These results translate to a prolonged economic lifespan of a fractured heterogeneous reservoir and a significant reduction in post-processing costs.",3,3,2
Oil Recovery,Matrix,"Bui, Binh T.; Tutuncu, Azra N.",Interfacial tension induced-transport in shale: A pore-scale study,,NETWORK MODELS; POROUS-MEDIA; WETTABILITY; THROAT,"While unconventional reservoirs have quickly become a main contributor to oil and gas production, the transport mechanism in shale is not well understood. Although water does not imbibe into oil-wetted rock matrix, it has been observed in laboratory measurements that it can. The amount of water imbibed into the rock matrix increases when the salinity of the injected water decreases. Wettability alteration is often considered as the main reason for this phenomenon. One of the physical mechanisms for the imbibition of low salinity water into an oil-wetted rock matrix is the variation of the interfacial tension and the contact angle. The change of salinity initiates the change of interfacial tension driving the movement of the interface imbibing water into oil-wetted pores. The imbibition of the water into the rock matrix is a complicated process requiring a comprehensive understanding of the mass transport at pore scale. Hence, pore scale modeling was used in this research study for understanding the physics of transport at pore scale caused by interfacial tension variation or interfacial tension-induced transport. First, a simplified pore-scale model is presented to simulate the imbibition of water into an oil-wetted pore. Next, a numerical solution and procedure are outlined to simulate the transient mass transport in the pore as the result of interfacial tension variation due to salinity. The results indicate that the interfacial tension-induced transport is a very important mechanism for water imbibition into oil-wetted pores. How fast the water imbibes into the pore depends on the salinity gradient and the type of solute used. When salinity at the inlet of the pore is low, more solute diffuses out of the pore resulting in higher cumulative recovery from the pore. Reducing the interfacial tension between oil and water forces oil out of the pores and improve the oil recovery. Hence, low salinity water is recommended for low salinity water injection enhanced oil recovery.",4,4,2
Oil Recovery,Matrix,"Jia, Hu; Deng, Li-hui",Non-equilibrium 3-D simulator applied to air injection EOR in light oil reservoirs,,POROUS-MEDIA; NUMERICAL-SIMULATION; CAPILLARY-PRESSURE; RECOVERY; COMBUSTION; PERFORMANCE; PROJECTS; FLOW; PERMEABILITY; MECHANISM,"In this paper, a 3-D simulator based on the assumption of both chemical and thermal non-equilibrium is presented for a more realistic view of non-equilibrium process for simulating air injection EOR (enhanced oil recovery). The mathematical model is based on a non-equilibrium stage with dynamic mass transfer process between different fluid phases and energy transfer process between fluid and matrix (solid). The light crude oil oxidation and air injection process are both simulated by this simulator, through which the pore blocking, gas breakthrough and gas override process are presented through the visualization of oil, gas saturation distributions. The crude oil oxidation is refined as in-phase and interphase reactions to investigate the effect of reactant dispersion caused by the gas-liquid mass transfer. The oxygen dissolution and the evaporation of light components in crude oil are considered in the non-equilibrium process. The results without mass transfer, with dynamic mass transfer and with instantaneous mass transfer between gas and liquid phases are compared through multiplying the gas-liquid interface area 0, 1 and 100 times respectively, and the influence of these different mass transfer conditions on the migration of temperature peak front and oil recovery is revealed. In addition, the effect of local chemical and thermal non-equilibrium in different matrix permeability as well as porosity scenarios is also investigated to obtain non-equilibrium behavior in different reservoir conditions when implementing air injection EOR. In the last section, we investigated the result with different simulation timescale to see if the non-equilibrium behavior can be captured in the simulator used in this paper. This study suggests that the non-equilibrium behavior would show obvious influence on oil recovery for air injection in the lower permeability reservoir. The non-equilibrium behavior is desirable to be considered for simulating air injection EOR in light oil reservoirs. The developed 3-D simulator is robust that can better reflect the mechanism of air injection EOR in light oil reservoirs. We hope this work encouraging more investigations for the simulation side of nonequilibrium phase behavior and energy transfer in the air injection process.",5,5,1
Oil Recovery,Matrix,"Bui, Binh T.; Tutuncu, Azra N.",Modeling the swelling of shale matrix in unconventional reservoirs,Shale swelling; Coupled modeling; Unconventional reservoirs; Dual-porosity model; Water injection; Mass transport,,"The imbibition of the injection water into shale matrix may result in shale swelling affecting oil recovery from the rock matrix and the transport properties of the fractures. The expansion of rock due to the swelling of shale matrix compresses the pore space in the rock matrix and the surrounding fractures. This reduces fracture and matrix porosity and permeability. The reduction of matrix pore space can reduce the rate of oil recovered from the rock matrix. On the other hand, it also forces the oil out of the matrix pore space increasing oil recovery. However, this effect has not been evaluated and integrated in reservoir modeling. This study presents a coupled fluid flow and geomechanics model for modeling shale swelling to quantitatively investigate the effect of swelling on transport properties of rock matrix and fractures. The main objective is to quantitatively determine the effect of shale swelling on the oil recovery from the rock matrix. A numerical solution is presented to solve the coupled equations simultaneously for the phase pressure, fluid saturation, stress, and strain. We show that the mechanical properties of the rock matrix vary significantly as the result of water imbibition. The reduction of the fracture and matrix permeability and porosity due to swelling is considerable. This results in the reduction of more than 50% of the oil recovered from shale matrix. Hence, shale swelling should be prevented in any water injection operations.",6,6,1
Oil Recovery,Matrix,"Wang, Fei; Pan, Ziqing; Zhang, Yichi; Zhang, Shicheng",Simulation of coupled hydro-mechanical-chemical phenomena in hydraulically fractured gas shale during fracturing-fluid flowback,Fracturing-fluid flowback; Shale gas reservoirs; Hydro-mechanical-chemical model; Fracture closure; Chemical osmosis,PART I; IMBIBITION; PRESSURE; BEHAVIOR; BRINE; WELLS; COAL; OIL,"Fracturing-fluid flowback in hydraulically fractured gas shale is a complicated transport behavior involving hydrodynamic (H), mechanical (M) and chemical (C) processes. Although, many flowback models have been published, none of the models flly coupled the transient fluid flow modeling with chemical-potential equilibrium and fracture closure phenomena. In this paper, a coupled hydro-mechanical-chemical (HMC) model based on hydrodynamics, linear-elastic fracture mechanics, and chemical-potential equations is presented to simulate the fracturing-fluid flowback behavior in hydraulically fractured gas shale. The HMC model takes into account a gas-liquid two-phase flow and a triple-porosity medium, which includes primary hydraulic fractures, secondary induced fractures and shale matrix. The flowback simulation with the HMC model accounts for all the important processes in fractured shale system, including (1) water transport driven by hydraulic, capillary and osmotic convections, (2) gas transport induced by both hydraulic pressure driven convection and adsorption, and (3) fracture closure considered as an elastic deformation. The fluid transport, coupled with rock deformation, are described by a set of partial differential equations. The semi-implicit finite-difference method is used to solve these equations. The evolution of pressure, saturation, salinity and aperture profiles of hydraulic fractures, induced fractures and matrix is calculated, revealing the multi-field coupled flowback behavior in fractured gas shale. The sensitivity analysis is also performed to investigate the physiochemical properties of shale on the water load recovery and gas production rate during the fracturing-fluid flowback. The results indicate that the capillarity has the most effect followed by chemical osmosis and induced fracture closure. The sub-irreducible water saturation has the weakest effect. Moreover, the matrix-related physiochemical parameters cause opposite influences on water load recovery and gas production rate. While, the influence of induced fracture-related parameters on both water load recovery and gas production rate is consistent. Results from this study are expected to explain which is the predominant mechanism for fracturing-fluid retention and the inherent relationship between fracturing-fluid flowback and gas production for different initial physiochemical properties of shale.",6,6,12
Oil Recovery,Matrix,"Song, Zhaojie; Bai, Baojun; Zhang, Hao",Preformed particle gel propagation and dehydration through semi-transparent fractures and their effect on water flow,Enhanced oil recovery; Preformed particle gel; Open fracture; Dehydration behavior; Conformance improvement,CONFORMANCE-CONTROL; HYDROLYZED POLYACRYLAMIDE; PERFORMANCE; TRANSPORT; INJECTION; MODELS,"Polymer gels have been widely applied to plug high permeability streaks or fractures, and to improve sweep efficiency of chase waterfloods. This work constructed semi-transparent fracture models to investigate gel propagation and dehydration behaviors using preformed particle gel (PPG) in open fractures. Roubidoux sandstone slabs were used in the models because they could better model the roughness of fractures and PPG dehydration in a real fracture system, which was rarely reported in earlier studies. Injection rate, fracture width, particle size, brine and gel concentration were taken into account to understand their effects on particle gel extrusion. Experimental results showed PPG propagated like a piston along a fracture when the fracture width was smaller than or similar to the particle size; and gravity will dominate the PPG movement when the fracture width was larger than the particle size. PPG dehydration decreased with the increasing gel injection rate, fracture width, and brine concentration used to prepare PPG. Higher PPG injection rates and lower injection rates for chase waterfloods are recommended to improve the sweep efficiency in the matrix. This study could provide an insight into the particular PPG gel treatment for conformance improvement.",7,7,1
Oil Recovery,Matrix,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Oil Recovery,Matrix,"Abolhosseini, Pejman; Khosravi, Maryam; Rostami, Behzad; Masoudi, Mohammad",Influence of Thermal Marangoni convection on the recovery of bypassed oil during immiscible injection,Injection into fracture; Marangoni flow; Benard-Marangoni convection; Immiscible injection,INTERFACIAL-TENSION; MASS-TRANSFER; FLUID; FLOW; MATRIX,"Several phenomena could recover the bypassed oil in matrixes and low permeable areas, among them; Marangoni is the most unfamiliar one in fluid flow model. This mechanism triggers a convective flow from low interfacial tension point to a high interfacial tension point because of variation in solvent concentration, temperature or electrical charge. In this study, experimental and analytical tools have been utilized to investigate the effect of thermal Marangoni flux on the enhancement of oil recovery during immiscible injection in a matrix-fracture system. Results of non-isothermal experiments have been compared with isothermal (as the zero level of Marangoni) to study the presence of Marangoni flow and its direction respect to the fracture location. Results show that not only the Marangoni flux does exist and has significant impact on the recovery of bypassed oil but also, its magnitude is proportional to the absolute value of temperature gradient in phases interface.",8,8,2
Oil Recovery,Gravity Drainage,"Borisov, D. N.; Tazeev, D. I.; Milordov, D. V.; Mironov, N. A.; Borisova, Y. Y.; Yakubov, M. R.; Beregovoy, A. N.; Amerkhanov, M. I.; Khisamov, R. S.",Physical modeling of the composite solvent injection to improve the ultra-viscous oil recovery efficiency steam-assisted gravity drainage,Ultra-viscous oil; Heavy oil; Solvent; Reservoir modeling; Thermal enhanced oil recovery techniques; Steam-assisted gravity drainage,ASPHALTENE PRECIPITATION; CRUDE OILS; AGGREGATION; PERFORMANCE; INHIBITION; RESERVOIRS; STABILITY; RESINS; CSI,"The experiments carried out on a physical model of reservoir of ultra-viscous oil have revealed features of oil displacement in various variants of the composite solvent and steam injection. In order to avoid precipitation of asphaltenes, the employment of inhibitors has been rationalized and their minimum fraction in displacement fluid has been determined. The effect of the sequence of solvent and vapor injection on the dynamics of ultra-viscous oil recovery has been investigated. The effect of clay and water in the rock on the rate of oil displacement and the ultimate oil recovery factor has been evaluated.",0,0,2
Oil Recovery,Gravity Drainage,"Wang, Kongyang; Yan, Wei; Deng, Jingen; Tian, Hao; Li, Wenbo; Wang, Yangang; Wang, Luyao; Ye, Sutao",Experimental study on H2S and CO2 generation capacities of the Bohai bay heavy oil,Heavy oil; Thermal recovery; Pyrolysis; H2S and CO2 generation; Partial pressure,CYMBOPOGON FLEXUOSUS BIOFUEL; FIREFLOOD FIELD PROJECTS; DIESEL-ENGINE; EMISSION CHARACTERISTICS; RECOVERY STRATEGIES; GRAVITY DRAINAGE; BIODIESEL BLEND; PERFORMANCE; COMBUSTION; RESERVOIRS,"Thermal recovery is a conventional technology for heavy oil development. During thermal oil recovery the reservoir could generate H2S and CO2. They will potentially threat the safety of downhole tubing regarding the sweet or sour corrosion. In some Bohai heavy oil fields CO2 and H2S under thermal recovery conditions lead to some corrosion problems of the tubing and equipment. Therefore, to determine the corrosive gas generation capacity is crucial for anti-corrosion design of downhole tubing and casing. Heavy oil samples from Bohai, China were experimentally studied for their pyrolysis characteristics using high-temperature-high-pressure autoclaves. The gases were collected when autoclaves cooled down to the in situ formation temperature. Effects of temperature, water chemistry and core mineral on corrosive gas generation were investigated. The results show that total pressure increase significantly when temperature reached 250 degrees C-280 degrees C under the single heavy oil condition. The additional water facilitates the reaction process, after more SO42- added in the mimic formation water, higher H2S content is obtained. Under the condition of multiphase of oil, formation water and cores, both of the H2S and CO2 content increase obviously, and the cores' effect on CO2 is greater than H2S. Anti-corrosion design usually concerns only the highest corrosive gas concentration without further analysis. The highest concentration does not always correspond to the best corrosive gases generation capacities of heavy oil. Comprehensive analysis of both the total pressure of reaction process and the quality of the reaction heavy oil is carried out, then the corrosive gases volume per unit mass of heavy oil is calculated. These can determine the strongest corrosive formation environment and the maximum gases generation capacities of heavy oil.",4,4,3
Oil Recovery,Gravity Drainage,"Baek, Kwang Hoon; Arguelles-Vivas, Francisco J.; Okuno, Ryosuke; Sheng, Kai; Sharma, Himanshu; Weerasooriya, Upali P.",Emulsification of Athabasca bitumen by organic alkali: Emulsion phase behavior and viscosity for bitumen/brine/triethylenetetramine,Bitumen; Organic alkali; Natural surfactant; Emulsion phase behavior; Emulsion viscosity,HEAVY OIL-RECOVERY; IN-WATER EMULSIONS; CRUDE-OIL; PIPELINE TRANSPORTATION; NATURAL SURFACTANTS; ASPHALTENE RATIO; STEAM CHAMBER; STABILITY; RHEOLOGY; RESINS,"Recovery of bitumen commonly uses steam assisted-gravity drainage, in which water throughput is intrinsically high. A large amount of condensed water near thermal fronts tends to substantially decrease the effective permeability to bitumen in the conventional gravity drainage process. This research investigates a potential way to use the condensed-water phase as an effective carrier for bitumen by making oil-in-water (o/w) emulsion. The expected mechanism depends on emulsification of bitumen into the water phase by natural surfactants that are generated through reactions of acidic oil components with organic alkali. The main objective of this paper is to study the ability of an organic alkali to create o/w emulsions that are much more mobile than the original bitumen. Triethylenetetramine (TETA) was selected as organic alkali for this paper with no other additives. The main contribution of this paper is a new set of experimental data (phase behavior and viscosities) for emulsions for mixtures of Athabasca bitumen, TETA, and NaCl brine at a wide range of alkali concentrations, salinities, and water-to-oil ratios (WORs) M temperatures up to 373 K. Results show that the o/w emulsions created by TETA can be an effective bitumen carrier with a low viscosity and high bitumen content in the emulsion. It is possible to create o/w emulsions by adding a small amount of TETA to Athabasca bitumen and NaC1 brine. Single-phase o/w emulsions, which are desirable as a bitumen carrier, were observed for TETA concentrations below 5.0 wt% M salinities 0 ppm and 1000 ppm at 373 K. The bitumen content in o/w emulsion was the highest for 2.0 wt% TETA samples, and it increased with increasing temperature. In comparison to the original bitumen, o/w emulsions were 4-5 orders of magnitude less viscous at 298 K, 2 to 3 orders of magnitude less viscous at 323 K, and 1 to 2 orders of magnitude less viscous at 353 K.",5,6,2
Oil Recovery,Gravity Drainage,"Lele, Pushan; Syed, Abdul Haseeb; Riordon, Jason; Mosavat, Nader; Guerrero, Adriana; Fadaei, Hossein; Sinton, David",Deformation of microdroplets in crude oil for rapid screening of enhanced oil recovery additives,EOR; Droplet deformation; Heavy oil; Interfacial tension; Alkaline flooding,INTERFACIAL-TENSION MEASUREMENT; MICROFLUIDICS-BASED MEASUREMENT; ASSISTED GRAVITY DRAINAGE; ON-A-CHIP; HEAVY OIL; IONIC-STRENGTH; SURFACTANT SOLUTIONS; BITUMEN EXTRACTION; SAGD PROCESSES; SYSTEMS,"We present a microfluidic method to rapidly screen enhanced oil recovery additives based on the deformation of aqueous microdroplets in oil. Conventional methods, such as the pendant drop method, are hindered by large fluid volumes that require several hours to thermally equilibrate between measurements. Here we demonstrate a complementary technology to conventional methods, by which additives can be rapidly screened to select the best candidates for further study. Our glass chip establishes thermal equilibrium (demonstrated at 80 degrees C) of undiluted, highly viscous, crude oil within seconds, and enables the rapid quantification of water-in-crude oil droplet deformation within minutes, at a reservoir-relevant scale. The influence of two alkaline additives, a surfactant and a salt in the injected water phase were quantified, demonstrating the applicability of our method to a variety of recovery strategies.",5,5,2
Oil Recovery,Gravity Drainage,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Oil Recovery,Gravity Drainage,"Guo, Yujia; Roostaei, Morteza; Nouri, Alireza; Fattahpour, Vahidoddin; Mahmoudi, Mahdi; Jung, Heeseok",Effect of stress build-up around standalone screens on the screen performance in SAGD wells,SAGD; Sand retention test; Slotted liner; Sand control,OIL,"Steam Assisted Gravity Drainage (SAGD) is the primary thermal recovery technology currently employed to extract heavy oil and high-viscosity bitumen from Alberta oil sands. In the near-wellbore region, the initial stresses are nearly zero, and as the SAGD chamber grows, the stresses tend to build up due to the thermal expansion of the formation. Also, melting of the bitumen and subsequent loss of the bonding between the grains leads to the collapse of the gap between the formation and sand control liner over time. The result will be effective stress buildup and gradual compaction of the oil sands around the liner. Slotted liners have been extensively used as a sand control device in SAGD wells. Slotted liners must allow free flow through the slots with minimal plugging and acceptable amounts of sand production. In our study, large-scale unconsolidated sand was packed over a multi-slot coupon of the slotted liner. The sand-pack was subjected to several stress conditions corresponding to the evolving stress conditions during the life cycle of a SAGD producer well. The testing program employed several multi-slot coupons to examine the flow performance under typical encountered stresses in SAGD wells. Cumulative produced sand was measured at the end of testing as an indicator of the sand control performance. The permeability evolution of the sand in the near-coupon zone was calculated by measurements of pressure differentials and considered as a measure of screen flow performance. Fines/clay concentration along the sand-pack was also quantified after the test to investigate the fines migration, a phenomenon which is considered to be the main reason for reduced wellbore productivity. Experimental results show that the liner performance is significantly affected by the normal stress buildup on the liner. Experimental observations indicate sand-pack compaction due to the increase of effective stress around the liner leads to a lower porosity and permeability. The situation near the liner is further complicated by the fines accumulation that results in pore plugging and further permeability reduction. When it comes to sanding, however, higher stresses help stabilize the sand bridges behind the slots, leading to less sand production. As for the design criteria, the lower and upper bounds of the slot size are governed by plugging and sand production, respectively. Considering the stress effect on plugging and sanding, testing data indicate that both the lower and upper bounds should be revised to larger slot aperture sizes.",8,8,2
Oil Recovery,Gravity Drainage,"Kathel, P.; Mohanty, K. K.",Dynamic surfactant-aided imbibition in fractured oil-wet carbonates,Wettability alteration; Imbibition; Gravity drainage; Fractured reservoirs; Carbonate rocks,WETTABILITY ALTERATION; GRAVITY DRAINAGE; RECOVERY; RESERVOIRS; WATER; TEMPERATURE,"Numerous studies based on static imbibition experiments at lab scale have established surfactant-aided imbibition as an improved oil recovery process for fractured oil-wet carbonate reservoirs. However, predicting performance at larger scales and at dynamic conditions (fluid flow through fracture) remains a challenge. In this study, experiments are performed on Estaillades Limestone and Texas Cream Limestone outcrop cores with varying height and diameter with permeability in the range of 8 mD to 150 mD to address this challenge. It is observed that dynamic imbibition process recovers oil faster than static imbibition. Imbibition experiments performed on cores with varying height and diameter show that oil recovery decreases with increasing diameter and height. A 3D fine grid mechanistic simulator was used to perform lab scale validation and analyze recovery mechanism. Numerically simulated velocity and saturation profiles demonstrated the recovery mechanism to be gravity dominated flow. A new scaling function is proposed for surfactant aided gravity dominated processes. Data with same boundary conditions, rock, fluids and varying dimensions can be correlated with the scaling function at early times with no fitting parameters involved. A good correlation is obtained with the data indicating the effectiveness of the scaling function. The scaling is applicable to both static as well as dynamic imbibition.",8,8,3
Oil Recovery,Residual Oil,"Gajo, Alessandro; Cecinato, Francesco; Loret, Benjamin",A computational framework for immiscible three-phase flow in deformable porous media,Immiscible fluids; Capillary pressures; Relative permeabilities; Gas injection; Imbibition; Finite element; Time marching scheme,SEMIDISCRETE FORMULATIONS; MULTIPHASE FLOW; MODEL; PERFORMANCE; TRANSPORT; FLUIDS,"Several soil decontamination processes and enhanced oil recovery techniques involve the co-existence of three immiscible fluids, such as water, a nonaqueous phase liquid and a gas. In this work, a computational framework based on the individual mass balance of each phase is developed, aimed at simulating three-phase flow in a deformable rock through the finite element method, without resorting to specific simplifications that are usually required by standard numerical schemes. Key ingredients of the model are: expression of the residual in terms of mass contents, consistent lumping of the storage terms in the residual and algorithmic (tangent) matrix, consistent integration rules, the use of a minimum relative permeability and a time marching scheme based on trapezoidal integration. Special convective boundary conditions are adopted for pressures to be consistent with the assumed rock wettability properties during co-current imbibition. The resulting numerical scheme can deal with arbitrary saturation and/or pressure boundary conditions. The model is tested by simulating gas injection tests, and both co- and counter-current water imbibition tests, in a deformable core. To assess the performance and robustness of the whole framework, sensitivity analyses are performed upon varying key constitutive, loading and numerical parameters.",2,2,0
Oil Recovery,Residual Oil,"Ansah, Eric O.; Sugai, Yuichi; Nguele, Ronald; Sasaki, Kyuro",Integrated microbial enhanced oil recovery (MEOR) simulation: Main influencing parameters and uncertainty assessment,Artificial intelligence; Capillary number; Enthalpy; Microbial enhanced oil recovery; Monte Carlo simulation; Response surface methodology,HEAVY OIL; TEMPERATURE; RESERVOIR; GROWTH; MECHANISMS; BACTERIA; FIELD,"The present study investigated the ability of a thermophilic anaerobic microbe (herein coded as AR80) for MEOR with the further objective to quantify the uncertainty of production forecast in terms of the cumulative probability distribution. A series of core flood experiments conducted in water-flooded Berea sandstone showed that up to 51% of initial oil-in-place was recovered when the plugs were treated with AR80 and shut-in for 14 days. Mainly, the oil recovery mechanisms were attributed to viscosity enhancement, wettability changes, permeability and flow effects. Matching the laboratory data using artificial intelligence: the optimized cumulative oil recovery could be achieved at an enthalpy of 894.2 J/gmol, Arrhenius frequency of 8.3, residual oil saturation of 20%, log of capillary number at microbe flooding stage of -1.26, and also depicted a history match error less than 3%. Therefrom, a sensitivity analysis conducted on reservoir shut-in period effect on oil recovery revealed that a relatively shorter shut-in period is recommended to warrant early incremental oil recovery effect for economical purposes. In addition, MEOR could enhance the oil recovery significantly if a larger capillary number (between 10(-5) and 10(-3.5)) is attained. Per probabilistic estimation, MEOR could sustain already water-flooded well for a set period of time. This study showed that there is a 20% frequency of increasing the oil recovery by above 20% when a mature water-flooded reservoir is further flooded with AR80 for 2 additional years. Lastly, it was demonstrated herein that increasing the nutrient (yeast extract) concentration (from 0.1 to 1% weight) had less or no significant effect on the oil viscosity and subsequent recovery.",4,4,0
Oil Recovery,Residual Oil,"Sanni, Modiu; Al-Abbad, Mohammed; Kokal, Sunil; Dugstad, Oyvind; Hartvig, Sven; Huseby, Olaf",Pushing the envelope of residual oil measurement: A field case study of a new class of inter-well chemical tracers,Tracer; Residual oil saturation; Remaining oil saturation; Inter-well chemical tracer test; IOR/EOR; Field trial or case study,REMEDIATION PERFORMANCE,"The success of any improved oil recovery (IOR) project is largely dependent on how much oil is remaining to be mobilized within the targeted area of the partially depleted or mature reservoir. Partitioning tracers are generally used to measure residual oil saturation (Sor) or remaining oil saturation (ROS) in the near wellbore region via a single well chemical tracer test (SWCTT) or in an inter-well region via a partitioning inter-well tracer test (PITT). There is a limited repertoire of nonradioactive and environmentally friendly inter-well partitioning tracers for measuring ROS. A new class of environmentally friendly partitioning tracers was field tested, in a giant carbonate reservoir undergoing peripheral waterflood, for measuring ROS in inter-well regions in a depleted area. The new partitioning tracers were qualified via laboratory experiments and are deemed to be very stable at reservoir conditions (213 degrees F and a salinity range of 60-200 kppm). The field pilot was conducted concurrently with a set of non-partitioning inter-well chemical tracer test (IWCTT) to determine reservoir connectivity, water breakthrough times, and injector-to-producer pair communication in an area selected for an IOR/EOR field pilot. An elaborate sampling and analysis program was carried out over a period of 30 months. This paper reviews the complete design and implementation of the test, operational issues, and the analyses and interpretation of the results. The breakthrough times of the passive and partitioning tracers are reported, and inter-well connectivity between the paired and cross-paired injectors and producers are analyzed. The ROS measured by a majority of the novel tracers is comparable to the saturations obtained via SWCTT, core and log derived saturations. The combination of conventional IWCTT and the novel partitioning tracers via PITT has been very useful in analyzing well interconnectivity, understanding the reservoir dynamics and quantifying remaining oil saturation distribution in the reservoir. This has led to better reservoir description and an improved dynamic simulation model.",6,6,2
Oil Recovery,Residual Oil,"Li, Qianwen; Pang, Xiongqi; Li, Boyuan; Zhao, Zhengfu; Shao, Xinhe; Zhang, Xian; Wang, Yingxun; Li, Wei","Discrimination of effective source rocks and evaluation of the hydrocarbon resource potential in Marsel, Kazakhstan",Effective source rocks discrimination; Petroleum resources evaluation; Marsel; Kazakhstan,PART; OIL,"Three rounds of exploration in Marsel, Kazakhstan show that the area has good petroleum geological conditions; however, the exploration degree is low and the resource potential is unclear. The total organic carbon (TOC) content is the criteria for effective source rocks and is also the key parameter to calculate the amount of resources; while previous evaluations of the effective source rocks and calculated amounts of resources were based on residual TOC, which gradually decreases with mass hydrocarbon expulsion; therefore, this will inevitably produce errors. For greater accuracy, the TOC recovery coefficient formula was used to recover the residual TOC in Marsel; then, the criteria of the effective source rocks were revised to calculate the Carboniferous and Devonian resources in Marsel. The results are as follows: for the source rocks in Marsel, the TOC recovery coefficient of the Carboniferous source rocks is approximately 1.6, while that for the Devonian is approximately 2.0; the revised lower limit of TOC for the effective source rocks is 0.3% and 0.25% for the Carboniferous and Devonian, respectively; after TOC recovery, the total amount of hydrocarbon expulsion is 26.7 x 10(12) m(3), the total amount of recoverable resources is 2.62-5.10 x 10(12) m(3), and the mean is 3.79 x 10(12) m(3) for the main source rocks. The effective source rocks evaluated based on the recovered TOC and the latter resources could reflect the quantity of source rocks and actual resource potential of Marsel more accurately. This has certain significance for the exploration of areas that have low levels of exploration with an unclear understanding of the resource potential as well as a high degree of thermal evolution and a low quantity of residual TOC.",7,8,2
Oil Recovery,Residual Oil,"Fang, Huijing; Xu, Huaimin; Wang, Zhenbiao; Jiang, Tongwen; Zhao, Yuyun; Li, Junjian","Formation mechanism of the Donghe Sandstone residual oil zone in the Tarim Basin, NW China",Residual oil zone; Structural adjustment; Microscopic occurrence state; Tarim basin,WATER-WET SANDSTONE; FIELD; SATURATION; RESERVOIRS; MORPHOLOGY; CONTACTS; STORAGE; MATS,"The residual oil zone (ROZ) with near-residual oil saturation is a naturally water-flooded interval adjacent to an oil-bearing reservoir. It has become a promising development target for the technical progress of enhanced oil recovery. The hydrocarbon show, bitumen distribution and grains containing oil inclusions all indicate the presence of ROZs in the Donghe Sandstone Member of the Tazhong4 and Hade Oilfields in the Tarim Basin. Analysis of the two ROZ examples reveals that a stable paleoreservoir and structural adjustment are significant elements of the ROZ-forming process. The ROZ of the Tazhong4 Oilfield is defined as a reactivated fault ROZ (RFROZ) lying between the paleo oil-water contact (OWC) and producing-OWC. Paleo-hydrocarbons leaked through the reactivated faults, and the current oil saturation has a positive proportion to baffle frequency. The ROZ in the paleo trap northwest of the current reservoir in the Hade Oilfield is defined as a migratory trap ROZ (MTROZ). Paleo-hydrocarbons migrated through connected sand bodies. The current oil saturation in the MTROZ has a positive proportion to baffle frequency and negative proportion to petrophysical properties. The microscopic occurrence state of the residual oil in ROZs was analyzed with direct computed tomography (CT) scanning. The displacement experiments coupled with CT scanning aimed to reveal the different occurrence states of the residual oil in the major stage of natural water flooding in the ROZ-forming process. In the microscopic view, the formation of both RFROZ and MTROZ is a process of clustered flow converting to discontinuous flow, and the clustered flow can be scattered to a larger extent in a high permeability zone. The ROZ development feasibility was preliminarily researched. Low-salinity water flooding after the displacement of the formation water in the etching model provided experimental corroboration for remobilizing the residual oil.",8,8,0
Oil Recovery,Residual Oil,"Alvarez, A. C.; Blom, T.; Lambert, W. J.; Bruining, J.; Marchesin, D.",Analytical and numerical validation of a model for flooding by saline carbonated water,Riemann problem; Waterflooding; Enhance oil recovery,EQUILIBRIUM PHASE COMPOSITIONS; VAPOR-LIQUID-EQUILIBRIA; HUCKEL LIMITING SLOPES; ACTIVITY-COEFFICIENT; RIEMANN PROBLEM; INTERFACIAL-TENSIONS; HYPERBOLIC SYSTEMS; DIOXIDE; SOLUBILITY; DENSITIES,"It has been shown experimentally in the literature that for clayey formations, oil with polar components and an aqueous phase with divalent ions, a secondary waterflood with low salinity water composition improves oil recovery by some 5-20%. Our focus is on a less well known mechanism, i.e. low salinity enhanced solvent (e.g. carbonated water) recovery, as low salinity enhances the aqueous solubility of carbon dioxide. Indeed, after injection the latter is transferred from the aqueous to oleic phase thus decreasing the oil concentration in the oleic phase and diluting the residual oil. To study this mechanism we formulate the conservation equations of total hydrogen, oxygen, chloride and decane. Therefore, we solve analytically and numerically these equations in 1-D in order to elucidate the effects of the injection of low salinity carbonated water into a reservoir containing oil equilibrated with high salinity carbonated water. We use PHREEQC (acronym of pH-REdox-Equilibrium C-program) to obtain the accurate equilibrium partition of neutral species that are soluble both in the oleic and the aqueous phase by application of the Krichevsky-Ilinskaya extension of Henry's law for solubility of gases in liquids. Using Gibbs phase rule it can be shown that the phase behavior only depends on the pH and the chloride concentration. The above mentioned equilibrium relations use Pitzer's activity coefficients to extend the validity up to 6M. We obtain the saturation, composition and the total Darcy velocity profiles. The significant new insight obtained is that by changing only the salinity in carbonated waterflooding the oil recovery can be enhanced.",8,8,2
Oil Recovery,Residual Oil,"Liu, Pengcheng; Yuan, Zhe; Zhang, Shengfei; Xu, Zhenhua; Li, Xiuluan",Experimental study of the steam distillation mechanism during the steam injection process for heavy oil recovery,Heavy oil; Steam distillation; Distillation rate; Superheated steam; Degree of superheating,SIMULATION; SOLVENT; DRIVE; FIELD,"Steam distillation can effectively enhance heavy oil recovery during steam injection process in heavy oil reservoirs. However, the mechanism of steam distillation is complex, and the changes in oil properties during distillation remain unclear. In this study, three comparative steam distillation experiments were designed and conducted, including distillation processes employing saturated steam, steam superheated by 10 degrees C, and steam superheated by 40 degrees C. Heavy oil samples were derived from the Jin-1 Block in a typical heavy oilfield, in China. The density, viscosity, SARA fractions, and carbon number distribution of the residual oil were compared to those obtained before conducting steam distillation experiments. The steam distillation rates obtained with steam superheated by 40 degrees C, steam superheated by 10 degrees C, and saturated steam were 11.158%, 10.903% and 10.423%, respectively. The results indicate that the steam distillation rate of heavy oil increases significantly with increasing degree of superheating. During the steam distillation process, the density and viscosity of residual oil increase, the contents of saturated hydrocarbons and resin decrease, and the contents of aromatic hydrocarbons and asphaltenes increase. In addition, analysis of the distilled components indicates that lightweight components with smaller carbon numbers are removed firstly by steam distillation, followed by heavier components with larger carbon numbers. Moreover, all hydrocarbons with carbon numbers less than C-22 are removed from heavy oil in the distillation process, while the maximum carbon number of the distilled components was C-34. This study is favorable for understanding the changes in the properties of residual oil after distillation during the steam injection process for heavy oil recovery.",8,8,7
Oil Recovery,Polymer,"Esmaeili, Akbar; Saremnia, Betsabe",Comparison study of adsorption and nanofiltration methods for removal of total petroleum hydrocarbons from oil-field wastewater,Adsorption; Nanozeolite NaA; Granulation; Nanofiltration; Membrane polyaniline; Total petroleum hydrocarbons (TPH),REACTIVE RED 198; AIR FLOTATION; TEXTILE DYE; MEMBRANE; POLYANILINE; ZEOLITE; NANOPARTICLES; SEPARATION; RECOVERY; SYSTEM,"The aim of the current study was to investigate and study adsorption and nanofiltration systems for separation of total petroleum hydrocarbons (TPH) from wastewater generated by an oil refinery in Bushehr, Iran. In the first step (previous study), NaA zeolite nanoparticles (NaA-ZNPs) were synthesized and granulated using a hydrothermal method in which the silica source was extracted from oat bran and then modified by the surfactant hexadecyltrimethylammonium bromide (CTAB). In the second step, polyaniline membranes and nanocomposite membranes were synthesized containing polyaniline as the main polymer and clinoptilolite zeolite as the mineral. The NaA-ZNPs and membranes were characterized by gas chromatography-mass spectroscopy (GC-MS), Fourier transform infrared spectroscopy (FT-IR), scanning electron (SEM), and atomic force microscopy (AFM). In order to evaluate the absorption and nanofiltration process, adsorbents in both batch and continuous process in a fixed-bed column with upward flow were used to remove TPH. Time, pH, and adsorbent dosage were studied in the batch process, and flow rate and column height were evaluated for the continuous process. In the batch and continuous systems, when the parameters were optimized, the highest TPH removal efficiencies were 92.3% and 87.4% respectively. Furthermore, in the nanofiltration process, permeation flux and TPH rejection were 190.96 kg h(-1) m(-2) and 99.77%. Finally, the removal efficiency for the hybrid absorption and nanofiltration process was 99.83%. In the hybrid system, due to the combination of two absorption and nanofiltration processes, as well as the effects of NaA-ZNPs functioning as adsorbents, membrane deflation was minimized and the efficiency of removing of TPH increased to 99.83%.",5,5,1
Oil Recovery,Polymer,"Pu, Jingyang; Geng, Jiaming; Bai, Baojun",Effect of the chromium ion diffusion in polyacrylamide/chromium acetate gelation system with surrounding water on gelation behavior,Cr3+ dialysis; Dialysis bag; Hydrolyzed polyacrylamide; Gelation type,CROSS-LINKING REACTION; AQUEOUS-SOLUTIONS; OIL-RECOVERY; HYDROGELS; ADSORPTION; CELLULOSE; REMOVAL; GEL,"The diffusion of Cr3+ from the Cr3+/HPAM system is simulated by quantifying the entrapment ability of the C-r3+ after dialysis analysis through a dialysis bag method to study the Cr3+ diffusion effect on the gelation types. After the gelant is put in the dialysis bag surrounded by the solvents, only the diffusion of the aqueous ions are allowed, which eventually can be detected in the dialysate. By monitoring the gelants with varying initial contents, we find that the Cr3+ dialysis kinetics and total dialyzed amount are changed. In this particular experiment, the gelation types are classified and the classification result differences for the same gelant with or without dialysis process are investigated and compared. In this study, we assess the gelant contents in terms of possible limiting scenarios for successful gelation and discuss their gelation results influenced by the Cr3+ diffusion The results demonstrate that Cr3+ diffusion, in different extent, influences the gelation types and gelation time of the Cr3+/HPAM systems with varying HPAM molecular weight (MW), the Cr3+ initial concentration, the initial HPAM polymer concentration, or the degree of initial HPAM hydrolysis. Along with the gelation types and the accompanying morphological study, determine the relationships between the initial Cr3+ concentration and the true Cr3+ concentration entrapped on the polymers are possible, which are pretty distinct from each other. Neglecting to consider such diffusion effects will lead to overestimating of the crosslinking results. In addition, a sorption model is used to demonstrate the sorption trend changes before and after the gelation time.",6,7,1
Oil Recovery,Polymer,"Lamas, Luis Fernando; Botechia, Vinicius Eduardo; Correia, Manuel Gomes; Schiozer, Denis Jose; Delshad, Mojdeh",Influence of polymer properties on selection of production strategy for a heavy oil field,Polymer flooding; Production strategy selection; Reservoir numerical simulation; Reservoir engineering; Chemical enhanced oil recovery; Reservoir management,,"Polymer flooding is an enhanced oil recovery method (EOR) where water-soluble polymer is added to the injection brine. This increases brine viscosity and reduces water mobility, aiming to increase volumetric sweep and thus oil recovery. Selection and development of a production strategy for oil field is a complex task. Polymer properties bring additional complexity to this process and it is important that each of them is properly treated and considered. This paper discusses the selection of production strategy considering different approaches: (1) water flooding, (2) ideal polymer (only viscosifying effect of polymer) and (3) polymer flooding, including separately four of the most influencing polymer properties i.e. retention, viscoelasticity, salinity and degradation. The analysis is extended to a probabilistic point of view, where scenarios were generated combining geological and polymer uncertainties. Selected production strategies are compared to quantify the impact of each property on field indicators. Comparisons were made in terms of net present value (NPV), produced oil, injected and produced water, oil recovery factor and polymer mass. Two different situations were considered: (1) to optimize considering each property since beginning (design thorn control variables, meaning development, and management stages) and (2) considering design variables (development stage) for ideal polymer, optimizing only control variables (management stage) for each property. The methodology is applied to a synthetic field, based on characteristics of an offshore field with high permeability (similar to 1 000 mD) and containing heavy and viscous oil (similar to 100 cP, 14 degrees API). Ranking the properties according to overall impact on the project NPV, it was found the impact of each variable in a descending order: degradation, salinity, viscoelasticity, and retention. Water and ideal polymer strategies limit indicators results, giving an idea of the performance of strategies. Considering the key polymer properties from the beginning of optimization process resulted in similar values in terms of NPV when compared with strategies that considered ideal polymer in the selection of project variables. Risk curves show that conclusions can be extended to a probabilistic point of view. The results allow a comprehensive understanding of the influence of each polymer property on selection of production strategy considering uncertainties. The results also show that it is possible to select a good strategy using Ideal polymer model. Finally, results show that strategies selected for water and for ideal polymer model act as lower and upper limits of performance for the field, giving valuable information to the decision maker, even before accurate data about polymer is available.",6,6,2
Oil Recovery,Polymer,"Liu, Jin-Feng; Feng, Jun-Ying; Hu, Hao; Li, Cai-Yun; Yang, Shi-Zhong; Gu, Ji-Dong; Mu, Bo-Zhong",Decrease in viscosity of partially hydrolyzed polyacrylamide solution caused by the interaction between sulfide ion and amide group,Amide group; Interaction; Mechanism; Polyacrylamide; Sulfide ion,SULFATE-REDUCING BACTERIA; HYDROGEN-SULFIDE; MOLECULAR-WEIGHT; OIL; SYSTEM; DEGRADATION; CORROSION; SALINITY; POLYMERS; RHEOLOGY,"Viscosity of polymer solution is one of the key factors which, in some case, notably influence its application effect. However, it has been found that the viscosity drops significantly with sulfide ion. To better understand this phenomenon, the rheological behavior, dynamic light scattering (DLS), and 1H NMR analysis were conducted. The results show that sulfide ion significantly reduced the viscosity of HPAM solution and this reduction was further enhanced under low pH and high O-2 content and, more specifically, could not be recovered by dialysis. The polymeric network structure of HPAM formed in water was apparently destroyed and the hydrodynamic radius was reduced by sulfide ion. Furthermore, 1H NMR spectra indicated that the chemical environment of some protons in the methyne group connected to amide group in HPAM was modified by sulfide ion. The interaction between sulfide ion and the amide groups in side chain intra-/inter-molecule of HPAM reduces the hydrodynamic radius and destroys the three dimensional network structure and consequently decreases the viscosity of HPAM solution. These results are helpful for investigating the mechanisms of HPAM-sulfide interaction and optimizing the usage of HPAM for enhanced oil recovery in oil reservoirs with sulfide ions produced by sulfate reducing bacteria.",6,6,4
Oil Recovery,Polymer,"Wu, Fei-peng; Liu, Jing; Wei, Xue-mei; Pu, Chun-sheng",A study on oxygen consumption mechanism of air-foam flooding in low-temperature oil reservoir,Low temperature and permeability oil reservoir; Air injection; Oxygen consumption mechanism; Oxygen consumption rate; Field test,AQUEOUS-SOLUTION; POLYMER GELS; OXIDATION; POLYACRYLAMIDE; INJECTION; DEGRADATION; SOLUBILITY; KINETICS; STABILITY; GAS,"Air flooding/air-foam flooding recovery technology has been attracting attention in oilfield development. The key point to the application of this technology is to ensure that the oxygen injected with the air can be fully dissipated inside the reservoir to lower the explosion risk in production wells and reduce the oxidation of the pipeline. It is generally believed that the oxygen and crude oil can react more in low-temperature-oxidation (LTO) reactions above 80 degrees C. As a large amount of oxygen would be spontaneously consumed at this temperature, this technology is mainly used in reservoirs where the temperature is greater than 80 degrees C. In the fractured low-permeability reservoir of China's Yanchang oilfield, where the reservoir temperature is only approximately 30 degrees C, a wide range of crude oil LTO would not be triggered theoretically. However, we found that the oxygen content of the associated gas in the gas channeling wells is significantly lower than that in the air. This phenomenon suggests that, there are other factors that could consume oxygen apart from the LTO reaction. To verify this assumption, an oxygen dissipation core flooding experiment at 30 degrees C and 80 degrees C was carried out to evaluate the oxygen consumption at different temperatures. At the same time, in order to determine the main controlling factors and dissipation mechanisms of oxygen dissipation, theoretical analyses and experimental studies were carried out from the aspects of reductive mineral oxidation reaction in the rock surface and formation water, the physical absorption of the micropore and the dissolution of the reservoir fluid. The results show that at the same experimental conditions, the oxygen consumption at 30 degrees C is 38.14% lower than that at 80 degrees C. The oxygen consumption factors in the low-temperature reservoir mainly include the chemical reactions between the oxygen and reducing minerals, dissolution and retention of formation water and oil, adsorption of Van der Waals forces in the reservoir and physical electronic adsorption of the hydrogen-sulfur bonds and carbon-sulfur bonds. In Chang 6 Reservoir of Ganguyi oilfield, formation water could theoretically consume 56 mg/L (1.75 mmol/L) oxygen through dissolved Fe2+. The dissolution by formation water could absorb 11.85 mmol/L oxygen (experimental value). The dissolution by oil could absorb 69.25 mmol/L oxygen (experimental test value), and the oxygen physical adsorption rate of rock pore surface was 1.26 mmol/L. Together with the pilot test data, the results show that the LTO reaction of the stratum crude oil barely occurs in the reservoir at low temperature (30 degrees C). However, a large amount of oxygen dissipation could still be achieved. This study demonstrates that air-foam flooding could break the applicable limit temperature and could also be applied in low-temperature reservoirs.",7,7,1
Oil Recovery,Polymer,"Song, Zhaojie; Bai, Baojun; Zhang, Hao",Preformed particle gel propagation and dehydration through semi-transparent fractures and their effect on water flow,Enhanced oil recovery; Preformed particle gel; Open fracture; Dehydration behavior; Conformance improvement,CONFORMANCE-CONTROL; HYDROLYZED POLYACRYLAMIDE; PERFORMANCE; TRANSPORT; INJECTION; MODELS,"Polymer gels have been widely applied to plug high permeability streaks or fractures, and to improve sweep efficiency of chase waterfloods. This work constructed semi-transparent fracture models to investigate gel propagation and dehydration behaviors using preformed particle gel (PPG) in open fractures. Roubidoux sandstone slabs were used in the models because they could better model the roughness of fractures and PPG dehydration in a real fracture system, which was rarely reported in earlier studies. Injection rate, fracture width, particle size, brine and gel concentration were taken into account to understand their effects on particle gel extrusion. Experimental results showed PPG propagated like a piston along a fracture when the fracture width was smaller than or similar to the particle size; and gravity will dominate the PPG movement when the fracture width was larger than the particle size. PPG dehydration decreased with the increasing gel injection rate, fracture width, and brine concentration used to prepare PPG. Higher PPG injection rates and lower injection rates for chase waterfloods are recommended to improve the sweep efficiency in the matrix. This study could provide an insight into the particular PPG gel treatment for conformance improvement.",7,7,1
Oil Recovery,Polymer,"Sandengen, K.; Meldahl, M. M.; Gjersvold, B.; Molesworth, P.; Gaillard, N.; Braun, O.; Antignard, S.",Long term stability of ATBS type polymers for enhanced oil recovery,,C-13 NMR-SPECTROSCOPY; ELEVATED-TEMPERATURE; AQUEOUS-SOLUTION; HYDROLYSIS; POLYACRYLAMIDE; COPOLYMERS; OXYGEN; IRON,"In offshore enhanced oil recovery (EOR) applications polymer residence time within the reservoir could be many years. Long term stability (preservation of solution viscosity) within the anaerobic reservoir is a fundamental property of the polymer chemical and consequently highly important for choosing a proper product. For high temperature and/or high salinity reservoirs co-polymers of acrylamide (AM) and acrylamide tertiary butyl sulfonic acid (ATBS) have become common in the industry. The present work aimed at developing generic stability diagrams for such polymers dissolved in seawater (SW). Herein a two-step approach was attempted where stability versus ATBS content was measured at elevated temperature. Thereafter these data were extrapolated to lower temperature. To arrive at a sound extrapolation knowledge of hydrolysis kinetics for the two species, AM and ATBS, was needed. Aqueous solutions of AM-ATBS and AA-ATBS co-polymers were therefore stored at elevated temperature (82-140 degrees C) and progressive changes in microstructure followed by use of C-13 NMR spectroscopy. A steady increase in polymer stability with ATBS content was observed up to around 70 mol%. From 70 to 80 mol% the robustness sharply improved. A striking observation was that stability loss, defined as < 80% remaining viscosity, occurred before significant amounts of ATBS had reacted even at the highest ATBS contents. Acrylamide (AM) hydrolysis was found to be inhibited by the presence of ATBS. This reduced AM conversion rate was believed to be the main reason for increased stability. For the brines tested herein hydrolysis rate was virtually uninfluenced by hardness/salinity, while viscosity was largely impacted. Hence it was concluded that different viscosity loss in various brines stems from carboxylate complexation equilibria and not altered hydrolysis rates. Temperature extrapolation was found to fit a simple Arrhenius approach and it has been suggested that the function should be sound up to around 70 mol% ATBS. With this methodology, the current dataset enabled the construction of a stability diagram for ATBS polymers (0-70 mol% ATBS) dissolved in seawater.",8,8,1
Oil Recovery,Imbibition,"Gajo, Alessandro; Cecinato, Francesco; Loret, Benjamin",A computational framework for immiscible three-phase flow in deformable porous media,Immiscible fluids; Capillary pressures; Relative permeabilities; Gas injection; Imbibition; Finite element; Time marching scheme,SEMIDISCRETE FORMULATIONS; MULTIPHASE FLOW; MODEL; PERFORMANCE; TRANSPORT; FLUIDS,"Several soil decontamination processes and enhanced oil recovery techniques involve the co-existence of three immiscible fluids, such as water, a nonaqueous phase liquid and a gas. In this work, a computational framework based on the individual mass balance of each phase is developed, aimed at simulating three-phase flow in a deformable rock through the finite element method, without resorting to specific simplifications that are usually required by standard numerical schemes. Key ingredients of the model are: expression of the residual in terms of mass contents, consistent lumping of the storage terms in the residual and algorithmic (tangent) matrix, consistent integration rules, the use of a minimum relative permeability and a time marching scheme based on trapezoidal integration. Special convective boundary conditions are adopted for pressures to be consistent with the assumed rock wettability properties during co-current imbibition. The resulting numerical scheme can deal with arbitrary saturation and/or pressure boundary conditions. The model is tested by simulating gas injection tests, and both co- and counter-current water imbibition tests, in a deformable core. To assess the performance and robustness of the whole framework, sensitivity analyses are performed upon varying key constitutive, loading and numerical parameters.",2,2,0
Oil Recovery,Imbibition,"Karimi, Somayeh; Saidian, Milad; Kazemi, Hossein",Experimental study of the effect of aging on fluid distribution in Middle Bakken cores,Wettability; Chemical osmosis; Capillary pressure; Centrifuge; Nuclear magnetic resonance; Pore size distribution,WETTABILITY LITERATURE SURVEY; NUCLEAR-MAGNETIC-RESONANCE; CHEMICAL OSMOSIS; INDEX DETERMINATION; CAPILLARY-PRESSURE; RECOVERY,"Formation wettability is a critical parameter when designing enhanced oil recovery (EOR) for field applications both in conventional and unconventional reservoirs. In this study, we only focused on one unconventional resource-the Bakken. Specifically, we conducted laboratory experiments in five uncleaned Middle Bakken cores with different initial fluid saturations to determine (1) where the fluids reside within the pores, and (2) the effect of aging on wettability change. The experimental protocol included hydrocarbon-saturation of three uncleaned cores with Bakken oil. The cores were aged at 180 degrees F and 2500 psi pressure for four weeks, and stored in crude oil for 1 year at ambient laboratory conditions (about 12 psi and 66 degrees F). Synthetic brine was then used to produce oil from the aged cores by spontaneous imbibition in Amott cell. Additional oil was produced from the cores using a high-speed centrifuge. For the remaining two uncleaned cores, synthetic brine was used to saturate them, and brine was replaced with oil using a centrifuge. The cores were stored in crude oil at ambient laboratory conditions for four months; then, oil recovery from the cores was measured in Amott cell. NMR measurements were conducted on the cores after each fluid saturation/de-saturation experiment to determine the effect of aging time and temperature on the core wettability and fluid distribution in the pores. Also, porosity and permeability of cleaned twin cores were measured at several net confining stresses. The experimental results indicated that hydrocarbon-saturated cores become slightly more oil-wet than brinesaturated cores. NMR measurements indicated that brine resides in smaller pores and as a brine film on grains regardless of aging time, and the core fluids re-distributed with time indicating a strong rock-fluid interaction. Finally, the analysis of oil production indicated the preponderance of chemical osmosis over imbibition as the mechanism of oil displacement in formations with high brine salinity.",4,4,0
Oil Recovery,Imbibition,"Bui, Binh T.; Tutuncu, Azra N.",Interfacial tension induced-transport in shale: A pore-scale study,,NETWORK MODELS; POROUS-MEDIA; WETTABILITY; THROAT,"While unconventional reservoirs have quickly become a main contributor to oil and gas production, the transport mechanism in shale is not well understood. Although water does not imbibe into oil-wetted rock matrix, it has been observed in laboratory measurements that it can. The amount of water imbibed into the rock matrix increases when the salinity of the injected water decreases. Wettability alteration is often considered as the main reason for this phenomenon. One of the physical mechanisms for the imbibition of low salinity water into an oil-wetted rock matrix is the variation of the interfacial tension and the contact angle. The change of salinity initiates the change of interfacial tension driving the movement of the interface imbibing water into oil-wetted pores. The imbibition of the water into the rock matrix is a complicated process requiring a comprehensive understanding of the mass transport at pore scale. Hence, pore scale modeling was used in this research study for understanding the physics of transport at pore scale caused by interfacial tension variation or interfacial tension-induced transport. First, a simplified pore-scale model is presented to simulate the imbibition of water into an oil-wetted pore. Next, a numerical solution and procedure are outlined to simulate the transient mass transport in the pore as the result of interfacial tension variation due to salinity. The results indicate that the interfacial tension-induced transport is a very important mechanism for water imbibition into oil-wetted pores. How fast the water imbibes into the pore depends on the salinity gradient and the type of solute used. When salinity at the inlet of the pore is low, more solute diffuses out of the pore resulting in higher cumulative recovery from the pore. Reducing the interfacial tension between oil and water forces oil out of the pores and improve the oil recovery. Hence, low salinity water is recommended for low salinity water injection enhanced oil recovery.",4,4,2
Oil Recovery,Imbibition,"Olatunji, Kayode; Zhang, Jin; Wang, Dongmei",Effect of the rock dimension on surfactant imbibition rate in the Middle Member of Bakken: Creating a model for frac design,Oil recovery; Cores; Length; Surface areas; Imbibition; Model; Frac design,SHALE; WETTABILITY,"As an unconventional energy resource, the Bakken Formation has long been considered an important source rock for oil in the Williston Basin. The naturally fractured Bakken Formation consists of thin shale and silty carbonate sequences, capable of producing oil at economic rates when completed using hydraulically fractured horizontal wells. However, because of its low permeability and oil-wet characters, the primary recovery values are still low. As part of our effort to assess the potential for imbibition to recover oil from tight rocks, we performed spontaneous imbibition experiments using brine and surfactant for different dimensions of cores from the Middle Member of the Bakken Formation in North Dakota. The effect of length of the core on imbibition rate in the cores was measured for brine and surfactants. The purpose of this study is to create a model which can be basis for development of design of hydraulic fracturing of the formation. These cores from Bakken were silt stone, limestone, and shale interlayers in lithology. To the point of scaling the dimension of the core from laboratory to a field application, the large area of fluid contact will promote higher imbibition rate and faster oil recovery from the rock. Although oil recovery was low during brine imbibition into the oil-wet cores, alkali/surfactant solution recovered approximately 30-45% of the oil based on the laboratory results. We found higher oil recovery factor was achieved from surfactant imbibition more than just used brine. As would be expected, a given level oil recovery was reached faster in shorter cores than in longer cores in same diameters. The shorter core has a larger ratio of surface area to volume. A model which describes the relationship between Peak Oil recovery and surface areas for cores was derived.",5,5,1
Oil Recovery,Imbibition,"Bui, Binh T.; Tutuncu, Azra N.",Modeling the swelling of shale matrix in unconventional reservoirs,Shale swelling; Coupled modeling; Unconventional reservoirs; Dual-porosity model; Water injection; Mass transport,,"The imbibition of the injection water into shale matrix may result in shale swelling affecting oil recovery from the rock matrix and the transport properties of the fractures. The expansion of rock due to the swelling of shale matrix compresses the pore space in the rock matrix and the surrounding fractures. This reduces fracture and matrix porosity and permeability. The reduction of matrix pore space can reduce the rate of oil recovered from the rock matrix. On the other hand, it also forces the oil out of the matrix pore space increasing oil recovery. However, this effect has not been evaluated and integrated in reservoir modeling. This study presents a coupled fluid flow and geomechanics model for modeling shale swelling to quantitatively investigate the effect of swelling on transport properties of rock matrix and fractures. The main objective is to quantitatively determine the effect of shale swelling on the oil recovery from the rock matrix. A numerical solution is presented to solve the coupled equations simultaneously for the phase pressure, fluid saturation, stress, and strain. We show that the mechanical properties of the rock matrix vary significantly as the result of water imbibition. The reduction of the fracture and matrix permeability and porosity due to swelling is considerable. This results in the reduction of more than 50% of the oil recovered from shale matrix. Hence, shale swelling should be prevented in any water injection operations.",6,6,1
Oil Recovery,Imbibition,"Wang, Fei; Pan, Ziqing; Zhang, Yichi; Zhang, Shicheng",Simulation of coupled hydro-mechanical-chemical phenomena in hydraulically fractured gas shale during fracturing-fluid flowback,Fracturing-fluid flowback; Shale gas reservoirs; Hydro-mechanical-chemical model; Fracture closure; Chemical osmosis,PART I; IMBIBITION; PRESSURE; BEHAVIOR; BRINE; WELLS; COAL; OIL,"Fracturing-fluid flowback in hydraulically fractured gas shale is a complicated transport behavior involving hydrodynamic (H), mechanical (M) and chemical (C) processes. Although, many flowback models have been published, none of the models flly coupled the transient fluid flow modeling with chemical-potential equilibrium and fracture closure phenomena. In this paper, a coupled hydro-mechanical-chemical (HMC) model based on hydrodynamics, linear-elastic fracture mechanics, and chemical-potential equations is presented to simulate the fracturing-fluid flowback behavior in hydraulically fractured gas shale. The HMC model takes into account a gas-liquid two-phase flow and a triple-porosity medium, which includes primary hydraulic fractures, secondary induced fractures and shale matrix. The flowback simulation with the HMC model accounts for all the important processes in fractured shale system, including (1) water transport driven by hydraulic, capillary and osmotic convections, (2) gas transport induced by both hydraulic pressure driven convection and adsorption, and (3) fracture closure considered as an elastic deformation. The fluid transport, coupled with rock deformation, are described by a set of partial differential equations. The semi-implicit finite-difference method is used to solve these equations. The evolution of pressure, saturation, salinity and aperture profiles of hydraulic fractures, induced fractures and matrix is calculated, revealing the multi-field coupled flowback behavior in fractured gas shale. The sensitivity analysis is also performed to investigate the physiochemical properties of shale on the water load recovery and gas production rate during the fracturing-fluid flowback. The results indicate that the capillarity has the most effect followed by chemical osmosis and induced fracture closure. The sub-irreducible water saturation has the weakest effect. Moreover, the matrix-related physiochemical parameters cause opposite influences on water load recovery and gas production rate. While, the influence of induced fracture-related parameters on both water load recovery and gas production rate is consistent. Results from this study are expected to explain which is the predominant mechanism for fracturing-fluid retention and the inherent relationship between fracturing-fluid flowback and gas production for different initial physiochemical properties of shale.",6,6,12
Oil Recovery,Imbibition,"Kathel, P.; Mohanty, K. K.",Dynamic surfactant-aided imbibition in fractured oil-wet carbonates,Wettability alteration; Imbibition; Gravity drainage; Fractured reservoirs; Carbonate rocks,WETTABILITY ALTERATION; GRAVITY DRAINAGE; RECOVERY; RESERVOIRS; WATER; TEMPERATURE,"Numerous studies based on static imbibition experiments at lab scale have established surfactant-aided imbibition as an improved oil recovery process for fractured oil-wet carbonate reservoirs. However, predicting performance at larger scales and at dynamic conditions (fluid flow through fracture) remains a challenge. In this study, experiments are performed on Estaillades Limestone and Texas Cream Limestone outcrop cores with varying height and diameter with permeability in the range of 8 mD to 150 mD to address this challenge. It is observed that dynamic imbibition process recovers oil faster than static imbibition. Imbibition experiments performed on cores with varying height and diameter show that oil recovery decreases with increasing diameter and height. A 3D fine grid mechanistic simulator was used to perform lab scale validation and analyze recovery mechanism. Numerically simulated velocity and saturation profiles demonstrated the recovery mechanism to be gravity dominated flow. A new scaling function is proposed for surfactant aided gravity dominated processes. Data with same boundary conditions, rock, fluids and varying dimensions can be correlated with the scaling function at early times with no fitting parameters involved. A good correlation is obtained with the data indicating the effectiveness of the scaling function. The scaling is applicable to both static as well as dynamic imbibition.",8,8,3
Oil Recovery,Mass Transfer,"Marotto, Tamires A.; Pires, Adolfo P.",Mathematical model for one-dimensional oil displacement by steam injection with solvent addition,Enhanced oil recovery; Thermal methods; Steam flooding; Solvent and steam co-injection,FRICTION THEORY; HOT FLUID,"Recently, co-injection of steam and solvent has shown to be an attractive technique to increase oil recovery, combining the advantages of viscosity reduction due to the heat transfer achieved from steam injection with the benefits of mass transfer obtained from miscible flooding. In this work, the problem of one-dimensional displacement of oil by steam injection combined with solvent is analyzed. The mathematical model is based on the mass conservation of components oil and solvent, and conservation of system energy. The solution, composed by shock and rarefaction waves and constant states, is obtained using the method of characteristics. Different solution structures were found for particular sets of reservoir-fluid system parameters, which are defined by the ratio between the value of Henry's constant and the system pressure. The results presented here may be used for fast and efficient evaluation of technical aspects of the best Enhanced Oil Recovery method for a particular field, specially for thin shallow viscous heavy oil reservoirs. This model is also useful for the development of streamlines simulators, where gravity and capillary effects are neglected.",3,3,1
Oil Recovery,Mass Transfer,"Jia, Hu; Deng, Li-hui",Non-equilibrium 3-D simulator applied to air injection EOR in light oil reservoirs,,POROUS-MEDIA; NUMERICAL-SIMULATION; CAPILLARY-PRESSURE; RECOVERY; COMBUSTION; PERFORMANCE; PROJECTS; FLOW; PERMEABILITY; MECHANISM,"In this paper, a 3-D simulator based on the assumption of both chemical and thermal non-equilibrium is presented for a more realistic view of non-equilibrium process for simulating air injection EOR (enhanced oil recovery). The mathematical model is based on a non-equilibrium stage with dynamic mass transfer process between different fluid phases and energy transfer process between fluid and matrix (solid). The light crude oil oxidation and air injection process are both simulated by this simulator, through which the pore blocking, gas breakthrough and gas override process are presented through the visualization of oil, gas saturation distributions. The crude oil oxidation is refined as in-phase and interphase reactions to investigate the effect of reactant dispersion caused by the gas-liquid mass transfer. The oxygen dissolution and the evaporation of light components in crude oil are considered in the non-equilibrium process. The results without mass transfer, with dynamic mass transfer and with instantaneous mass transfer between gas and liquid phases are compared through multiplying the gas-liquid interface area 0, 1 and 100 times respectively, and the influence of these different mass transfer conditions on the migration of temperature peak front and oil recovery is revealed. In addition, the effect of local chemical and thermal non-equilibrium in different matrix permeability as well as porosity scenarios is also investigated to obtain non-equilibrium behavior in different reservoir conditions when implementing air injection EOR. In the last section, we investigated the result with different simulation timescale to see if the non-equilibrium behavior can be captured in the simulator used in this paper. This study suggests that the non-equilibrium behavior would show obvious influence on oil recovery for air injection in the lower permeability reservoir. The non-equilibrium behavior is desirable to be considered for simulating air injection EOR in light oil reservoirs. The developed 3-D simulator is robust that can better reflect the mechanism of air injection EOR in light oil reservoirs. We hope this work encouraging more investigations for the simulation side of nonequilibrium phase behavior and energy transfer in the air injection process.",5,5,1
Oil Recovery,Mass Transfer,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Oil Recovery,Mass Transfer,"Abolhosseini, Pejman; Khosravi, Maryam; Rostami, Behzad; Masoudi, Mohammad",Influence of Thermal Marangoni convection on the recovery of bypassed oil during immiscible injection,Injection into fracture; Marangoni flow; Benard-Marangoni convection; Immiscible injection,INTERFACIAL-TENSION; MASS-TRANSFER; FLUID; FLOW; MATRIX,"Several phenomena could recover the bypassed oil in matrixes and low permeable areas, among them; Marangoni is the most unfamiliar one in fluid flow model. This mechanism triggers a convective flow from low interfacial tension point to a high interfacial tension point because of variation in solvent concentration, temperature or electrical charge. In this study, experimental and analytical tools have been utilized to investigate the effect of thermal Marangoni flux on the enhancement of oil recovery during immiscible injection in a matrix-fracture system. Results of non-isothermal experiments have been compared with isothermal (as the zero level of Marangoni) to study the presence of Marangoni flow and its direction respect to the fracture location. Results show that not only the Marangoni flux does exist and has significant impact on the recovery of bypassed oil but also, its magnitude is proportional to the absolute value of temperature gradient in phases interface.",8,8,2
Oil Recovery,Mass Transfer,"Foroozesh, Jalal; Jamiolahmady, Mahmoud",The physics of CO2 transfer during carbonated water injection into oil reservoirs: From non-equilibrium core-scale physics to field-scale implication,Carbonated water injection (CWI); Mass transfer; Equilibrium CO2 storage; Core-scale; Reservoir-scale,NONAQUEOUS PHASE LIQUID; SATURATED SUBSURFACE SYSTEMS; MASS-TRANSFER RATES; POROUS-MEDIA; RECOVERY; STORAGE; GAS; DISSOLUTION; DISPLACEMENT; COEFFICIENTS,"CO2 can be dissolved into water to make carbonated water (CW). CW can be injected into oil reservoirs for enhanced oil recovery (EOR) and CO2 sequestration purposes. Carbonated water injection (CWI) technique is a cost-effective CO2 based injection strategy that needs less amount of CO2 as compared to other CO2-EOR techniques. We previously showed that for simulation of CWI coreflood experiments, the kinetics of CO2 transfer between the phases should be considered and we accordingly developed a non-equilibrium based two-phase compositional simulator. We also used the developed simulator to simulate some CWI coreflood experiments. This paper aims to explore the role of mass transfer during simulation of CWI process at field (large)-scale by analysing the data of core-scale simulations. To do so, the results of CWI core-scale simulations obtained from our non-equilibrium based simulator are benchmarked against the results from an equilibrium based simulator and a dimensionless number so-called equilibrium number (Ne) is introduced. It is shown that in a specific range of Ne values, the contact time of the oil and water phases inside the system is large enough that the CO2 can be distributed between the phases based on its equilibrium concentration. Contrary to core-scale simulation, it is concluded that mass transfer kinetics during large-scale simulation of CWI process is not important. Moreover, higher oil recovery factor and CO2 storage are predicted at large-scale (reservoir-scale) as compared to the core-scale's results. The findings of this paper can help to better understand the importance of mass transfer kinetics between the phases in porous media.",8,8,2
Oil Recovery,History Match,"Dachanuwattana, Silpakorn; Yu, Wei; Zuloaga-Molero, Pavel; Sepehrnoori, Kamy",Application of assisted-history-matching workflow using proxy-based MCMC on a shale oil field case,Assisted history matching; Markov chain Monte Carlo; Proxy; K-nearest neighboring; Shale oil,,"History matching is a crucial step for reservoir simulation and for decision-making process in field development under uncertainty. The history-matching task is well known to be technically and computationally challenging. Several algorithms have been studied for more than a decade to assist history matching. One of the algorithms used is Markov chain Monte Carlo (MCMC), which is capable of providing accurate posterior probability density (PPD) of the history-matched realizations. While several researchers have applied and studied MCMC for assisted history matching (AHM) in many conventional reservoirs, only few studies have been performed on unconventional reservoirs. Since the difference in physics of the two reservoir types are important, it is worthwhile investigating the performance of AHM in unconventional reservoirs. For this purpose, we apply an AHM workflow using proxy-based MCMC on a shale oil well in Vaca Muerta formation to demonstrate application of the workflow and highlight the lessons learnt. The direct MCMC is also performed on the same field case to compare accuracy and efficiency of the first method. In this study, design of experiment (DOE) is used for selecting the most influential uncertain parameters before performing either of the two MCMC methods. It is found that the direct MCMC cannot find enough solutions to construct the statistically meaningful PPD in an efficient manner. By contrast, the proxy-based MCMC is less computationally demanding than the direct MCMC and efficient enough to construct the PPD. The tested workflow was then used to probabilistically forecast the cumulative oil and water production as well as the oil recovery factor for the Vaca Muerta well.",1,1,1
Oil Recovery,History Match,"Ansah, Eric O.; Sugai, Yuichi; Nguele, Ronald; Sasaki, Kyuro",Integrated microbial enhanced oil recovery (MEOR) simulation: Main influencing parameters and uncertainty assessment,Artificial intelligence; Capillary number; Enthalpy; Microbial enhanced oil recovery; Monte Carlo simulation; Response surface methodology,HEAVY OIL; TEMPERATURE; RESERVOIR; GROWTH; MECHANISMS; BACTERIA; FIELD,"The present study investigated the ability of a thermophilic anaerobic microbe (herein coded as AR80) for MEOR with the further objective to quantify the uncertainty of production forecast in terms of the cumulative probability distribution. A series of core flood experiments conducted in water-flooded Berea sandstone showed that up to 51% of initial oil-in-place was recovered when the plugs were treated with AR80 and shut-in for 14 days. Mainly, the oil recovery mechanisms were attributed to viscosity enhancement, wettability changes, permeability and flow effects. Matching the laboratory data using artificial intelligence: the optimized cumulative oil recovery could be achieved at an enthalpy of 894.2 J/gmol, Arrhenius frequency of 8.3, residual oil saturation of 20%, log of capillary number at microbe flooding stage of -1.26, and also depicted a history match error less than 3%. Therefrom, a sensitivity analysis conducted on reservoir shut-in period effect on oil recovery revealed that a relatively shorter shut-in period is recommended to warrant early incremental oil recovery effect for economical purposes. In addition, MEOR could enhance the oil recovery significantly if a larger capillary number (between 10(-5) and 10(-3.5)) is attained. Per probabilistic estimation, MEOR could sustain already water-flooded well for a set period of time. This study showed that there is a 20% frequency of increasing the oil recovery by above 20% when a mature water-flooded reservoir is further flooded with AR80 for 2 additional years. Lastly, it was demonstrated herein that increasing the nutrient (yeast extract) concentration (from 0.1 to 1% weight) had less or no significant effect on the oil viscosity and subsequent recovery.",4,4,0
Oil Recovery,History Match,"Alpak, Faruk O.; Vink, Jeroen C.",Rapid and accurate simulation of the In-situ Conversion Process using upscaled dynamic models,In-situ Conversion Process (ICP); Oil shale; Flow-based transmissibility upscaling; Unconventional oil; Reservoir simulation; Thermal recovery,OIL-SHALE; FLOW,"Numerical modeling of the In-situ Conversion Process (ICP) is a challenging endeavor involving non-isothermal multiphase flow, compositional PVT behavior, and chemical reactions that convert solid kerogen into light hydrocarbons and are tightly coupled to the temperature propagation. The objective of the reported work is to significantly accelerate the ICP simulations using fast upscaled dynamic models that deliver good prediction accuracy. We take advantage of the fluid-and heat-flow based local transmissibility upscaling techniques. A fully automatic scale-up workflow is scripted for pattern-scale ICP models, which generates upscaled models that are, in turn, simulated using a proprietary simulator. We demonstrate the consistency, accuracy, and efficiency of the upscaling workflow using a realistic pattern-scale ICP model. A simple yet effective upscaling workflow is developed for the fast and accurate simulation of ICP using a novel integrated upscaling and flow simulation platform. Overall, the upscaling workflow is simple, generic, and delivers computational speed-up while retaining a reasonable level of fine-scale model accuracy. Upscaled models lead to more robust simulations of ICP from the numerical perspective as evidenced by main numerical performance indicators. The upscaling script is implemented as part of an easily customizable ICP simulation deck. It is used for simulation-intensive ICP performance forecasting workflows (e.g., optimization, uncertainty quantification, and history matching) targeting oil-shale resources worldwide.",6,6,2
Oil Recovery,History Match,"Min, Baehyun; Sun, Alexander Y.; Wheeler, Mary F.; Jeong, Hoonyoung",Utilization of multiobjective optimization for pulse testing dataset from a CO2-EOR/sequestration field,Geological carbon storage; Leakage; Pulse testing; History matching; Multi-objective optimization,NONDOMINATED SORTING APPROACH; LEAKAGE DETECTION; SENSITIVITY-ANALYSIS; CO2 SEQUESTRATION; GENETIC ALGORITHM; RESERVOIR; FLOW; MODEL; PERFORMANCE; PRESSURE,"In a geological carbon storage project, leakage should be monitored to ensure safe long-term storage of injected CO2. Leakage can be detected early and cost-effectively by monitoring subsurface pressure. The uncertainty in geological models also needs to be sufficiently reduced to detect leakage based on pressure monitoring data. This study presents numerical results of field pulse testing experiments that are designed to detect leakage based on pressure monitoring data for periodical CO2 injection at a CO2 enhanced oil recovery field in Mississippi, USA. In the pulse test, sinusoidal pressure patterns are captured in transitional pressure data because CO2 injection and shut-in are repeated. The patterns are parameterized and history-matched efficiently in the frequency domain. Sensitivity analyses of pulse test parameters such as injection period and rate show that the frequency domain is more advantageous than the time domain for estimating leakage probability and well connectivity. We also conduct multi-objective history matching of pulse testing parameters in the frequency domain for reducing the uncertainty in geological models. This history matching reveals a clearer trade-off relationship between the matching qualities than conventional global-objective history matching, thereby being advantageous to yielding converged and diversified geological models for uncertainty quantification.",8,8,0
Oil Recovery,Hydraulic Fracture,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun; Almansour, Abdullah",Numerical simulation study to understand the performance of RPM gels in water-shutoff treatments,,DISPROPORTIONATE PERMEABILITY REDUCTION; WELLS,"Disproportionate Permeability Reduction (DPR) is often used as a water-shutoff treatment in production wells when conventional solutions such as mechanical isolations are difficult to perform. Although this property has been well documented by different investigators, the performance of DPR treatments in field applications has varied between success and failure without understandable reasons. This work investigated the DPR performance in different scenarios to see when, where and at which conditions DPR treatments can give better results. Numerical simulation methods were used to simulate different scenarios happening in oil and gas fields such as five-spot pattern system and linear-system, with different number of layers, with and without crossflow. The possibility of using DPR treatment in hydraulically-fractured reservoirs was also investigated since many reports indicated that there is an increase in the water production for some oil and gas reservoirs after being hydraulically-fractured. Moreover, the physical reasoning behind the variations in the DPR performance for different scenarios has been extensively discussed. The results explored that the DPR performance was excellent in both of water-cut reduction and oil-recovery improvement when the flow regime was viscous dominated (viscous-gravity number < 0.1). On the other hand, when the flow regime was gravity dominated (viscous-gravity number > 10), the effective period of DPR treatment was a short-term remedy. Secondly, when the high-K layer is existed at the lower-zone of oil or gas reservoir, the reservoir would be a good candidate for the DPR treatment as compared with the reservoirs that have the high-K layer located at the upper zone. Furthermore, selecting the correct time to perform DPR treatments generally could have a significant role to mitigate water production. Finally, the dimensions of the treated fracture are the key components to get a successful DPR-treatment in the hydraulically fractured reservoirs.",5,5,0
Oil Recovery,Hydraulic Fracture,"Olatunji, Kayode; Zhang, Jin; Wang, Dongmei",Effect of the rock dimension on surfactant imbibition rate in the Middle Member of Bakken: Creating a model for frac design,Oil recovery; Cores; Length; Surface areas; Imbibition; Model; Frac design,SHALE; WETTABILITY,"As an unconventional energy resource, the Bakken Formation has long been considered an important source rock for oil in the Williston Basin. The naturally fractured Bakken Formation consists of thin shale and silty carbonate sequences, capable of producing oil at economic rates when completed using hydraulically fractured horizontal wells. However, because of its low permeability and oil-wet characters, the primary recovery values are still low. As part of our effort to assess the potential for imbibition to recover oil from tight rocks, we performed spontaneous imbibition experiments using brine and surfactant for different dimensions of cores from the Middle Member of the Bakken Formation in North Dakota. The effect of length of the core on imbibition rate in the cores was measured for brine and surfactants. The purpose of this study is to create a model which can be basis for development of design of hydraulic fracturing of the formation. These cores from Bakken were silt stone, limestone, and shale interlayers in lithology. To the point of scaling the dimension of the core from laboratory to a field application, the large area of fluid contact will promote higher imbibition rate and faster oil recovery from the rock. Although oil recovery was low during brine imbibition into the oil-wet cores, alkali/surfactant solution recovered approximately 30-45% of the oil based on the laboratory results. We found higher oil recovery factor was achieved from surfactant imbibition more than just used brine. As would be expected, a given level oil recovery was reached faster in shorter cores than in longer cores in same diameters. The shorter core has a larger ratio of surface area to volume. A model which describes the relationship between Peak Oil recovery and surface areas for cores was derived.",5,5,1
Oil Recovery,Hydraulic Fracture,"Wang, Fei; Pan, Ziqing; Zhang, Yichi; Zhang, Shicheng",Simulation of coupled hydro-mechanical-chemical phenomena in hydraulically fractured gas shale during fracturing-fluid flowback,Fracturing-fluid flowback; Shale gas reservoirs; Hydro-mechanical-chemical model; Fracture closure; Chemical osmosis,PART I; IMBIBITION; PRESSURE; BEHAVIOR; BRINE; WELLS; COAL; OIL,"Fracturing-fluid flowback in hydraulically fractured gas shale is a complicated transport behavior involving hydrodynamic (H), mechanical (M) and chemical (C) processes. Although, many flowback models have been published, none of the models flly coupled the transient fluid flow modeling with chemical-potential equilibrium and fracture closure phenomena. In this paper, a coupled hydro-mechanical-chemical (HMC) model based on hydrodynamics, linear-elastic fracture mechanics, and chemical-potential equations is presented to simulate the fracturing-fluid flowback behavior in hydraulically fractured gas shale. The HMC model takes into account a gas-liquid two-phase flow and a triple-porosity medium, which includes primary hydraulic fractures, secondary induced fractures and shale matrix. The flowback simulation with the HMC model accounts for all the important processes in fractured shale system, including (1) water transport driven by hydraulic, capillary and osmotic convections, (2) gas transport induced by both hydraulic pressure driven convection and adsorption, and (3) fracture closure considered as an elastic deformation. The fluid transport, coupled with rock deformation, are described by a set of partial differential equations. The semi-implicit finite-difference method is used to solve these equations. The evolution of pressure, saturation, salinity and aperture profiles of hydraulic fractures, induced fractures and matrix is calculated, revealing the multi-field coupled flowback behavior in fractured gas shale. The sensitivity analysis is also performed to investigate the physiochemical properties of shale on the water load recovery and gas production rate during the fracturing-fluid flowback. The results indicate that the capillarity has the most effect followed by chemical osmosis and induced fracture closure. The sub-irreducible water saturation has the weakest effect. Moreover, the matrix-related physiochemical parameters cause opposite influences on water load recovery and gas production rate. While, the influence of induced fracture-related parameters on both water load recovery and gas production rate is consistent. Results from this study are expected to explain which is the predominant mechanism for fracturing-fluid retention and the inherent relationship between fracturing-fluid flowback and gas production for different initial physiochemical properties of shale.",6,6,12
Oil Recovery,In-situ Combustion,"Zhao, Renbao; Li, Bochun; Yang, Xiaoying; Yang, Jie; Yu, Shuai; Jin, Jun; Zhang, Jianhua",Analysis of a feasible field THAI pattern by the derivation of scaling criteria and combustion experiments,In-situ combustion; Toe-to-heel air injection process; Scaling criteria; Three dimensional cylindrical model,HEAVY OIL; SIMULATION,"Toe-to-heel air injection (THAI) process is considered as a potential enhanced oil recovery (EOR) method for heavy oil production. For physical simulation of THAI process in laboratory conditions, the simplified scaling criteria of THAI process were derived and a novel three-dimensional cylindrical apparatus was used to construct the new THAI pattern in this study. Equation analysis and dimensional analysis (Buckingham at-theorem) were applied to deduce the whole dimensionless groups, and sensitivity of the coefficients described with their distortion coefficients were used to obtain the influential weights and the simplified scaling criteria. STARS module in Computer Modeling Group (CMG) was used to verify the feasibility of the THAI pattern by two models, which represent the reservoir prototype and the 3D apparatus respectively. With an effective simulation of experimental results, a reasonable data set was obtained, and then those values were upscaled for simulation of field THAI process by the simplified scaling criteria. The experiment results showed that the horizontal well was well protected by a slant distribution of coke zone and the other parameters about oil production (such as the high temperature swept volume, oil production rate and recovery) were still satisfactory. The similarity of variation process of temperature field, oil saturation distribution and production performance between the laboratory results and THAI simulation in reservoir prototype showed the validity of the scaling criteria and indicated that a feasible field THAI process with a large combustion chamber upon horizontal well can be predicted to achieve.",0,0,3
Oil Recovery,In-situ Combustion,"Yoo, Kuy Hun Koh; Sampaio, Luiz Bittencourt; Gerritsen, Margot; Kovscek, Anthony R.",An optimization algorithm for evaluation of kinetic parameters for crude oil combustion,In situ combustion; Ramped temperature oxidation; Oxidation kinetics,IN-SITU-COMBUSTION; FIELD-SCALE; PREDICTABILITY,"The design of enhanced oil recovery processes that employ in-situ combustion requires high-fidelity simulation models that accurately describe the physics and chemistry of reactive, exothermic multiphase fluid flow. Therefore, a detailed description of oil combustion kinetics is required. The goal of this work is to present and apply a workflow to define and match pseudo-kinetic reaction models based on Arrhenius kinetics. These models are meant to be used at the laboratory scale with high-resolution, fully-resolved simulation models as a tool to generate high density data required by upscaled models at reservoir scale. The workflow starts by performing ramped temperature oxidation (RTO) experiments for a wide range of heating rates. New experimental equipment has allowed us to obtain data for large heating rates (>15 degrees C/min) that were not achievable in the past. A subset of the experiments are selected to match the oxygen consumption curves by tuning kinetic parameters of several global reaction models using pattern search optimization. Those models that obtain a match are validated by predicting a second subset of the data that was not considered during the optimization. The workflow is tested using a heavy oil and two satisfactory matches with two different global reaction models are obtained.",4,4,0
Oil Recovery,In-situ Combustion,"Yang, Shangyu; Han, Lihong; Feng, Chun; Wang, Hang; Feng, Yaorong; Wu, Xingru",Mechanical performance of casing in in-situ combustion thermal recovery,Casing performance; Heavy oil; In-situ combustion; Casing design; Steam flooding,OIL; WELLS,"In-situ combustion is often used to develop heavy oil as it has multiple advantages over alternative thermal methods. However, the wellbore integrity can be compromised if the casing is not properly designed or manufactured. Based on the fundamentals of heat transfer, a mathematical model with multiphysics is built to study the temperature and pressure distributions surrounding the wellbore during in-situ combustion. In laboratory, real casings and coupons with grades of N80, P110, and 3Cr110 were tested under high temperature to study their mechanical performances in the in-situ combustion recovery. From the modeling and laboratory testing results, we propose the casing design and manufacture protocols for thermal recovery of heavy oil. Field applications in Liaohe oil field, Du-66 Block, shows that the mechanical deterioration of P110 and 3Cr110 is less than that of N80 and the mechanical performance stability of 3Cr110 is better than others when the temperature is less than 600 degrees C. When the temperature is above 600 degrees C for more than 10 h, the mechanical performance of all casing grades declines quickly. Applying finite element analysis, we recommend a safety factor of 1.1 for designing casing at the temperatures of 250 degrees C,480 degrees C and 485 degrees C. The finding of this study provides fundamentals for the casing design and material selection for in-situ combustion recovery.",6,6,0
Oil Recovery,Source Rocks,"Olatunji, Kayode; Zhang, Jin; Wang, Dongmei",Effect of the rock dimension on surfactant imbibition rate in the Middle Member of Bakken: Creating a model for frac design,Oil recovery; Cores; Length; Surface areas; Imbibition; Model; Frac design,SHALE; WETTABILITY,"As an unconventional energy resource, the Bakken Formation has long been considered an important source rock for oil in the Williston Basin. The naturally fractured Bakken Formation consists of thin shale and silty carbonate sequences, capable of producing oil at economic rates when completed using hydraulically fractured horizontal wells. However, because of its low permeability and oil-wet characters, the primary recovery values are still low. As part of our effort to assess the potential for imbibition to recover oil from tight rocks, we performed spontaneous imbibition experiments using brine and surfactant for different dimensions of cores from the Middle Member of the Bakken Formation in North Dakota. The effect of length of the core on imbibition rate in the cores was measured for brine and surfactants. The purpose of this study is to create a model which can be basis for development of design of hydraulic fracturing of the formation. These cores from Bakken were silt stone, limestone, and shale interlayers in lithology. To the point of scaling the dimension of the core from laboratory to a field application, the large area of fluid contact will promote higher imbibition rate and faster oil recovery from the rock. Although oil recovery was low during brine imbibition into the oil-wet cores, alkali/surfactant solution recovered approximately 30-45% of the oil based on the laboratory results. We found higher oil recovery factor was achieved from surfactant imbibition more than just used brine. As would be expected, a given level oil recovery was reached faster in shorter cores than in longer cores in same diameters. The shorter core has a larger ratio of surface area to volume. A model which describes the relationship between Peak Oil recovery and surface areas for cores was derived.",5,5,1
Oil Recovery,Source Rocks,"Li, Qianwen; Pang, Xiongqi; Li, Boyuan; Zhao, Zhengfu; Shao, Xinhe; Zhang, Xian; Wang, Yingxun; Li, Wei","Discrimination of effective source rocks and evaluation of the hydrocarbon resource potential in Marsel, Kazakhstan",Effective source rocks discrimination; Petroleum resources evaluation; Marsel; Kazakhstan,PART; OIL,"Three rounds of exploration in Marsel, Kazakhstan show that the area has good petroleum geological conditions; however, the exploration degree is low and the resource potential is unclear. The total organic carbon (TOC) content is the criteria for effective source rocks and is also the key parameter to calculate the amount of resources; while previous evaluations of the effective source rocks and calculated amounts of resources were based on residual TOC, which gradually decreases with mass hydrocarbon expulsion; therefore, this will inevitably produce errors. For greater accuracy, the TOC recovery coefficient formula was used to recover the residual TOC in Marsel; then, the criteria of the effective source rocks were revised to calculate the Carboniferous and Devonian resources in Marsel. The results are as follows: for the source rocks in Marsel, the TOC recovery coefficient of the Carboniferous source rocks is approximately 1.6, while that for the Devonian is approximately 2.0; the revised lower limit of TOC for the effective source rocks is 0.3% and 0.25% for the Carboniferous and Devonian, respectively; after TOC recovery, the total amount of hydrocarbon expulsion is 26.7 x 10(12) m(3), the total amount of recoverable resources is 2.62-5.10 x 10(12) m(3), and the mean is 3.79 x 10(12) m(3) for the main source rocks. The effective source rocks evaluated based on the recovered TOC and the latter resources could reflect the quantity of source rocks and actual resource potential of Marsel more accurately. This has certain significance for the exploration of areas that have low levels of exploration with an unclear understanding of the resource potential as well as a high degree of thermal evolution and a low quantity of residual TOC.",7,8,2
Oil Recovery,Incremental Oil Recovery,"Ansah, Eric O.; Sugai, Yuichi; Nguele, Ronald; Sasaki, Kyuro",Integrated microbial enhanced oil recovery (MEOR) simulation: Main influencing parameters and uncertainty assessment,Artificial intelligence; Capillary number; Enthalpy; Microbial enhanced oil recovery; Monte Carlo simulation; Response surface methodology,HEAVY OIL; TEMPERATURE; RESERVOIR; GROWTH; MECHANISMS; BACTERIA; FIELD,"The present study investigated the ability of a thermophilic anaerobic microbe (herein coded as AR80) for MEOR with the further objective to quantify the uncertainty of production forecast in terms of the cumulative probability distribution. A series of core flood experiments conducted in water-flooded Berea sandstone showed that up to 51% of initial oil-in-place was recovered when the plugs were treated with AR80 and shut-in for 14 days. Mainly, the oil recovery mechanisms were attributed to viscosity enhancement, wettability changes, permeability and flow effects. Matching the laboratory data using artificial intelligence: the optimized cumulative oil recovery could be achieved at an enthalpy of 894.2 J/gmol, Arrhenius frequency of 8.3, residual oil saturation of 20%, log of capillary number at microbe flooding stage of -1.26, and also depicted a history match error less than 3%. Therefrom, a sensitivity analysis conducted on reservoir shut-in period effect on oil recovery revealed that a relatively shorter shut-in period is recommended to warrant early incremental oil recovery effect for economical purposes. In addition, MEOR could enhance the oil recovery significantly if a larger capillary number (between 10(-5) and 10(-3.5)) is attained. Per probabilistic estimation, MEOR could sustain already water-flooded well for a set period of time. This study showed that there is a 20% frequency of increasing the oil recovery by above 20% when a mature water-flooded reservoir is further flooded with AR80 for 2 additional years. Lastly, it was demonstrated herein that increasing the nutrient (yeast extract) concentration (from 0.1 to 1% weight) had less or no significant effect on the oil viscosity and subsequent recovery.",4,4,0
Oil Recovery,Incremental Oil Recovery,"Olabode, O. A.; Orodu, O. D.; Isehunwa, S. O.; Mamudu, A.; Rotimi, Tosin",Effect of foam and WAG (water alternating gas) injection on performance of thin oil rim reservoirs,Incremental oil recovery; Design of experiment; Placket burman; Water injection; Gas injection; Up dip injection; Down dip injection; Response surface model,,"A design of experiment was used to create oil rim models from a wider range of reservoir, operational and reservoir architecture parameters. A response surface model was generated based on a concurrent oil and gas production and a Pareto analysis was conducted to ascertain the significance of the parameters. The models were classified based on the Pareto analysis and due to the low oil recoveries arising from the complexity of oil rims, a series of secondary injection schemes were instigated. The results from the models indicated an optimum 2 cycle WAG up dip injection and WAG down dip injection for thin oil rims. Also the results estimated an incremental oil recovery of 9.2% and 30.1% with respect to base case (no injection) for WAG up dip injection and 10.66% and 6.11% for WAG down dip injection while an incremental recovery of 14.2% and 52.74% for up dip foam injection and 18.19% and 29.73% incremental oil recovery for foam down dip injection for oil rim model '3' with large gas cap and large aquifer and model '7' with small gas cap small aquifer respectively. A case study reservoir from the Niger delta region of Nigeria showed an 8.57% and 8.56% incremental oil recovery for foam up dip and foam down dip injection and incremental oil recovery of 8.35% and 7.94% for WAG up dip and WAG down dip injection. This paper will provide useful information as to the extent of oil recovery in different oil rim models under different foam and WAG injection.",8,8,1
Drilling,Oil,"Sun, Youhong; Shi, Yuanling; Wang, Qingyan; Yao, Zongwei",Study on speed characteristics of hydraulic top drive under fluctuating load,Hydraulic top drive; Main transmission system; Fluctuating load; Speed characteristic; Electro-hydraulic proportional control,STICK-SLIP; SYSTEM; PUMP; SIMULATION; DYNAMICS,"A hydraulic top drive is a high-power gyrator used in oil or scientific drilling rigs, whose shaft is connected to drill pipe when it drives drilling tools to excavate well. The output speed of top drive determines the speed of drill bit directly. Load acting on the top drive shaft fluctuates randomly, which will cause top drive output speed hard to be in consistent with the setting value. This paper presents a main transmission system of a hydraulic top drive designed for deep continental scientific drilling, which was built with a multi-stage mechanical structure and a closed circuit hydraulic system with variable displacement pumps and motors. Electro-hydraulic proportional control was applied to vary the speed of the hydraulic top drive. A theoretical model is detailed for the hydraulic top drive main transmission system. Among the new techniques proposed in this paper is a simulation model for studying the performance of hydraulic top drive and capturing speed characteristics under fluctuant load. A drilling experiment of the hydraulic top drive was performed on the CRUST-I drilling rig in CCSD-SK-II well site. This paper concludes by comparing the results of the simulation model with theoretical results and drilling experimental data gathered in the hydraulic top drive possessing the same architecture, components, and control methods used within the simulation model. The drilling experiment and the analysis result showed that the hydraulic top drive could meet the requirements of deep continental scientific drilling and that the speed could be output according to the setting speed with very small oscillation. The simulation model can be used for several applications such as hydraulic top drive design and performance analysis of various drilling conditions.",1,1,2
Drilling,Oil,"Abramov, A. V.; Bikbulatov, R. V.; Kolesnik, I. Yu.; Vinokurov, A. N.; Mukhametshin, V. Kh.",Boosting economic efficiency of pads drilling projects. A comprehensive study of wells groupings and localization of the global maximum,Pad drilling; Multi-well pad; Wells grouping; Wellheads grouping; Batch drilling; Well clusters,,"The work demonstrates an approach to improve economic performance of well pads drilling projects by selecting an appropriate grouping of wells (wellheads). Scope of the work covers all thinkable groupings of a 24-well pad. We systematically enumerate groupings and estimate economic parameters of every grouping. Results of these calculations are represented in the form of NPV (Net Present Value) surfaces and NPV distributions which naturally locate global maxima for different starting flow rates. It is shown that traditionally used in oil industry groupings of wells do not provide the best economic efficiency of pads drilling projects. The top economic results could only be achieved by taking into account all available information on performance of wells. On basis of the study it is suggested to reconsider design of prospective well pads applying presented approach to boost economy of drilling. The problem of finding optimal wells grouping could be defined in two ways: specific and general. The specific formulation implies equal (constant) number of wells in every group, whereas the general formulation admits having different number of wells in the groups. It is clear that computational complexity of the specific formulation is much smaller than that of the general. The total number of groupings in the specific case is bounded from above by the product of number of wells in every group and number of these groups, i.e. for a well pad of 24 wells the total number of possible groupings is less than 576. If the total number of wells in a pad is N then the number of groupings in the general case is 2<^>(N-1), i.e. for a pad of 24 wells this gives 8,388,608 possible groupings. Having all these grouping options considered it is easy to show that the largest increase in NPV of a pad could be achieved with unequal (varying) number of wells in groups. Further analysis shows that NPV maximizing well pad configurations depend on characteristics of wells, especially the starting flow rate. Economic performance of the optimal groupings is compared with that of the pad consisting of six groups each including four wells. NPV increase of the optimal groupings is exceeding 1% and in carefully chosen parameters of the economic model reaches few millions to tens of millions of Russian rubles. It is demonstrated that reasons for these gains are, in decreasing order of importance: (i) increased oil production accompanied with elevated CAPEX (Capital Expenditures); and (ii) decreased CAPEX accompanied with reduced oil production.",3,4,0
Drilling,Oil,"Ekpo, B. O.; Essien, N.; Neji, P. A.; Etsenake, R. O.",Geochemical fingerprinting of western offshore Niger Delta oils,Oil fingerprinting; Organic geochemistry; Niger Delta; Nigeria,CRUDE OILS; PETROLEUM GEOCHEMISTRY; GAS-CHROMATOGRAPHY; SOURCE ROCKS; PART II; BASIN; FIELD; BIODEGRADATION; DISTRIBUTIONS; ASPHALTENES,"This study reports the findings based on analyses of saturated (normal alkanes and aliphatic isoprenoid) hydrocarbons and biomarkers in twenty four (24) crude oil samples from western offshore Niger Delta of Nigeria using gas chromatography (GC), gas chromatography-mass spectrometry (GC-MS) and carbon isotopy. The major objectives were to apply reservoir geochemistry and oil fingerprinting to characterize the oils in order to determine their origin and to identify the existence of reservoir continuity and/or compartmentalization. Results from this study using the distributions of normal alkanes, tricyclic and tetracyclic terpanes as well as source specific maturity and facies controlled biomarker ratios of the oils including pristane/phytane (Pr/Ph), Pr/n-C-17, Ph/n-C-l8, C-31:22S/(22S + 22R) homohopane, C-29:alpha alpha(20S/(20S + 20R)) steranes, moretane/C-30-Hopane and Ts/(Ts + Tm), showed that the entire crude oil samples from three reservoir units are the same, the differences are small. The oils originated from same source rocks which were deposited under oxidizing condition with mixed marine/terrigeneous organic source inputs and thermal maturity. This genetic classification is supported by stable carbon isotopic compositions (delta C-13) of the hydrocarbon fractions and multivariate statistical (Principal Component and Cluster) analyses. Geochemical, fingerprinting and multivariate statistical data provided corroborative evidence of a single compartment with vertical and lateral reservoir continuity across the fault complex within the studied fields. This information can be utilized by geologists and petroleum engineers in solving production related problems such as optimising hydrocarbon production via drilling horizontal wells to arrest the reservoir communication that occurs with existing vertical wells.",4,5,1
Drilling,Oil,"Mousavi, E.; Cheshomi, A.; Ashtari, M.",Estimating elasticity modulus and uniaxial compressive strength of sandstone using indentation test,UCS; Elasticity modulus; Indentation test; Critical transition force (CTF); Indentation modulus (IM),LOAD TEST; ROCK,"Elastic modulus (E) and uniaxial compressive strength (UCS) are very important engineering parameters that is required for many engineering projects. In some projects such as well drilling for oil production, deep underground tunnels in crushed zone, due to the depth of the well and fractures of rocks, there are some problems for obtained standard core samples. In this situations various methods have been developed for determining UCS and E using drilling cutting. Indentation test is one of these methods, in this method, an indenter penetrates into the stabilized samples in the surrounding material and then Critical Transition Force (CTF) and Indentation modulus (IM) determine. In the present study in order to developing the application of indentation testing for sandstone, and investigate the effect of particles size, shape and thickness, 14 sandstone blocks were collected from different formations in Iran and their physical characteristics, UCS and, E were measured using standard methods. After crushing the blocks and preparing 600 particles with dimensions of 3x3x3 mm(3), 5x5x3 mm(3), 5x5x5 mm(3), 5x5x8 mm(3), and 8x8x8 mm(3) and irregular shape particles with a thickness of 5 mm, indentation tests were performed on each particle and CTF and IM were calculated for each particle separately. According to the tests carried out some empirical relationships were proposed between UCS CTF (with R-2 >= 0.86) and E - IM (with R-2 >= 0.73) for different shapes and dimensions. Due to the differences in the dimensions of the produced particles, investigating the effect of surface and thickness of particle on the CTF and the IM revealed that the particle's surface had a considerable effect on the CTF and IM; however, the effect of thickness was negligible. Using the dimensionless surface parameter (S and Si), some empirical relationships between UCS - CTF/S (with R-2 >= 0.80) and E - IM/Si (with R-2 >= 0.77) were proposed for predicting UCS and E of sandstone particles with different shapes and dimensions. The accuracy of these relations was validated by performing standard uniaxial and indentation tests on 4 sandstone blocks and comparing measured UCS and E with those predicted using these relations. This comparison showed there is a good correlation between measured and predicted values. The proposed equations in this study were compared with results of previous studies. The relationship proposed in the present study to predict sandstone UCS has a similar accuracy with those proposed in by other researchers.",4,5,2
Drilling,Oil,"Lopes, Rui L.; Jorge, Alipio M.",Assessment of predictive learning methods for the completion of gaps in well log data,Well log data; Completion of gaps; Ensemble models; Regression,OIL-FIELD; POROSITY; PERMEABILITY; MACHINE; ALGERIA; PYTHON,"Well logs are records of petro-physical data acquired along a borehole, providing direct information about what is in the subsurface. The data collected by logging wells can have significant economic consequences in oil and gas exploration, not only because it has a direct impact on the following decisions, but also due to the subsequent costs inherent to drilling wells, and the potential return of oil deposits. These logs frequently present gaps of varied sizes in the sensor recordings, that happen for diverse reasons. These gaps result in less information used by the interpreter to build the stratigraphic models, and consequently larger uncertainty regarding what will be encountered when the next well is drilled. The main goal of this work is to compare Gradient Tree Boosting, Random Forests, Artificial Neural Networks, and three algorithms of Linear Regression on the prediction of the gaps in well log data. Given the logs from a specific well, we use the intervals with complete information as the training data to learn a regression model of one of the sensors for that well. The algorithms are compared with each other using a few individual example wells with complete information, on which we build artificial gaps to cross validate the results. We show that the ensemble algorithms tend to perform significantly better, and that the results hold when addressing the different examples individually. Moreover, we performed a grid search over the ensembles parameters space, but did not find a statistically significant difference in any situation.",4,4,2
Drilling,Oil,"Choi, Myoungsung; Scherer, George W.; Prudhomme, Robert K.",Novel methodology to evaluate displacement efficiency of drilling mud using fluorescence in primary cementing,Primary cementing; Displacement; Fluorescence; Metallurgy; Surface roughness,CONTACT ANGLES; SURFACES; WETTABILITY; ROUGHNESS; ADHESION; ENERGY,"For primary cementing of a well, successful displacement of drilling mud from the casing and annulus, and properly conditioning those surfaces to bond with the cement slurry, are paramount to achieve zonal isolation. In this study, to evaluate displacement of drilling mud from well casings, a fluorescence methodology incorporating a hydrophobic dye was developed. Fluorescence is attractive because the dye is highly oil soluble and non-polar and can be detected at very low concentrations, so chemical interference between dye and drilling mud is minimized. From the fluorescence measurements, the thickness of residual drilling mud can be quantitatively determined, which makes it possible to quantify the efficiency of drilling mud removal. Residual oil layers under consideration in this study from 32 mu m to 1.5 mu m are observed. The spacer fluids D and E are excellent in their ability to remove the drilling mud, whereas spacer F performs poorly. The effects of metallurgy and surface roughness on wettability were investigated using the measured thickness of residual drilling mud. There is little effect of the composition of the steel tube on wettability, but the surface roughness or presence of corrosion can significantly affect the wettability.",5,5,0
Drilling,Oil,"Wang, Changjin; Li, Zifeng; Li, Yinpeng; Qi, Min; Wang, Lei",Experimental study on the rotation of compression-buckling rod column in a liquid-filled cylinder,Drill string; Rotation; Buckling; Axial load; Backward whirl,,"In oil drilling, the main form of movement of the bottom hole assembly is self-rotation and whirling after buckling. The rotation of a compression-buckling rotation drill string can increase the frictional force between the drill string and borehole wall, induce lateral vibration and whirl of the drill string, generate borehole wall instability and drill string damage, and even cause a drilling failure. At present, studies on the motion laws of a pressure-rotating buckling drill string are incomplete, and some are even incorrect, necessitating further improvements. In this work, the effects of axial load, rotational speed, drilling fluid, and inner diameter on the rotational motion of a compression-buckling column in a cylinder were experimentally studied. The dissipation energy before and after the transition state of the simulated drill string, from the forward whirl to self-rotation, or from the forward whirl to the backward whirl, were analysed. The results indicate the following: (1) With an increase in the axial load, a buckling drill string first experiences forward whirl. Next, both forward whirl and self-rotation occur, along with a combination of backward whirl and self-rotation along the partial vertical wall. Finally, backward whirl occurs along the wall. (2) A dynamic lubrication of the drilling fluid can reduce the forward whirl rotation amplitude of the drill string and prevent the formation of backward whirl. (3) When dynamic lubrication by the drilling fluid is improved, the borehole diameter is reduced, the hole-deviation angle increases, the critical axial load of the backward whirl increases. (4) Backward whirl may occur twice for the drill string as the axial load increases. (5) The state transition of the drill string motion conforms to the minimum dissipation power principle. The experimental results described herein can serve as a reference for studies regarding drill string dynamics and drilling practice.",5,6,1
Drilling,Oil,"Wang, Peng; Ni, Hongjian; Wang, Xueying; Wang, Ruihe; Lu, Shuangfang",Research on the characteristics of earthworm-like vibration drilling,Earthworm-like drilling; Friction reduction; Load transfer; Position optimization,TANGENTIAL VIBRATIONS; SLIDING MOTION; REDUCTION; FRICTION; FORCE,"The load transfer difficulty caused by borehole wall friction limits the rate of penetration (ROP) and extended-reach limit of complex structural well enormously. A new friction reduction technology called ""earthworm-like drilling"", which can improve the load transfer and extended-reach limit, is proposed in this paper. A mathematical model based on ""soft-string"" model is developed to analysis the characteristics of this technology. Simulation results indicate that more stick-slip and load transfer issue are caused by higher friction. The earthworm-like drilling is more effective in reducing friction than single-point vibration drilling and less effective than multipoint vibration drilling because of the pulse pressure attenuation. However, this disadvantage can be offset by adding the number of axial oscillators. Amplitude and frequency of pulse pressure and the installation position of axial oscillators have great impact on the friction reduction and load transfer. An optimizing model based on projection gradient method is developed and used to optimize the position of three axial oscillators in a three-dimensional horizontal well. The weight on bit (WOB) increases significantly after the optimized position and the new position of axial oscillators move towards bottom of well and close to each other. Results verify the feasibility and advantages of earthworm-like drilling, and lay a solid theoretical foundation for its application in oil field drilling.",5,5,2
Drilling,Oil,"Liang, Bo; Lan, Hui-qing; Lin, Nan",Diffusion simulation and safety assessment of oil leaked in the ground,Oil; Leak Multi-phase flow in porous media; Diffusion; Test; Safety assessment,ASSESSING NAPL CONTAMINATION; MULTIPHASE FLOW MODEL; POROUS-MEDIA; GRAVITY CURRENTS; RISK-ASSESSMENT; FRACTURED MEDIA; PERSPECTIVE; SITE,"Oil leaked in the ground causes pollution of land and groundwater, and even leads to an explosion. Therefore, it is significant to make a research on safety assessment of diffusion of oil in the ground after oil leakage accident happened. Taken a perforation-caused leakage accident of oil in buried piping in China as an example, the computational fluid dynamics method of multiphase flow in porous media was used to determine the distribution of leaked oil in the ground in this paper. Then, an onsite drilling test was carried put and it's found that the simulation of distribution of leaked oil agreed with the test result. Finally, on the base of the simulation results, fuzzy synthetic evaluation method was carried out and hazardous areas of oil leaked in the ground were put forward.",5,6,2
Drilling,Oil,"Zhu, Dongya; Meng, Qingqiang; Liu, Quanyou; Zhou, Bing; Jin, Zhijun; Hu, Wenxuan",Natural enhancement and mobility of oil reservoirs by supercritical CO2 and implication for vertical multi-trap CO2 geological storage,Supercritical CO2; Reservoir enhancement; Dawsonite; Geological storage; Huangqiao reservoir,RARE-EARTH-ELEMENT; CARBON-DIOXIDE; FLUID INCLUSIONS; SALINE AQUIFERS; BASIN; SEQUESTRATION; ACCUMULATION; GAS; RECOVERY; MODEL,"The accumulation and production of both deep mantle-derived CO2 and light oil were discovered in the Huangqiao reservoir, which is located in the Subei Basin, East China. The Huangqiao reservoir shows that both CO2 and oil are entrapped in and produced from vertical multi-traps. The effects of deep CO2 on the accumulation and production of oil under natural conditions and the implications for CO2 geological storage are investigated in detail. The fluid inclusions in quartz or calcite veins from the Silurian Fentou Formation (S(2-3)f), Permian Longtan Formation (P(2)l) and Triassic Qinglong Formation (T(1)q) have homogenization temperatures (Ths) that display peak ranges of 180 degrees C-190 degrees C, 170 degrees C-180 degrees C and 150 degrees C-160 degrees C, respectively. The Ths are higher than the formation temperatures. The calcite veins have light carbon and oxygen isotope compositions and have high Sr-87/Sr-86 ratios and positive Eu anomalies. These characteristics reveal the activities of deep CO2-rich hydrothermal fluids in the basin strata. The feldspar in the S(2-3)f and P(2)l sandstone reservoirs underwent significant dissolution because of the presence of CO2-rich fluids, forming of a large amount of secondary pores in the sandstone reservoirs and enhancing the reservoirs' physical properties. The measured porosity reaches 12.3%. CO2 in a supercritical state extracted or dissolved light petroleum components out of sedimentary rocks and then carried them towards reservoirs. Thus, CO2 and oil co-accumulated in the enhanced reservoirs, e.g. S(2-3)f, P(2)l and T(1)q. During drilling development, this supercritical CO2 naturally increased the mobility of oil, resulting in the co-production of highly pure CO2 and light oil. Based on the unique features of the Huangqiao CO2-oil reservoir, we propose a new CO2 geological storage model, namely, a vertical multi-trap geological storage model, which can either entrap large volumes of CO2 or lower the risk of long-term storage.",5,7,4
Drilling,Oil,"Shan, Liqun; Guo, Boyun; Weng, Dingwei; Liu, Zhe; Chu, Henry",Posteriori assessment of fracture propagation in refractured vertical oil wells by pressure transient analysis,Refracturing; Oil; Wells; Fractures; Propagation; Assessment,,"Oil companies have realized that refracturing old wells is the more budget-friendly way to achieve cash flow than drilling and completing new wells in the down turn of the energy industry. But it has been seen that the refracturing technology does not always work equally well in all reservoir conditions. It is desirable to have a quantitative method for assessment of well refracturing design and operations. An analytical transient flow model was derived in this study to estimate the orthogonality between the old and new hydraulic fractures after refracturing. Pressure transient data from seven wells refractured in an oilfield in the southwestern China was analyzed with the model. The model implies that orthogonal fractures created in well refracturing treatments induce orthogonal reservoir linear flow in the stimulated reservoir volume. This fracture configuration can be identified by the unit slope of pressure derivative in the log-log diagnosis plot. The angle between fractures initiated from wellbore can be estimated using pressure transient data analysis technique with a log-log diagnostic plot, with extreme situations that merged or parallel fractures will show a half slope and orthogonal fractures will show a unit slope. Case studies of data from 7 wells show that orthogonal fractures were created in 3 wells, merging or parallel fractures were created in 1 well, and fractures with non-right angles were created in 3 wells. The actual well productivity data for the 7 wells are basically consistent with the expected trend implied by the estimated fracture configurations with an exception of one well. The reason is not clear and needs further investigations. More production data from refractured wells are required to further validate the technique.",6,6,0
Drilling,Oil,"Freire Soares, Andreia Silveira; Costa Marques, Monica Regina; Calcada, Luis Americo; Borges Filho, Moacyr Nogueira; de Oliveira Petkowicz, Carmem Lucia",Interaction of blockers on drilling fluids rheology and its effects on sealing of fractures and prevention of filtrate invasion,Drilling fluids; Lost circulation and loss control material,XANTHAN GUM; PARTICLE-SIZE; FLOCCULATION; BENTONITE; WATER; MONTMORILLONITE; PERFORMANCE; POLYMERS; CHARGE,"Drilling fluids from oil wells play an important role in the drilling operations, including cleaning and maintaining well stability, as well as cooling and lubricating the drill bit. Invasion of fluid in the rock formation, through natural or induced fractures, can compromise the entire well. In this work we evaluated the effect of combination of viscosifiers xanthan gum (XG), carboxymethylcellulose (CMC), Hydroxypropylstarch (HPS) and bentonite in the interaction with lost circulation materials diatomaceous earth (DE) and hydrogel (HG). The main objective was to obtain a product with adequate rheological properties showing viscoelastic behavior and minimizing loss of fluid to the wellbore. Tests of X-ray diffraction (XRD) and zeta potential were performed to analyze the interactions between the particles present in the fluids. With rheological tests we studied the effects of the addition of different components on the fluid rheology. XRD technique showed that the bentonite deflocculated only in polymer suspensions with DE. The results of zeta potential suggest that only the fluid with Hydroxypropylstarch and HG was completely flocculated and unstable, showed through particle sizes distribution tests. The gel modulus (G') and viscous modulus (G '') of the fluids were affected by the interaction of bentonite layers with lost circulation materials particles, with significant increase of G' with the addition of HG to the suspension. There was a decrease of viscosity due to agglomeration of HG and DE particles, an increase of G' can be observed as well. Among all the fluids, the suspension of CMC and bentonite showed better affinity with the HG lost circulation material, presenting thermal stability and a wide range of particle size, essential property to avoid the loss of fluid through the fractures and pores of the rock formation.",6,6,2
Drilling,Oil,"Ettehadi, Ali; Altun, Gursat",Functional and practical analytical pressure surges model through herschel bulkley fluids,Herschel bulkley model; Surge and swab pressures; Sepiolite mud; Rheological constants; High temperature,SWAB; WELL,"Substantially large pressure surges are generated while drilling a well due to tripping operations in which a central drillstring is being moved up or down through non-Newtonian fluid. The presence of these subsurface surge pressures must be considered and determined in almost every well drilled. Wells exhibiting high geothermal temperature gradient further complicate the determination of wellbore pressures since the classical viscometer does not characterize the non-Newtonian nature of fluids accurately at elevated temperatures. More importantly, rheological model selection also plays a key role for effectively proposing safe tripping speeds without violating the mud window constraints. Herschel-Bulkley rheological model has gained more reputation among others due to better predictions of wellbore hydraulic pressures as suggested by the American Petroleum Institute. A new practical and dimensional analytical model was developed for Herschel Bulkley (HB) fluid to calculate pressure surges caused by drillstring movement for non-Newtonian fluids under the fully developed flow (steady state) conditions in the laminar flow range in a slot geometry. The proposed analytical method was applied on unweighted fresh water sepiolite mud as a non-Newtonian fluid since the sepiolite muds are among the few water based muds performing adequately at extreme temperatures as the synthetic and oil base muds. Already measured rheological constants of selected fluid system using both HTHP dynamic rheometer and classical viscometer were considered to obtain surge pressures at ambient to extreme temperature ranges. The results are compared with already developed Burkhardt method for Bingham Plastic fluid and Schuh method for Power Law fluid and other proposed numerical and analytical solutions. Substantial differences on the pressure surges between the conventional viscometer and the HTHP rheometer measurements were also presented. The precision of the developed model is shown to be acceptable for most practical applications. Being operationally easy and applicable with a convenient solution code make the proposed model straightforward to be used as a part of drilling software.",6,6,2
Drilling,Oil,"Paes de Godoi, Felipe Augusto; Scheid, Claudia Miriam; Bernardo, Leticia Siqueira; de Oliveira, Beatriz Rosas; Borges Filho, Moacyr Nogueira; Calcada, Luis Americo",Study of the pressure drop and the flow of loss circulation material suspensions in a physical simulator of fractures,Fractures sealing; Flow of suspensions; Calcium carbonate; Particulate system,,"The loss of fluid to the rock formation is one of the main problems encountered in oil well drilling operations. To mitigate this problem, particulate materials responsible for sealing fractures or for strengthening the well are used. The main objective of this work is to study the flow of Non-Newtonian suspensions through fractures, the pressure drop associated with this flow and the process of sealing fractures using particulate materials suspensions. The flow through fracture of Non-Newtonian suspensions was studied using an apparatus that allowed these fluids to flow through three different artificial fractures with widths of 2 mm, 5 mm and 10 mm and an average 1 cm depth. The suspensions were prepared by mixing water, viscosifying polymer and particulate materials based on laminar calcium carbonate. The particulate materials used are called fine and medium because they have different particle size distributions. The characterization of the solutions and suspensions was carried out from the rheological tests and the determination of the densities and the particle size distributions. The influence of factors such as flow rate, concentration and particle size distributions on the flow of the suspensions through fractures and its sealing capabilities were evaluated. The suspensions of the fine material particles were able to seal only the 2 mm fracture. The suspension composed of the particles of the medium material proved efficient in sealing the three fractures. A mathematical methodology was proposed with the objective of correlating the pressure drop and the flow rate of suspensions in fractures.",7,7,3
Drilling,Oil,"Vega, Marcia Peixoto; de Moraes Oliveira, Gabrielle Fontella; Fernandes, Lindoval Domiciano; Martins, Andre Leibsohn",Monitoring and control strategies to manage pressure fluctuations during oil well drilling,Kick; Circulation loss; Downhole pressure control; Decision making; Gain scheduling,LOST CIRCULATION; KICK DETECTION; MODEL; FLUID; DEEP; MUD; MITIGATION; PREDICTION; RESERVOIR; SYSTEM,"During drilling the mud flows through the drill string and exits through the choke valve. The mud density range has as constraints: pore pressure (minimum limit) and fracture pressure (maximum limit). In fact, annulus bottomhole (downhole) pressure needs to be higher than pore pressure, in order to prevent kick, and smaller than fracture pressure, for avoiding mud loss and formation damage. Experimental and simulation studies were implemented in order build a monitoring - diagnosing tool working together with a decision making routine based on an adaptive control scheme that employs gain scheduling. An experimental unit was built, presenting the most important characteristics of the drilling process. The transient nature of annulus bottomhole pressure is due to the process inherent disturbances: rheology, rate of penetration (ROP), kick and mud loss, which were all implemented at the experimental unit. The major objective of the present paper is using the experimental plant and a phenomenological model for implementing real time process automation, in order to assure drilling inside operational window, using in line measurements for flow and density disturbances under circulation loss and kick scenarios.",8,8,1
Drilling,Oil,"Eren, Tuna; Kok, Mustafa Versan",A new drilling performance benchmarking: ROP indexing methodology,Rate of penetration; Rigs; Performance monitoring; Middle east geomarket; ROP indexing; Benchmarking,,"The performance efficiency in drilling oil, gas wells is eventually measured by means of comparing the time versus depth curve. However this is now being questioned, is a well drilled relatively in a shorter time period the most efficient well? Large data are now being acquired while drilling, however not all of the data available is utilized appropriately to get the big picture of the well being drilled. This research study is aiming to introduce a performance comparison methodology based on Rate of Penetration (ROP). All other operational steps other than drilling activity is routine unless there are hole problems and not dependent on formation. Drilling ROP on the other hand is a parameter that can be used to benchmark the efficiency of the drilling performances. In this research study the data of 40 wells drilled in Middle East Geomarket is used. This document describes ROP Indexing Methodology for drilling performance, and gives examples of its application from actual data. The study showed that previously used drillability performance comparisons by the industry are not feasible for benchmarking. It is obvious that he drilling industry needs a new methodology to benchmark drilling performance of the wells using advanced computers and available data being acquired from the rigs.",9,9,0
Drilling,Oil,"Gautam, Sidharth; Guria, Chandan; Rajak, Dilip K.; Pathak, Akhilendra K.",Functionalization of fly ash for the substitution of bentonite in drilling fluid,Alpha-glycol and amine substituted fly ash; API-Grade drilling bentonite; Surface characterization; Rheology; Frictional and filtration behavior,,"Oil exploration activities have increased the demand for American Petroleum Institute (API-) grade drilling bentonite leading to a significant increase in the cost of naturally occurring bentonite and overall cost of the drilling operations. In this work, fly ash (FA) was functionalized to replace API- grade drilling bentonite for drilling of wells. Epichlorohydrin and aminopropyl triethoxysilane were used to functionalize the ultrafine-structured planetary ball-milled FA. The morphology, mineralogy, structure and specific surface area of the functionalized FA were determined by the field emission scanning electron microscopy, energy dispersive X-ray spectroscopy, X-ray diffractometry and Brunauer-Emmett-Teller analysis, respectively, to determine the efficacy of functionalized FA as a colloidal base in aqueous suspension. Fourier-transform infrared spectrometer and X-ray photoelectron spectroscopy analysis was used to confirm the grafting of alpha-glycol and amine functional group on FA surface and quantified by iodometric and acid-base titration method, respectively. The zeta potential and cation-exchange capacity of functionalized FA were found to be -47.1 to -68.1 mV in pH range 8-12 and similar to 68.0 meq/100 g of functionalized FA, respectively, and were found comparable to API- grade drilling bentonite. Rheological behavior and filtration loss properties of the functionalized FA in aqueous suspension were determined and compared with the API- grade drilling bentonite yielding similar results. The performance of the functionalized FA-based drilling mud system involving tamarind gum and polyanionic cellulose was evaluated by determining the thermal stability, cuttings transportation ability, friction and shelf-life properties under the downhole condition at 75 degrees C and 100 psig and the results were compared against the existing drilling mud system, yielding the comparable performance. Finally, the functionalized FA was found to be cost-effective over API- grade bentonite.",9,9,0
Drilling,Drilling Mud,"Sabah, Mohammad; Ameri, Mohammad Javad; Sedigh, Maryam",Natural bridging as a tertiary well control method in deep-water wells: A case study from Caspian Sea,Blowout; Self-killing; Natural bridging; Deep-water well; Caspian Sea,FAILURE CRITERIA; PREDICTION; PRESSURE; STRESS; WINDOW,"Blowout is the uncontrolled flow of reservoir fluids into the well, which can cause different types of problems during the drilling operations. In high-pressure formations with low rock strengths, it is more likely to occur self-killing through bridging mechanisms. The underbalanced conditions that are induced during developing a kick, leading into sufficient instability in exposed formations such that the borehole bridges over and kick kills itself. In this research, the potential of natural bridging is studied in one of the deep-water wells in the Caspian Sea to figure out whether this natural phenomenon is able to terminate the uncontrolled influxes of formation fluids into the borehole. For the reason, a series of semi-integrated numerical simulators are employed to evaluate wellbore pressure profile and wellbore instability as a function of time under blowout conditions. Applied analyses to a particular blowout scenario indicated that rock fragments falling off the wellbore wall are suspended in the two-phase flow (a mixture of gas and drilling mud) during developing the kick. As a result, cavings settlement is less not probable to plug the wellbore. On the other hand, suspension of rock fragments gradually increases the solid concentration of fluid phase until it hits a critical value at a certain time after the beginning of the kick, thereby bridging occurs before developing the kick into a blowout.",0,0,0
Drilling,Drilling Mud,"Chen, Yuanhang; Yu, Mengjiao; Takach, Nicholas",Modeling and analysis of coupled thermal-hydrologic-mechanical processes during lost circulation,Wellbore stability; Lost circulation; Numerical simulation; Heat transfer; Geomechanics; Coupled processes,WELLBORE STABILITY; SIMULATION; BOREHOLE; FLUIDS; FLOW,"Wellbore stability remains as one of the major challenges to drilling engineers. Results of recent survey showed about one third of non-productive time of drilling operation is classified as borehole problem, where a significant part is attributed to borehole instability. The thermal regime of a formation in the vicinity of a wellbore affects the stability of the well significantly during drilling operations, especially in High pressure High Temperature (HPHT) wells. This paper describes how the thermal behavior of a tubular-wellbore-reservoir system is altered during mud loss, as well as its consequent impact on near-wellbore state of stresses and critical mud weights. A fully coupled three dimensional thermal-poro-elastic model, integrated with a transient tubular-wellbore-reservoir heat flow model, is developed to evaluate near-wellbore stresses and pore pressure redistribution during mud loss. The forced convective heat transfer coefficients in both conduits-drillpipe and annulus-are rigorously determined as a function of local flow and fluid properties. The results reveal that continuous mud loss destabilizes the wellbore as the pressure window shifts considerably over time. Critical mud weights for both tensile and compressive failures decrease during mud loss over the entire length of the wellbore, in addition to the point of loss. During severe losses, the fracture gradient at the bottom of the well can decrease by over 1 ppg within the first hour. This can intensify the existing fracturing condition and allow the development of new fractures at other locations, which leads to further losses as time progresses. This model enables prediction of a more realistic operating window during lost circulation by taking additional thermally-induced effects into account. In addition, failure indexes during mud loss considering P-rho-T coupling effect on a compressible mud column in the annulus are investigated with the proposed model. During drilling operations, especially Managed Pressure Drilling (MPD) and offshore applications with moderate to severe mud loss, the operation window should be modified by taking mud loss-induced thermal stresses into account. The mud type, wellbore geometry, circulation rate, and other parameters affect the magnitude of shift in critical mud weight during mud loss, hence evaluations should be based on specific cases.",0,0,1
Drilling,Drilling Mud,"Pirir, Ivan; Jinasena, Asanthi; Sharma, Roshan",A dynamic model for drain back to active mud pit combined with a well model during drilling,Well drilling; Combined model; Open channel flow; Saint-Venant equations; Kurganov-Petrova scheme,SHALLOW-WATER EQUATIONS; CENTRAL-UPWIND SCHEME; SYSTEM,"There are no published mathematical models that combine the dynamics of the returned fluid flow to the active mud pit (top side drilling) and the dynamics of the bottom side of the well being drilled. In this paper a simple dynamic model that combines the top and the bottom side drilling operations is provided. The model has been simulated for various operational scenarios during drilling including pipe connection, movements of drill string and reservoir influx. This combined model can be used for studying not only the pressure dynamics but also to estimate the return fluid flow rate and hence to detect kicks and losses occurring in the well.",1,1,0
Drilling,Drilling Mud,"Dominato, Karlynne R.; Rostron, Benjamin J.; Hendry, M. Jim; Schmeling, Erin E.; Sandau, Courtney D.; Mundle, Scott O. C.","Developing deep high-resolution concentration and C-13 isotope profiles for methane, ethane, and propane",Methane; Isotopes; Drilling; Profile; Gas migration; Reservoir,DISSOLVED METHANE; SEDIMENTARY BASIN; WATER; SASKATCHEWAN; CARBON; PROJECT; STORAGE; GASES; SHALE; FIELD,"Methods to collect and analyze concentration-depth profiles of dissolved methane (C-1), ethane (C-2), and propane (C-3) and their delta C-13-values from directional drilling operations were evaluated. The delta C-13 values of C-1-C-3 gases from drill cuttings were consistent; however, deeper zones (> 1200m BG) were subject to greater variability. The variability for C-1-C-3 isotope values was attributed to the drilling process, where the samples reflected mixing between different geologic zones. Gases and rock fragments from several formations likely contaminated the samples collected from the underlying intervals. The effects of mixing were observed in deeper zones in the borehole below the 'kick off' point for the directional drilling process. The greatest impact was observed for C-1 and C-2 gases, which was attributed to greater concentrations of these gases in shallow gas-bearing zones. This study demonstrates that mud gas and drill cuttings can generate high-resolution concentration and isotope depth profiles for C-1, C-2, and C-3 gases. However, mixing between zones along the borehole during drilling, an effect that can be exacerbated by directional drilling techniques, can impact the precision and accuracy of the geochemical profiles. The variability in the geochemical data generated from drilling programs can have a significant impact on the effectiveness of these profiles for reservoir characterization, exploration, and in identifying the source(s) of fugitive gases migrating to surface.",1,1,1
Drilling,Drilling Mud,"Ghimire, Bishwas; Daigle, Hugh; Gray, Ken E.",Modeling formation resistivity changes due to invasion and deformation during initial leak-off test build-up,Leak-off test; Invasion; Formation resistivity,SIMULATION; PERMEABILITY; LOG,"Leak-off tests (LOTs) are performed to determine the strength of a newly drilled formation below a cased interval and to characterize the upper bound of mud weight that can be safely used while drilling the next section, without risk of formation breakdown and lost circulation. In an LOT, drilling mud is pumped into the wellbore, causing the wellbore pressure to increase and exceed the formation pore pressure. During the initial LOT build up, excess pressure in the wellbore causes the surrounding rock to deform and mud filtrate to invade into the formation via porous flow. In this paper, change in formation resistivity around a wellbore during initial LOT build-up has been investigated. Invasion is modeled assuming two-phase radial Darcy flow and deformation using a 3D finite element model. Invasion may result in an exchange of conductive ions between water-based drilling mud and formation water both by diffusion in the direction favored by the concentration gradient of the ions and by convective transport. This process is incorporated into the model by solving the radial convection-diffusion equation for the aqueous phase using a finite difference method. Archie's law is used to determine the formation resistivity. Findings show that the direct effect of deformation on porosity, therefore on formation resistivity during an LOT, is negligibly small even when the formation rock is highly compressible with compressibility in the order of 10(-3) psi(-1). While salinity solely controls formation resistivity during an LOT conducted in a fully water-saturated interval, water saturation change and salinity change compete to produce a compound effect on formation resistivity of an oil-bearing zone where water saturation varies dynamically due to displacement of formation fluids. Unlike compressibility, the effect of permeability on formation resistivity response is found to be evident and readily observable. While analyzing the formation resistivity responses at various depths of investigation (DOIs), it is found that the effect of DOI on resistivity response can be useful in studying invasion and assessing formation damage during an LOT. In addition to this, through comparing time-lapse resistivity logs at multiple DOIs during an LOT with numerically synthesized resistivity responses, the model promises a novel approach towards determining the permeability of a freshly drilled and unaltered interval.",2,2,1
Drilling,Drilling Mud,"Afolabi, Richard O.",A new model for predicting fluid loss in nanoparticle modified drilling mud,Nanotechnology; Drilling muds; Filtration; Predictive modeling,RHEOLOGICAL PROPERTIES,"Quantitative prediction of the properties for nano-modified drilling mud has evolved over time as a challenge towards its application. The known predictive models used in the description of drilling mud performance cannot quantitatively capture the impact of nanoparticles. In this work, existing theories on the kinetics of mud cake formation and colloidal particle behavior were applied in deriving a new fluid loss model. The new model described the fluid loss behavior of the mud with the capability of predicting a maximum for cumulative value. The new model was compared with the known API model using statistical measures, Root Mean Square Error (RMSE) and Coefficient of Determination (R-2). The new model compares favorably with the API model with RMSE and R-2 values 0.8549-0.4595 cm(3) and 98.9-99.9% respectively. The development of the model for nano-drilling fluids would allow for detailed modeling, design and cost-effective drilling operations as the quantitative amount of nanoparticles required would be captured.",4,4,0
Drilling,Drilling Mud,"Ashena, Rahman; Thonhauser, Gerhard; Vortisch, Walter; Rasouli, Vamegh; Azizmohammadi, Siroos",Optimization of core retrieval using a Thermo-Poro-Elastic (T-P-E) approach,,EMPIRICAL RELATIONS; STRENGTH,"One most common cause of damage of the recovered cores occurs during their fast decompression from the bottomhole to the surface. This occurs as sufficient time is not allowed for the pore fluids in the center of the core to dissipate than in the annulus. As a result, excessive pore pressure difference and stresses are induced in the core body. This may cause tensile failure which shows itself as microfractures in its body. These microfractures adversely alter the core rock and mechanical properties. Therefore, the sample should be retrieved/tripped slowly enough so that the induced pore pressure and stress difference do not become excessive and the core does not undergo tensile failure. On the other hand, this slow enough retrieval rate should meet the operational rig costs so that it does not cause invisible lost time. Therefore, the optimal tripping rate should be determined for each case. This should be used as the basis of coring method/tool candidate selection. The industry has so far utilized only generic methods for selecting their core tripping schedules and thus their coring methods (used for coring tool candidate selection). Just recently, there has been some research in this regard which failed to consider the thermal, mechanical, and mud cake effects, they did not also evaluate the induced stresses and the optimal rates. Therefore, in this work, a state-of-the-art T-P-E model is developed and applied to evaluate the optimal tripping rates. This work includes: 1) the modeling, derivation, and evaluation of the hydraulic and thermal effects including the neglected ones in the literature, i.e., the thermal, mud cake, and the mechanical properties, 2) summing-up of all the effects to produce the induced stresses, 3) comparing the induced stresses with the tensile strength, 4) indicating whether tensile failure occurs for a specified tripping rate, and 5) repeating the trial and error process for different tripping rates until the optimal rate can be obtained. Therefore, in this work, a standard procedure is proposed to optimize the retrieval rate by requesting a standard set of inputs and running the model for different tripping rates. In addition, during the modeling process, the contributing parameters have been identified. Having found the contributing parameters, using rig site data including the cuttings analysis (which is used to estimate several input parameters), it is not possible to find the value of the hydraulic diffusivity with certainty. So far, the magnitude of the tripping rate (finding the optimal value of which is the objective of the work) has been controlled just arbitrarily by the drilling crew. Therefore, these two parameters have been introduced as the main uncertain parameters and thus the sensitivity analyses of their effects have been investigated. Using this analysis, some extremes for tripping rates have been introduced, which can be used as a general engineered guideline for coring tool/method candidate selection.",4,4,0
Drilling,Drilling Mud,"Nguyen, T. C.; Al-Safran, E.; Nguyen, V.",Theoretical modeling of Positive Displacement Motors performance,Positive displacement motor (PDM); Theoretical modeling; Motor performance; Downhole mud motor,PROGRESSING CAVITY PUMP,"Positive Displacement Motor (PDM) has been used extensively in directional and horizontal drilling operations. To the best of our knowledge, there is no reliable analytical model to predict the performance of PDMs. Based on motor geometry; each PDM has its own unique performance that is experimentally obtained by manufacturers using water as a testing fluid. These experiments are not only costly and time-consuming, but also with conditions that do not represent the actual down-hole conditions. The key to improve the prediction of motor performance is to, accurately; determine the flowing cross-sectional area of PDM. This paper uses Nguyen et al. (2014) model for calculating flow area of a multi-lobe progressing cavity pump, in addition to two developed analytical models for predicting the actual performance of a multi-lobe PDM. A sensitivity analysis was performed to optimize motor geometry to maximize motor torque. The developed models were validated using experimental data from a single 1:2-lobe and multi 2:3-lobe PDMs. The results revealed that when the stator lobe number is greater than five, torque is maximized if the dimensionless motor geometry is zero. The flowing cross-sectional area is reduced when the stator lobe number is higher than four lobes. However, the flow rate is always higher when the stator lobe number is increased. The results also showed that it is not recommended designing a PDM which has the stator lobe greater than twelve. Furthermore, model validation showed that the proposed model predicts the actual multi-lobe PDM performance with average percent error of less than 6% when differential pressure across the motor is 300 psi or less. The results of this study are not only important for manufacturers to optimize PDM design, but also for operators to improve the performance and efficiency of PDMs.",4,5,1
Drilling,Drilling Mud,"Choi, Myoungsung; Scherer, George W.; Prudhomme, Robert K.",Novel methodology to evaluate displacement efficiency of drilling mud using fluorescence in primary cementing,Primary cementing; Displacement; Fluorescence; Metallurgy; Surface roughness,CONTACT ANGLES; SURFACES; WETTABILITY; ROUGHNESS; ADHESION; ENERGY,"For primary cementing of a well, successful displacement of drilling mud from the casing and annulus, and properly conditioning those surfaces to bond with the cement slurry, are paramount to achieve zonal isolation. In this study, to evaluate displacement of drilling mud from well casings, a fluorescence methodology incorporating a hydrophobic dye was developed. Fluorescence is attractive because the dye is highly oil soluble and non-polar and can be detected at very low concentrations, so chemical interference between dye and drilling mud is minimized. From the fluorescence measurements, the thickness of residual drilling mud can be quantitatively determined, which makes it possible to quantify the efficiency of drilling mud removal. Residual oil layers under consideration in this study from 32 mu m to 1.5 mu m are observed. The spacer fluids D and E are excellent in their ability to remove the drilling mud, whereas spacer F performs poorly. The effects of metallurgy and surface roughness on wettability were investigated using the measured thickness of residual drilling mud. There is little effect of the composition of the steel tube on wettability, but the surface roughness or presence of corrosion can significantly affect the wettability.",5,5,0
Drilling,Drilling Mud,"Dutta, Jayanta; Kumar, Ashutosh; Bhardwaj, Nitin; Gunasekaran, Karthikeyan; Mohammed, Sajid","Production induced faulting risk assessment in a depleted reservoir: A case study from deepwater Krishna-Godavari basin, India",Deepwater depleted reservoir; Risk assessment; Production induced faulting; Slip tendency; Dilation tendency; Secondary fractures re-activation,IN-SITU STRESS; FLUID-FLOW; PORE PRESSURE; REACTIVATION; FIELD,"In a producing field, the fluid conduit nature of faults could initiate due to changes in the stress state within the reservoir. It has large impacts on different aspects (seal integrity, casing shear, mud loss during drilling, reservoir permeability, and induced earthquakes) of the field performance. In order to optimize the future drilling campaign and field management strategy, production induced faulting risk assessment was performed to evaluate the fault behavior in a depleted reservoir, where the reservoir pressure has decreased by 40% from its pre-production pressure. The risk assessment was done through (i) identifying the critically stressed fracture/fault in the pre-production stage, (ii) assesses the risk of production induced new fractures/faults generation & reactivation of existing faults, and (iii) risk ranking of faults within the reservoir. The assessment model was based on the relationship between failure mode and fluid flow with change in stresses on the fault planes due to reservoir pressure depletion. The model was built through integrating different data, such as, reservoir fault mapping, core data, drilling data, production data, and geomechanical modelling. The analysis revealed that all the faults at the pre-production stage were not critically stressed and therefore, were closed. Production induced new fractures/faults are neither generated nor existing faults re-activated till the current depleted reservoir condition in the study field. Risk ranking based on the slip and dilation tendency analysis suggests that because of the depletion fault slip tendency has not increased much and risk of fault slip is on the lower side. But, the dilation tendency has increased for all the faults which makes these faults more prone to extensional/tensile failure than shear failure. Furthermore, the analysis suggests that the severe mud loss events encountered in the post-production wells were due to re-activation of existing secondary fractures at the fault intersection depths during drilling.",5,5,3
Drilling,Drilling Mud,"Ettehadi, Ali; Altun, Gursat",Functional and practical analytical pressure surges model through herschel bulkley fluids,Herschel bulkley model; Surge and swab pressures; Sepiolite mud; Rheological constants; High temperature,SWAB; WELL,"Substantially large pressure surges are generated while drilling a well due to tripping operations in which a central drillstring is being moved up or down through non-Newtonian fluid. The presence of these subsurface surge pressures must be considered and determined in almost every well drilled. Wells exhibiting high geothermal temperature gradient further complicate the determination of wellbore pressures since the classical viscometer does not characterize the non-Newtonian nature of fluids accurately at elevated temperatures. More importantly, rheological model selection also plays a key role for effectively proposing safe tripping speeds without violating the mud window constraints. Herschel-Bulkley rheological model has gained more reputation among others due to better predictions of wellbore hydraulic pressures as suggested by the American Petroleum Institute. A new practical and dimensional analytical model was developed for Herschel Bulkley (HB) fluid to calculate pressure surges caused by drillstring movement for non-Newtonian fluids under the fully developed flow (steady state) conditions in the laminar flow range in a slot geometry. The proposed analytical method was applied on unweighted fresh water sepiolite mud as a non-Newtonian fluid since the sepiolite muds are among the few water based muds performing adequately at extreme temperatures as the synthetic and oil base muds. Already measured rheological constants of selected fluid system using both HTHP dynamic rheometer and classical viscometer were considered to obtain surge pressures at ambient to extreme temperature ranges. The results are compared with already developed Burkhardt method for Bingham Plastic fluid and Schuh method for Power Law fluid and other proposed numerical and analytical solutions. Substantial differences on the pressure surges between the conventional viscometer and the HTHP rheometer measurements were also presented. The precision of the developed model is shown to be acceptable for most practical applications. Being operationally easy and applicable with a convenient solution code make the proposed model straightforward to be used as a part of drilling software.",6,6,2
Drilling,Drilling Mud,"Malgaresi, Gabriel V. C.; Vaz, Alexandre S. L., Jr.; Correa, Cleysson C.; Cruz, Georgiana F.; Lomba, Rosana F. T.; Waldmann, Alex",A new crude-glycerin-based drilling fluid,Drilling fluid; Crude glycerin; Dynamic filtration; Return permeability,CROSS-FLOW FILTRATION; POROUS-MEDIA; COLLOIDAL TRANSPORT; HYDROCHLORIC-ACID; FILTER CAKE; PERFORMANCE; DISSOLUTION; SUSPENSIONS; ACIDIZATION; SYSTEM,"A new drilling fluid proposed was obtained by substitution of half of water in water-based drilling fluid by crude glycerine, and matching API properties by regulating the additives. The comparative laboratory study of the new and conventional drilling fluids included the cross-flow mud circulation in the slot with transversal core; it followed by acidizing and return permeability measurements under the reversed flow. A series of six experiments were conducted on Berea sandstone cores to measure the amount of invading fluid and formation damage under different-rate return flow. The glycerine-based and water-based drilling fluids were circulated across the core face. After mud circulation, HCl acid was circulated, and the return permeability was measured under increasing flow rate of the reversed flow. The glycerin-based mud exhibited significantly lower leak-off than the water-based drilling fluid. The filter-cake stabilization time is lower for the glycerin-based drilling fluid. The return permeability is higher for the glycerin-based drilling fluid. The above three items constitute the advantages of a new glycerine-based drilling fluid over the traditional water-based mud.",7,8,0
Drilling,Drilling Mud,"Qi, Dexuan; Li, Lijuan; Jiao, Yongshu",The stress state around an elliptical borehole in anisotropy medium,Borehole stability; Elliptical borehole; Stress state; Anisotropic elasticity; Complex variable method; Analytical solution,WELLBORE STABILITY; FAILURE; ROCKS,"Under the assumption of generalized plane strain condition, this paper presents an analytical solution for stresses near an inclined elliptical wellbore drilled in anisotropic formation based on the linear theory of anisotropic elasticity and complex variable method. The solution is suitable for calculating the stresses around an elliptical borehole drilled with any inclination and orientation angles in a linear elastic, continuous, homogeneous and general anisotropic medium. The solution for the stresses can also show the effects of the liquid pressure exerted by drilling mud, the ratio and the direction of the in-situ stresses. For engineering utilization the transformation of compliance matrix for the transversely isotropic medium is formulated. An example is calculated and shown by contours of stress components around an inclined elliptical wellbore in a transversely isotropic formation. The stress contours can be utilized to some extent to predict the location, the range, the depth and even the outlines of fractured or collapsed well wall. Then a range of parametric analysis is carried out on the impacts of borehole inclination, orientation and ellipticity on the first principal stress and maximum shearing stress. The results indicate that for various boreholes with different degree of formation anisotropy the algebraic values of the first principal stress and maximum shearing stress go down gradually with the increase of borehole inclination, and these two stresses vary in the pattern of half a sinusoidal wave with the variation of orientation angles. Furthermore, the stresses go up with the increase of ellipticity. The solution presented in this paper might supply a more realistic technique for assessing the stability of borehole and optimizing the well path in anisotropic medium.",8,8,1
Drilling,Drilling Mud,"Vega, Marcia Peixoto; de Moraes Oliveira, Gabrielle Fontella; Fernandes, Lindoval Domiciano; Martins, Andre Leibsohn",Monitoring and control strategies to manage pressure fluctuations during oil well drilling,Kick; Circulation loss; Downhole pressure control; Decision making; Gain scheduling,LOST CIRCULATION; KICK DETECTION; MODEL; FLUID; DEEP; MUD; MITIGATION; PREDICTION; RESERVOIR; SYSTEM,"During drilling the mud flows through the drill string and exits through the choke valve. The mud density range has as constraints: pore pressure (minimum limit) and fracture pressure (maximum limit). In fact, annulus bottomhole (downhole) pressure needs to be higher than pore pressure, in order to prevent kick, and smaller than fracture pressure, for avoiding mud loss and formation damage. Experimental and simulation studies were implemented in order build a monitoring - diagnosing tool working together with a decision making routine based on an adaptive control scheme that employs gain scheduling. An experimental unit was built, presenting the most important characteristics of the drilling process. The transient nature of annulus bottomhole pressure is due to the process inherent disturbances: rheology, rate of penetration (ROP), kick and mud loss, which were all implemented at the experimental unit. The major objective of the present paper is using the experimental plant and a phenomenological model for implementing real time process automation, in order to assure drilling inside operational window, using in line measurements for flow and density disturbances under circulation loss and kick scenarios.",8,8,1
Drilling,Drilling Mud,"Gautam, Sidharth; Guria, Chandan; Rajak, Dilip K.; Pathak, Akhilendra K.",Functionalization of fly ash for the substitution of bentonite in drilling fluid,Alpha-glycol and amine substituted fly ash; API-Grade drilling bentonite; Surface characterization; Rheology; Frictional and filtration behavior,,"Oil exploration activities have increased the demand for American Petroleum Institute (API-) grade drilling bentonite leading to a significant increase in the cost of naturally occurring bentonite and overall cost of the drilling operations. In this work, fly ash (FA) was functionalized to replace API- grade drilling bentonite for drilling of wells. Epichlorohydrin and aminopropyl triethoxysilane were used to functionalize the ultrafine-structured planetary ball-milled FA. The morphology, mineralogy, structure and specific surface area of the functionalized FA were determined by the field emission scanning electron microscopy, energy dispersive X-ray spectroscopy, X-ray diffractometry and Brunauer-Emmett-Teller analysis, respectively, to determine the efficacy of functionalized FA as a colloidal base in aqueous suspension. Fourier-transform infrared spectrometer and X-ray photoelectron spectroscopy analysis was used to confirm the grafting of alpha-glycol and amine functional group on FA surface and quantified by iodometric and acid-base titration method, respectively. The zeta potential and cation-exchange capacity of functionalized FA were found to be -47.1 to -68.1 mV in pH range 8-12 and similar to 68.0 meq/100 g of functionalized FA, respectively, and were found comparable to API- grade drilling bentonite. Rheological behavior and filtration loss properties of the functionalized FA in aqueous suspension were determined and compared with the API- grade drilling bentonite yielding similar results. The performance of the functionalized FA-based drilling mud system involving tamarind gum and polyanionic cellulose was evaluated by determining the thermal stability, cuttings transportation ability, friction and shelf-life properties under the downhole condition at 75 degrees C and 100 psig and the results were compared against the existing drilling mud system, yielding the comparable performance. Finally, the functionalized FA was found to be cost-effective over API- grade bentonite.",9,9,0
Drilling,Stress,"Sabah, Mohammad; Ameri, Mohammad Javad; Sedigh, Maryam",Natural bridging as a tertiary well control method in deep-water wells: A case study from Caspian Sea,Blowout; Self-killing; Natural bridging; Deep-water well; Caspian Sea,FAILURE CRITERIA; PREDICTION; PRESSURE; STRESS; WINDOW,"Blowout is the uncontrolled flow of reservoir fluids into the well, which can cause different types of problems during the drilling operations. In high-pressure formations with low rock strengths, it is more likely to occur self-killing through bridging mechanisms. The underbalanced conditions that are induced during developing a kick, leading into sufficient instability in exposed formations such that the borehole bridges over and kick kills itself. In this research, the potential of natural bridging is studied in one of the deep-water wells in the Caspian Sea to figure out whether this natural phenomenon is able to terminate the uncontrolled influxes of formation fluids into the borehole. For the reason, a series of semi-integrated numerical simulators are employed to evaluate wellbore pressure profile and wellbore instability as a function of time under blowout conditions. Applied analyses to a particular blowout scenario indicated that rock fragments falling off the wellbore wall are suspended in the two-phase flow (a mixture of gas and drilling mud) during developing the kick. As a result, cavings settlement is less not probable to plug the wellbore. On the other hand, suspension of rock fragments gradually increases the solid concentration of fluid phase until it hits a critical value at a certain time after the beginning of the kick, thereby bridging occurs before developing the kick into a blowout.",0,0,0
Drilling,Stress,"Chen, Yuanhang; Yu, Mengjiao; Takach, Nicholas",Modeling and analysis of coupled thermal-hydrologic-mechanical processes during lost circulation,Wellbore stability; Lost circulation; Numerical simulation; Heat transfer; Geomechanics; Coupled processes,WELLBORE STABILITY; SIMULATION; BOREHOLE; FLUIDS; FLOW,"Wellbore stability remains as one of the major challenges to drilling engineers. Results of recent survey showed about one third of non-productive time of drilling operation is classified as borehole problem, where a significant part is attributed to borehole instability. The thermal regime of a formation in the vicinity of a wellbore affects the stability of the well significantly during drilling operations, especially in High pressure High Temperature (HPHT) wells. This paper describes how the thermal behavior of a tubular-wellbore-reservoir system is altered during mud loss, as well as its consequent impact on near-wellbore state of stresses and critical mud weights. A fully coupled three dimensional thermal-poro-elastic model, integrated with a transient tubular-wellbore-reservoir heat flow model, is developed to evaluate near-wellbore stresses and pore pressure redistribution during mud loss. The forced convective heat transfer coefficients in both conduits-drillpipe and annulus-are rigorously determined as a function of local flow and fluid properties. The results reveal that continuous mud loss destabilizes the wellbore as the pressure window shifts considerably over time. Critical mud weights for both tensile and compressive failures decrease during mud loss over the entire length of the wellbore, in addition to the point of loss. During severe losses, the fracture gradient at the bottom of the well can decrease by over 1 ppg within the first hour. This can intensify the existing fracturing condition and allow the development of new fractures at other locations, which leads to further losses as time progresses. This model enables prediction of a more realistic operating window during lost circulation by taking additional thermally-induced effects into account. In addition, failure indexes during mud loss considering P-rho-T coupling effect on a compressible mud column in the annulus are investigated with the proposed model. During drilling operations, especially Managed Pressure Drilling (MPD) and offshore applications with moderate to severe mud loss, the operation window should be modified by taking mud loss-induced thermal stresses into account. The mud type, wellbore geometry, circulation rate, and other parameters affect the magnitude of shift in critical mud weight during mud loss, hence evaluations should be based on specific cases.",0,0,1
Drilling,Stress,"Zahoor, Mudasar; Puri, Saurabh",Non-local continuum ductile damage model for rocks under high pressure and high temperature (HPHT),Rock; Drilling; Computational; Free-energy; Ductile-damage; Local; Non-local; Indentation; Void-volume fraction,THERMAL VISCOPLASTIC MATERIALS; SHEAR LOCALIZATION; ENERGY CRITERION; STRAIN; NUCLEATION; PLASTICITY; FRAMEWORK; FAILURE; ONSET,"The primary phenomenon responsible for rock failure called damage is described as the nucleation and evolution of voids in the rock matrix. The damage of rocks especially under the extreme conditions of High Pressure and High Temperature (HPHT) is studied. Rocks demonstrate ductile behavior in HPHT conditions, which is attributed to high confining pressure due to which fragments are held together and a continuum flow is possible. A new 3D non-local macroscopic continuum ductile-damage model is developed for realistic modeling of behavior of rocks under HPHT conditions. The model uses a damage variable, which is a volumetric quantity, called the void-volume fraction. It is assumed that damage is initiated and then driven by the onset of plasticity in a coupled non-local system. The numerical model is applied to a uniaxial compression and the dynamic indentation problems respectively. The dynamic indentation problem is of particular interest to rock drilling at ultra deep depths. Numerically, indentation introduces high stress concentrations and strain localizations, which are generally very hard to handle, owing to issues like loss of hyperbolicity, material length scale and shear deformation bands, using classical methods. The selected problems are solved by local and non-local approaches respectively. The uniaxial compression problem demonstrates the large difference in failure strains of rocks under normal pressure and temperature conditions and HPHT conditions. Results obtained from the dynamic indentation problem show that the damage is incurred in a rock body under the action of an indentor in the form of damage-zones of varying degrees of damage. The results also indicate the importance of non-locality that provides stability and convergence to the numerical solution.",1,1,0
Drilling,Stress,"Tang, Zhiqiang; Li, Qian; Yin, Hu",The influence of solute concentration and temperature of drilling fluids on wellbore failure in tight formation,Tight formation; Thermo-chemical coupling; Pore pressure; Wellbore failure,STABILITY; MODEL; SHALES; FLOW; BOREHOLE,"The performance of drilling fluids influences the efficiency of drilling operations. The near-wellbore pore pressure and stress distribution will change with time due to the hydraulic, chemical and thermal potential gradients between the drilling and formation fluids, resulting in wellbore instability during drilling a tight formation. The pore pressure diffusion equation, which considers the effects of hydraulic diffusion, thermal diffusion, and solute diffusion, is presented and the analytic expressions of the near-wellbore pore pressure and stress distribution induced by pore pressure change and temperature stress are presented. An example is used to study the influence of the temperature and solute concentration on the near-wellbore pore pressure and effective stress and the degree of wellbore failure with time. The results show that increasing the solute concentration of drilling fluid reduces the pore pressure but increases the radial and tangential effective stress. In addition, decreasing drilling fluid temperature reduces the pore pressure and tangential effective stress but increases the radial effective stress, both of which are beneficial to wellbore stability. When wellbore failure occurs, increasing the drilling fluid temperature will cause a slight increase of wellbore failure and decreasing the solute concentration may cause a more serious failure in early time.",3,3,1
Drilling,Stress,"Ashena, Rahman; Thonhauser, Gerhard; Vortisch, Walter; Rasouli, Vamegh; Azizmohammadi, Siroos",Optimization of core retrieval using a Thermo-Poro-Elastic (T-P-E) approach,,EMPIRICAL RELATIONS; STRENGTH,"One most common cause of damage of the recovered cores occurs during their fast decompression from the bottomhole to the surface. This occurs as sufficient time is not allowed for the pore fluids in the center of the core to dissipate than in the annulus. As a result, excessive pore pressure difference and stresses are induced in the core body. This may cause tensile failure which shows itself as microfractures in its body. These microfractures adversely alter the core rock and mechanical properties. Therefore, the sample should be retrieved/tripped slowly enough so that the induced pore pressure and stress difference do not become excessive and the core does not undergo tensile failure. On the other hand, this slow enough retrieval rate should meet the operational rig costs so that it does not cause invisible lost time. Therefore, the optimal tripping rate should be determined for each case. This should be used as the basis of coring method/tool candidate selection. The industry has so far utilized only generic methods for selecting their core tripping schedules and thus their coring methods (used for coring tool candidate selection). Just recently, there has been some research in this regard which failed to consider the thermal, mechanical, and mud cake effects, they did not also evaluate the induced stresses and the optimal rates. Therefore, in this work, a state-of-the-art T-P-E model is developed and applied to evaluate the optimal tripping rates. This work includes: 1) the modeling, derivation, and evaluation of the hydraulic and thermal effects including the neglected ones in the literature, i.e., the thermal, mud cake, and the mechanical properties, 2) summing-up of all the effects to produce the induced stresses, 3) comparing the induced stresses with the tensile strength, 4) indicating whether tensile failure occurs for a specified tripping rate, and 5) repeating the trial and error process for different tripping rates until the optimal rate can be obtained. Therefore, in this work, a standard procedure is proposed to optimize the retrieval rate by requesting a standard set of inputs and running the model for different tripping rates. In addition, during the modeling process, the contributing parameters have been identified. Having found the contributing parameters, using rig site data including the cuttings analysis (which is used to estimate several input parameters), it is not possible to find the value of the hydraulic diffusivity with certainty. So far, the magnitude of the tripping rate (finding the optimal value of which is the objective of the work) has been controlled just arbitrarily by the drilling crew. Therefore, these two parameters have been introduced as the main uncertain parameters and thus the sensitivity analyses of their effects have been investigated. Using this analysis, some extremes for tripping rates have been introduced, which can be used as a general engineered guideline for coring tool/method candidate selection.",4,4,0
Drilling,Stress,"Gholami, Raoof; Rabiei, Minou; Aadnoy, Brent; Rasouli, Vamgh",A methodology for wellbore stability analysis of drilling into presalt formations: A case study from southern Iran,Presalt formations; Drilling; Stability; Creep; Viscoelastic; Analytical model,ROCK-SALT; BEHAVIOR; FLOW,"Drilling into presalt formations has been a long-standing issue due to the rapid changes in the diameter of the borehole during drilling operations either because of creep or wash-out dissolution. There have been many studies on characterization of salts, with many mathematical models being presented to estimate the pressure induced due to the squeezing salt sheets. However, the results of none of these models have been fully validated against real field data and some recommendations have been made based on numerical simulations. In this study, attempts were made to introduce a methodology based on damage mechanics for wellbore stability analysis of a wells drilled in the southern part of Iran. The results obtained indicated that the presence of a thick salt layer in the well has resulted in significant wellbore closure in the intervals above the reservoir section. It was also found that the salt exhibits viscoelastic behaviour during drilling due to the homogeneous temperature which has not reached the threshold limit of viscoplastic boundary. A complicated change in the stress regime was also observed which could be linked to the existence of the thick salt layer or presences of a fault crossing the well. Therefore, it is recommended to further validate this model in other wells using the methodology presented.",4,4,0
Drilling,Stress,"Kan, Changbin; Yang, Jin; Yu, Xiaocong; Dong, Tiejun; Wu, Xudong; Liu, Ming; Li, Chun; Zhang, Changliang; Fu, Jinbao",Load bearing characteristics study on novel deepwater composite drilling conductor by simulation and experimental methods,Composite drilling conductor; Laboratory experiment; Numerical simulation; Vertical bearing capacity; Lateral displacement; Soil pressure variation,SAND; SOIL,"A novel design of composite drilling conductor (CDC) was carried out for improving the vertical and lateral bearing capacity. Bearing characteristics of CDC was investigated when subjected to lateral and longitudinal loads based on the ultimate subgrade reaction method and pile foundation bearing theory. Theoretical models for lateral displacement and vertical load were established. Finite element analysis (FEA) was conducted, and bearing capacity and influencing factors of the composite structure were studied. Through laboratory experiments, the interaction between the structure and the soil as well as the regularity of soil deformation and stress variation in the surrounding soil were studied during installation, vertical and lateral load application. The results showed that the vertical bearing capacity increased with increasing depth of the bucket foundation under the combined effect of the composite structure. Meanwhile, the depth of the embedded point of the composite conductor increased with an increased bending moment when subjected to a combined load with a constant vertical force. When the bending moment on the structure top was constant, the lateral displacement of the structure as well as the depth of the embedded point would increase with increasing vertical force. Furthermore, the bending moment change on the top of the CDC was more significant than the vertical force regarding the lateral displacement. It is also showed that the internal bucket foundation produced an ""elastic plugging"" effect when the CDC was subjected to vertical loading, while soil pressure transmission occurred from the upper soil to the underlying strata soil. When subjected to lateral loads, the earth pressure on the bucket sidewall was redistributed, and the bucket foundation produced a lateral supporting effect on CDC. The composite structure effectively reduced the conductor vertical and lateral displacement and improved the lateral and vertical bearing capacity. These results provide useful theoretical references for further development and optimization of the CDC structure.",4,6,1
Drilling,Stress,"Zamiran, Siavash; Rafieepour, Saeed; Ostadhassan, Mehdi",A geomechanical study of Bakken Formation considering the anisotropic behavior of shale layers,Unconventional reservoirs; Shale layers; Bakken Formation; Williston basin; Geomechanical modeling; FLAC3D,WELLBORE STABILITY,"In this study, the geomechanical behavior of the shale layers is investigated in various capacities under isotropic and anisotropic scenarios. Primarily, an accurate estimation of geomechanical properties is carried out. Different geomechanical parameters including Young's modulus, Poisson's ratio, and rock strength for both isotropic and anisotropic modes are estimated based on field investigations for all three members. Dynamic elastic moduli are estimated from advanced acoustic log tests, and static moduli are measured in the laboratory. Then, a comparison is made, and a correlation is developed to convert dynamic to static elastic properties. Consequently, stress alteration and deformation changes around the boreholes are modeled in response to drilling. Measured parameters are utilized in a finite difference numerical model to predict rock deformation and stress variation. Based on the geomechanical models, stress regimes and medium deformations around the borehole are compared in both anisotropic and isotropic circumstances. Moreover, the effects of wellbore inclination on stress distribution, wellbore deformation, and yielding zones are discussed. The effects of wellbore inclination on stress distribution are monitored by studying horizontal principal stresses. According to the results, the relative plasticity radius of the medium is determined by dividing maximum radius of the yielded zone by the primary radius of the wellbore. Consequently, the failure zones and relative plasticity radiuses are compared for different well inclinations from vertical to horizontal wellbores. The relative plasticity radiuses are shown constant from vertical borehole to the borehole with 45 degrees of inclination with a gradual increase in values towards a horizontal borehole.",4,4,1
Drilling,Stress,"Lyu, Zehao; Song, Xianzhi; Li, Gensheng; Wang, Gaosheng; Shi, Yu; Liu, Yu; Zheng, Rui",Experimental analysis on characteristics of micro-structure and mineralogy changes in thermal spallation drilling,Thermal spallation; Rock sample; Mineral; X-ray diffraction; SEM,IMPACT FLOW-FIELD; NUMERICAL-ANALYSIS; HEAT-TRANSFER; ROCK FAILURE; WATER; PERMEABILITY; ETHANOL,"Thermal spallation drilling is a promising technology expected to exploit hydrocarbons in hard rocks. In this paper, thermal spallation experiments are conducted on six types of rocks. Comparisons are made in terms of mineral compositions and micro-structures. Spallation temperatures are obtained, and analytical results are compared with experimental data. Results show that spallation temperatures obtained by analytical method show good agreement with experimental data. Additionally, drilling performances can be continuous or intermittent for various types of rocks. Quartz expands in different rocks after thermal impact. Calcite increases and dolomite decreases due to thermal decomposition. Moreover, the induced thermal stresses in sandstone push against the micro-particle and melting may occur. For granite, micro-cracks and micro-particles exist after spallation. In contrast, there are no cracks in shale, but melt holes and micro-particles distributed randomly due to reaction. For limestone, there exist relatively large cracks, micro-cracks and micro-particles. For dolomite, no obvious micro-particles remain but only a few micro-cracks. The variations of elements correspond well with mineral changes. However, under the conditions of this paper, marble fails to break due to strong homogeneity. All results can provide guidance for the further study on the rock-breaking of thermal spallation drilling.",4,4,3
Drilling,Stress,"Tang, Ming; Yuan, Lanfeng; He, Shiming; Fu, Tao",Simplified modeling of YPL fluid flow through a concentric elliptical annular pipe,YPL fluids; Elliptical wellbore; Laminar flow; Pressure gradient; Simplified model,TURBULENT-FLOW; LAMINAR; DUCTS,"Accurate prediction of the pressure gradient is the prerequisite for precise control of downhole pressure; such control can effectively avoid the complicated underground situations caused by improper downhole pressure control, such as well leakage, overflow and wall instability. The existing model of the annular pressure gradient in drilling process only considers a perfectly cylindrical wellbore; however, the real drilling hole easily becomes an elliptical wellbore under non-uniform in situ stress, leading to the relatively large error of the conventional model. Based on the theories of fluid mechanics, the analytical and simplified models of steady-state laminar flow in the concentric elliptical annular (elliptical wellbore) pipe are established. The analytical model is validated by the computational fluid dynamics (CFD) simulations of Fluent software. In addition, the simplified model was validated by analytical solutions. The primary conclusions are as follows. (1) When the flow rate is constant, the axial average and maximum velocities increases linearly and exponentially, respectively, with the increase of epsilon. The velocity profile of the analytical model is in good agreement with the velocity profile of the CFD simulations. (2) The CFD simulations are in perfect agreement with the analytical results, and the error of the pressure gradient is within +/- 10% error bands for pressure gradient. (3) The simplified model predictions are in good agreement with the analytical model results, and the error of most of the results is within +/- 5% bars. The model is convenient for use in predicting the pressure gradient accurately for yield power law (YPL) fluid flowing in an elliptical wellhole.",5,5,2
Drilling,Stress,"Dutta, Jayanta; Kumar, Ashutosh; Bhardwaj, Nitin; Gunasekaran, Karthikeyan; Mohammed, Sajid","Production induced faulting risk assessment in a depleted reservoir: A case study from deepwater Krishna-Godavari basin, India",Deepwater depleted reservoir; Risk assessment; Production induced faulting; Slip tendency; Dilation tendency; Secondary fractures re-activation,IN-SITU STRESS; FLUID-FLOW; PORE PRESSURE; REACTIVATION; FIELD,"In a producing field, the fluid conduit nature of faults could initiate due to changes in the stress state within the reservoir. It has large impacts on different aspects (seal integrity, casing shear, mud loss during drilling, reservoir permeability, and induced earthquakes) of the field performance. In order to optimize the future drilling campaign and field management strategy, production induced faulting risk assessment was performed to evaluate the fault behavior in a depleted reservoir, where the reservoir pressure has decreased by 40% from its pre-production pressure. The risk assessment was done through (i) identifying the critically stressed fracture/fault in the pre-production stage, (ii) assesses the risk of production induced new fractures/faults generation & reactivation of existing faults, and (iii) risk ranking of faults within the reservoir. The assessment model was based on the relationship between failure mode and fluid flow with change in stresses on the fault planes due to reservoir pressure depletion. The model was built through integrating different data, such as, reservoir fault mapping, core data, drilling data, production data, and geomechanical modelling. The analysis revealed that all the faults at the pre-production stage were not critically stressed and therefore, were closed. Production induced new fractures/faults are neither generated nor existing faults re-activated till the current depleted reservoir condition in the study field. Risk ranking based on the slip and dilation tendency analysis suggests that because of the depletion fault slip tendency has not increased much and risk of fault slip is on the lower side. But, the dilation tendency has increased for all the faults which makes these faults more prone to extensional/tensile failure than shear failure. Furthermore, the analysis suggests that the severe mud loss events encountered in the post-production wells were due to re-activation of existing secondary fractures at the fault intersection depths during drilling.",5,5,3
Drilling,Stress,"Ding, Lu; Ni, Hongjian; Li, Mukun; Li, Wentuo; Song, Weiqiang; Guo, Xing",Wellbore collapse pressure analysis under supercritical carbon dioxide drilling condition,Supercritical carbon dioxide; Drilling; Pore pressure; Collapse pressure; Wellbore stability,,"Compared with the conventional drilling methods, supercritical carbon dioxide used in drilling and completion has considerable potentials and many advantages. However, it is found in the research and practice that there are yet many basic problems to be solved. Wellbore stability is one of them. Firstly, in this paper, on the basis of Span & Wagner equation, combined with unique physical properties of supercritical carbon dioxide, parameters such as temperature and pressure in the wellbore while the supercritical carbon dioxide drilling are calculated. Secondly, the heat and mass transfer effect between the supercritical carbon dioxide and the formation has been studied, and the temperature change near the wellbore formation and stress change near the wellbore have been obtained. Thus, pore pressure change near the wellbore has been obtained. When the depth reaches 1500 m, the downhole temperature will be 12 K lower than the wellbore temperature, and the pore pressure will increase to 20 Mpa as the supercritical carbon dioxide seeps into the formation. Thirdly, mechanical properties change rules when rocks are soaked in the supercritical carbon dioxide are obtained through experiments. The compressive strength decreases by 64%, the elastic modulus increases by 153%, and the poisson ratio decreases by 8%. Based on the above research, the wellbore collapse pressure model has been established. It is revealed that the wellbore collapse pressure rises from 9.17 Mpa to 16.26 MPa with the increase of time, which is still lower than the bottom pressure and cannot lead to instability. Meanwhile, the bottom collapse failure index keeps positive and increases gradually with the increase of time. It means that there is no wellbore enlargement. Therefore, the results have verified the wellbore stability while the supercritical carbon dioxide drilling. It has laid a solid foundation for the future development of supercritical carbon dioxide drilling.",8,12,0
Drilling,Stress,"Qi, Dexuan; Li, Lijuan; Jiao, Yongshu",The stress state around an elliptical borehole in anisotropy medium,Borehole stability; Elliptical borehole; Stress state; Anisotropic elasticity; Complex variable method; Analytical solution,WELLBORE STABILITY; FAILURE; ROCKS,"Under the assumption of generalized plane strain condition, this paper presents an analytical solution for stresses near an inclined elliptical wellbore drilled in anisotropic formation based on the linear theory of anisotropic elasticity and complex variable method. The solution is suitable for calculating the stresses around an elliptical borehole drilled with any inclination and orientation angles in a linear elastic, continuous, homogeneous and general anisotropic medium. The solution for the stresses can also show the effects of the liquid pressure exerted by drilling mud, the ratio and the direction of the in-situ stresses. For engineering utilization the transformation of compliance matrix for the transversely isotropic medium is formulated. An example is calculated and shown by contours of stress components around an inclined elliptical wellbore in a transversely isotropic formation. The stress contours can be utilized to some extent to predict the location, the range, the depth and even the outlines of fractured or collapsed well wall. Then a range of parametric analysis is carried out on the impacts of borehole inclination, orientation and ellipticity on the first principal stress and maximum shearing stress. The results indicate that for various boreholes with different degree of formation anisotropy the algebraic values of the first principal stress and maximum shearing stress go down gradually with the increase of borehole inclination, and these two stresses vary in the pattern of half a sinusoidal wave with the variation of orientation angles. Furthermore, the stresses go up with the increase of ellipticity. The solution presented in this paper might supply a more realistic technique for assessing the stability of borehole and optimizing the well path in anisotropic medium.",8,8,1
Drilling,Stress,"Shen, Jian; Qin, Yong; Li, Yepeng; Yang, Yanhui; Ju, Wei; Yang, Chunli; Wang, Geoff","In situ stress field in the FZ Block of Qinshui Basin, China: Implications for the permeability and coalbed methane production",In situ stress; High-rank coal; Coalbed methane; Permeability; Gas and water production; Qinshui basin,EASTERN ORDOS BASIN; SHANXI PROVINCE; ORIENTATION; EXPLORATION; MAGNITUDE; RESERVOIR; PART; AREA; GEOMECHANICS; FRACTURES,"In situ stress affects reservoir permeability and stimulation, and thus coalbed methane (CBM) recovery. In this study, the in situ stress field measured from 238 CBM wells in the FZ Block of Qinshui Basin, China, was investigated. The vertical stress, horizontal maximum and minimum principal stress are 5.92-20.08 MPa, 8.03-41.75 MPa, and 5.38-21.24 MPa, respectively. The in situ stress magnitudes increase with burial depth of the coal seams. The FZ Block is dominated by reverse and strike-slip faulting stress regimes. Most of reverse fault stress regimes appear within burial depth less than 500 m, whereas normal and strike faulting stress regimes are deeper than 500 m. The relation between the coefficient of lateral stress and burial depth shows that shallow strata are characterized by horizontal stresses, whereas deep strata are generally hydrostatic pressures that approximately equal to the principal stresses. Low gas and high water production are associated with vertical hydraulic fractures, wherein the horizontal minimum principal stress is the minimum stress. High gas and low water production are associated with horizontal hydraulic fractures, wherein the vertical stress is the minimum stress. This results are attributed to the enhanced permeability of the coal seam and the communication with overlying or underlying aquifers because the minimum stress varies between vertical and horizontal minimum stress. The orientation of the horizontal maximum principal stress is -NEE-NE and is locally distorted by faults, which can be used to optimize the drilling, completion, and stimulation of CBM wells in the study area.",8,10,1
Drilling,Stress,"Masoudi, Pedram; Aifa, Tahar; Memarian, Hossein; Tokhmechi, Behzad",Uncertainty assessment of porosity and permeability by clustering algorithm and fuzzy arithmetic,Porosity; Permeability; Uncertainty projection; Fuzzy arithmetic; Fuzzy power; Clustering,WELL-LOGS; PREDICTION; IRAN; FIELD,"A hybrid clustering-fuzzy arithmetic algorithm is here proposed, which uses cluster analysis to quantify porosity uncertainty, then the uncertainty is projected to the irreducible water saturation and permeability by the means of fuzzy arithmetic. The proposed method is applied to five wells of the carbonate Sarvak Formation, in an Iranian onshore oil-field. First, cluster analysis is applied to the porosity logs including neutron porosity, bulk density and sonic transit time. The uncertainty range of porosity is defined by the range of neutron porosity in each cluster. In order to estimate the core porosity, neutron porosity is calibrated to the core porosity in each cluster. Due to the average of error, the calibrated clustering-based porosity is at least 33% more accurate than the conventional methods. Based on the generalization ability of porosity estimators, a homogeneous porosity zone is determined northward. Irreducible water saturation, analyzed by the proposed method, has less overestimation, compared to the conventional evaluation of irreducible water saturation. Permeability fuzzy number is compatible with core tests, except in well S1, which is drilled in a location, compressed by two stress regimes (N-S and NW-SE). Two criteria are defined for validating the fuzzy numbers by core data: (i) Crit1 finds an average alpha-cut of core values; (ii) Crit2 finds the best alpha-cut to optimize uncertainty interval of the fuzzy number. The alpha > 0.90 is the most appropriate for porosity and permeability studies.",9,9,0
Drilling,Design,"Sun, Youhong; Shi, Yuanling; Wang, Qingyan; Yao, Zongwei",Study on speed characteristics of hydraulic top drive under fluctuating load,Hydraulic top drive; Main transmission system; Fluctuating load; Speed characteristic; Electro-hydraulic proportional control,STICK-SLIP; SYSTEM; PUMP; SIMULATION; DYNAMICS,"A hydraulic top drive is a high-power gyrator used in oil or scientific drilling rigs, whose shaft is connected to drill pipe when it drives drilling tools to excavate well. The output speed of top drive determines the speed of drill bit directly. Load acting on the top drive shaft fluctuates randomly, which will cause top drive output speed hard to be in consistent with the setting value. This paper presents a main transmission system of a hydraulic top drive designed for deep continental scientific drilling, which was built with a multi-stage mechanical structure and a closed circuit hydraulic system with variable displacement pumps and motors. Electro-hydraulic proportional control was applied to vary the speed of the hydraulic top drive. A theoretical model is detailed for the hydraulic top drive main transmission system. Among the new techniques proposed in this paper is a simulation model for studying the performance of hydraulic top drive and capturing speed characteristics under fluctuant load. A drilling experiment of the hydraulic top drive was performed on the CRUST-I drilling rig in CCSD-SK-II well site. This paper concludes by comparing the results of the simulation model with theoretical results and drilling experimental data gathered in the hydraulic top drive possessing the same architecture, components, and control methods used within the simulation model. The drilling experiment and the analysis result showed that the hydraulic top drive could meet the requirements of deep continental scientific drilling and that the speed could be output according to the setting speed with very small oscillation. The simulation model can be used for several applications such as hydraulic top drive design and performance analysis of various drilling conditions.",1,1,2
Drilling,Design,"Guo, Zhengwei; Deng, Rong; Liang, Zheng; Yang, Song",Non-spherical single cone bit mechanics analysis and tooth load test,Non-spherical single cone bit; Kinetic equation; Tooth load test; Load changing regularity,WEAR,"The non-spherical single cone bit is a new type of cone bit designed on the basis of the spherical single cone bit; the new cone bit performs rock breaking by shocking and scraping to achieve a good effect on hard strata. Mechanics analysis is performed, and the kinetic equations are established in the drilling process to study the law of rock breaking of the bit. The tooth load of the bit, which is linked to the bit dynamic equation, is tested using a full-scale drilling test bench for different weight on bit (WOB) and rock. The test results demonstrate that the tooth is most easily damaged when the end of cone tooth-row tooth has the highest peak load. Axial force is greater than the tangential force and the radial force on the same tooth. The tooth load increases approximately linearly with the WOB increasing. The tooth load when drilling into sandstone is lower than that when drilling into limestone under the same WOB. In the process of the tooth rock breaking, the directions of the axial force and the tangential force remain constant, whereas the radial force direction changes. The study not only deepens the understanding of the rock breaking mechanism of a non-spherical single cone bit but also offers some guidance on the design of the bit.",1,1,2
Drilling,Design,"Li, Zhiyong; Wang, Sunan; Tao, Ye; Ma, Hongtao; Wu, Jiang",Research and application of the HTHS anti-H2S gel valve for underbalanced drilling,Underbalanced drilling (UBD); Gel valve; High temperature; Anti-H2S; High strength; Performance evaluation,,"Nowadays the whole underbalanced status of the well during underbalanced drilling process needs to be realized to a great extent, and gel valve is helpful to achieve it. However, there is occasionally H2S in the formation during underbalanced drilling (Hereinafter abbreviated as UBD), which will seriously affect the performance and lifetime of gel valve. Thus, in this paper, a formula of high temperature high strength (HTHS) anti-H2S gel valve was developed based on the optimization of different additives, such as hydrolyzed polyacryamide (HPAM), organic crosslinking agents, sulfur removal agents, etc., which could withstand temperature up to 320 degrees F(160 degrees C). The gel valve was made by crosslinking reaction at high temperature to form strong chemical bonds of spatial network structure. With its own strength and adhesion to the casing wall after gelation, the gel valve could meet the requirements for sealing. The properties of the final formula were evaluated, including viscosity, temperature stability, anti-H2S performance, gel sealing pressure, gel strength gel breaking performance, etc. In addition, a new evaluation apparatus for high toxic H2S invasion was designed specifically. The results show that the gel viscosity is around 50 mPa . s before being pumped into well, meaning a good fluidity. Its sealing pressure is high enough to balance downhole pressure and resist invasion of 10,000 ppm H2S after gelation. In addition, the gel valve can be completely broken after adding 10% breaking agents for 60 min, meaning it can easily flow back and does not influence the subsequent normal operations. Field application shows that the gel valve had good sealing property, peak of total hydrocarbon in gas logging increased from 0 to 66.6% before and after the gel broken. The gel flowed out completely after it was broken and there was successful ignition at the well site. Thus, the HTHS anti-H2S gel valve can effectively meet the operational requirements, and is an alternative method to achieve the target of the whole process of UBD operations.",2,3,0
Drilling,Design,"Huang, Wenjun; Gao, Deli; Liu, Yinghua",Mechanical model and optimal design method of tubular strings with connectors constrained in extended-reach and horizontal wells,Extended-reach drilling; Tubular string; Connector; Extending limit; Optimal design,THIN ROD; PIPE; WELLBORES; CYLINDER; TORQUE,"Mechanical analysis and optimal design of down-hole tubular strings with connectors are the key theoretical bases of design and operation in extended-reach and horizontal drilling and completion. However, the complex mechanical interaction between spring connectors and open wellbores are not fully considered in conventional tubular models and the conventional design methods are mostly based on experience and lack of rigorous mathematical derivations. To overcome these shortcomings, a new revised mechanical model and an optimal design method of connectors on down-hole tubular strings have been built. Firstly, the local loads on a unified connector which can depict common spring and rigid connectors constrained in open wellbores are studied. The local connector loads are further introduced into the local mechanical model of tubular strings. The integral mechanical model of tubular strings is amended by the local model. Next, the integral design model of connectors while considering friction reduction, tubular centricity and cost is built. The integral design model is divided into a series of local design models according to the properties of tubular mechanical behaviors on extended-reach and horizontal wellbores. At last, the mechanical model and design method are applied to drill strings with joints and casing strings with centralizers in horizontal drilling and completion. The results indicate that the revised tubular mechanical model and connector design model are stable and fast. The coupling effects of connector and buckling, local drags on connector and radial compression of spring connectors are all included in the mechanical model, so the new model gives a more sophisticated description of mechanical behaviors of tubular strings with connectors. The design results of anti-drag joints are closely related to the clean condition of wellbores. Proper optimal design of connectors and good clean condition of wellbores can inhibit helical buckling, decrease friction factor and reduce plough effect, leading to larger lateral extending limits. Compared with the initial design results of centralizers, friction force is decreased and casing centricity is increased through optimization design. The optimization results of centralizers are closely related to the weight values of friction reduction, casing centricity and cost. Therefore, the key problem is how to assign these three weight values under actual engineering conditions.",2,6,1
Drilling,Design,"Abramov, A. V.; Bikbulatov, R. V.; Kolesnik, I. Yu.; Vinokurov, A. N.; Mukhametshin, V. Kh.",Boosting economic efficiency of pads drilling projects. A comprehensive study of wells groupings and localization of the global maximum,Pad drilling; Multi-well pad; Wells grouping; Wellheads grouping; Batch drilling; Well clusters,,"The work demonstrates an approach to improve economic performance of well pads drilling projects by selecting an appropriate grouping of wells (wellheads). Scope of the work covers all thinkable groupings of a 24-well pad. We systematically enumerate groupings and estimate economic parameters of every grouping. Results of these calculations are represented in the form of NPV (Net Present Value) surfaces and NPV distributions which naturally locate global maxima for different starting flow rates. It is shown that traditionally used in oil industry groupings of wells do not provide the best economic efficiency of pads drilling projects. The top economic results could only be achieved by taking into account all available information on performance of wells. On basis of the study it is suggested to reconsider design of prospective well pads applying presented approach to boost economy of drilling. The problem of finding optimal wells grouping could be defined in two ways: specific and general. The specific formulation implies equal (constant) number of wells in every group, whereas the general formulation admits having different number of wells in the groups. It is clear that computational complexity of the specific formulation is much smaller than that of the general. The total number of groupings in the specific case is bounded from above by the product of number of wells in every group and number of these groups, i.e. for a well pad of 24 wells the total number of possible groupings is less than 576. If the total number of wells in a pad is N then the number of groupings in the general case is 2<^>(N-1), i.e. for a pad of 24 wells this gives 8,388,608 possible groupings. Having all these grouping options considered it is easy to show that the largest increase in NPV of a pad could be achieved with unequal (varying) number of wells in groups. Further analysis shows that NPV maximizing well pad configurations depend on characteristics of wells, especially the starting flow rate. Economic performance of the optimal groupings is compared with that of the pad consisting of six groups each including four wells. NPV increase of the optimal groupings is exceeding 1% and in carefully chosen parameters of the economic model reaches few millions to tens of millions of Russian rubles. It is demonstrated that reasons for these gains are, in decreasing order of importance: (i) increased oil production accompanied with elevated CAPEX (Capital Expenditures); and (ii) decreased CAPEX accompanied with reduced oil production.",3,4,0
Drilling,Design,"Li, Yinpeng; Li, Zifeng; Wang, Changjin; Qi, Min; Ren, Wenming",Particle image velocimetry analysis of plane flow field induced by drill string planetary motion based on superposition principle,Drill string; Planetary motion; Particle image velocimetry; Secondary flow,,"To study the law of a fluid plane flow induced by the planetary motion of the drill string and solve the practical engineering problems, such as improving the cutting-carrying capacity of a drilling fluid and reducing the flow pressure loss or damage to the drill string by whirling, a method based on the superposition principle is proposed. The flow field induced by the planetary motion is decomposed into a centrifugal force field through an equal angle rotation of the drill string and wellbore, and a flow field induced by through the simultaneous rotation of the drill string and wellbore. To analyze the latter, an experimental device was designed to measure the plane flow field of a fluid induced by the rotation of the internal rod and outer cylinder, and a particle image velocimetry experiment was performed. The results are as follows: the velocity of the plane flow field induced by the rotation of the internal rod and outer cylinder has an approximately symmetrical distribution, with the line connecting the cross section centers of the outer cylinder and inner rod as the axis of symmetry; when the outer cylinder is motionless and the inner rod rotates eccentrically, there is a critical value of the eccentricity upon which the secondary flow occurs and it is 0.7, moreover, the secondary flow occurs in a place far away from the inner rod and near the wall of the outer cylinder; when the inner rod and outer cylinder rotate in the same direction, the occurrence of the secondary flow is related to the eccentricity, and the area of distribution of the secondary flow expands with the increase in the eccentricity, for example, when the inner rod and outer cylinder rotate in the same direction with the speed of 60 r/min and 120 r/min respectively, the secondary flow occurs only when the eccentricity exceeds 0.4, and the area of the secondary flow becomes larger and larger with the increase of the eccentricity; when the inner rod and outer cylinder rotate in the same direction, the occurrence of the secondary flow is related to the difference in rotation speed between the inner rod and outer cylinder, and the area of distribution of the secondary flow expands with the increase in this difference, for example, when the eccentricity is 0.4, the secondary flow disappears or does not occur on the rotating speed difference being 0, and the area of distribution of the secondary flow expands with the rotating speed difference increasing from 60 r/min to 120r/min; when the inner rod and outer cylinder rotate in opposite directions, for example, when both of them rotate at speed of 60 r/min and the eccentricity of 0.2, the secondary flow occurs, the distribution of the secondary flow is approximately symmetrical and shaped like a crescent moon, and the area of distribution expands with the increase in the rotation speed of the inner rod or outer cylinder and the increase in eccentricity.",3,3,1
Drilling,Design,"Afolabi, Richard O.",A new model for predicting fluid loss in nanoparticle modified drilling mud,Nanotechnology; Drilling muds; Filtration; Predictive modeling,RHEOLOGICAL PROPERTIES,"Quantitative prediction of the properties for nano-modified drilling mud has evolved over time as a challenge towards its application. The known predictive models used in the description of drilling mud performance cannot quantitatively capture the impact of nanoparticles. In this work, existing theories on the kinetics of mud cake formation and colloidal particle behavior were applied in deriving a new fluid loss model. The new model described the fluid loss behavior of the mud with the capability of predicting a maximum for cumulative value. The new model was compared with the known API model using statistical measures, Root Mean Square Error (RMSE) and Coefficient of Determination (R-2). The new model compares favorably with the API model with RMSE and R-2 values 0.8549-0.4595 cm(3) and 98.9-99.9% respectively. The development of the model for nano-drilling fluids would allow for detailed modeling, design and cost-effective drilling operations as the quantitative amount of nanoparticles required would be captured.",4,4,0
Drilling,Design,"Nguyen, T. C.; Al-Safran, E.; Nguyen, V.",Theoretical modeling of Positive Displacement Motors performance,Positive displacement motor (PDM); Theoretical modeling; Motor performance; Downhole mud motor,PROGRESSING CAVITY PUMP,"Positive Displacement Motor (PDM) has been used extensively in directional and horizontal drilling operations. To the best of our knowledge, there is no reliable analytical model to predict the performance of PDMs. Based on motor geometry; each PDM has its own unique performance that is experimentally obtained by manufacturers using water as a testing fluid. These experiments are not only costly and time-consuming, but also with conditions that do not represent the actual down-hole conditions. The key to improve the prediction of motor performance is to, accurately; determine the flowing cross-sectional area of PDM. This paper uses Nguyen et al. (2014) model for calculating flow area of a multi-lobe progressing cavity pump, in addition to two developed analytical models for predicting the actual performance of a multi-lobe PDM. A sensitivity analysis was performed to optimize motor geometry to maximize motor torque. The developed models were validated using experimental data from a single 1:2-lobe and multi 2:3-lobe PDMs. The results revealed that when the stator lobe number is greater than five, torque is maximized if the dimensionless motor geometry is zero. The flowing cross-sectional area is reduced when the stator lobe number is higher than four lobes. However, the flow rate is always higher when the stator lobe number is increased. The results also showed that it is not recommended designing a PDM which has the stator lobe greater than twelve. Furthermore, model validation showed that the proposed model predicts the actual multi-lobe PDM performance with average percent error of less than 6% when differential pressure across the motor is 300 psi or less. The results of this study are not only important for manufacturers to optimize PDM design, but also for operators to improve the performance and efficiency of PDMs.",4,5,1
Drilling,Design,"Kan, Changbin; Yang, Jin; Yu, Xiaocong; Xie, Renjun; Wu, Yi; Li, Yanjun; Chen, Haodong; Guan, Shen; Liu, Hexing; Gu, Chunwei; Lin, Siyuan; Wang, Huanhuan; Abimbola, Fatai",Field experimental investigation of bit stick-out for different soil strengths during deepwater conductor injection,Conductor injection; Bit stick-out; Field experiment; Soil strength; Installation efficiency; Bearing capacity,,"The jetting method of deepwater conductor installation is the most widely applied method of underwater well construction. The degree of bit stick-out from the running conductor assembly directly affects the efficiency of the injection process and the bearing safety of the conductor after installation, a key factor in deepwater drilling design. In order to improve the efficiency and safety of conductor installation, it is necessary to determine a reasonable range of bit stick-out for soil formations with different shear strengths. In this paper, a modified model for selecting the bit stick-out is developed based on the theory of water jet ground breaking and the conservation of momentum. The key factors influencing the optimal bit stick-out, such as hydraulic parameters, formation strength, and the ratio of bit-to-conductor dimensions, are also considered. Orthogonal experiments of conductor jetting were conducted in in-situ soil strata with different soil strengths. The influence law of parameter change on bit stick-out is studied, including hydraulic parameters change, bit stick-out variation and running assembly structural change. The results indicate that the bit stick-out is a key factor affecting the efficient jetting of the conductor as well as the bearing capacity of the conductor after injection. For different soil shear strengths, the effects of bit stick-out on the jetting efficiency and bearing capacity are different. In soil strata with low shear strength, the bit stick-out from the running assembly has little influence on the jetting efficiency, but a significant influence on the bearing capacity of the conductor, and hydraulic factors dominate the jetting efficiency and conductor stability. In soil strata with relatively high shear strength, the bit stick-out has a significant influence on the installation efficiency and a relatively small influence on conductor bearing capacity. An optimal drill bit stick-out is then determined that provides the highest jetting efficiency under a given drilling fluid discharge rate. From the field experiments, the optimal bit stick-out is determined to be 147.4 mm, and the range of reasonable bit stick-out is 96.6-198.2 mm. In total, these research results provide a design basis and theoretical guidance for optimizing the bit stick-out of deepwater conductor running assemblies.",4,4,1
Drilling,Design,"Kan, Changbin; Yang, Jin; Yu, Xiaocong; Dong, Tiejun; Wu, Xudong; Liu, Ming; Li, Chun; Zhang, Changliang; Fu, Jinbao",Load bearing characteristics study on novel deepwater composite drilling conductor by simulation and experimental methods,Composite drilling conductor; Laboratory experiment; Numerical simulation; Vertical bearing capacity; Lateral displacement; Soil pressure variation,SAND; SOIL,"A novel design of composite drilling conductor (CDC) was carried out for improving the vertical and lateral bearing capacity. Bearing characteristics of CDC was investigated when subjected to lateral and longitudinal loads based on the ultimate subgrade reaction method and pile foundation bearing theory. Theoretical models for lateral displacement and vertical load were established. Finite element analysis (FEA) was conducted, and bearing capacity and influencing factors of the composite structure were studied. Through laboratory experiments, the interaction between the structure and the soil as well as the regularity of soil deformation and stress variation in the surrounding soil were studied during installation, vertical and lateral load application. The results showed that the vertical bearing capacity increased with increasing depth of the bucket foundation under the combined effect of the composite structure. Meanwhile, the depth of the embedded point of the composite conductor increased with an increased bending moment when subjected to a combined load with a constant vertical force. When the bending moment on the structure top was constant, the lateral displacement of the structure as well as the depth of the embedded point would increase with increasing vertical force. Furthermore, the bending moment change on the top of the CDC was more significant than the vertical force regarding the lateral displacement. It is also showed that the internal bucket foundation produced an ""elastic plugging"" effect when the CDC was subjected to vertical loading, while soil pressure transmission occurred from the upper soil to the underlying strata soil. When subjected to lateral loads, the earth pressure on the bucket sidewall was redistributed, and the bucket foundation produced a lateral supporting effect on CDC. The composite structure effectively reduced the conductor vertical and lateral displacement and improved the lateral and vertical bearing capacity. These results provide useful theoretical references for further development and optimization of the CDC structure.",4,6,1
Drilling,Design,"Movahedi, Hamed; Shad, Saeed; Mokhtari-Hosseini, Zahra B.",Modeling and simulation of barite deposition in an annulus space of a well using CFD,Barite settling; Eulerian-eulerian model; Single particle model; CFD simulation,SPHERICAL-PARTICLES; DEM SIMULATION; FLOW; FLUIDS; FIBER,"In drilling industry, barite particles settling and barite sag as a major problem can potentially impose significant operational issues. Static conditions, in which well undergoes an extended shut-in period, could occur during different drilling and completion operations such fishing operation, tripping, and logging. Despite its importance, such phenomenon is not well understood yet. To avoid issues related to barite settlement and barite sag, a good understanding of the impact of different drilling parameters on barite settlement and sag phenomenon is required. Recently, the mathematical formulation and modeling of settlement and sag processes have gained more attention. In order to better design the drilling fluids and to optimize the operational conditions such as flow rate and drill pipe rotation speed, as well as drilling well trajectory design to avoid barite settlement, the mathematical formulation and modeling of such physical phenomena is required. This study is aimed at mathematically describing and analyzing the settling of barite particles in annular concentric space without axial flow by the means of computational fluid dynamic (CFD) simulation. The modeling approach consists of two main steps: a) simple vertical annular domain and b) complex three dimensional barite settlement process in a deviated well with rotational drill pipe. The current work is based on Eulerian two phase model. The settling of the single particle and the hindering effect of other particles on settling velocity have been investigated. Based on single particle model, the rate of barite settlement and fluid pressure reduction have been modeled. However, the single particle model cannot describe the particle to particle interactions and their impacts on settlement such as particle shearing viscosity, kinetic particle viscosity, and collisional effects. In this study, the accurate and comprehensive modeling of barite settlement has been done by applying the Eulerian-Eulerian approach. The models have been validated against available published experimental data in the literature. In addition, in order to further validate the model presented here, drill pipe rotation, fluid rheology, and inclination angle impacts have been experimental investigation and compared with results of the proposed model. The results indicate that the model based on using Eulerian-Eulerian approach accurately predicts the experimental data results. Afterward, the sensitivity analyses were carried out to show the impact of inclination angle, inner pipe rotation, fluid rheology, and barite content on the rate of settlement. This study showed that drag forces induced resuspension plays a vital role in barite settlement inside a deviated well. The results reveal that the settling rate is decreased with increasing the inner pipe rotation and the vortex effect created by inner pipe rotational, play a major role in the reduction of barite settlement. The results also show that the maximum settlement rate accrues at the deviation angles between of 45-60 degrees.",5,5,0
Drilling,Design,"Shan, Liqun; Guo, Boyun; Weng, Dingwei; Liu, Zhe; Chu, Henry",Posteriori assessment of fracture propagation in refractured vertical oil wells by pressure transient analysis,Refracturing; Oil; Wells; Fractures; Propagation; Assessment,,"Oil companies have realized that refracturing old wells is the more budget-friendly way to achieve cash flow than drilling and completing new wells in the down turn of the energy industry. But it has been seen that the refracturing technology does not always work equally well in all reservoir conditions. It is desirable to have a quantitative method for assessment of well refracturing design and operations. An analytical transient flow model was derived in this study to estimate the orthogonality between the old and new hydraulic fractures after refracturing. Pressure transient data from seven wells refractured in an oilfield in the southwestern China was analyzed with the model. The model implies that orthogonal fractures created in well refracturing treatments induce orthogonal reservoir linear flow in the stimulated reservoir volume. This fracture configuration can be identified by the unit slope of pressure derivative in the log-log diagnosis plot. The angle between fractures initiated from wellbore can be estimated using pressure transient data analysis technique with a log-log diagnostic plot, with extreme situations that merged or parallel fractures will show a half slope and orthogonal fractures will show a unit slope. Case studies of data from 7 wells show that orthogonal fractures were created in 3 wells, merging or parallel fractures were created in 1 well, and fractures with non-right angles were created in 3 wells. The actual well productivity data for the 7 wells are basically consistent with the expected trend implied by the estimated fracture configurations with an exception of one well. The reason is not clear and needs further investigations. More production data from refractured wells are required to further validate the technique.",6,6,0
Drilling,Design,"Raef, Abdelmoneam E.; Kamari, Arash; Totten, Matthew; Harris, Dustin; Janssen, Kale; Lambert, Michael","The dynamic elastic and mineralogical Brittleness of Woodford shale of the Anadarko Basin: Ultrasonic P-wave and S-wave velocities, XRD-Mineralogy and predictive models",Shale; Brittleness index; Elastic properties; Mineralogy; Hydraulic fracturing,OKLAHOMA; VISCOSITY; SYSTEMS; ROCKS,"The recent advances in drilling and hydraulic fracturing technology rendered the Woodford shale of the Anadarko basin a prolific resource play producing gas and liquid hydrocarbons. Among the challenges facing improved economics, there is variable production from one well to another as well as from a completion stage to another due to the variability in facture gradient or brittleness index (BI) and the kerogen content. This investigation relies on laboratory ultrasonic P-wave and S-wave velocity in Woodford core samples to estimate BI based on the estimated elastic moduli. We modified a literature mineralogical brittleness index equation in order to take into account additional iron-rich minerals like pyrite, hematite, and iron oxides that are present in the Woodford shales, and also investigated the impact of total organic content (TOC) on the mineralogical brittleness index. Furthermore, a number of new reliable equations based on different elastic properties have been introduced in this study for the evaluation of the elastic BI, which is of significant importance in designing hydraulic fracturing in shale and tight reservoirs. In another panel of our study, the sensitivities of both mineralogical makeup of Woodford shale and elastic properties calculated -including density, acoustic impedance, Poisson's ratio, Young's modules, Lame's parameters-to the elastic brittleness index are examined. It was indicated that they have a positive effect on the prediction and can be employed in the respective predictive methods for the estimation of elastic BI. However, the analysis demonstrated that TOC has no considerable effect on mineral BI, at least in Woodford sample studied. A comparison between these newly developed predictive equations and the most commonly used methods for the prediction of elastic brittleness index available in the literature demonstrates that the new equations have a better performance in terms of both accuracy and simplicity. On comparing the BI prediction equation, with highest prediction quality ""Method 1"", that was developed based on ultrasonic elastic moduli with a corresponding equation based on sonic well-logs elastic moduli, Method1 was proven applicable to estimating BI based sonic frequency elastic moduli.",8,9,1
Drilling,Tests,"Guo, Zhengwei; Deng, Rong; Liang, Zheng; Yang, Song",Non-spherical single cone bit mechanics analysis and tooth load test,Non-spherical single cone bit; Kinetic equation; Tooth load test; Load changing regularity,WEAR,"The non-spherical single cone bit is a new type of cone bit designed on the basis of the spherical single cone bit; the new cone bit performs rock breaking by shocking and scraping to achieve a good effect on hard strata. Mechanics analysis is performed, and the kinetic equations are established in the drilling process to study the law of rock breaking of the bit. The tooth load of the bit, which is linked to the bit dynamic equation, is tested using a full-scale drilling test bench for different weight on bit (WOB) and rock. The test results demonstrate that the tooth is most easily damaged when the end of cone tooth-row tooth has the highest peak load. Axial force is greater than the tangential force and the radial force on the same tooth. The tooth load increases approximately linearly with the WOB increasing. The tooth load when drilling into sandstone is lower than that when drilling into limestone under the same WOB. In the process of the tooth rock breaking, the directions of the axial force and the tangential force remain constant, whereas the radial force direction changes. The study not only deepens the understanding of the rock breaking mechanism of a non-spherical single cone bit but also offers some guidance on the design of the bit.",1,1,2
Drilling,Tests,"Ghimire, Bishwas; Daigle, Hugh; Gray, Ken E.",Modeling formation resistivity changes due to invasion and deformation during initial leak-off test build-up,Leak-off test; Invasion; Formation resistivity,SIMULATION; PERMEABILITY; LOG,"Leak-off tests (LOTs) are performed to determine the strength of a newly drilled formation below a cased interval and to characterize the upper bound of mud weight that can be safely used while drilling the next section, without risk of formation breakdown and lost circulation. In an LOT, drilling mud is pumped into the wellbore, causing the wellbore pressure to increase and exceed the formation pore pressure. During the initial LOT build up, excess pressure in the wellbore causes the surrounding rock to deform and mud filtrate to invade into the formation via porous flow. In this paper, change in formation resistivity around a wellbore during initial LOT build-up has been investigated. Invasion is modeled assuming two-phase radial Darcy flow and deformation using a 3D finite element model. Invasion may result in an exchange of conductive ions between water-based drilling mud and formation water both by diffusion in the direction favored by the concentration gradient of the ions and by convective transport. This process is incorporated into the model by solving the radial convection-diffusion equation for the aqueous phase using a finite difference method. Archie's law is used to determine the formation resistivity. Findings show that the direct effect of deformation on porosity, therefore on formation resistivity during an LOT, is negligibly small even when the formation rock is highly compressible with compressibility in the order of 10(-3) psi(-1). While salinity solely controls formation resistivity during an LOT conducted in a fully water-saturated interval, water saturation change and salinity change compete to produce a compound effect on formation resistivity of an oil-bearing zone where water saturation varies dynamically due to displacement of formation fluids. Unlike compressibility, the effect of permeability on formation resistivity response is found to be evident and readily observable. While analyzing the formation resistivity responses at various depths of investigation (DOIs), it is found that the effect of DOI on resistivity response can be useful in studying invasion and assessing formation damage during an LOT. In addition to this, through comparing time-lapse resistivity logs at multiple DOIs during an LOT with numerically synthesized resistivity responses, the model promises a novel approach towards determining the permeability of a freshly drilled and unaltered interval.",2,2,1
Drilling,Tests,"Shan, Jingfu; Lin, Zhipeng; Zhang, Bin; Fang, Wei; Xie, Lili; Liu, Bo; Zhang, Le; Fang, Shixiang; Yan, Xue; Chen, Le","Stratigraphic architecture, depositional systems and controls on sediment filling in Nanber sub-basin, Tamtsag basin, Mongolia",Nanber sub-basin; Stratigraphic architecture; Palaeomorphology; Fault-scarp; Fault-terrace; Fault-break,ALBERTA FORELAND BASIN; SEQUENCE STRATIGRAPHY; LOW-ACCOMMODATION; JUNGGAR BASIN; RIFT-BASIN; EVOLUTION; MODEL; MIDDLE; DELTA,"The Nanber sub-basin is a secondary and minor tectonic unit in the centre of the Tamtsag Basin, Mongolia. The structural and sedimentary evolution of the depositional systems were significantly affected by active faults at the basin boundaries. In this paper, full coverage of the study area is achieved using high-quality 3D seismic and comprehensive drilling, test data, and analysis, while the stratigraphic architecture is finely characterized in an isochronal framework. The study reveals that the infilling of the lacustrine basin in the Early Cretaceous can be divided into three different evolutionary stages: syn-rift, rift climax, and post-rift. These evolutionary stages have different sequences and sedimentary systems: (1) the syn-rift sequence stage (SQ1+SQ2), which is characterised as ""narrow basin-shallow water"", developed primarily from fan-delta sedimentary systems; (2) the rift climax sequence stage (SQ3), which is characterized as ""wide basin-deep water"", developed primarily from fan-delta and nearshore subaqueous fan sedimentary systems; and (3) the post-rift sequence stage (SQ4), which is characterized as ""wide basin-shallow water"", developed primarily from braided river delta sedimentary systems. The varying tectonic evolutionary stages formed different types of stratigraphic structures and sedimentary fillings. Simultaneously, differential tectonic settlement and fault block rotation controlled the different palaeogeomorphology backgrounds in the basin. The fault-scarp formed by rapid subsidence of the boundary faults, which predominantly dictated the formation and development of fan-deltas. The fault-terrace formed by differential settlement and controlled the formation and development of fan-deltas and subaqueous fans, while the secondary fault-break in the basin largely controlled the formation and development of sub-lacustrine fans. During the post-rifting period, most of the boundary faults that had been active, such as controlling traps, basically ceased, and formed a braided river delta depositional system characterised by widely developed sedimentation along the long-axis of the basin. Thus, under conditions featuring plenty of sediment and weak tectonic activity, the key factor controlling sequence stratigraphy and sedimentary system filling patterns within the lake basin was the abundant source supply, not tectonic activity.",3,4,1
Drilling,Tests,"Nguyen, T. C.; Al-Safran, E.; Nguyen, V.",Theoretical modeling of Positive Displacement Motors performance,Positive displacement motor (PDM); Theoretical modeling; Motor performance; Downhole mud motor,PROGRESSING CAVITY PUMP,"Positive Displacement Motor (PDM) has been used extensively in directional and horizontal drilling operations. To the best of our knowledge, there is no reliable analytical model to predict the performance of PDMs. Based on motor geometry; each PDM has its own unique performance that is experimentally obtained by manufacturers using water as a testing fluid. These experiments are not only costly and time-consuming, but also with conditions that do not represent the actual down-hole conditions. The key to improve the prediction of motor performance is to, accurately; determine the flowing cross-sectional area of PDM. This paper uses Nguyen et al. (2014) model for calculating flow area of a multi-lobe progressing cavity pump, in addition to two developed analytical models for predicting the actual performance of a multi-lobe PDM. A sensitivity analysis was performed to optimize motor geometry to maximize motor torque. The developed models were validated using experimental data from a single 1:2-lobe and multi 2:3-lobe PDMs. The results revealed that when the stator lobe number is greater than five, torque is maximized if the dimensionless motor geometry is zero. The flowing cross-sectional area is reduced when the stator lobe number is higher than four lobes. However, the flow rate is always higher when the stator lobe number is increased. The results also showed that it is not recommended designing a PDM which has the stator lobe greater than twelve. Furthermore, model validation showed that the proposed model predicts the actual multi-lobe PDM performance with average percent error of less than 6% when differential pressure across the motor is 300 psi or less. The results of this study are not only important for manufacturers to optimize PDM design, but also for operators to improve the performance and efficiency of PDMs.",4,5,1
Drilling,Tests,"Zamiran, Siavash; Rafieepour, Saeed; Ostadhassan, Mehdi",A geomechanical study of Bakken Formation considering the anisotropic behavior of shale layers,Unconventional reservoirs; Shale layers; Bakken Formation; Williston basin; Geomechanical modeling; FLAC3D,WELLBORE STABILITY,"In this study, the geomechanical behavior of the shale layers is investigated in various capacities under isotropic and anisotropic scenarios. Primarily, an accurate estimation of geomechanical properties is carried out. Different geomechanical parameters including Young's modulus, Poisson's ratio, and rock strength for both isotropic and anisotropic modes are estimated based on field investigations for all three members. Dynamic elastic moduli are estimated from advanced acoustic log tests, and static moduli are measured in the laboratory. Then, a comparison is made, and a correlation is developed to convert dynamic to static elastic properties. Consequently, stress alteration and deformation changes around the boreholes are modeled in response to drilling. Measured parameters are utilized in a finite difference numerical model to predict rock deformation and stress variation. Based on the geomechanical models, stress regimes and medium deformations around the borehole are compared in both anisotropic and isotropic circumstances. Moreover, the effects of wellbore inclination on stress distribution, wellbore deformation, and yielding zones are discussed. The effects of wellbore inclination on stress distribution are monitored by studying horizontal principal stresses. According to the results, the relative plasticity radius of the medium is determined by dividing maximum radius of the yielded zone by the primary radius of the wellbore. Consequently, the failure zones and relative plasticity radiuses are compared for different well inclinations from vertical to horizontal wellbores. The relative plasticity radiuses are shown constant from vertical borehole to the borehole with 45 degrees of inclination with a gradual increase in values towards a horizontal borehole.",4,4,1
Drilling,Tests,"Mousavi, E.; Cheshomi, A.; Ashtari, M.",Estimating elasticity modulus and uniaxial compressive strength of sandstone using indentation test,UCS; Elasticity modulus; Indentation test; Critical transition force (CTF); Indentation modulus (IM),LOAD TEST; ROCK,"Elastic modulus (E) and uniaxial compressive strength (UCS) are very important engineering parameters that is required for many engineering projects. In some projects such as well drilling for oil production, deep underground tunnels in crushed zone, due to the depth of the well and fractures of rocks, there are some problems for obtained standard core samples. In this situations various methods have been developed for determining UCS and E using drilling cutting. Indentation test is one of these methods, in this method, an indenter penetrates into the stabilized samples in the surrounding material and then Critical Transition Force (CTF) and Indentation modulus (IM) determine. In the present study in order to developing the application of indentation testing for sandstone, and investigate the effect of particles size, shape and thickness, 14 sandstone blocks were collected from different formations in Iran and their physical characteristics, UCS and, E were measured using standard methods. After crushing the blocks and preparing 600 particles with dimensions of 3x3x3 mm(3), 5x5x3 mm(3), 5x5x5 mm(3), 5x5x8 mm(3), and 8x8x8 mm(3) and irregular shape particles with a thickness of 5 mm, indentation tests were performed on each particle and CTF and IM were calculated for each particle separately. According to the tests carried out some empirical relationships were proposed between UCS CTF (with R-2 >= 0.86) and E - IM (with R-2 >= 0.73) for different shapes and dimensions. Due to the differences in the dimensions of the produced particles, investigating the effect of surface and thickness of particle on the CTF and the IM revealed that the particle's surface had a considerable effect on the CTF and IM; however, the effect of thickness was negligible. Using the dimensionless surface parameter (S and Si), some empirical relationships between UCS - CTF/S (with R-2 >= 0.80) and E - IM/Si (with R-2 >= 0.77) were proposed for predicting UCS and E of sandstone particles with different shapes and dimensions. The accuracy of these relations was validated by performing standard uniaxial and indentation tests on 4 sandstone blocks and comparing measured UCS and E with those predicted using these relations. This comparison showed there is a good correlation between measured and predicted values. The proposed equations in this study were compared with results of previous studies. The relationship proposed in the present study to predict sandstone UCS has a similar accuracy with those proposed in by other researchers.",4,5,2
Drilling,Tests,"Liang, Bo; Lan, Hui-qing; Lin, Nan",Diffusion simulation and safety assessment of oil leaked in the ground,Oil; Leak Multi-phase flow in porous media; Diffusion; Test; Safety assessment,ASSESSING NAPL CONTAMINATION; MULTIPHASE FLOW MODEL; POROUS-MEDIA; GRAVITY CURRENTS; RISK-ASSESSMENT; FRACTURED MEDIA; PERSPECTIVE; SITE,"Oil leaked in the ground causes pollution of land and groundwater, and even leads to an explosion. Therefore, it is significant to make a research on safety assessment of diffusion of oil in the ground after oil leakage accident happened. Taken a perforation-caused leakage accident of oil in buried piping in China as an example, the computational fluid dynamics method of multiphase flow in porous media was used to determine the distribution of leaked oil in the ground in this paper. Then, an onsite drilling test was carried put and it's found that the simulation of distribution of leaked oil agreed with the test result. Finally, on the base of the simulation results, fuzzy synthetic evaluation method was carried out and hazardous areas of oil leaked in the ground were put forward.",5,6,2
Drilling,Tests,"Freire Soares, Andreia Silveira; Costa Marques, Monica Regina; Calcada, Luis Americo; Borges Filho, Moacyr Nogueira; de Oliveira Petkowicz, Carmem Lucia",Interaction of blockers on drilling fluids rheology and its effects on sealing of fractures and prevention of filtrate invasion,Drilling fluids; Lost circulation and loss control material,XANTHAN GUM; PARTICLE-SIZE; FLOCCULATION; BENTONITE; WATER; MONTMORILLONITE; PERFORMANCE; POLYMERS; CHARGE,"Drilling fluids from oil wells play an important role in the drilling operations, including cleaning and maintaining well stability, as well as cooling and lubricating the drill bit. Invasion of fluid in the rock formation, through natural or induced fractures, can compromise the entire well. In this work we evaluated the effect of combination of viscosifiers xanthan gum (XG), carboxymethylcellulose (CMC), Hydroxypropylstarch (HPS) and bentonite in the interaction with lost circulation materials diatomaceous earth (DE) and hydrogel (HG). The main objective was to obtain a product with adequate rheological properties showing viscoelastic behavior and minimizing loss of fluid to the wellbore. Tests of X-ray diffraction (XRD) and zeta potential were performed to analyze the interactions between the particles present in the fluids. With rheological tests we studied the effects of the addition of different components on the fluid rheology. XRD technique showed that the bentonite deflocculated only in polymer suspensions with DE. The results of zeta potential suggest that only the fluid with Hydroxypropylstarch and HG was completely flocculated and unstable, showed through particle sizes distribution tests. The gel modulus (G') and viscous modulus (G '') of the fluids were affected by the interaction of bentonite layers with lost circulation materials particles, with significant increase of G' with the addition of HG to the suspension. There was a decrease of viscosity due to agglomeration of HG and DE particles, an increase of G' can be observed as well. Among all the fluids, the suspension of CMC and bentonite showed better affinity with the HG lost circulation material, presenting thermal stability and a wide range of particle size, essential property to avoid the loss of fluid through the fractures and pores of the rock formation.",6,6,2
Drilling,Tests,"Corina, A. N.; Hovda, S.",Automatic lithology prediction from well logging using kernel density estimation,Real-time drilling data; Gamma ray; Statistical classification; Kernel density estimation; Non-parametric data; Lithology prediction,FACIES; LOGS,"Technologies of real-time data measurement during drilling operation have kept the attention of petroleum industries in the past years, especially with the benefit of real-time formation evaluation through logging-while-drilling technology. It is expected that most of the logging data will be recorded in real-time operation. Hence, application of automated lithology prediction tool will be essential. An automatic method to predict lithology from borehole geophysical data was developed. It was solved as a multivariate classification problem with multidimensional explanatory variables. The learning algorithm combines kernel density estimates and a classification rule that is based on these estimates. The goal of this work is to test the method on a univariate variable and validate the prediction accuracy by calculating the misclassification rates. In addition, the results will be established as a baseline for application in practice and future developments for multivariate variables analysis. Gamma-ray from wireline logging is selected as the variable to describe two lithology groups of shale and not-shale. Data from six wells in the Norwegian Continental Shelf were extracted and examined with aids of explorative data analysis and hypothesis testing, and then divided into a training-and test data set. The selected algorithm processed the training data into models, and later each element of test data was assigned to the models to get the prediction. The results were validated with cutting data, and it was proved that the models predicted the lithology effectively with misclassification rates less than 15% at its lowest and average of +/- 31%. Moreover, the results confirmed that the method has a promising prospect as lithology prediction tool, especially in real-time operation, because the non-parametric approach allows real-time modeling with fewer data assumptions required.",7,8,2
Drilling,Tests,"Paes de Godoi, Felipe Augusto; Scheid, Claudia Miriam; Bernardo, Leticia Siqueira; de Oliveira, Beatriz Rosas; Borges Filho, Moacyr Nogueira; Calcada, Luis Americo",Study of the pressure drop and the flow of loss circulation material suspensions in a physical simulator of fractures,Fractures sealing; Flow of suspensions; Calcium carbonate; Particulate system,,"The loss of fluid to the rock formation is one of the main problems encountered in oil well drilling operations. To mitigate this problem, particulate materials responsible for sealing fractures or for strengthening the well are used. The main objective of this work is to study the flow of Non-Newtonian suspensions through fractures, the pressure drop associated with this flow and the process of sealing fractures using particulate materials suspensions. The flow through fracture of Non-Newtonian suspensions was studied using an apparatus that allowed these fluids to flow through three different artificial fractures with widths of 2 mm, 5 mm and 10 mm and an average 1 cm depth. The suspensions were prepared by mixing water, viscosifying polymer and particulate materials based on laminar calcium carbonate. The particulate materials used are called fine and medium because they have different particle size distributions. The characterization of the solutions and suspensions was carried out from the rheological tests and the determination of the densities and the particle size distributions. The influence of factors such as flow rate, concentration and particle size distributions on the flow of the suspensions through fractures and its sealing capabilities were evaluated. The suspensions of the fine material particles were able to seal only the 2 mm fracture. The suspension composed of the particles of the medium material proved efficient in sealing the three fractures. A mathematical methodology was proposed with the objective of correlating the pressure drop and the flow rate of suspensions in fractures.",7,7,3
Drilling,Tests,"Masoudi, Pedram; Aifa, Tahar; Memarian, Hossein; Tokhmechi, Behzad",Uncertainty assessment of porosity and permeability by clustering algorithm and fuzzy arithmetic,Porosity; Permeability; Uncertainty projection; Fuzzy arithmetic; Fuzzy power; Clustering,WELL-LOGS; PREDICTION; IRAN; FIELD,"A hybrid clustering-fuzzy arithmetic algorithm is here proposed, which uses cluster analysis to quantify porosity uncertainty, then the uncertainty is projected to the irreducible water saturation and permeability by the means of fuzzy arithmetic. The proposed method is applied to five wells of the carbonate Sarvak Formation, in an Iranian onshore oil-field. First, cluster analysis is applied to the porosity logs including neutron porosity, bulk density and sonic transit time. The uncertainty range of porosity is defined by the range of neutron porosity in each cluster. In order to estimate the core porosity, neutron porosity is calibrated to the core porosity in each cluster. Due to the average of error, the calibrated clustering-based porosity is at least 33% more accurate than the conventional methods. Based on the generalization ability of porosity estimators, a homogeneous porosity zone is determined northward. Irreducible water saturation, analyzed by the proposed method, has less overestimation, compared to the conventional evaluation of irreducible water saturation. Permeability fuzzy number is compatible with core tests, except in well S1, which is drilled in a location, compressed by two stress regimes (N-S and NW-SE). Two criteria are defined for validating the fuzzy numbers by core data: (i) Crit1 finds an average alpha-cut of core values; (ii) Crit2 finds the best alpha-cut to optimize uncertainty interval of the fuzzy number. The alpha > 0.90 is the most appropriate for porosity and permeability studies.",9,9,0
Drilling,Drill String,"Pirir, Ivan; Jinasena, Asanthi; Sharma, Roshan",A dynamic model for drain back to active mud pit combined with a well model during drilling,Well drilling; Combined model; Open channel flow; Saint-Venant equations; Kurganov-Petrova scheme,SHALLOW-WATER EQUATIONS; CENTRAL-UPWIND SCHEME; SYSTEM,"There are no published mathematical models that combine the dynamics of the returned fluid flow to the active mud pit (top side drilling) and the dynamics of the bottom side of the well being drilled. In this paper a simple dynamic model that combines the top and the bottom side drilling operations is provided. The model has been simulated for various operational scenarios during drilling including pipe connection, movements of drill string and reservoir influx. This combined model can be used for studying not only the pressure dynamics but also to estimate the return fluid flow rate and hence to detect kicks and losses occurring in the well.",1,1,0
Drilling,Drill String,"Huang, Wenjun; Gao, Deli; Liu, Yinghua",Mechanical model and optimal design method of tubular strings with connectors constrained in extended-reach and horizontal wells,Extended-reach drilling; Tubular string; Connector; Extending limit; Optimal design,THIN ROD; PIPE; WELLBORES; CYLINDER; TORQUE,"Mechanical analysis and optimal design of down-hole tubular strings with connectors are the key theoretical bases of design and operation in extended-reach and horizontal drilling and completion. However, the complex mechanical interaction between spring connectors and open wellbores are not fully considered in conventional tubular models and the conventional design methods are mostly based on experience and lack of rigorous mathematical derivations. To overcome these shortcomings, a new revised mechanical model and an optimal design method of connectors on down-hole tubular strings have been built. Firstly, the local loads on a unified connector which can depict common spring and rigid connectors constrained in open wellbores are studied. The local connector loads are further introduced into the local mechanical model of tubular strings. The integral mechanical model of tubular strings is amended by the local model. Next, the integral design model of connectors while considering friction reduction, tubular centricity and cost is built. The integral design model is divided into a series of local design models according to the properties of tubular mechanical behaviors on extended-reach and horizontal wellbores. At last, the mechanical model and design method are applied to drill strings with joints and casing strings with centralizers in horizontal drilling and completion. The results indicate that the revised tubular mechanical model and connector design model are stable and fast. The coupling effects of connector and buckling, local drags on connector and radial compression of spring connectors are all included in the mechanical model, so the new model gives a more sophisticated description of mechanical behaviors of tubular strings with connectors. The design results of anti-drag joints are closely related to the clean condition of wellbores. Proper optimal design of connectors and good clean condition of wellbores can inhibit helical buckling, decrease friction factor and reduce plough effect, leading to larger lateral extending limits. Compared with the initial design results of centralizers, friction force is decreased and casing centricity is increased through optimization design. The optimization results of centralizers are closely related to the weight values of friction reduction, casing centricity and cost. Therefore, the key problem is how to assign these three weight values under actual engineering conditions.",2,6,1
Drilling,Drill String,"Li, Yinpeng; Li, Zifeng; Wang, Changjin; Qi, Min; Ren, Wenming",Particle image velocimetry analysis of plane flow field induced by drill string planetary motion based on superposition principle,Drill string; Planetary motion; Particle image velocimetry; Secondary flow,,"To study the law of a fluid plane flow induced by the planetary motion of the drill string and solve the practical engineering problems, such as improving the cutting-carrying capacity of a drilling fluid and reducing the flow pressure loss or damage to the drill string by whirling, a method based on the superposition principle is proposed. The flow field induced by the planetary motion is decomposed into a centrifugal force field through an equal angle rotation of the drill string and wellbore, and a flow field induced by through the simultaneous rotation of the drill string and wellbore. To analyze the latter, an experimental device was designed to measure the plane flow field of a fluid induced by the rotation of the internal rod and outer cylinder, and a particle image velocimetry experiment was performed. The results are as follows: the velocity of the plane flow field induced by the rotation of the internal rod and outer cylinder has an approximately symmetrical distribution, with the line connecting the cross section centers of the outer cylinder and inner rod as the axis of symmetry; when the outer cylinder is motionless and the inner rod rotates eccentrically, there is a critical value of the eccentricity upon which the secondary flow occurs and it is 0.7, moreover, the secondary flow occurs in a place far away from the inner rod and near the wall of the outer cylinder; when the inner rod and outer cylinder rotate in the same direction, the occurrence of the secondary flow is related to the eccentricity, and the area of distribution of the secondary flow expands with the increase in the eccentricity, for example, when the inner rod and outer cylinder rotate in the same direction with the speed of 60 r/min and 120 r/min respectively, the secondary flow occurs only when the eccentricity exceeds 0.4, and the area of the secondary flow becomes larger and larger with the increase of the eccentricity; when the inner rod and outer cylinder rotate in the same direction, the occurrence of the secondary flow is related to the difference in rotation speed between the inner rod and outer cylinder, and the area of distribution of the secondary flow expands with the increase in this difference, for example, when the eccentricity is 0.4, the secondary flow disappears or does not occur on the rotating speed difference being 0, and the area of distribution of the secondary flow expands with the rotating speed difference increasing from 60 r/min to 120r/min; when the inner rod and outer cylinder rotate in opposite directions, for example, when both of them rotate at speed of 60 r/min and the eccentricity of 0.2, the secondary flow occurs, the distribution of the secondary flow is approximately symmetrical and shaped like a crescent moon, and the area of distribution expands with the increase in the rotation speed of the inner rod or outer cylinder and the increase in eccentricity.",3,3,1
Drilling,Drill String,"Wang, Changjin; Li, Zifeng; Li, Yinpeng; Qi, Min; Wang, Lei",Experimental study on the rotation of compression-buckling rod column in a liquid-filled cylinder,Drill string; Rotation; Buckling; Axial load; Backward whirl,,"In oil drilling, the main form of movement of the bottom hole assembly is self-rotation and whirling after buckling. The rotation of a compression-buckling rotation drill string can increase the frictional force between the drill string and borehole wall, induce lateral vibration and whirl of the drill string, generate borehole wall instability and drill string damage, and even cause a drilling failure. At present, studies on the motion laws of a pressure-rotating buckling drill string are incomplete, and some are even incorrect, necessitating further improvements. In this work, the effects of axial load, rotational speed, drilling fluid, and inner diameter on the rotational motion of a compression-buckling column in a cylinder were experimentally studied. The dissipation energy before and after the transition state of the simulated drill string, from the forward whirl to self-rotation, or from the forward whirl to the backward whirl, were analysed. The results indicate the following: (1) With an increase in the axial load, a buckling drill string first experiences forward whirl. Next, both forward whirl and self-rotation occur, along with a combination of backward whirl and self-rotation along the partial vertical wall. Finally, backward whirl occurs along the wall. (2) A dynamic lubrication of the drilling fluid can reduce the forward whirl rotation amplitude of the drill string and prevent the formation of backward whirl. (3) When dynamic lubrication by the drilling fluid is improved, the borehole diameter is reduced, the hole-deviation angle increases, the critical axial load of the backward whirl increases. (4) Backward whirl may occur twice for the drill string as the axial load increases. (5) The state transition of the drill string motion conforms to the minimum dissipation power principle. The experimental results described herein can serve as a reference for studies regarding drill string dynamics and drilling practice.",5,6,1
Drilling,Drill String,"Wang, Heng; Guan, Zhi-chuan; Shi, Yu-cai; Chen, Wei-qing; Liu, Yong-wang; Zhang, Bo; Liang, De-yang; Wang, Xiao-hui",Modeling and analyzing the motion state of bottom hole assembly in highly deviated wells,Motion state; BHA; Highly deviated wells; Rotary speed; Weight on bit,STEERABLE DRILLING SYSTEM; LATERAL VIBRATION; FINITE-ELEMENT; ROTARY; DRILLSTRINGS; DYNAMICS,"Motion state of bottom hole assembly (BHA) has a great effect on the performance of downhole drilling tools. In this article, we developed a finite element model for characterizing the lateral motion of BHA in highly deviated wells taking discontinuous interaction between drill strings and wellbore into consideration. Numerical simulations were conducted by solving the motion equation through Newmark method. To verify the established model, an indoor experimental apparatus was built based on the similarity criterion. Numerical and experimental simulation results were compared and analyzed under different rotary speed, weight on bit (WOB) and well inclination condition. Both of the results showed that BHA locates in and swings along the lower right part of borehole in highly deviated wells without forming into backward whirl motion. Rotary speed has an obvious effect on BHA lateral motion state where the vibration amplitude and frequency get improved with the increase of rotary speed. Compared with rotary speed, WOB and well inclination angle has a much smaller effect on the BHA lateral motion in highly deviated wells. Based on the analyses, relevant recommendations were given for the engineering practical use. This study can help understand the dynamic characteristics of BHA in highly deviated wells and select operation parameters for better drilling.",8,10,0
Drilling,Drill String,"Vega, Marcia Peixoto; de Moraes Oliveira, Gabrielle Fontella; Fernandes, Lindoval Domiciano; Martins, Andre Leibsohn",Monitoring and control strategies to manage pressure fluctuations during oil well drilling,Kick; Circulation loss; Downhole pressure control; Decision making; Gain scheduling,LOST CIRCULATION; KICK DETECTION; MODEL; FLUID; DEEP; MUD; MITIGATION; PREDICTION; RESERVOIR; SYSTEM,"During drilling the mud flows through the drill string and exits through the choke valve. The mud density range has as constraints: pore pressure (minimum limit) and fracture pressure (maximum limit). In fact, annulus bottomhole (downhole) pressure needs to be higher than pore pressure, in order to prevent kick, and smaller than fracture pressure, for avoiding mud loss and formation damage. Experimental and simulation studies were implemented in order build a monitoring - diagnosing tool working together with a decision making routine based on an adaptive control scheme that employs gain scheduling. An experimental unit was built, presenting the most important characteristics of the drilling process. The transient nature of annulus bottomhole pressure is due to the process inherent disturbances: rheology, rate of penetration (ROP), kick and mud loss, which were all implemented at the experimental unit. The major objective of the present paper is using the experimental plant and a phenomenological model for implementing real time process automation, in order to assure drilling inside operational window, using in line measurements for flow and density disturbances under circulation loss and kick scenarios.",8,8,1
Drilling,Drill String,"Liang, Zheng; Zhu, ZhaoLiang",Critical helical buckling load assessment of coiled tubing under axial force by use of the explicit finite-element method,Helical buckling; Coiled tubing; Axial force; Explicit FEA; Transmission,,"Previous theoretical formulations for helical buckling of drill strings vary significantly and are mostly proposed for the linear questions. But there are a little no-linear questions in the mechanical behaviour of tubulars. Explicit finite element analysis (FEA) method has the ability to consider geometric details and nonlinearities. This paper builds an explicit FEA model to describe the behaviors of comprehensive buckling and transmission of axial force for coiled tubing (CT) with residual bending in a horizontal well. The calculational results show that the CT with residual bending is easier to buckle than a straight CT. For the CT with an initial sinusoidal shape, the parameters of initial amplitude and initial pitch are inversely proportional to the helical buckling force, and the outer diameter (OD) is proportional to the helical buckling force. In the process of axial force transmission, the parameters of initial amplitude and frictional coefficient are inversely proportional to the axial force, the OD and initial pitch are proportional to axial force. Residual curvature in coiled tubing appears to have only a small effect on its downhole performance, based on FEA modeling of CT with sinusoidal curvature.",9,10,0
Drilling,Drill String,"Zeng, Shubin; Li, Dawei; Wilton, Donald R.; Chen, Jiefu",Fast and accurate simulation of electromagnetic telemetry in deviated and horizontal drilling,Deviated and horizontal drilling; Electromagnetic telemetry; Integral equations; Layered medium Green's function; Thin wire kernel,MULTILAYERED MEDIA; GREENS-FUNCTIONS; TRANSMISSION,"Electromagnetic (EM) telemetry systems are widely used for measurement-while-drilling (MWD), especially in unconventional drilling. In this paper, a numerical method for the simulation of EM telemetry systems in deviated and horizontal drilling is introduced. The underground formation is assumed to be horizontally layered media, and the long, metal drill string acts as an antenna that may be treated as a thin wire excited by a gap voltage source located near the drill bit. The numerical model employs the electric field integral equation (EFIE) and the method of moments (MoM) to obtain a linear system for the axial current distribution on the drill string, which is subdivided into several one-dimensional segments. By using the thin wire kernel, near-field interactions can be evaluated accurately and efficiently, while also reducing problem dimensionality and singularity order of the homogeneous medium contribution to the layered medium Green's function (LMGF). The latter typically takes the form of a dyadic spectral domain integral, the asymptotics of whose integrands may be estimated and combined with Kummer's method to accelerate its evaluation, with the asymptotic correction terms evaluated in closed or easily evaluated forms. Numerical results are presented to verify the fast and accurate performance of the proposed approach. Results for signal voltage receivability by a surface antenna are also presented and discussed.",9,10,0
Drilling,Lost Circulation,"Chen, Yuanhang; Yu, Mengjiao; Takach, Nicholas",Modeling and analysis of coupled thermal-hydrologic-mechanical processes during lost circulation,Wellbore stability; Lost circulation; Numerical simulation; Heat transfer; Geomechanics; Coupled processes,WELLBORE STABILITY; SIMULATION; BOREHOLE; FLUIDS; FLOW,"Wellbore stability remains as one of the major challenges to drilling engineers. Results of recent survey showed about one third of non-productive time of drilling operation is classified as borehole problem, where a significant part is attributed to borehole instability. The thermal regime of a formation in the vicinity of a wellbore affects the stability of the well significantly during drilling operations, especially in High pressure High Temperature (HPHT) wells. This paper describes how the thermal behavior of a tubular-wellbore-reservoir system is altered during mud loss, as well as its consequent impact on near-wellbore state of stresses and critical mud weights. A fully coupled three dimensional thermal-poro-elastic model, integrated with a transient tubular-wellbore-reservoir heat flow model, is developed to evaluate near-wellbore stresses and pore pressure redistribution during mud loss. The forced convective heat transfer coefficients in both conduits-drillpipe and annulus-are rigorously determined as a function of local flow and fluid properties. The results reveal that continuous mud loss destabilizes the wellbore as the pressure window shifts considerably over time. Critical mud weights for both tensile and compressive failures decrease during mud loss over the entire length of the wellbore, in addition to the point of loss. During severe losses, the fracture gradient at the bottom of the well can decrease by over 1 ppg within the first hour. This can intensify the existing fracturing condition and allow the development of new fractures at other locations, which leads to further losses as time progresses. This model enables prediction of a more realistic operating window during lost circulation by taking additional thermally-induced effects into account. In addition, failure indexes during mud loss considering P-rho-T coupling effect on a compressible mud column in the annulus are investigated with the proposed model. During drilling operations, especially Managed Pressure Drilling (MPD) and offshore applications with moderate to severe mud loss, the operation window should be modified by taking mud loss-induced thermal stresses into account. The mud type, wellbore geometry, circulation rate, and other parameters affect the magnitude of shift in critical mud weight during mud loss, hence evaluations should be based on specific cases.",0,0,1
Drilling,Lost Circulation,"Ghimire, Bishwas; Daigle, Hugh; Gray, Ken E.",Modeling formation resistivity changes due to invasion and deformation during initial leak-off test build-up,Leak-off test; Invasion; Formation resistivity,SIMULATION; PERMEABILITY; LOG,"Leak-off tests (LOTs) are performed to determine the strength of a newly drilled formation below a cased interval and to characterize the upper bound of mud weight that can be safely used while drilling the next section, without risk of formation breakdown and lost circulation. In an LOT, drilling mud is pumped into the wellbore, causing the wellbore pressure to increase and exceed the formation pore pressure. During the initial LOT build up, excess pressure in the wellbore causes the surrounding rock to deform and mud filtrate to invade into the formation via porous flow. In this paper, change in formation resistivity around a wellbore during initial LOT build-up has been investigated. Invasion is modeled assuming two-phase radial Darcy flow and deformation using a 3D finite element model. Invasion may result in an exchange of conductive ions between water-based drilling mud and formation water both by diffusion in the direction favored by the concentration gradient of the ions and by convective transport. This process is incorporated into the model by solving the radial convection-diffusion equation for the aqueous phase using a finite difference method. Archie's law is used to determine the formation resistivity. Findings show that the direct effect of deformation on porosity, therefore on formation resistivity during an LOT, is negligibly small even when the formation rock is highly compressible with compressibility in the order of 10(-3) psi(-1). While salinity solely controls formation resistivity during an LOT conducted in a fully water-saturated interval, water saturation change and salinity change compete to produce a compound effect on formation resistivity of an oil-bearing zone where water saturation varies dynamically due to displacement of formation fluids. Unlike compressibility, the effect of permeability on formation resistivity response is found to be evident and readily observable. While analyzing the formation resistivity responses at various depths of investigation (DOIs), it is found that the effect of DOI on resistivity response can be useful in studying invasion and assessing formation damage during an LOT. In addition to this, through comparing time-lapse resistivity logs at multiple DOIs during an LOT with numerically synthesized resistivity responses, the model promises a novel approach towards determining the permeability of a freshly drilled and unaltered interval.",2,2,1
Drilling,Lost Circulation,"Xiao, Dong; Meng, Yingfeng; Li, Gao; Shu, Gang; Li, Shutao; Guo, Yuying",Development of a mathematical model and experimental validation of borehole instability due to gravity displacement during drilling in a fractured formation,Gravity displacement; Fracture formation; Drilling; Mathematical model; Model experiment,LOST CIRCULATION; WELL KICK,"Lost Circulation and overflow often occur concurrently in fracture formation due to gravity displacement, causing a downhole complexity, out of control for blowout, reservoir damage, well control difficulty, drilling cycle prolonging and cost overrun. There is still ongoing investigation and lack of basic theoretical understanding. In this paper, a mathematical model of gas-liquid gravity displacement is established and solved, as well as verified by model experiment. The results are used to develop a theoretical foundation that explains the phenomena, and a solution method is proposed for practical application.",3,5,0
Drilling,Lost Circulation,"Hu, Xiaodong; Song, Xianzhi; Liu, Yu; Li, Gensheng; Shen, Zhonghou; Lyu, Zehao",Aspect ratio of spalls of granite in flame-jet spallation and its effect on the modeling prediction of spallation properties,Drilling engineering; Thermal spallation; Spalls; Granite; Aspect ratio,THERMAL SPALLATION; NUMERICAL-SIMULATION; LOST CIRCULATION; ROCK; PERFORMANCE; INJECTION,"Thermal spallation is an effective drilling technique for hard rock formations. Models based on Weibull statistical failure theory are widely used in the simulation in thermal spallation. The aspect ratio (diameter/thickness), a parameter in Weibull models, is assumed as a constant in the previous simulations of flame-jet spallation. We conducted the flame-jet experiment in granite and collected 280 spalls to calculate the aspect ratio. Results show that the aspect ratio is size-dependent. A new trimodal distribution of aspect ratio is proposed to incorporate in Weibull models to accurately predict the rate of penetration. The comparison results show that the size-dependent aspect ratio has a significant effect on the rate of penetration. Meanwhile, a smaller aspect ratio (6.91) is recommended for the prediction of the surface temperature in the Weibull model, by which the predicted result can get a better match with the published data. Additionally, given the aspect ratio and rock intrinsic strength of 6.91 (dimensionless) and 70 Mpa, a homogeneity factor is recommended between 10 and 17 (dimensionless). This study can provide an accurate aspect ratio for simulating properties of flame-jet spallation in granite using Weibull models.",3,3,1
Drilling,Lost Circulation,"Freire Soares, Andreia Silveira; Costa Marques, Monica Regina; Calcada, Luis Americo; Borges Filho, Moacyr Nogueira; de Oliveira Petkowicz, Carmem Lucia",Interaction of blockers on drilling fluids rheology and its effects on sealing of fractures and prevention of filtrate invasion,Drilling fluids; Lost circulation and loss control material,XANTHAN GUM; PARTICLE-SIZE; FLOCCULATION; BENTONITE; WATER; MONTMORILLONITE; PERFORMANCE; POLYMERS; CHARGE,"Drilling fluids from oil wells play an important role in the drilling operations, including cleaning and maintaining well stability, as well as cooling and lubricating the drill bit. Invasion of fluid in the rock formation, through natural or induced fractures, can compromise the entire well. In this work we evaluated the effect of combination of viscosifiers xanthan gum (XG), carboxymethylcellulose (CMC), Hydroxypropylstarch (HPS) and bentonite in the interaction with lost circulation materials diatomaceous earth (DE) and hydrogel (HG). The main objective was to obtain a product with adequate rheological properties showing viscoelastic behavior and minimizing loss of fluid to the wellbore. Tests of X-ray diffraction (XRD) and zeta potential were performed to analyze the interactions between the particles present in the fluids. With rheological tests we studied the effects of the addition of different components on the fluid rheology. XRD technique showed that the bentonite deflocculated only in polymer suspensions with DE. The results of zeta potential suggest that only the fluid with Hydroxypropylstarch and HG was completely flocculated and unstable, showed through particle sizes distribution tests. The gel modulus (G') and viscous modulus (G '') of the fluids were affected by the interaction of bentonite layers with lost circulation materials particles, with significant increase of G' with the addition of HG to the suspension. There was a decrease of viscosity due to agglomeration of HG and DE particles, an increase of G' can be observed as well. Among all the fluids, the suspension of CMC and bentonite showed better affinity with the HG lost circulation material, presenting thermal stability and a wide range of particle size, essential property to avoid the loss of fluid through the fractures and pores of the rock formation.",6,6,2
Drilling,Lost Circulation,"Vega, Marcia Peixoto; de Moraes Oliveira, Gabrielle Fontella; Fernandes, Lindoval Domiciano; Martins, Andre Leibsohn",Monitoring and control strategies to manage pressure fluctuations during oil well drilling,Kick; Circulation loss; Downhole pressure control; Decision making; Gain scheduling,LOST CIRCULATION; KICK DETECTION; MODEL; FLUID; DEEP; MUD; MITIGATION; PREDICTION; RESERVOIR; SYSTEM,"During drilling the mud flows through the drill string and exits through the choke valve. The mud density range has as constraints: pore pressure (minimum limit) and fracture pressure (maximum limit). In fact, annulus bottomhole (downhole) pressure needs to be higher than pore pressure, in order to prevent kick, and smaller than fracture pressure, for avoiding mud loss and formation damage. Experimental and simulation studies were implemented in order build a monitoring - diagnosing tool working together with a decision making routine based on an adaptive control scheme that employs gain scheduling. An experimental unit was built, presenting the most important characteristics of the drilling process. The transient nature of annulus bottomhole pressure is due to the process inherent disturbances: rheology, rate of penetration (ROP), kick and mud loss, which were all implemented at the experimental unit. The major objective of the present paper is using the experimental plant and a phenomenological model for implementing real time process automation, in order to assure drilling inside operational window, using in line measurements for flow and density disturbances under circulation loss and kick scenarios.",8,8,1
Drilling,Rotation,"Li, Yinpeng; Li, Zifeng; Wang, Changjin; Qi, Min; Ren, Wenming",Particle image velocimetry analysis of plane flow field induced by drill string planetary motion based on superposition principle,Drill string; Planetary motion; Particle image velocimetry; Secondary flow,,"To study the law of a fluid plane flow induced by the planetary motion of the drill string and solve the practical engineering problems, such as improving the cutting-carrying capacity of a drilling fluid and reducing the flow pressure loss or damage to the drill string by whirling, a method based on the superposition principle is proposed. The flow field induced by the planetary motion is decomposed into a centrifugal force field through an equal angle rotation of the drill string and wellbore, and a flow field induced by through the simultaneous rotation of the drill string and wellbore. To analyze the latter, an experimental device was designed to measure the plane flow field of a fluid induced by the rotation of the internal rod and outer cylinder, and a particle image velocimetry experiment was performed. The results are as follows: the velocity of the plane flow field induced by the rotation of the internal rod and outer cylinder has an approximately symmetrical distribution, with the line connecting the cross section centers of the outer cylinder and inner rod as the axis of symmetry; when the outer cylinder is motionless and the inner rod rotates eccentrically, there is a critical value of the eccentricity upon which the secondary flow occurs and it is 0.7, moreover, the secondary flow occurs in a place far away from the inner rod and near the wall of the outer cylinder; when the inner rod and outer cylinder rotate in the same direction, the occurrence of the secondary flow is related to the eccentricity, and the area of distribution of the secondary flow expands with the increase in the eccentricity, for example, when the inner rod and outer cylinder rotate in the same direction with the speed of 60 r/min and 120 r/min respectively, the secondary flow occurs only when the eccentricity exceeds 0.4, and the area of the secondary flow becomes larger and larger with the increase of the eccentricity; when the inner rod and outer cylinder rotate in the same direction, the occurrence of the secondary flow is related to the difference in rotation speed between the inner rod and outer cylinder, and the area of distribution of the secondary flow expands with the increase in this difference, for example, when the eccentricity is 0.4, the secondary flow disappears or does not occur on the rotating speed difference being 0, and the area of distribution of the secondary flow expands with the rotating speed difference increasing from 60 r/min to 120r/min; when the inner rod and outer cylinder rotate in opposite directions, for example, when both of them rotate at speed of 60 r/min and the eccentricity of 0.2, the secondary flow occurs, the distribution of the secondary flow is approximately symmetrical and shaped like a crescent moon, and the area of distribution expands with the increase in the rotation speed of the inner rod or outer cylinder and the increase in eccentricity.",3,3,1
Drilling,Rotation,"Shan, Jingfu; Lin, Zhipeng; Zhang, Bin; Fang, Wei; Xie, Lili; Liu, Bo; Zhang, Le; Fang, Shixiang; Yan, Xue; Chen, Le","Stratigraphic architecture, depositional systems and controls on sediment filling in Nanber sub-basin, Tamtsag basin, Mongolia",Nanber sub-basin; Stratigraphic architecture; Palaeomorphology; Fault-scarp; Fault-terrace; Fault-break,ALBERTA FORELAND BASIN; SEQUENCE STRATIGRAPHY; LOW-ACCOMMODATION; JUNGGAR BASIN; RIFT-BASIN; EVOLUTION; MODEL; MIDDLE; DELTA,"The Nanber sub-basin is a secondary and minor tectonic unit in the centre of the Tamtsag Basin, Mongolia. The structural and sedimentary evolution of the depositional systems were significantly affected by active faults at the basin boundaries. In this paper, full coverage of the study area is achieved using high-quality 3D seismic and comprehensive drilling, test data, and analysis, while the stratigraphic architecture is finely characterized in an isochronal framework. The study reveals that the infilling of the lacustrine basin in the Early Cretaceous can be divided into three different evolutionary stages: syn-rift, rift climax, and post-rift. These evolutionary stages have different sequences and sedimentary systems: (1) the syn-rift sequence stage (SQ1+SQ2), which is characterised as ""narrow basin-shallow water"", developed primarily from fan-delta sedimentary systems; (2) the rift climax sequence stage (SQ3), which is characterized as ""wide basin-deep water"", developed primarily from fan-delta and nearshore subaqueous fan sedimentary systems; and (3) the post-rift sequence stage (SQ4), which is characterized as ""wide basin-shallow water"", developed primarily from braided river delta sedimentary systems. The varying tectonic evolutionary stages formed different types of stratigraphic structures and sedimentary fillings. Simultaneously, differential tectonic settlement and fault block rotation controlled the different palaeogeomorphology backgrounds in the basin. The fault-scarp formed by rapid subsidence of the boundary faults, which predominantly dictated the formation and development of fan-deltas. The fault-terrace formed by differential settlement and controlled the formation and development of fan-deltas and subaqueous fans, while the secondary fault-break in the basin largely controlled the formation and development of sub-lacustrine fans. During the post-rifting period, most of the boundary faults that had been active, such as controlling traps, basically ceased, and formed a braided river delta depositional system characterised by widely developed sedimentation along the long-axis of the basin. Thus, under conditions featuring plenty of sediment and weak tectonic activity, the key factor controlling sequence stratigraphy and sedimentary system filling patterns within the lake basin was the abundant source supply, not tectonic activity.",3,4,1
Drilling,Rotation,"Movahedi, Hamed; Shad, Saeed; Mokhtari-Hosseini, Zahra B.",Modeling and simulation of barite deposition in an annulus space of a well using CFD,Barite settling; Eulerian-eulerian model; Single particle model; CFD simulation,SPHERICAL-PARTICLES; DEM SIMULATION; FLOW; FLUIDS; FIBER,"In drilling industry, barite particles settling and barite sag as a major problem can potentially impose significant operational issues. Static conditions, in which well undergoes an extended shut-in period, could occur during different drilling and completion operations such fishing operation, tripping, and logging. Despite its importance, such phenomenon is not well understood yet. To avoid issues related to barite settlement and barite sag, a good understanding of the impact of different drilling parameters on barite settlement and sag phenomenon is required. Recently, the mathematical formulation and modeling of settlement and sag processes have gained more attention. In order to better design the drilling fluids and to optimize the operational conditions such as flow rate and drill pipe rotation speed, as well as drilling well trajectory design to avoid barite settlement, the mathematical formulation and modeling of such physical phenomena is required. This study is aimed at mathematically describing and analyzing the settling of barite particles in annular concentric space without axial flow by the means of computational fluid dynamic (CFD) simulation. The modeling approach consists of two main steps: a) simple vertical annular domain and b) complex three dimensional barite settlement process in a deviated well with rotational drill pipe. The current work is based on Eulerian two phase model. The settling of the single particle and the hindering effect of other particles on settling velocity have been investigated. Based on single particle model, the rate of barite settlement and fluid pressure reduction have been modeled. However, the single particle model cannot describe the particle to particle interactions and their impacts on settlement such as particle shearing viscosity, kinetic particle viscosity, and collisional effects. In this study, the accurate and comprehensive modeling of barite settlement has been done by applying the Eulerian-Eulerian approach. The models have been validated against available published experimental data in the literature. In addition, in order to further validate the model presented here, drill pipe rotation, fluid rheology, and inclination angle impacts have been experimental investigation and compared with results of the proposed model. The results indicate that the model based on using Eulerian-Eulerian approach accurately predicts the experimental data results. Afterward, the sensitivity analyses were carried out to show the impact of inclination angle, inner pipe rotation, fluid rheology, and barite content on the rate of settlement. This study showed that drag forces induced resuspension plays a vital role in barite settlement inside a deviated well. The results reveal that the settling rate is decreased with increasing the inner pipe rotation and the vortex effect created by inner pipe rotational, play a major role in the reduction of barite settlement. The results also show that the maximum settlement rate accrues at the deviation angles between of 45-60 degrees.",5,5,0
Drilling,Rotation,"Du, Hui; Wang, Gui; Deng, Guicai; Cao, Cheng",Modelling the effect of mudstone cuttings on rheological properties of KCl/Polymer water-based drilling fluid,Drill cuttings; Rheology; Drilling fluids; Tikhonov regularization,COUETTE VISCOMETRY DATA; ILL-POSED PROBLEMS; BENTONITE SUSPENSIONS; REGULARIZATION; PARAMETERS; RATES,"Drill cuttings unavoidably enter the annulus and affect the rheology of the drilling fluid in the process of drilling. The rheological properties of drilling fluids containing varying particle size and cuttings amounts were measured by using a rotational viscometer equipped with a widened gap. An algorithm based on Tikhonov regularization was proposed to transform the viscometry data into flow curves. Validity and availability of the presented algorithm were investigated by applying the algorithm to the base drilling fluid (without cuttings). Results showed that the flow curves of the cuttings-laden KCl/Polymer drilling fluids used in this study can be well depicted by the Herschel-Bulkley (H-B) model. Based on the rheological parameters obtained from curve fitting, the empirical correlations for the flow behavior index and the consistency coefficient were proposed. The consistency coefficient increases with the increase of cuttings amounts and the reduction of cuttings size. While the flow behavior index decreases with the increase of cuttings amounts and the reduction of the cuttings size. The proposed rheology determination approach in this study could give an orientative performance for cuttings-laden drilling fluids.",5,6,0
Drilling,Rotation,"Wang, Changjin; Li, Zifeng; Li, Yinpeng; Qi, Min; Wang, Lei",Experimental study on the rotation of compression-buckling rod column in a liquid-filled cylinder,Drill string; Rotation; Buckling; Axial load; Backward whirl,,"In oil drilling, the main form of movement of the bottom hole assembly is self-rotation and whirling after buckling. The rotation of a compression-buckling rotation drill string can increase the frictional force between the drill string and borehole wall, induce lateral vibration and whirl of the drill string, generate borehole wall instability and drill string damage, and even cause a drilling failure. At present, studies on the motion laws of a pressure-rotating buckling drill string are incomplete, and some are even incorrect, necessitating further improvements. In this work, the effects of axial load, rotational speed, drilling fluid, and inner diameter on the rotational motion of a compression-buckling column in a cylinder were experimentally studied. The dissipation energy before and after the transition state of the simulated drill string, from the forward whirl to self-rotation, or from the forward whirl to the backward whirl, were analysed. The results indicate the following: (1) With an increase in the axial load, a buckling drill string first experiences forward whirl. Next, both forward whirl and self-rotation occur, along with a combination of backward whirl and self-rotation along the partial vertical wall. Finally, backward whirl occurs along the wall. (2) A dynamic lubrication of the drilling fluid can reduce the forward whirl rotation amplitude of the drill string and prevent the formation of backward whirl. (3) When dynamic lubrication by the drilling fluid is improved, the borehole diameter is reduced, the hole-deviation angle increases, the critical axial load of the backward whirl increases. (4) Backward whirl may occur twice for the drill string as the axial load increases. (5) The state transition of the drill string motion conforms to the minimum dissipation power principle. The experimental results described herein can serve as a reference for studies regarding drill string dynamics and drilling practice.",5,6,1
Drilling,Rotation,"Hovda, Sigve",Automatic detection of abnormal torque while reaming,Drillstring dynamics; Torsional vibration; Couette Poiseuille flow; Detection algorithm,WAVE-PROPAGATION,"A lumped element model is implemented to describe the torsional vibrations of the drillstring while reaming, i.e. rotating off-bottom. The rotary motions and the torques anywhere in the drillstring are simply convolutions of the surface rotary motion with analytical expressions that are derived in this paper. The Coulomb friction forces are divided into steady-state forces and time-dependent forces. The drillstring vibrates around a stable position that is determined by the steady-state friction torques. The vibrations are damped by viscous friction forces and in particular the Basset forces dominate the damping. The time-dependent part of the Coulomb friction forces are related to when something is not normal in the well. For instance, when the drill bit is hindered by a cuttings bed or the bottom part of the drillstring is hung up in a sharp curvature. The model is further used in an algorithm for detecting the time-dependent Coulomb friction coefficients. A sensitivity study is added and the detection algorithm seems to be mathematically robust. This motivates experimental verifications of both the model and the detection algorithm in the future.",6,6,1
Drilling,Thermal Spallation,"Lyu, Zehao; Song, Xianzhi; Li, Gensheng",Numerical simulation of reaction under high pressure conditions for thermal spallation drilling,Thermal spallation; Reaction; Numerical simulation; High pressure,HEAT-TRANSFER; MODEL; JET; FIELD; FLAME; ROCK; FLOW,"Thermal spallation technology is a drilling method, which is potentially suitable for the exploitation of petroleum in hard rocks with low costs. In this paper, characteristics of reaction are investigated under relatively high pressure in thermal spallation drilling. The Peng-Robinson equation of state and eddy dissipation model are applied in the simulation. Effects of methane and oxygen flow rate, nitrogen fraction on the flow field are studied. Simulation results are validated in experiments that monitor the temperature of the flame jet using thermocouples. Results show that besides a portion of oxygen reacting with the methane, the left oxygen mainly flows towards the boundary of the reactor. The reaction between methane and oxygen mainly occurs at the central part of the reactor. Also, the temperature close to the wall of the reactor is only 1300 K, which can help to protect the reactor wall from damage due to high temperature. Increasing the methane flow rate within a certain range can help to obtain high temperature and high jet velocity simultaneously. Also, injecting mixture of oxygen and nitrogen can prevent too much excessive oxygen from existing in the wellbore during thermal spallation drilling. Results in this paper could provide guidance for field applications.",1,1,0
Drilling,Thermal Spallation,"Hu, Xiaodong; Song, Xianzhi; Liu, Yu; Li, Gensheng; Shen, Zhonghou; Lyu, Zehao",Aspect ratio of spalls of granite in flame-jet spallation and its effect on the modeling prediction of spallation properties,Drilling engineering; Thermal spallation; Spalls; Granite; Aspect ratio,THERMAL SPALLATION; NUMERICAL-SIMULATION; LOST CIRCULATION; ROCK; PERFORMANCE; INJECTION,"Thermal spallation is an effective drilling technique for hard rock formations. Models based on Weibull statistical failure theory are widely used in the simulation in thermal spallation. The aspect ratio (diameter/thickness), a parameter in Weibull models, is assumed as a constant in the previous simulations of flame-jet spallation. We conducted the flame-jet experiment in granite and collected 280 spalls to calculate the aspect ratio. Results show that the aspect ratio is size-dependent. A new trimodal distribution of aspect ratio is proposed to incorporate in Weibull models to accurately predict the rate of penetration. The comparison results show that the size-dependent aspect ratio has a significant effect on the rate of penetration. Meanwhile, a smaller aspect ratio (6.91) is recommended for the prediction of the surface temperature in the Weibull model, by which the predicted result can get a better match with the published data. Additionally, given the aspect ratio and rock intrinsic strength of 6.91 (dimensionless) and 70 Mpa, a homogeneity factor is recommended between 10 and 17 (dimensionless). This study can provide an accurate aspect ratio for simulating properties of flame-jet spallation in granite using Weibull models.",3,3,1
Drilling,Thermal Spallation,"Lyu, Zehao; Song, Xianzhi; Li, Gensheng; Wang, Gaosheng; Shi, Yu; Liu, Yu; Zheng, Rui",Experimental analysis on characteristics of micro-structure and mineralogy changes in thermal spallation drilling,Thermal spallation; Rock sample; Mineral; X-ray diffraction; SEM,IMPACT FLOW-FIELD; NUMERICAL-ANALYSIS; HEAT-TRANSFER; ROCK FAILURE; WATER; PERMEABILITY; ETHANOL,"Thermal spallation drilling is a promising technology expected to exploit hydrocarbons in hard rocks. In this paper, thermal spallation experiments are conducted on six types of rocks. Comparisons are made in terms of mineral compositions and micro-structures. Spallation temperatures are obtained, and analytical results are compared with experimental data. Results show that spallation temperatures obtained by analytical method show good agreement with experimental data. Additionally, drilling performances can be continuous or intermittent for various types of rocks. Quartz expands in different rocks after thermal impact. Calcite increases and dolomite decreases due to thermal decomposition. Moreover, the induced thermal stresses in sandstone push against the micro-particle and melting may occur. For granite, micro-cracks and micro-particles exist after spallation. In contrast, there are no cracks in shale, but melt holes and micro-particles distributed randomly due to reaction. For limestone, there exist relatively large cracks, micro-cracks and micro-particles. For dolomite, no obvious micro-particles remain but only a few micro-cracks. The variations of elements correspond well with mineral changes. However, under the conditions of this paper, marble fails to break due to strong homogeneity. All results can provide guidance for the further study on the rock-breaking of thermal spallation drilling.",4,4,3
Drilling,Hydraulic Fracture,"Shan, Liqun; Guo, Boyun; Weng, Dingwei; Liu, Zhe; Chu, Henry",Posteriori assessment of fracture propagation in refractured vertical oil wells by pressure transient analysis,Refracturing; Oil; Wells; Fractures; Propagation; Assessment,,"Oil companies have realized that refracturing old wells is the more budget-friendly way to achieve cash flow than drilling and completing new wells in the down turn of the energy industry. But it has been seen that the refracturing technology does not always work equally well in all reservoir conditions. It is desirable to have a quantitative method for assessment of well refracturing design and operations. An analytical transient flow model was derived in this study to estimate the orthogonality between the old and new hydraulic fractures after refracturing. Pressure transient data from seven wells refractured in an oilfield in the southwestern China was analyzed with the model. The model implies that orthogonal fractures created in well refracturing treatments induce orthogonal reservoir linear flow in the stimulated reservoir volume. This fracture configuration can be identified by the unit slope of pressure derivative in the log-log diagnosis plot. The angle between fractures initiated from wellbore can be estimated using pressure transient data analysis technique with a log-log diagnostic plot, with extreme situations that merged or parallel fractures will show a half slope and orthogonal fractures will show a unit slope. Case studies of data from 7 wells show that orthogonal fractures were created in 3 wells, merging or parallel fractures were created in 1 well, and fractures with non-right angles were created in 3 wells. The actual well productivity data for the 7 wells are basically consistent with the expected trend implied by the estimated fracture configurations with an exception of one well. The reason is not clear and needs further investigations. More production data from refractured wells are required to further validate the technique.",6,6,0
Drilling,Hydraulic Fracture,"Raef, Abdelmoneam E.; Kamari, Arash; Totten, Matthew; Harris, Dustin; Janssen, Kale; Lambert, Michael","The dynamic elastic and mineralogical Brittleness of Woodford shale of the Anadarko Basin: Ultrasonic P-wave and S-wave velocities, XRD-Mineralogy and predictive models",Shale; Brittleness index; Elastic properties; Mineralogy; Hydraulic fracturing,OKLAHOMA; VISCOSITY; SYSTEMS; ROCKS,"The recent advances in drilling and hydraulic fracturing technology rendered the Woodford shale of the Anadarko basin a prolific resource play producing gas and liquid hydrocarbons. Among the challenges facing improved economics, there is variable production from one well to another as well as from a completion stage to another due to the variability in facture gradient or brittleness index (BI) and the kerogen content. This investigation relies on laboratory ultrasonic P-wave and S-wave velocity in Woodford core samples to estimate BI based on the estimated elastic moduli. We modified a literature mineralogical brittleness index equation in order to take into account additional iron-rich minerals like pyrite, hematite, and iron oxides that are present in the Woodford shales, and also investigated the impact of total organic content (TOC) on the mineralogical brittleness index. Furthermore, a number of new reliable equations based on different elastic properties have been introduced in this study for the evaluation of the elastic BI, which is of significant importance in designing hydraulic fracturing in shale and tight reservoirs. In another panel of our study, the sensitivities of both mineralogical makeup of Woodford shale and elastic properties calculated -including density, acoustic impedance, Poisson's ratio, Young's modules, Lame's parameters-to the elastic brittleness index are examined. It was indicated that they have a positive effect on the prediction and can be employed in the respective predictive methods for the estimation of elastic BI. However, the analysis demonstrated that TOC has no considerable effect on mineral BI, at least in Woodford sample studied. A comparison between these newly developed predictive equations and the most commonly used methods for the prediction of elastic brittleness index available in the literature demonstrates that the new equations have a better performance in terms of both accuracy and simplicity. On comparing the BI prediction equation, with highest prediction quality ""Method 1"", that was developed based on ultrasonic elastic moduli with a corresponding equation based on sonic well-logs elastic moduli, Method1 was proven applicable to estimating BI based sonic frequency elastic moduli.",8,9,1
Drilling,Hydraulic Fracture,"Shen, Jian; Qin, Yong; Li, Yepeng; Yang, Yanhui; Ju, Wei; Yang, Chunli; Wang, Geoff","In situ stress field in the FZ Block of Qinshui Basin, China: Implications for the permeability and coalbed methane production",In situ stress; High-rank coal; Coalbed methane; Permeability; Gas and water production; Qinshui basin,EASTERN ORDOS BASIN; SHANXI PROVINCE; ORIENTATION; EXPLORATION; MAGNITUDE; RESERVOIR; PART; AREA; GEOMECHANICS; FRACTURES,"In situ stress affects reservoir permeability and stimulation, and thus coalbed methane (CBM) recovery. In this study, the in situ stress field measured from 238 CBM wells in the FZ Block of Qinshui Basin, China, was investigated. The vertical stress, horizontal maximum and minimum principal stress are 5.92-20.08 MPa, 8.03-41.75 MPa, and 5.38-21.24 MPa, respectively. The in situ stress magnitudes increase with burial depth of the coal seams. The FZ Block is dominated by reverse and strike-slip faulting stress regimes. Most of reverse fault stress regimes appear within burial depth less than 500 m, whereas normal and strike faulting stress regimes are deeper than 500 m. The relation between the coefficient of lateral stress and burial depth shows that shallow strata are characterized by horizontal stresses, whereas deep strata are generally hydrostatic pressures that approximately equal to the principal stresses. Low gas and high water production are associated with vertical hydraulic fractures, wherein the horizontal minimum principal stress is the minimum stress. High gas and low water production are associated with horizontal hydraulic fractures, wherein the vertical stress is the minimum stress. This results are attributed to the enhanced permeability of the coal seam and the communication with overlying or underlying aquifers because the minimum stress varies between vertical and horizontal minimum stress. The orientation of the horizontal maximum principal stress is -NEE-NE and is locally distorted by faults, which can be used to optimize the drilling, completion, and stimulation of CBM wells in the study area.",8,10,1
Drilling,Supercritical Carbon Dioxide,"Sun, Xue; Ni, Hongjian; Wang, Ruihe; Shen, Zhonghou; Zhao, Mengyun",Characteristic study on supercritical carbon dioxide impinging jet: Calculation and stagnation properties analysis,Supercritical carbon dioxide; Impinging jet; Submerged jet; Calculation method,TEMPERATURE; FLOW; GAS,"Supercritical carbon dioxide jet is an emerging technology for drilling. Proper understanding of supercritical carbon dioxide impinging jet is the basis for researching and developing this new technology. However, supercritical carbon dioxide has different compressibility and thermal properties from water and ideal gas, which bring difficulties to flow field analysis. The analytical methods reported are limited to experiment and numerical simulation now. In this paper, the flow characteristics of supercritical carbon dioxide jet under different conditions are analyzed. Based on jet dynamics theory and carbon dioxide property equations, we established mathematical model for supercritical carbon dioxide impinging jet and gave a solution algorithm. Use this method, the stagnation properties are discussed. Under the calculation condition, as inject pressure increases from 20 MPa to 50 MPa, stagnation pressure increases by 144.6%, while ambient temperature decreases by 4.14%. With inject temperature rising from 310 K to 340 K, the stagnation pressure changes little and ambient temperature increases by 4.85%. On the condition of same jet pressure difference, improving ambient pressure from 8 MPa to 20 MPa, the stagnation pressure and ambient temperature increases by 46.52%, 2.55%, respectively. The stagnation temperature is mainly controlled by inject temperature, while inject pressure and ambient pressure do not affect it seriously. The method proposed and findings would provide theoretical guidance for field applications.",6,6,4
Drilling,Supercritical Carbon Dioxide,"Ding, Lu; Ni, Hongjian; Li, Mukun; Li, Wentuo; Song, Weiqiang; Guo, Xing",Wellbore collapse pressure analysis under supercritical carbon dioxide drilling condition,Supercritical carbon dioxide; Drilling; Pore pressure; Collapse pressure; Wellbore stability,,"Compared with the conventional drilling methods, supercritical carbon dioxide used in drilling and completion has considerable potentials and many advantages. However, it is found in the research and practice that there are yet many basic problems to be solved. Wellbore stability is one of them. Firstly, in this paper, on the basis of Span & Wagner equation, combined with unique physical properties of supercritical carbon dioxide, parameters such as temperature and pressure in the wellbore while the supercritical carbon dioxide drilling are calculated. Secondly, the heat and mass transfer effect between the supercritical carbon dioxide and the formation has been studied, and the temperature change near the wellbore formation and stress change near the wellbore have been obtained. Thus, pore pressure change near the wellbore has been obtained. When the depth reaches 1500 m, the downhole temperature will be 12 K lower than the wellbore temperature, and the pore pressure will increase to 20 Mpa as the supercritical carbon dioxide seeps into the formation. Thirdly, mechanical properties change rules when rocks are soaked in the supercritical carbon dioxide are obtained through experiments. The compressive strength decreases by 64%, the elastic modulus increases by 153%, and the poisson ratio decreases by 8%. Based on the above research, the wellbore collapse pressure model has been established. It is revealed that the wellbore collapse pressure rises from 9.17 Mpa to 16.26 MPa with the increase of time, which is still lower than the bottom pressure and cannot lead to instability. Meanwhile, the bottom collapse failure index keeps positive and increases gradually with the increase of time. It means that there is no wellbore enlargement. Therefore, the results have verified the wellbore stability while the supercritical carbon dioxide drilling. It has laid a solid foundation for the future development of supercritical carbon dioxide drilling.",8,12,0
Drilling,Bearing Capacity,"Kan, Changbin; Yang, Jin; Yu, Xiaocong; Xie, Renjun; Wu, Yi; Li, Yanjun; Chen, Haodong; Guan, Shen; Liu, Hexing; Gu, Chunwei; Lin, Siyuan; Wang, Huanhuan; Abimbola, Fatai",Field experimental investigation of bit stick-out for different soil strengths during deepwater conductor injection,Conductor injection; Bit stick-out; Field experiment; Soil strength; Installation efficiency; Bearing capacity,,"The jetting method of deepwater conductor installation is the most widely applied method of underwater well construction. The degree of bit stick-out from the running conductor assembly directly affects the efficiency of the injection process and the bearing safety of the conductor after installation, a key factor in deepwater drilling design. In order to improve the efficiency and safety of conductor installation, it is necessary to determine a reasonable range of bit stick-out for soil formations with different shear strengths. In this paper, a modified model for selecting the bit stick-out is developed based on the theory of water jet ground breaking and the conservation of momentum. The key factors influencing the optimal bit stick-out, such as hydraulic parameters, formation strength, and the ratio of bit-to-conductor dimensions, are also considered. Orthogonal experiments of conductor jetting were conducted in in-situ soil strata with different soil strengths. The influence law of parameter change on bit stick-out is studied, including hydraulic parameters change, bit stick-out variation and running assembly structural change. The results indicate that the bit stick-out is a key factor affecting the efficient jetting of the conductor as well as the bearing capacity of the conductor after injection. For different soil shear strengths, the effects of bit stick-out on the jetting efficiency and bearing capacity are different. In soil strata with low shear strength, the bit stick-out from the running assembly has little influence on the jetting efficiency, but a significant influence on the bearing capacity of the conductor, and hydraulic factors dominate the jetting efficiency and conductor stability. In soil strata with relatively high shear strength, the bit stick-out has a significant influence on the installation efficiency and a relatively small influence on conductor bearing capacity. An optimal drill bit stick-out is then determined that provides the highest jetting efficiency under a given drilling fluid discharge rate. From the field experiments, the optimal bit stick-out is determined to be 147.4 mm, and the range of reasonable bit stick-out is 96.6-198.2 mm. In total, these research results provide a design basis and theoretical guidance for optimizing the bit stick-out of deepwater conductor running assemblies.",4,4,1
Drilling,Bearing Capacity,"Kan, Changbin; Yang, Jin; Yu, Xiaocong; Dong, Tiejun; Wu, Xudong; Liu, Ming; Li, Chun; Zhang, Changliang; Fu, Jinbao",Load bearing characteristics study on novel deepwater composite drilling conductor by simulation and experimental methods,Composite drilling conductor; Laboratory experiment; Numerical simulation; Vertical bearing capacity; Lateral displacement; Soil pressure variation,SAND; SOIL,"A novel design of composite drilling conductor (CDC) was carried out for improving the vertical and lateral bearing capacity. Bearing characteristics of CDC was investigated when subjected to lateral and longitudinal loads based on the ultimate subgrade reaction method and pile foundation bearing theory. Theoretical models for lateral displacement and vertical load were established. Finite element analysis (FEA) was conducted, and bearing capacity and influencing factors of the composite structure were studied. Through laboratory experiments, the interaction between the structure and the soil as well as the regularity of soil deformation and stress variation in the surrounding soil were studied during installation, vertical and lateral load application. The results showed that the vertical bearing capacity increased with increasing depth of the bucket foundation under the combined effect of the composite structure. Meanwhile, the depth of the embedded point of the composite conductor increased with an increased bending moment when subjected to a combined load with a constant vertical force. When the bending moment on the structure top was constant, the lateral displacement of the structure as well as the depth of the embedded point would increase with increasing vertical force. Furthermore, the bending moment change on the top of the CDC was more significant than the vertical force regarding the lateral displacement. It is also showed that the internal bucket foundation produced an ""elastic plugging"" effect when the CDC was subjected to vertical loading, while soil pressure transmission occurred from the upper soil to the underlying strata soil. When subjected to lateral loads, the earth pressure on the bucket sidewall was redistributed, and the bucket foundation produced a lateral supporting effect on CDC. The composite structure effectively reduced the conductor vertical and lateral displacement and improved the lateral and vertical bearing capacity. These results provide useful theoretical references for further development and optimization of the CDC structure.",4,6,1
Drilling,Load Transfer,"Wang, Peng; Ni, Hongjian; Wang, Xueying; Wang, Ruihe; Lu, Shuangfang",Research on the characteristics of earthworm-like vibration drilling,Earthworm-like drilling; Friction reduction; Load transfer; Position optimization,TANGENTIAL VIBRATIONS; SLIDING MOTION; REDUCTION; FRICTION; FORCE,"The load transfer difficulty caused by borehole wall friction limits the rate of penetration (ROP) and extended-reach limit of complex structural well enormously. A new friction reduction technology called ""earthworm-like drilling"", which can improve the load transfer and extended-reach limit, is proposed in this paper. A mathematical model based on ""soft-string"" model is developed to analysis the characteristics of this technology. Simulation results indicate that more stick-slip and load transfer issue are caused by higher friction. The earthworm-like drilling is more effective in reducing friction than single-point vibration drilling and less effective than multipoint vibration drilling because of the pulse pressure attenuation. However, this disadvantage can be offset by adding the number of axial oscillators. Amplitude and frequency of pulse pressure and the installation position of axial oscillators have great impact on the friction reduction and load transfer. An optimizing model based on projection gradient method is developed and used to optimize the position of three axial oscillators in a three-dimensional horizontal well. The weight on bit (WOB) increases significantly after the optimized position and the new position of axial oscillators move towards bottom of well and close to each other. Results verify the feasibility and advantages of earthworm-like drilling, and lay a solid theoretical foundation for its application in oil field drilling.",5,5,2
Drilling,Load Transfer,"Wang, Peng; Ni, Hongjian; Wang, Xueying; Wang, Ruihe",Modelling the load transfer and tool surface for friction reduction drilling by vibrating drill-string,Friction reduction; Vibration drilling; Load transfer; Tool face; Drill-string dynamic safety,WELLS,"A unified mathematical model, considering the two mechanisms of static-dynamic friction conversion and friction decomposition, is developed to analysis the effect of different vibration manners and parameters on axial load transfer and tool face of positive displacement motor and evaluate the vibration level and dynamic security of the drill-string. A second-order finite difference method is used to solve this model. The change of weight on bit, rate of penetration and tool face of positive displacement motor under three different slide drilling manners are obtained. Simulation results show that the vibrations applied on drill-string mitigate the stick-slip and adhesion phenomenon and make the load transfer and movement of the drill-string smoother. The increment of weight on bit is the combined effect of the change of axial friction acting on drill-string and the exciting force. Among the three vibration manners, the axial vibration applied at bottom hole has the best friction reduction and tool face stabilization effects and the lowest vibration intensity. The torsional vibration applied at wellhead mainly affects the upper drill-string and has an optimal torsion angle subject to the torsional depth. The axial vibration applied at wellhead has a strong effect on the drill-string of vertical section. Results provide guidance and advice to the research and applications of friction reduction by vibrating drill-string.",8,8,0
Drilling,Temperature Variation,"Wang, Chao; Liu, Gonghui; Li, Jun; Zhang, Tao; Jiang, Hailong; Ling, Xiao; Ren, Kai",New methods of eliminating downhole WOB measurement error owing to temperature variation and well pressure differential,Downhole WOB measurement; Pressure and temperature differential; Wheatstone bridges; Hydrostatic and flowing pressure load analysis; New minimizing error methods,,"The downhole weight on bit (WOB) measurement sensor can produce significant inaccuracies in its readings owing to the effects of temperature variation and well pressure differential. To improve the accuracy of downhole WOB measurement, the impacts of temperature variation and pressure differential on WOB measurement were studied via theoretical derivations, laboratory experiments, and field experiments. Based on the constitutive equations of thermoelastic materials and the strain theory of strain gauge, the equation of error induced by temperature variation was deduced. Through laboratory experiments, the conventional temperature compensatory method, and the new compensatory temperature method proposed herein were compared. The experimental results show that the proposed new temperature compensatory method performed better in eliminating the effects of temperature variation. The shortcoming of the conventional WOB correction method for eliminating the pressure differential impact is that it does not consider the pressure drop in the drill motor. A new WOB correction method is proposed based on the momentum equation of flowing fluid and floating body theory. The field experimental results indicate that the measurement error of the conventional correction method could reach up to 80 kN. The work presented herein can serve as guidance for the downhole WOB measurement.",4,4,2
Drilling,Temperature Variation,"Lyu, Zehao; Song, Xianzhi; Li, Gensheng; Wang, Gaosheng; Shi, Yu; Liu, Yu; Zheng, Rui",Experimental analysis on characteristics of micro-structure and mineralogy changes in thermal spallation drilling,Thermal spallation; Rock sample; Mineral; X-ray diffraction; SEM,IMPACT FLOW-FIELD; NUMERICAL-ANALYSIS; HEAT-TRANSFER; ROCK FAILURE; WATER; PERMEABILITY; ETHANOL,"Thermal spallation drilling is a promising technology expected to exploit hydrocarbons in hard rocks. In this paper, thermal spallation experiments are conducted on six types of rocks. Comparisons are made in terms of mineral compositions and micro-structures. Spallation temperatures are obtained, and analytical results are compared with experimental data. Results show that spallation temperatures obtained by analytical method show good agreement with experimental data. Additionally, drilling performances can be continuous or intermittent for various types of rocks. Quartz expands in different rocks after thermal impact. Calcite increases and dolomite decreases due to thermal decomposition. Moreover, the induced thermal stresses in sandstone push against the micro-particle and melting may occur. For granite, micro-cracks and micro-particles exist after spallation. In contrast, there are no cracks in shale, but melt holes and micro-particles distributed randomly due to reaction. For limestone, there exist relatively large cracks, micro-cracks and micro-particles. For dolomite, no obvious micro-particles remain but only a few micro-cracks. The variations of elements correspond well with mineral changes. However, under the conditions of this paper, marble fails to break due to strong homogeneity. All results can provide guidance for the further study on the rock-breaking of thermal spallation drilling.",4,4,3
Porous Media,Relation,"Zhang, Guowei; Yao, Guangqing; Li, Jiqing; Wu, Hua; Liu, Zhijun; Li, Desheng","A new experimental method for measuring the three-phase relative permeability of oil, gas, and water",Three-phase relative permeability; Saturation history; Archie equation; CT scan; Wettability,RESISTIVITY,"For tertiary oil recovery, the gas drive is often implemented after water flooding. The three-phase flow phenomenon of oil, gas, and water exists during the process of gas injection. The three-phase relative permeability should be measured to further study the flow characteristics of oil, gas, and water in porous media. In this work, the steady-state flow method is adopted to establish a combined experimental method based on the principle of relationship between resistivity and water saturation, and the principle of on-line CT scanning is used to measure the three-phase relative permeability. The relative permeability of oil, gas, and water is measured under different saturation histories, including the water alternating gas flooding, in which water saturation decreases, oil saturation decreases, and gas saturation increases, as well as gas alternating water flooding, in which water saturation increases, oil saturation decreases, and gas saturation decreases. The experimental results show that in a water-wet core, the relative permeability of water is a function of its own saturation, and its isoperms are straight lines. The relative permeability of oil and gas phase is affected by their saturation and other phase saturations. In an oil-wet core, the isoperms of oil, water, and gas are convex to the point of 100% their own saturation, which means the relative permeability of oil, gas and water depend on all the three phase saturations. The saturation histories influence the isoperms of the three phases differently. Compared with the two-phase flow, the three-phase flow is more complex. This new experiment provides an approach and theory for the study of three-phase seepage laws in the gas drive.",1,1,1
Porous Media,Relation,"Han, Lu; Dai, Liming",Spherical wave attenuation under multiple energy source in viscous fluid-saturated elastic porous media,Porous media; Spherical wave; Multiple energy sources; Fluid viscosity; Wave frequency; Modified constitutive relation,COMPRESSIONAL-WAVE; FREQUENCY RANGE; ROCKS; PROPAGATION; VELOCITIES,"In viscous fluid-saturated elastic porous media, the spherical dilatational wave displacement equations are developed on Biot's theory and the spherical shear wave displacement equations are developed based on a modified wave frame. Analytical forms of the solutions are introduced by considering the wave magnitude dispersion due to the viscosity of Newtonian fluids. The attenuation of dilatational wave and shear wave are separately studied. Due to the high attenuation of the shear wave, the superposition characteristic is only considered for dilatational waves under the multiple energy source models. Many advantages of the multiple sources over the single source have been theoretically or numerically demonstrated, such as multiple energy sources can produce a larger relative displacement than single source, the wave direction is controllable and the magnitude of the relative displacement can be adjusted as required under the multiple source.",2,2,0
Porous Media,Relation,"Gajo, Alessandro; Cecinato, Francesco; Loret, Benjamin",A computational framework for immiscible three-phase flow in deformable porous media,Immiscible fluids; Capillary pressures; Relative permeabilities; Gas injection; Imbibition; Finite element; Time marching scheme,SEMIDISCRETE FORMULATIONS; MULTIPHASE FLOW; MODEL; PERFORMANCE; TRANSPORT; FLUIDS,"Several soil decontamination processes and enhanced oil recovery techniques involve the co-existence of three immiscible fluids, such as water, a nonaqueous phase liquid and a gas. In this work, a computational framework based on the individual mass balance of each phase is developed, aimed at simulating three-phase flow in a deformable rock through the finite element method, without resorting to specific simplifications that are usually required by standard numerical schemes. Key ingredients of the model are: expression of the residual in terms of mass contents, consistent lumping of the storage terms in the residual and algorithmic (tangent) matrix, consistent integration rules, the use of a minimum relative permeability and a time marching scheme based on trapezoidal integration. Special convective boundary conditions are adopted for pressures to be consistent with the assumed rock wettability properties during co-current imbibition. The resulting numerical scheme can deal with arbitrary saturation and/or pressure boundary conditions. The model is tested by simulating gas injection tests, and both co- and counter-current water imbibition tests, in a deformable core. To assess the performance and robustness of the whole framework, sensitivity analyses are performed upon varying key constitutive, loading and numerical parameters.",2,2,0
Porous Media,Relation,"Alamooti, Amirhossein Mohammdi; Ghazanfari, Mohmmad Hossein; Masihi, Mohsen",Investigating the relative permeability behavior in presence of capillary effects in composite core systems,Composite core systems; Relative permeability; Experimental; Modeling; Layered heterogeneous porous media,DISPLACEMENT EXPERIMENTS,"Successful designs for an injection process to improve reservoir recovery seek more accurate values of saturation dependent functions, including relative permeability curves. The ignorance on underlying heterogeneity (e.g. layering) might lead to inaccurate predicting of flow behavior in layered heterogeneous porous media. Analysis of experimental core flood results in composite core systems (the system) along with numerical simulation at the core scale can provide an insight into this problem, especially when the capillary effects are present. In this study unsteady state two phase displacements have been conducted on the system with different internal arrangements. The main contribution is to compare the relative permeability behavior of composite system against the results of single cores using both explicit as well as implicit methods in the presence of capillary forces. The experimental results showed that fluid flow behavior in the system significantly differs from of the flow characteristics in single cores. The controlling parameters on the relative permeability behavior of whole system include the internal arrangement, permeability values and length of cores. Simulation results showed that in the case of descending ordering (of permeability), the relative permeability of the system is almost independent of the individual cores' length. In contrast, in the case of ascending ordering of core permeability values, it strongly depends on the core structure. When the capillary pressure and relative permeability curves of individual cores are the same, simulation results showed that Huppler arrangement gives the relative permeability of the system close to the behavior of the individual cores. A new correlation set has been developed which predict the relative permeability of whole system based on the relative permeability, internal arrangements, and lengths of single cores with a reasonable agreement.",2,2,0
Porous Media,Relation,"Zheng, Da; Reza, Zulfiquar",Prediction of pore-scale transport properties in unconventional reservoirs using novel theoretical dendroidal pore-network model,,POROUS-MEDIA; SHALE; FLOW,"Measurement of transport properties of shale in laboratories can be expensive, extremely time-intensive and inaccurate due to lack of sufficient tool resolution. On the other hand, rigorous pore-scale simulation is prohibitively compute-intensive and is limited to sub-micron scale lacking volume-representativeness. Thus, theoretical pore-network modeling is a routine method to characterize the transport properties of shales. Connectivity architecture of porous media observed in unconventional shale reservoirs is markedly different from that in conventional reservoirs. The theoretical models developed for conventional reservoirs are explicitly proven to be not appropriate in capturing the unique characteristics of unconventional reservoirs; meanwhile, most models proposed for unconventional reservoirs are too simplified to capture realistic pore distribution. This paper presents a stochastically-distributed dendroidal pore-network model based on the analysis of pore-networks extracted from scanning electron tomographic microscope (SEM) images. Semi-acyclic model is adopted to capture the non-plateau trend of mercury intrusion capillary pressure (MICP) versus non-wetting phase saturation curve. Mercury drainage experimental data have also been compensated for the effect of pore compressibility. Intrinsic permeability and relative permeability is evaluated and validated to be in an acceptable range. Apparent permeability and its relation to intrinsic permeability is predicted by different gas-slippage correlations based on the dendroidal models. Data and samples from Marcellus shales are employed to validate the new proposed pore-network model and to compare different correlations of apparent permeability. Besides the predictive power, this new dendroidal model can also be employed as an analog of real shale porous media to perform different pore-scale simulations and analyses.",3,3,0
Porous Media,Relation,"Bagudu, U.; McDougall, S. R.; Mackay, E. J.",Network modelling analysis of a depressurization experiment on a North Sea reservoir core sample,Network modelling; Solution gas drive; Crtical gas saturation; Depressurization; Depletion rate,SOLUTION-GAS DRIVE; DEPLETION EXPERIMENTS; PRESSURE DEPLETION; SOLUTE DIFFUSION; POROUS-MEDIA; PORE-NETWORK; VISUALIZATION; SIMULATION; MIGRATION; TENSION,"Solution gas drive following depressurization of oil reservoirs below the bubble point is the oldest and perhaps one of the most challenging oil recovery mechanisms to quantify. Part of the challenge lies in designing repeatable experiments and then translating experimental observations into practical solutions in the field - laboratory depressurization rates are typically orders of magnitude higher than practical field rates. Using a case study we show how pore network modelling can help make sense of the underlying physical mechanisms governing gas flow behaviour in porous media during solution gas drive whilst also serving as a forward modelling tool for developing relative permeability functions for use in field scale simulators. Core scale simulations performed on a pore network anchored to measured petrophysical properties of a 0.23mD chalk core from a North Sea reservoir show a very weak correlation between depletion rate and critical gas saturation, contrary to observations in higher permeability clastic media. In addition, solution gas drive oil recovery was found to increase with higher initial water saturation.",3,3,0
Porous Media,Relation,"Marandi, Samira Zargari; Salehi, Mahsa Baghban; Moghadam, Asefe Mousavi",Sand control: Experimental performance of polyacrylamide hydrogels,Gelation time; Sand control; Rheology; Gel strength; Coreflooding,WATER SHUTOFF; CONFORMANCE-CONTROL; GEL; POLYMER; FIELDS; PERMEABILITY; GAS,"Improvement of sand consolidation is an impressive process to reduce severe operational problems of sandstone oil reservoirs. In this study, appropriate polymeric hydrogels for the southern Iranian reservoirs was produced and their performance in porous media was studied to reduce the sand production. Designing and producing hydrogel to increase the mechanical strength of reservoir rock and preserving desirable permeability at the same time, is one of the outcomes of the current study. A set of experiments were performed, conducting bottle test, rheology, and coreflooding tests on sandstone core. According to the results, the optimized hydrogel based on maintaining structural strength against stress, temperature and available ions in formation water was approved with 9500 ppm of sulfonated polyacrylamide copolymer, 0.5 wt ratio of Cr(OAc)(3) to copolymer, ultimate elastic modulus of 23 kPa, heat resistant, structural strength at 90 degrees C, and lack of rupture till applying 38700 mu N m torque. Sandstone coreflooding experiment also confirmed a 90% decrease in sand production after the hydrogel injection. Moreover, the water and oil permeabilities were decreased 95 and 7.5 times after the hydrogel injection, respectively. Therefore, the designed hydrogel with the dual function of sand control and relative permeability modification was presented for the field operations.",4,4,1
Porous Media,Relation,"Meng, He",Study on the rock-electric and the relative permeability characteristics in porous rocks based on the curved cylinder-sphere model,Pore structure; Fluid distribution; Wettability; Curved cylinder-sphere model; Rock-electric characteristics; Relative permeability,MEDIA,"Usually, in conventional reservoirs, the rock-electric properties can be explained by Archie's law, and the relative permeability is only considered as a function of fluid saturation. However, as for the complex reservoirs, Archie's law fails to accurately describe the rock-electric properties and the relative permeability is not only affected by saturation, the reason is that both rock-electric and relative permeability characteristics are influenced by multifactors, including the complex pore structure, fluid distribution, and wettability. Currently, there lacks the theoretical method to comprehensively study the multi-factors effect on rock-electric and relative permeability characteristics. In this paper, the curved cylinder-sphere model is developed to illustrate the complex pore-throat structure, fluid distribution, and wettability in real rocks, which can be characterized by two important parameters: the ratio Cd of the curved cylinder radius to the sphere radius and the tortuosity t. Based on the curved cylinder-sphere model, and by using Ohm's law, one can carry out the research on the effect of pore geometry, fluid distribution, and wettability on rock-electric characteristics. Moreover, by combining the curved cylinder-sphere model with Li's model, the effect of pore structure, fluid distribution, and wettability can be incorporated into the relative permeability calculation model. By means of the numerical simulation and analysis, it comes to conclusions that pore structure, fluid distribution, and wettability are the principal factors affecting both rock-electric and relative permeability characteristics, which may cause different formation factor, resistivity index, and relative permeability even in those reservoirs with the same porosity and fluid saturation. Besides, the study demonstrates that the complex pore structure, fluid distribution, and wettability may cause the non-Archie phenomenon of rock-electric characteristics, in addition, the complex pore structure can lead to the decrease of water relative permeability and the increase of oil relative permeability, and when the rock wettability changes from water-wet to oil-wet, water relative permeability increases and oil relative permeability decreases. Furthermore, by the comparison of the simulation results and Lab data, the important effect of complex pore structure and fluid saturation is confirmed.",6,6,1
Porous Media,Relation,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Porous Media,Potential,"Wang, Xin; Guo, Chaohua; He, Sheng; Jiang, Zeyun; Ma, Yongjie",Improved skeleton extraction method considering surface feature of natural micro fractures in unconventional shale/tight reservoirs,Digital core; Natural micro fractures; Skeleton model; Pore-fracture system; Morphological operation,COMPUTED-TOMOGRAPHY; NETWORK MODELS; PORE-SCALE; TOPOLOGY; FLOW; IMAGES; ALGORITHM; SHALE,"Massive micro fractures (MFs) developed in the ultra-tight formations (such as shale/tight reservoirs), which provide preferential channels for the fluids flow. Accurate characterization of such pore-fracture systems and suitable pore network models are the fundamentals of pore structure characterization and micro scale flow simulation. Conventional medial axis (MA) skeleton extraction method cannot preserve the fracture surface feature and connectivity information, which is not suitable for accurate pore scale simulation for these porous media with MFs. In this paper, a new skeleton model was proposed to distinguish MFs from pore space via extraction of surface points set of MFs. In the procedure of points set extraction, we improved the classic ""MA based"" shrink method to ""medial surface (MS) based"" method for the MFs characterization through introducing a new set of skeleton points (i.e., surface points and edge points of the micro fractures). The former describes their apertures and the latter is used for collecting connectivity information and determining the extension ranges of the MFs. Comparison of connectivity index, fracture length, Euclidean distance showed enhanced effectiveness and accuracy of the proposed method. The proposed method was applied in four ideal models and one field shale core sample. Results show that the proposed skeleton model can show more comprehensible forms of the real connected junction instead of the conventional ideal model. The extracted skeleton can also satisfy demands of the traditional skeleton extraction model and preserve the topology of the original pore-fracture space. This work proposed a more accurate method for pore-scale modeling in cores with natural MFs, and potentially applicable for pore scale flow simulations for tight/shale reservoirs.",0,0,4
Porous Media,Potential,"Shahsenov, I. S.; Orujov, G. I.",Modeling of the cementation factor and hydraulic permeability using Mercury Injection Capillary Pressure (MICP) measurements,Cementation factor; Pore size distribution; Mercury Injection Capillary Pressure (MICP); Probabilistic model,POROUS-MEDIA,"Electrical models of the porous medium are widely used for the estimation of the volume fraction of fluids filling in the pore space. One of the input parameters into this type of models is the geometrical factor associated with the complexity of the pore network system also known as ""cementation factor"" used in Archie's saturation model. While this parameter can be measured in the laboratory, the aim of this work is to infer it from the pore size distribution (PSD), which in itself does not bear any information about the geometry of the 3D pore network. The proposed probabilistic model assumes a predefined geometry of the elementary cell, and uses PSD obtained from the Mercury Injection Capillary Pressure (MICP) measurements and porosity to predict the cementation factor. The model achieved a good agreement with an average value of the cementation factor measured on the numerous core samples obtained from the two fields investigated in this study. Geometrical considerations were also investigated through introduction of tortuosity and shape of the capillaries in the model to allow for the potential lithological variations of the reservoir rocks. Similar approach was used to estimate hydraulic permeability using the probabilistic model, and the results were tested against air permeability values measured in the laboratory.",3,3,1
Porous Media,Potential,"Li, Z.; Wang, Y. H.; Chow, J. K.; Su, Z.; Li, X.",3D pore network extraction in granular media by unifying the Delaunay tessellation and maximal ball methods,Pore network extraction; Delaunay tessellation; Maximal ball; DEM simulation,SIZE DISTRIBUTION; POROUS-MEDIA; COMPUTER RECONSTRUCTION; MICROTOMOGRAPHY IMAGES; TOMOGRAPHIC-IMAGES; DEM SIMULATION; THROAT SIZE; TIGHT OIL; PERMEABILITY; SPACE,"In this study, a novel method for pore network extraction in the weakly consolidated media is reported, which unifies both the Delaunay tessellation (DT) and maximal ball (MB) methods in a complementary way. This unified method retains the advantages of both methods, and most importantly, eliminates the disadvantages when either the DT or the MB method is used individually. As a result of such a combination, the merging process of the Delaunay tetrahedra can be carried out in an objective way by utilizing the clustering results of maximal balls. Furthermore, the problems generated in using the maximal balls method, e. g., underestimating the throat size and producing tiny and incorrect throats, can be eliminated by incorporating the Delaunay tessellation, which enables precisely partition the pore space and accurately defining the throat size. Examination of this unified method, based on the results of pore network extraction on a sample (with a periodic boundary) before and after the triaxial shearing using DEM simulation, verifies that this method is objective and effective. The associated morphology of the pore space therefore can be accurately described in terms of the pore size, throat size and the associated distributions. This unified method also has the potential to characterize another dimension of fabric in granular media, i.e., the throat-based fabric.",3,3,1
Porous Media,Potential,"Djuraev, Ulugbek; Jufar, Shiferaw Regassa; Mahardika, Harry; Ooi, Phey Chee",Numerical simulation of seismoelectric effect for monitoring foam propagation through a reservoir,Seismoelectric effect; Foam propagation; Reservoir monitoring,POROUS-MEDIA; FIELD-MEASUREMENTS; JOINT INVERSION; ELASTIC WAVES; CONVERSIONS; EXPLORATION; EQUATIONS,"The seismoelectric phenomenon describes generation of electromagnetic fields when seismic wave passes through fluid saturated porous media. Discovered in the 1930s, the seismoelectric effect have gained attention only in the last few decades as a tool of great potential in geophysical applications. Despite some usage in mineral exploration and ground water flow, routine field applications of this phenomenon are still under development. Nevertheless, recent advancements show great potential of the seismoelectric method in the oil and gas industry. It is now known that several rock and fluid properties affect the seismoelectric response, hence application of this response may be used for reservoir characterization, subsurface imaging and mapping, and monitoring fluid propagation through a reservoir. In this paper, we numerically studied the prospect of monitoring foam propagation through a reservoir using the seismoelectric phenomenon. The reservoir model used in the study was developed using real field data. The virtual pilot area comprised of a cross-well domain between injector well and producer well, where pre-generated foam was continuously injected into the reservoir for the period of 150 days. The seismoelectric data acquisition was modeled in the domain, where the seismic source was deployed in the injection well, and the receiving stations were installed in production well accordingly. The results of the seismoelectric surveys, with interval of 30 days, produced both seismic and seismoelectric signals received by the stations. The processed data, coupled with the average seismic velocity and arrival times of the seismoelectric conversions, were analyzed with regard to determining the locations of the displacing foam front. Subsequent comparison and analysis showed high accuracy match and consistency between the true front positions obtained from the reservoir simulator and the determined locations produced using the seismoelectric method. Additionally, to demonstrate how the seismoelectric signals can be processed in field trials, we applied noise to the same synthetic data used to estimate the foam front positions. We observed that the occurrence of the seismoelectric signal was imperceptible due to the prevailing noise. Subsequently, we applied a filtering method to reduce the effect of the noise that showed great results in uncovering the presence of the seismoelectric conversion in the electrogram while preserving amplitudes and time arrivals of the seismoelectric, seismic and co-seismic signals. According to the obtained findings, we can state that later computations of locating the foam front would yield results with the same accuracy as the noise-free synthetic signals.",4,4,1
Porous Media,Potential,"Rahbar, Marziyeh; Pahlavanzadeh, Hassan; Ayatollahi, Shahab; Manteghian, Mehrdad","Predicting the rock wettability changes using solutions with different pH, through streaming potential measurement",Streaming potential; Zeta potential; pH; Wettability; Calcite,POROUS-MEDIA; LABORATORY MEASUREMENTS; CALCITE; BEHAVIOR; WATER; SURFACES; IMPACT,"The high reactivity of the carbonate rocks at various pH makes it difficult to evaluate the wettability, hence to find the recovery mechanisms behind modified waterflood in carbonate reservoirs. More recently, the streaming potential measurement is introduced as a method of electrokinetic phenomena more relevant to the subsurface systems. Regarding few experimental studies and in order to improve our understanding on streaming potential measurement, the electrokinetic studies on quartz and calcite surface were conducted as a function of pH in the range of 1.5-11.5 using an in-house novel setup of streaming potential measurement. High sensitivity of streaming potential coupling coefficient to pH variation in domain of pH lower than 4 for quartz and higher than 8 for calcite samples, underscores the fact that pH has to be well monitored during water based EOR tests to have more clear and predictable results. In the experiments reported here, measurements of streaming potential were compared with the adhesion test results to use streaming potential measurement as a promising tool to characterize wetting state and quantify wettability of a porous media. The results showed a clear correlation between streaming potential coupling coefficient/zeta potential change, wetting state and calcium concentration expressed as pCa(2+), irrespective of how the pH is changed. Moreover, the equilibrium solutions analyses suggest that streaming potential measurement results are more reliable and applicable compared to electrophoresis method to extend to the subsurface setting during a dynamic injection process.",7,7,0
Porous Media,Potential,"Ghommem, Mehdi; Qiu, Xiangdong; Aidagulov, Gallyam; Abbad, Mustapha",Streaming potential measurements for downhole monitoring of reservoir fluid flows: A laboratory study,Streaming potential; Coreflooding experiments; Flow in porous media; Production and stimulation operations,,"In this paper, we conduct an experimental study to investigate the use of streaming potential measurements for downhole monitoring of fluid flows in porous media for production and stimulation operations. The streaming potential arises from the movement of conductive fluid through a porous medium under an applied pressure gradient. It is generated through a passive electrokinetic process that does not require any electrical power source. Existing coreflooding apparatus is enhanced with capability of streaming potential measurements as oils or brines of different composition and salinity are injected at varying flow rates into carbonate core samples at elevated pressure. The main objective is to establish a correlation between the trend in the variations of the streaming potential and fluid flow in the core and develop the experimental fundamentals within the coreflood equipment. First experimental results are found consistent with previously published data which verifies the new experimental setup. This is followed by performing and analysis of additional experimental cases showing the sensitivity of streaming potential response on the composition of the saturating fluid and the rock permeability. The magnitude of the streaming potential is observed to decrease as the salinity of the brine injected into the core sample is increased and/or rock permeability is higher when maintaining the same fluid injection rate. The streaming potential is also measured for oil-saturated cores while injecting brine. The obtained trend in the streaming potential demonstrates the potential use of such measurements to track the water front during production operations. The goal is to establish experimental fundamentals within the coreflood equipment and this will be used for a further large scale experiment. This is expected to enable a better understanding of the electrokinetic process and alleviate the inherent uncertainties associated with the application of the streaming potential in the field.",8,8,0
Porous Media,Potential,"Nelson, Rhodri; Zuo, Lihua; Weijermars, Ruud; Crowdy, Darren","Applying improved analytical methods for modelling flood displacement fronts in bounded reservoirs (Quitman field, east Texas)",Bounded reservoirs; Potential flow models; Waterflooding; Flow visualization; Time-of-flight contours; Conformal mapping techniques,POROUS-MEDIA FLOW; WATERFLOOD PERFORMANCE; POINT VORTEX; PATH LINES; SIMULATION; DOMAINS; MOTION; GRIDS,"We apply an improved potential flow model based on conformal mapping to study the sweep pattern of waterfloods in bounded reservoirs. Solutions for streamlines and flood advancement obtained with the new model are validated using an independent but more intricate numerical streamline simulation method. Subsequently, the use of the benchmarked model is demonstrated in a review of the flow patterns in the Quitman field, a tabular reservoir comprising an 18 ft thick payzone of Harris sand interfingering with shales of the Eagle Ford formation. The reservoir is bound by impervious faults modelled by the method of images in earlier studies of the 1970's. In the present study, Riemann's mapping theorem in combination with the Schottky-Klein prime function is applied to find complex potentials that describe the flow in the bounded reservoir. Such an approach can model waterflooding in marginal fields like the Quitman oil field more accurately than previous potential flow methods and can visualize the sweep pattern and compute time-of-flight contours in a simpler and faster fashion than numerical streamline simulators.",8,8,0
Porous Media,Potential,"Shovkun, Igor; Espinoza, D. Nicolas",Geomechanical implications of dissolution of mineralized natural fractures in shale formations,Stimulated reservoir volume; Shear failure; Mineral dissolution; Hydraulic fracturing; Acidizing,BARNETT SHALE; GAS-PRODUCTION; POROUS-MEDIA; PERMEABILITY; ROCK; BASIN; FLOW; NETWORKS; MODEL; COAL,"Organic shale reservoirs accommodate large amounts of hydrocarbons in extremely tight rock matrix. Slick water hydraulic fracturing and proppant placement is the most spread stimulating technology for this type of reservoirs. Some shale formations contain a fair amount of easily-dissolvable carbonates, which prompts shale acidizing as a potential method to increase reservoir permeability. Carbonates in shale formations can be present as a part of rock matrix or can be localized in natural fractures - so-called mineral veins. Previous studies investigated the effects of chemical dissolution within the matrix, implying that acidizing can etch the rock, open new conduits for flow, and increase fracture permeability after closure. This study rather focuses on the reservoir-scale geomechanical implications of chemical dissolution of mineral filling in natural fractures. We use a combination of elasto-plastic analytical methods, analogous thermo-elastic numerical solutions, and experimental results to elucidate the impact of veins dissolution on in-situ stresses. Analytical, numerical, and experimental results indicate that mineral dissolution of localized carbonate fractures leads to changes of local in-situ stresses. The direction of stress relaxation strongly depends on the orientation of mineralized fractures. Dissolution of near-vertical mineralized fractures contributes the most to decreases of effective horizontal stress and reduce stress shadow effects in multistage hydraulic fracture completions. Mineral dissolution, similar to pore pressure depletion or thermal cooling/heating, can increase stress anisotropy, which can reactivate critically-oriented natural fractures. In-situ stress chemical manipulation can be used advantageously to enlarge the stimulated reservoir volume.",8,9,1
Porous Media,Potential,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun; Alsaba, Mortadha",Lessons learned from IOR pilots in Bakken formation by using numerical simulation,CO2-EOR in shale oil reservoirs; CO2-EOR huff-n-puff operations; Unconventional EOR methods; Improved oil recovery,RESERVOIRS,"Bakken is the most productive formation among unconventional plays in North America. This formation has about 7.4 billion barrels of recoverable oil. However, the primary oil recovery is still low as 5-10%. Miscible natural gas and carbon dioxide (CO2) might be the most two potential strategies to improve oil recovery in such a complex play. In this study, some of the IOR pilots which have been conducted in Montana, North Dakota, and South Saskatchewan have been presented. The performance results of these pilots in US-Bakken versus Canadian-Bakken have been compared. Moreover, the reasons behind the successful IOR pilots in Canadian-Bakken versus US-Bakken have been discussed. Then, numerical simulation models have been constructed to mimic the results of some pilots. Two different compositional models have been built for oils of two different formations. Furthermore, two different models, single porosity model and dual permeability model have been created to match the performance of some pilots. Implementation of molecular diffusion mechanism has been conducted in both of single porosity and dual permeability model. Finally, the continuous miscible gases injection versus huff-n-puff protocols have been compared and investigated. The results showed that the performance of natural gases generally over-performed the CO2 injection technique's in Bakken formation. Although the diffusion flow is dominant in these types of reservoirs, the diffusivity of the injected CO2 into formation oil is slow due to the fact that CO2 has large molecules as compared with the small pore throats of these porous media. Accordingly, miscible CO2-EOR might not be beneficial in huff-n-puff operations as in continuous flooding process. However, the success of natural gases based EOR does not have that strong functionality of molar diffusivity. Therefore, their performance was much better than CO2 performance in the field scale of these tight formations. Furthermore, the numerical simulation of this study concluded that the spacing between the production wells and injection wells should be minimized, for the continuous flooding process of miscible-gases EOR, to enhance their performance. Although the permeability of Canadian-Bakken has a permeability of 1-2 order higher than the permeability of US-Bakken, the pilots' spacing between injectors and producers in Canadian Bakken is interestingly much shorter than that for US-Bakken, which might be the reason behind the EOR success in Canadian Bakken. Finally, the activatiown process of the highly intensive natural fractures might be the key to enhance the diffusivity of CO2-EOR. Otherwise, natural gases are highly recommended to be the most potential EOR in these types of reservoirs. This study explains how the diffusion mechanism affects the performance of different miscible gases to improve oil recovery in these plays since they are more complex and very different from conventional formations. Also, it suggests that CO2 flooding process would be a good practice to overcome the limitations of CO2-diffusion rate in these reservoirs if the conformance problems are wisely controlled.",8,8,4
Porous Media,Shale,"Wang, Xin; Guo, Chaohua; He, Sheng; Jiang, Zeyun; Ma, Yongjie",Improved skeleton extraction method considering surface feature of natural micro fractures in unconventional shale/tight reservoirs,Digital core; Natural micro fractures; Skeleton model; Pore-fracture system; Morphological operation,COMPUTED-TOMOGRAPHY; NETWORK MODELS; PORE-SCALE; TOPOLOGY; FLOW; IMAGES; ALGORITHM; SHALE,"Massive micro fractures (MFs) developed in the ultra-tight formations (such as shale/tight reservoirs), which provide preferential channels for the fluids flow. Accurate characterization of such pore-fracture systems and suitable pore network models are the fundamentals of pore structure characterization and micro scale flow simulation. Conventional medial axis (MA) skeleton extraction method cannot preserve the fracture surface feature and connectivity information, which is not suitable for accurate pore scale simulation for these porous media with MFs. In this paper, a new skeleton model was proposed to distinguish MFs from pore space via extraction of surface points set of MFs. In the procedure of points set extraction, we improved the classic ""MA based"" shrink method to ""medial surface (MS) based"" method for the MFs characterization through introducing a new set of skeleton points (i.e., surface points and edge points of the micro fractures). The former describes their apertures and the latter is used for collecting connectivity information and determining the extension ranges of the MFs. Comparison of connectivity index, fracture length, Euclidean distance showed enhanced effectiveness and accuracy of the proposed method. The proposed method was applied in four ideal models and one field shale core sample. Results show that the proposed skeleton model can show more comprehensible forms of the real connected junction instead of the conventional ideal model. The extracted skeleton can also satisfy demands of the traditional skeleton extraction model and preserve the topology of the original pore-fracture space. This work proposed a more accurate method for pore-scale modeling in cores with natural MFs, and potentially applicable for pore scale flow simulations for tight/shale reservoirs.",0,0,4
Porous Media,Shale,"Zheng, Da; Reza, Zulfiquar",Prediction of pore-scale transport properties in unconventional reservoirs using novel theoretical dendroidal pore-network model,,POROUS-MEDIA; SHALE; FLOW,"Measurement of transport properties of shale in laboratories can be expensive, extremely time-intensive and inaccurate due to lack of sufficient tool resolution. On the other hand, rigorous pore-scale simulation is prohibitively compute-intensive and is limited to sub-micron scale lacking volume-representativeness. Thus, theoretical pore-network modeling is a routine method to characterize the transport properties of shales. Connectivity architecture of porous media observed in unconventional shale reservoirs is markedly different from that in conventional reservoirs. The theoretical models developed for conventional reservoirs are explicitly proven to be not appropriate in capturing the unique characteristics of unconventional reservoirs; meanwhile, most models proposed for unconventional reservoirs are too simplified to capture realistic pore distribution. This paper presents a stochastically-distributed dendroidal pore-network model based on the analysis of pore-networks extracted from scanning electron tomographic microscope (SEM) images. Semi-acyclic model is adopted to capture the non-plateau trend of mercury intrusion capillary pressure (MICP) versus non-wetting phase saturation curve. Mercury drainage experimental data have also been compensated for the effect of pore compressibility. Intrinsic permeability and relative permeability is evaluated and validated to be in an acceptable range. Apparent permeability and its relation to intrinsic permeability is predicted by different gas-slippage correlations based on the dendroidal models. Data and samples from Marcellus shales are employed to validate the new proposed pore-network model and to compare different correlations of apparent permeability. Besides the predictive power, this new dendroidal model can also be employed as an analog of real shale porous media to perform different pore-scale simulations and analyses.",3,3,0
Porous Media,Shale,"Li, Haibo; Guo, Hekun; Yang, Zhengming; Wang, Xuewu; Sun, Yuping; Xu, Hongcheng; Zhang, Hewen; Lu, Haibing; Meng, Huan",Boundary retention layer influence on permeability of tight reservoir,Tight oil reservoir; Boundary retention layer; Permeability; Fluid medium; Pore structure; Movable fluid; Clay content,HEAT-TRANSFER; TRANSIENT ANALYSIS; MAGNETIC-FIELD; GAS-RESERVOIRS; POROUS-MEDIA; NANOFLUID; WATER; TURBULATORS; EXCHANGER; SHALE,"The permeability of typical tight oil reservoir cores is measured using difference fluid medium (nitrogen, formation water, kerosene), and a capillary permeability model considering boundary retention layers is build. The computed values of the model are compared with experimental values of cores. The difference of permeability using different fluid medium is discussed concerning boundary retention layer thickness, movable fluid pore space and clay contents. The experiment results showed that targeted reservoir cores klinkenberg permeability K-infinity was 66.86% of conventional gas permeability K-g, and water permeability K-w was 11.66% of K-g, and oil permeability K-o was 2.46% of K-g. K-w and K-o could characterize reservoir water injection and development difficulty better than K-g. K-h/K (ratio between permeability of capillary model considering and not considering boundary retention layer), is perfectly consistent with K-infinity/K-g, which indicates that capillary permeability model considering boundary retention layer has good consistency with seepage characteristics of actual reservoir. The tight cores have smaller effective pore-throat space for flowing, and get larger effect of boundary retention layers. The smaller the permeability core have, the closer between K-h/K and K-infinity/K-g . Boundary layer thickness are increased by Clay swelling, and flow channel are blocked by clay off and migration, that the main reason of K-w smaller than K-infinity. The lower K-g cores have, the more K-w/K-infinity, decrease magnitude. K-o is much lower than IL and K-w because of increased oil seepage resistance by two-phase seepage and boundary retention layer.",4,4,1
Porous Media,Shale,"Bui, Binh T.; Tutuncu, Azra N.",Interfacial tension induced-transport in shale: A pore-scale study,,NETWORK MODELS; POROUS-MEDIA; WETTABILITY; THROAT,"While unconventional reservoirs have quickly become a main contributor to oil and gas production, the transport mechanism in shale is not well understood. Although water does not imbibe into oil-wetted rock matrix, it has been observed in laboratory measurements that it can. The amount of water imbibed into the rock matrix increases when the salinity of the injected water decreases. Wettability alteration is often considered as the main reason for this phenomenon. One of the physical mechanisms for the imbibition of low salinity water into an oil-wetted rock matrix is the variation of the interfacial tension and the contact angle. The change of salinity initiates the change of interfacial tension driving the movement of the interface imbibing water into oil-wetted pores. The imbibition of the water into the rock matrix is a complicated process requiring a comprehensive understanding of the mass transport at pore scale. Hence, pore scale modeling was used in this research study for understanding the physics of transport at pore scale caused by interfacial tension variation or interfacial tension-induced transport. First, a simplified pore-scale model is presented to simulate the imbibition of water into an oil-wetted pore. Next, a numerical solution and procedure are outlined to simulate the transient mass transport in the pore as the result of interfacial tension variation due to salinity. The results indicate that the interfacial tension-induced transport is a very important mechanism for water imbibition into oil-wetted pores. How fast the water imbibes into the pore depends on the salinity gradient and the type of solute used. When salinity at the inlet of the pore is low, more solute diffuses out of the pore resulting in higher cumulative recovery from the pore. Reducing the interfacial tension between oil and water forces oil out of the pores and improve the oil recovery. Hence, low salinity water is recommended for low salinity water injection enhanced oil recovery.",4,4,2
Porous Media,Shale,"Tian, Xiao; Daigle, Hugh",Permeability prediction from a pore-scale network model constrained by low-pressure nitrogen sorption isotherms,Shale; Permeability; Pore network model; Percolation theory; Nitrogen sorption,ADSORPTION-DESORPTION MEASUREMENTS; SHALE GAS-RESERVOIR; ORGANIC-MATTER; BARNETT SHALE; SURFACE-AREA; POROUS-MEDIA; DYNAMIC PROPERTIES; GRAIN ASSEMBLAGES; SEDIMENTARY-ROCKS; SIZE DISTRIBUTION,"The matrix permeability of shale is controlled by the microstructure of shale pore network. Therefore, a thorough understanding of shale pore structure is fundamental to the prediction of shale permeability. We constructed a physically representative pore network model for two Barnett Shale samples. We predicted a Darcy permeability of 7.19 nanodarcies (nd) and apparent permeability of 57.34 nd for these samples. We explored the pore structure of shale matrix with low-pressure nitrogen adsorption/desorption isotherms. The pore size distribution, the network connectivity, as well as pore spatial arrangement are determined for the organic matter and the whole matrix. We separated pores in the network model into two groups: the affiliated pores and the dominant pores. For these samples, the affiliated pores are pores with diameters smaller than 8 nm and the dominant pores are with diameters larger than 8 nm. The affiliated pores develop on the walls of the dominant pores. The cutoff value between affiliated pores and dominant pores may differ for different samples. The pore spatial arrangement is validated against previous literature resultsand a diagenetic explanation for development of shale pore system. The network model can be used to predict shale permeability and other petrophysical properties.",5,5,1
Porous Media,Shale,"Lee, Kyung Jae; Finsterle, Stefan; Moridis, George J.",Analyzing the impact of reaction models on the production of hydrocarbons from thermally upgraded oil shales,In-situ upgrading; Oil shale; Numerical simulation; Sensitivity analysis; Uncertainty prediction; Data-worth analysis,SIMPLE KINETIC-MODELS; NUMERICAL-SIMULATION; PETROLEUM FORMATION; GAS GENERATION; POROUS-MEDIA; EXPULSION; CRACKING; EQUATION,"Reaction parameters significantly affect oil production from shales by means of heating and in-situ upgrading. In this study, we perform numerical simulations of two chemical reaction models, which are mainly used in the research of kerogen pyrolysis and subsequent hydrocarbon decomposition in organic-rich porous media. They are the Braun and Burnham model and Wellington model. In these forward numerical simulations, we present the influence of the two reaction models on hydrocarbon production. The Braun and Burnham reaction model shows more vigorous kerogen and subsequent decomposition reactions and more hydrocarbon production than the Wellington model. A local sensitivity analysis identifies the reaction parameters with the highest influence on productivity, and the most sensitive outputs. A data-worth analysis identifies the most valuable observation data to be measured for the best prediction of total hydrocarbon production. We find that the most valuable observation data is the cumulative production of heavy oil in the Braun and Burnham model and of light oil in the Wellington model, respectively. Once we determine the maximum allowable prediction uncertainty and the expected measurement uncertainty, the observation data to be measured for the minimization of prediction uncertainty can be obtained.",6,6,0
Porous Media,Shale,"Nelson, Rhodri; Zuo, Lihua; Weijermars, Ruud; Crowdy, Darren","Applying improved analytical methods for modelling flood displacement fronts in bounded reservoirs (Quitman field, east Texas)",Bounded reservoirs; Potential flow models; Waterflooding; Flow visualization; Time-of-flight contours; Conformal mapping techniques,POROUS-MEDIA FLOW; WATERFLOOD PERFORMANCE; POINT VORTEX; PATH LINES; SIMULATION; DOMAINS; MOTION; GRIDS,"We apply an improved potential flow model based on conformal mapping to study the sweep pattern of waterfloods in bounded reservoirs. Solutions for streamlines and flood advancement obtained with the new model are validated using an independent but more intricate numerical streamline simulation method. Subsequently, the use of the benchmarked model is demonstrated in a review of the flow patterns in the Quitman field, a tabular reservoir comprising an 18 ft thick payzone of Harris sand interfingering with shales of the Eagle Ford formation. The reservoir is bound by impervious faults modelled by the method of images in earlier studies of the 1970's. In the present study, Riemann's mapping theorem in combination with the Schottky-Klein prime function is applied to find complex potentials that describe the flow in the bounded reservoir. Such an approach can model waterflooding in marginal fields like the Quitman oil field more accurately than previous potential flow methods and can visualize the sweep pattern and compute time-of-flight contours in a simpler and faster fashion than numerical streamline simulators.",8,8,0
Porous Media,Shale,"Shovkun, Igor; Espinoza, D. Nicolas",Geomechanical implications of dissolution of mineralized natural fractures in shale formations,Stimulated reservoir volume; Shear failure; Mineral dissolution; Hydraulic fracturing; Acidizing,BARNETT SHALE; GAS-PRODUCTION; POROUS-MEDIA; PERMEABILITY; ROCK; BASIN; FLOW; NETWORKS; MODEL; COAL,"Organic shale reservoirs accommodate large amounts of hydrocarbons in extremely tight rock matrix. Slick water hydraulic fracturing and proppant placement is the most spread stimulating technology for this type of reservoirs. Some shale formations contain a fair amount of easily-dissolvable carbonates, which prompts shale acidizing as a potential method to increase reservoir permeability. Carbonates in shale formations can be present as a part of rock matrix or can be localized in natural fractures - so-called mineral veins. Previous studies investigated the effects of chemical dissolution within the matrix, implying that acidizing can etch the rock, open new conduits for flow, and increase fracture permeability after closure. This study rather focuses on the reservoir-scale geomechanical implications of chemical dissolution of mineral filling in natural fractures. We use a combination of elasto-plastic analytical methods, analogous thermo-elastic numerical solutions, and experimental results to elucidate the impact of veins dissolution on in-situ stresses. Analytical, numerical, and experimental results indicate that mineral dissolution of localized carbonate fractures leads to changes of local in-situ stresses. The direction of stress relaxation strongly depends on the orientation of mineralized fractures. Dissolution of near-vertical mineralized fractures contributes the most to decreases of effective horizontal stress and reduce stress shadow effects in multistage hydraulic fracture completions. Mineral dissolution, similar to pore pressure depletion or thermal cooling/heating, can increase stress anisotropy, which can reactivate critically-oriented natural fractures. In-situ stress chemical manipulation can be used advantageously to enlarge the stimulated reservoir volume.",8,9,1
Porous Media,Shale,"Alfarge, Dheiaa; Wei, Mingzhen; Bai, Baojun; Alsaba, Mortadha",Lessons learned from IOR pilots in Bakken formation by using numerical simulation,CO2-EOR in shale oil reservoirs; CO2-EOR huff-n-puff operations; Unconventional EOR methods; Improved oil recovery,RESERVOIRS,"Bakken is the most productive formation among unconventional plays in North America. This formation has about 7.4 billion barrels of recoverable oil. However, the primary oil recovery is still low as 5-10%. Miscible natural gas and carbon dioxide (CO2) might be the most two potential strategies to improve oil recovery in such a complex play. In this study, some of the IOR pilots which have been conducted in Montana, North Dakota, and South Saskatchewan have been presented. The performance results of these pilots in US-Bakken versus Canadian-Bakken have been compared. Moreover, the reasons behind the successful IOR pilots in Canadian-Bakken versus US-Bakken have been discussed. Then, numerical simulation models have been constructed to mimic the results of some pilots. Two different compositional models have been built for oils of two different formations. Furthermore, two different models, single porosity model and dual permeability model have been created to match the performance of some pilots. Implementation of molecular diffusion mechanism has been conducted in both of single porosity and dual permeability model. Finally, the continuous miscible gases injection versus huff-n-puff protocols have been compared and investigated. The results showed that the performance of natural gases generally over-performed the CO2 injection technique's in Bakken formation. Although the diffusion flow is dominant in these types of reservoirs, the diffusivity of the injected CO2 into formation oil is slow due to the fact that CO2 has large molecules as compared with the small pore throats of these porous media. Accordingly, miscible CO2-EOR might not be beneficial in huff-n-puff operations as in continuous flooding process. However, the success of natural gases based EOR does not have that strong functionality of molar diffusivity. Therefore, their performance was much better than CO2 performance in the field scale of these tight formations. Furthermore, the numerical simulation of this study concluded that the spacing between the production wells and injection wells should be minimized, for the continuous flooding process of miscible-gases EOR, to enhance their performance. Although the permeability of Canadian-Bakken has a permeability of 1-2 order higher than the permeability of US-Bakken, the pilots' spacing between injectors and producers in Canadian Bakken is interestingly much shorter than that for US-Bakken, which might be the reason behind the EOR success in Canadian Bakken. Finally, the activatiown process of the highly intensive natural fractures might be the key to enhance the diffusivity of CO2-EOR. Otherwise, natural gases are highly recommended to be the most potential EOR in these types of reservoirs. This study explains how the diffusion mechanism affects the performance of different miscible gases to improve oil recovery in these plays since they are more complex and very different from conventional formations. Also, it suggests that CO2 flooding process would be a good practice to overcome the limitations of CO2-diffusion rate in these reservoirs if the conformance problems are wisely controlled.",8,8,4
Porous Media,Behavior,"Orlov, Denis; Koroteev, Dmitry; Sitnikov, Alexander",Self-Colmatation in terrigenic oil reservoirs of Eastern Siberia,Colmatation; Formation damage; Permeability reduction; Water flooding; Fine migration; Rock properties,DEEP BED FILTRATION; POROUS-MEDIA; WATER-SENSITIVITY; FORMATION DAMAGE; FINES; MODEL; MIGRATION; TRANSPORT; SANDSTONE; FLOW,"The main objective of this work is to study formation damage phenomenon associated with in-situ migration of fines in rock samples from terrigenic reservoirs of Eastern Siberia experimentally. Results of oil flooding for the wide range of flow rates and permeabilities show that oil does not lead to fine mobilization and its consequent retention with permeability reduction. The permeability decrease is observed only when water is flowing in the porous space. Water itself is shown to be a strong driver of self-colmatation, which is likely because of its intensive physicochemical reaction with pore surface. Performing multiple core flooding tests and analyzing the data, we define the range of rock properties and flow conditions corresponding to development of the situ formation damage (self-colmatation). We classify self-colmatation over 5 types characterized with different behaviors of permeability decrease. We comprehensively study the dependencies of permeability reduction specifics on rock properties and flooding conditions. The dependencies account for multiple parameters correlated with permeability reduction: absolute permeability, residual oil saturation, three characteristic pore diameters, four characteristic grain diameters and four major minerals within the rock structure. We discovered that the increase of formation damages are associated with high absolute permeability and low residual oil saturations. It was shown that characteristic size of migrating fines is 0.01-0.005 mm and the diameter of pores where these fines can be strained is 12 mu m. We derive a single numerical criterion to estimate the influence of 13 parameters on colmatation process. The absolute permeability and the fraction of pore throats with diameters higher than 30 mu m are shown to be the strongest influencers on colmatation.",2,2,0
Porous Media,Behavior,"Alamooti, Amirhossein Mohammdi; Ghazanfari, Mohmmad Hossein; Masihi, Mohsen",Investigating the relative permeability behavior in presence of capillary effects in composite core systems,Composite core systems; Relative permeability; Experimental; Modeling; Layered heterogeneous porous media,DISPLACEMENT EXPERIMENTS,"Successful designs for an injection process to improve reservoir recovery seek more accurate values of saturation dependent functions, including relative permeability curves. The ignorance on underlying heterogeneity (e.g. layering) might lead to inaccurate predicting of flow behavior in layered heterogeneous porous media. Analysis of experimental core flood results in composite core systems (the system) along with numerical simulation at the core scale can provide an insight into this problem, especially when the capillary effects are present. In this study unsteady state two phase displacements have been conducted on the system with different internal arrangements. The main contribution is to compare the relative permeability behavior of composite system against the results of single cores using both explicit as well as implicit methods in the presence of capillary forces. The experimental results showed that fluid flow behavior in the system significantly differs from of the flow characteristics in single cores. The controlling parameters on the relative permeability behavior of whole system include the internal arrangement, permeability values and length of cores. Simulation results showed that in the case of descending ordering (of permeability), the relative permeability of the system is almost independent of the individual cores' length. In contrast, in the case of ascending ordering of core permeability values, it strongly depends on the core structure. When the capillary pressure and relative permeability curves of individual cores are the same, simulation results showed that Huppler arrangement gives the relative permeability of the system close to the behavior of the individual cores. A new correlation set has been developed which predict the relative permeability of whole system based on the relative permeability, internal arrangements, and lengths of single cores with a reasonable agreement.",2,2,0
Porous Media,Behavior,"Wang, Shuyan; Li, Haoting; Wang, Ruichen; Tian, Ruichao; Sun, Qiji; Ma, Yimei",Numerical simulation of flow behavior of particles in a porous media based on CFD-DEM,Porous media; Microchannel; Computational fluid dynamic (CFD); Simulation; Discrete element method (DEM); Grains of sand,GAS-SOLID FLOW; PETROLEUM MIGRATION; FLUIDIZED-BED; MODEL; OIL,"The movements of particles in porous media exist in various modules of oil field development and production. Flow behavior of particles in a porous media is simulated by means of CFD-DEM. The lubrication force originated from the normal ""squeezing"" motion of the particles is considered. By changing the porosity of the porous media, the distributions of velocity, residence time of particles, and granular temperature are analyzed within the porous media. At a low porosity, particles will be blocked and deposited in the porous media. Increasing porosity prolongs the trajectory of particles, and particles do reciprocating motion and flow out the microchannel. Simulated results indicate that with an increase of porosity, the residence time is decreased, and then increased, while the granular temperature is in reverse. The predicted axial velocity of particles and the granular temperature decrease with an increase of liquid viscosity, while the mean residence time and contact force increase with an increase of liquid viscosity. Simulations indicate that the granular temperature and the contact force are increased, and the residence time of grains is reduced, with an increase of liquid velocity. The main contribution here is that the hydrodynamic characteristics of particles in a porous media are revealed based on the detail information of flow behaviors of particles.",4,4,8
Porous Media,Behavior,"Jia, Hu; Deng, Li-hui",Non-equilibrium 3-D simulator applied to air injection EOR in light oil reservoirs,,POROUS-MEDIA; NUMERICAL-SIMULATION; CAPILLARY-PRESSURE; RECOVERY; COMBUSTION; PERFORMANCE; PROJECTS; FLOW; PERMEABILITY; MECHANISM,"In this paper, a 3-D simulator based on the assumption of both chemical and thermal non-equilibrium is presented for a more realistic view of non-equilibrium process for simulating air injection EOR (enhanced oil recovery). The mathematical model is based on a non-equilibrium stage with dynamic mass transfer process between different fluid phases and energy transfer process between fluid and matrix (solid). The light crude oil oxidation and air injection process are both simulated by this simulator, through which the pore blocking, gas breakthrough and gas override process are presented through the visualization of oil, gas saturation distributions. The crude oil oxidation is refined as in-phase and interphase reactions to investigate the effect of reactant dispersion caused by the gas-liquid mass transfer. The oxygen dissolution and the evaporation of light components in crude oil are considered in the non-equilibrium process. The results without mass transfer, with dynamic mass transfer and with instantaneous mass transfer between gas and liquid phases are compared through multiplying the gas-liquid interface area 0, 1 and 100 times respectively, and the influence of these different mass transfer conditions on the migration of temperature peak front and oil recovery is revealed. In addition, the effect of local chemical and thermal non-equilibrium in different matrix permeability as well as porosity scenarios is also investigated to obtain non-equilibrium behavior in different reservoir conditions when implementing air injection EOR. In the last section, we investigated the result with different simulation timescale to see if the non-equilibrium behavior can be captured in the simulator used in this paper. This study suggests that the non-equilibrium behavior would show obvious influence on oil recovery for air injection in the lower permeability reservoir. The non-equilibrium behavior is desirable to be considered for simulating air injection EOR in light oil reservoirs. The developed 3-D simulator is robust that can better reflect the mechanism of air injection EOR in light oil reservoirs. We hope this work encouraging more investigations for the simulation side of nonequilibrium phase behavior and energy transfer in the air injection process.",5,5,1
Porous Media,Behavior,"Rahbar, Marziyeh; Pahlavanzadeh, Hassan; Ayatollahi, Shahab; Manteghian, Mehrdad","Predicting the rock wettability changes using solutions with different pH, through streaming potential measurement",Streaming potential; Zeta potential; pH; Wettability; Calcite,POROUS-MEDIA; LABORATORY MEASUREMENTS; CALCITE; BEHAVIOR; WATER; SURFACES; IMPACT,"The high reactivity of the carbonate rocks at various pH makes it difficult to evaluate the wettability, hence to find the recovery mechanisms behind modified waterflood in carbonate reservoirs. More recently, the streaming potential measurement is introduced as a method of electrokinetic phenomena more relevant to the subsurface systems. Regarding few experimental studies and in order to improve our understanding on streaming potential measurement, the electrokinetic studies on quartz and calcite surface were conducted as a function of pH in the range of 1.5-11.5 using an in-house novel setup of streaming potential measurement. High sensitivity of streaming potential coupling coefficient to pH variation in domain of pH lower than 4 for quartz and higher than 8 for calcite samples, underscores the fact that pH has to be well monitored during water based EOR tests to have more clear and predictable results. In the experiments reported here, measurements of streaming potential were compared with the adhesion test results to use streaming potential measurement as a promising tool to characterize wetting state and quantify wettability of a porous media. The results showed a clear correlation between streaming potential coupling coefficient/zeta potential change, wetting state and calcium concentration expressed as pCa(2+), irrespective of how the pH is changed. Moreover, the equilibrium solutions analyses suggest that streaming potential measurement results are more reliable and applicable compared to electrophoresis method to extend to the subsurface setting during a dynamic injection process.",7,7,0
Porous Media,Behavior,"Phirani, J.; Roy, S.; Pant, H. J.",Predicting stagnant pore volume in porous media using temporal moments of tracer breakthrough curves,Temporal moments; Coats-Smith model; Porous media; Tracer breakthrough curve,DISPERSION; FLOW; TRANSPORT; BEHAVIOR,"The heterogeneity in complex porous media like oil reservoirs and aquifers many times renders a fraction of fluid in the pores immobile. The tracer breakthrough curves that are used to characterize the porous media are impacted by the immobile volume fraction and show a tailing effect. It is important to first recognize the presence of the immobile volume and quantify it based on a single tracer breakthrough curve in complex geological environments. In this work, we use the method of moments on the tracer breakthrough curve to solve the inverse problem of porous media characterization with stagnant volume fractions. In particular, we use a three parameter model describing the tracer transport in a porous medium with an immobile fluid fraction and solve the forward problem analytically. We derive mean, variance, skewness, and kurtosis of the analytical solution for the exit age density of the injected tracer in the porous medium. We then describe the behavior of the moments in the parameter space of the transport model and relate it with the tracer transport behavior in the porous medium. We then develop the solution for the inverse problem of using these higher order temporal moments of the effluent tracer concentration to estimate the immobile fluid volume in the porous medium.",7,7,2
Porous Media,Behavior,"Liu, Yuetian; Yu, Peng; Ding, Zupeng",Research on stress-sensitivity of fractured porous media,Oil and gas reservoir; Zero-stress model; High dip fracture; Fracture aperture; Fracture permeability,PERMEABILITY; COMPRESSIBILITY; DEFORMATION; BEHAVIOR; POROSITY; WHOLE,"Stress sensitivity parameters of a fracture are often tested under compression on both sides of the fractured medium, which is considered as an elastic solid. However, the elastic solid assumption will fail when two fracture surfaces, if applied to tensile stresses, are out of contact. In such cases, effective stress in the fracture is zero and the change of fracture aperture is not determined by the fracture itself, but by the deformation of the matrix and the overall deformation of the fractured region. This paper proposed a zero-stress model that is applicable after the failure of elastic fracture model as described above. The model analyzes the deformation mechanism of fractures and derives a new equation that can be used to describe the aperture and permeability behavior of a fractured medium under the condition of zero stress. The model is derived for different geometric shapes of fractured region under hydrostatic pressures. The model equations can be used to calculate aperture and permeability changes caused by the production of oil and gas from a reservoir as well as the injection of water or gases for EOR. Sensitivity analysis of the model found that both shape factor of the fractured region and elastic modulus of the surrounding rocks have a significant impact on the outcome of the aperture and permeability forecast as a function of changing pore pressure. The permeability model can also be used in reservoir engineering analysis and reservoir numerical simulation. The new model is joined with the traditional elastic model to better describe the deformation process of fractures.",7,7,3
Porous Media,Behavior,"Dong, Kai; Zhu, Ding; Hill, A. Daniel",Mechanism of wormholing and its optimal conditions: A fundamental explanation,Wormholing mechanism; Carbonate acidizing; Optimal conditions; Pore growth function; Pore scale,POROUS-MEDIA,"Acid stimulation is commonly used in carbonate reservoirs, which can be either matrix acidizing or acid fracturing. In both treatments, wormholes can form. In matrix acidizing, wormholing is favorable because the damaged region can be bypassed. In acid fracturing, wormholing is not desired because it can increase fluid loss, which can limit conductive fracture length. Three major processes are involved for wormholing: convection, diffusion and surface reaction. A thorough understanding of these processes is necessary for engineering design. In this paper, we fundamentally explore wormholing mechanisms starting from pore growth. A wormhole forms when larger pores grow in cross-sectional area at a rate that greatly exceeds the growth rate of smaller pores due to surface reaction. This happens when pore growth follows a particular mechanism, which is discussed in this paper. We developed a model to predict wormhole growth behavior. The model uses the mode-size pore in a pore size distribution - the pore size that appears most frequently in a distribution - to predict the growth of the pore. By controlling the acid velocity inside of it, we can make larger pores grow much faster than other smaller pores, thus reaching the most favorable condition for wormholing. This also results in a balance between overall acid/rock reaction and acid flow. By understanding the wormholing mechanism, engineers can select proper treatment fluids and pumping rate for acid stimulation design.",8,9,0
Porous Media,Behavior,"Wei, Peng; Pu, Wanfen; Sun, Lin; Zhou, Wei; Ji, Xudong",Foam stabilized by alkyl polyglycoside and isoamyl alcohol for enhancing oil recovery in the low-permeable reservoir,APG foam; Isoamyl alcohol; Surface behavior; Foam stability; Low permeability,HIGH-SALINITY ENVIRONMENTS; AIR-WATER-INTERFACE; POROUS-MEDIA; HIGH-TEMPERATURE; CO2 FOAM; GAS TYPE; SURFACTANT; COALESCENCE; DRAINAGE; FILM,"Few studies have delved into the effect of low molecular alcohol on foam stability. This study firstly investigated the improvement in adsorption behavior and viscoelastic behavior at the surface of the APG solution in the presence of isoamyl alcohol, and then we observed that isoamyl alcohol could hinder the liquid drainage and retard the foam rupture by introducing the stabilization capacity (i.e., reducing the surface tension, increasing the surface viscoelasticity, creating the H-bond and providing the disjoining pressure). Afterwards, the addition of isoamyl alcohol can efficiently diminish the defoaming effect of crude oil and impose a considerable oil resistant in foam system. Finally, the flooding experiments were conducted in the tight formation. The results indicate that APG-alcohol foam presents a fine texture and reaches the maximum apparent viscosity at the transition foam quality of 0.67. As presented in the NMR experiment, APG-alcohol foam can efficiently displace the oil in pores with various sizes and substantially promote the EOR to 30.35%.",8,8,5
Porous Media,Surface,"Yoshida, Takero; Brumby, Paul E.; Oyama, Hiroyuki; Fytianos, Georgios; Sato, Toru; Sakaizawa, Ryosuke; Fuji, Tatsuya; Nagao, Jiro; Tenma, Norio; Narita, Hideo",Modeling of shear stress distribution on mud surface in the subsea sand-mud alternate layer,Sand-mud alternate layer; Mud surface erosion; Sandy porous media; Shear stress distribution; Lattice Boltzmann method; Gamma distribution function,EASTERN NANKAI TROUGH; PRODUCTION TEST-SITE; DAINI-ATSUMI KNOLL; EQUATION; EROSION,"This study aims at showing that the shear stress distribution on a flat surface in the porous media can be expressed by just one probability density function. It is known that methane hydrate exists in the sand layers off Kii Peninsula in Japan within the turbidite sand-mud alternate strata. One of the concerns about gas production from methane hydrate is mud erosion and consequent reservoir clog caused by skin formation. The erosion rate of mud particles depends on the shear stress distribution on the surface of the mud layer in the alternates. The distribution of shear stress should depend on the flow and reservoir properties. Being able to predict the total mass of the eroded mud in advance would definitely be convenient. The objective of this paper is to propose a mathematical model of shear stress distribution on a flat interface between sand and mud layers, because it is believed that the maximum mud-erosion rate is given at the very beginning of the gas production when the mud surface is almost flat. To obtain the shear stress distribution on a flat surface, we conducted pore-scale numerical simulations using computational domains including numerically generated sand-mud beds. Interestingly, we found that the histograms of the shear stresses fit just one curve by means of proper non-dimensionalization. These consistent histograms of the non-dimensional shear stress were then matched with a Gamma distribution function, to develop a mathematical model. This new finding may make possible to predict the maximum rate of mud erosion if we know water flow velocity and reservoir properties, such as porosity and permeability.",0,0,1
Porous Media,Surface,"Wang, Xin; Guo, Chaohua; He, Sheng; Jiang, Zeyun; Ma, Yongjie",Improved skeleton extraction method considering surface feature of natural micro fractures in unconventional shale/tight reservoirs,Digital core; Natural micro fractures; Skeleton model; Pore-fracture system; Morphological operation,COMPUTED-TOMOGRAPHY; NETWORK MODELS; PORE-SCALE; TOPOLOGY; FLOW; IMAGES; ALGORITHM; SHALE,"Massive micro fractures (MFs) developed in the ultra-tight formations (such as shale/tight reservoirs), which provide preferential channels for the fluids flow. Accurate characterization of such pore-fracture systems and suitable pore network models are the fundamentals of pore structure characterization and micro scale flow simulation. Conventional medial axis (MA) skeleton extraction method cannot preserve the fracture surface feature and connectivity information, which is not suitable for accurate pore scale simulation for these porous media with MFs. In this paper, a new skeleton model was proposed to distinguish MFs from pore space via extraction of surface points set of MFs. In the procedure of points set extraction, we improved the classic ""MA based"" shrink method to ""medial surface (MS) based"" method for the MFs characterization through introducing a new set of skeleton points (i.e., surface points and edge points of the micro fractures). The former describes their apertures and the latter is used for collecting connectivity information and determining the extension ranges of the MFs. Comparison of connectivity index, fracture length, Euclidean distance showed enhanced effectiveness and accuracy of the proposed method. The proposed method was applied in four ideal models and one field shale core sample. Results show that the proposed skeleton model can show more comprehensible forms of the real connected junction instead of the conventional ideal model. The extracted skeleton can also satisfy demands of the traditional skeleton extraction model and preserve the topology of the original pore-fracture space. This work proposed a more accurate method for pore-scale modeling in cores with natural MFs, and potentially applicable for pore scale flow simulations for tight/shale reservoirs.",0,0,4
Porous Media,Surface,"Orlov, Denis; Koroteev, Dmitry; Sitnikov, Alexander",Self-Colmatation in terrigenic oil reservoirs of Eastern Siberia,Colmatation; Formation damage; Permeability reduction; Water flooding; Fine migration; Rock properties,DEEP BED FILTRATION; POROUS-MEDIA; WATER-SENSITIVITY; FORMATION DAMAGE; FINES; MODEL; MIGRATION; TRANSPORT; SANDSTONE; FLOW,"The main objective of this work is to study formation damage phenomenon associated with in-situ migration of fines in rock samples from terrigenic reservoirs of Eastern Siberia experimentally. Results of oil flooding for the wide range of flow rates and permeabilities show that oil does not lead to fine mobilization and its consequent retention with permeability reduction. The permeability decrease is observed only when water is flowing in the porous space. Water itself is shown to be a strong driver of self-colmatation, which is likely because of its intensive physicochemical reaction with pore surface. Performing multiple core flooding tests and analyzing the data, we define the range of rock properties and flow conditions corresponding to development of the situ formation damage (self-colmatation). We classify self-colmatation over 5 types characterized with different behaviors of permeability decrease. We comprehensively study the dependencies of permeability reduction specifics on rock properties and flooding conditions. The dependencies account for multiple parameters correlated with permeability reduction: absolute permeability, residual oil saturation, three characteristic pore diameters, four characteristic grain diameters and four major minerals within the rock structure. We discovered that the increase of formation damages are associated with high absolute permeability and low residual oil saturations. It was shown that characteristic size of migrating fines is 0.01-0.005 mm and the diameter of pores where these fines can be strained is 12 mu m. We derive a single numerical criterion to estimate the influence of 13 parameters on colmatation process. The absolute permeability and the fraction of pore throats with diameters higher than 30 mu m are shown to be the strongest influencers on colmatation.",2,2,0
Porous Media,Surface,"Hwang, Jongsoo; Sharma, Mukul M.",Generation and filtration of O/W emulsions under near-wellbore flow conditions during produced water re-injection,O/W emulsions; Filtration; Capillary desaturation; Near-well flow conditions; Produced water re-injection; Water injectivity,POROUS-MEDIA; STABLE EMULSIONS; RESIDUAL OIL; WASTE-WATER; MODEL; INJECTIVITY; TRANSPORT; DILUTE,"Produced water in the oilfield contains oil droplets in the form of oil-in-water (O/W) emulsions. These oil droplets cannot be completely separated from the water by surface facilities, and produced water still containing suspended emulsions is re-injected into formations. These oil droplets plug the pore space in the near-wellbore or near-fracture region, resulting in rapid declines in the performance of water injection wells where the remediation processes can be expensive. Displaced oil droplets also contribute to the plugging of pore space near injection wells. These oil droplets are generated by high-velocity flow displacing residual oil in the rock. Because generation and filtration processes occur simultaneously, it is critical to understand both processes at high-velocity flow conditions. This paper experimentally quantifies the rate of generation and filtration of oil droplets in high-velocity flow. For the first time, empirical models were suggested to predict droplet size and rate of generation as a function of trapping number. For the filtration, synthetic dilute O/W emulsions were injected into granular packs to measure the filtration coefficient at various trapping numbers, grain sizes, and fluid velocities. We compared the measurements with known models. Also, filtration mechanisms of straining and interception are explained under high-velocity flow conditions experienced near injection wells. Based on this work, a macroscopic material balance model of O/W emulsion flow in porous media can precisely predict the near-well formation damage and the subsequent performance of injection wells during produced water re-injection (PWRI).",5,4,1
Porous Media,Surface,"Gonzalez, J. L.; de Faria, E. L.; Albuquerque, Marcelo P.; Albuquerque, Marcio P.; Bom, Clecio R.; Freitas, Jair C. C.; Cremasco, Carlos W.; Correia, Maury D.",Representative elementary volume for NMR simulations based on X-ray microtomography of sedimentary rock,Representative elementary volume; Nuclear magnetic resonance; X-ray microtomography,NUCLEAR MAGNETIC-RELAXATION; POROUS-MEDIA; COMPUTED-TOMOGRAPHY; PERCOLATION; DIFFUSION; GEOMETRY; MODELS,"In porous systems like natural rocks, many phenomenological models have been developed in order to study the correlations between physical properties and the pore structure of these systems. The high resolution obtained with X-ray microtomography (mu CT) images (micro or nanometer scales) has allowed exploring in details the complex morphology of the pore space in natural rocks. This has promoted the development of numerical simulations at the pore-scale level aiming to improve our comprehension about the correlations between pore structure and macroscopic physical properties. In this respect, simulations of nuclear magnetic resonance properties performed directly on mu CT images are very important, since petrophysical properties can be predicted using a realistic model for the heterogeneous porous structure. Also these simulations can include a specific morphology of the pore geometry, which can be controlled in order to verify the different hypotheses introduced during NMR interpretation of physical properties, like for example, permeability predictions and/or fluid typing. In addition, NMR simulations allow to study the existence of a representative volume of the whole system, whose experimental determination is a major challenge. In this work, nuclear magnetic relaxations are simulated on a pore geometry obtained from microtomography of a natural rock formation, localized in the southeast of Brazil. The simulations were performed through a discrete random-walk algorithm computed at the pore scale. In the simulations bulk relaxation was not considered, while the relaxation rate at the surface of the pores was assumed constant. Our results indicate that the relaxation curves can be considered representatives of the whole system for volumes above a representative volume with dimensions of some cubic millimeters. In addition, this representative elementary volume seems to be of the same order that the one found from the analyses of the porosity on the same digital rock. In summary, this study points out to the importance of verifying the existence of this characteristic volume during NMR simulations directly on images obtained from tomography, in order to ensure the reliability of the information obtained from the numerical simulations.",5,6,5
Porous Media,Surface,"Rahbar, Marziyeh; Pahlavanzadeh, Hassan; Ayatollahi, Shahab; Manteghian, Mehrdad","Predicting the rock wettability changes using solutions with different pH, through streaming potential measurement",Streaming potential; Zeta potential; pH; Wettability; Calcite,POROUS-MEDIA; LABORATORY MEASUREMENTS; CALCITE; BEHAVIOR; WATER; SURFACES; IMPACT,"The high reactivity of the carbonate rocks at various pH makes it difficult to evaluate the wettability, hence to find the recovery mechanisms behind modified waterflood in carbonate reservoirs. More recently, the streaming potential measurement is introduced as a method of electrokinetic phenomena more relevant to the subsurface systems. Regarding few experimental studies and in order to improve our understanding on streaming potential measurement, the electrokinetic studies on quartz and calcite surface were conducted as a function of pH in the range of 1.5-11.5 using an in-house novel setup of streaming potential measurement. High sensitivity of streaming potential coupling coefficient to pH variation in domain of pH lower than 4 for quartz and higher than 8 for calcite samples, underscores the fact that pH has to be well monitored during water based EOR tests to have more clear and predictable results. In the experiments reported here, measurements of streaming potential were compared with the adhesion test results to use streaming potential measurement as a promising tool to characterize wetting state and quantify wettability of a porous media. The results showed a clear correlation between streaming potential coupling coefficient/zeta potential change, wetting state and calcium concentration expressed as pCa(2+), irrespective of how the pH is changed. Moreover, the equilibrium solutions analyses suggest that streaming potential measurement results are more reliable and applicable compared to electrophoresis method to extend to the subsurface setting during a dynamic injection process.",7,7,0
Porous Media,Surface,"Liu, Yuetian; Yu, Peng; Ding, Zupeng",Research on stress-sensitivity of fractured porous media,Oil and gas reservoir; Zero-stress model; High dip fracture; Fracture aperture; Fracture permeability,PERMEABILITY; COMPRESSIBILITY; DEFORMATION; BEHAVIOR; POROSITY; WHOLE,"Stress sensitivity parameters of a fracture are often tested under compression on both sides of the fractured medium, which is considered as an elastic solid. However, the elastic solid assumption will fail when two fracture surfaces, if applied to tensile stresses, are out of contact. In such cases, effective stress in the fracture is zero and the change of fracture aperture is not determined by the fracture itself, but by the deformation of the matrix and the overall deformation of the fractured region. This paper proposed a zero-stress model that is applicable after the failure of elastic fracture model as described above. The model analyzes the deformation mechanism of fractures and derives a new equation that can be used to describe the aperture and permeability behavior of a fractured medium under the condition of zero stress. The model is derived for different geometric shapes of fractured region under hydrostatic pressures. The model equations can be used to calculate aperture and permeability changes caused by the production of oil and gas from a reservoir as well as the injection of water or gases for EOR. Sensitivity analysis of the model found that both shape factor of the fractured region and elastic modulus of the surrounding rocks have a significant impact on the outcome of the aperture and permeability forecast as a function of changing pore pressure. The permeability model can also be used in reservoir engineering analysis and reservoir numerical simulation. The new model is joined with the traditional elastic model to better describe the deformation process of fractures.",7,7,3
Porous Media,Surface,"Dong, Kai; Zhu, Ding; Hill, A. Daniel",Mechanism of wormholing and its optimal conditions: A fundamental explanation,Wormholing mechanism; Carbonate acidizing; Optimal conditions; Pore growth function; Pore scale,POROUS-MEDIA,"Acid stimulation is commonly used in carbonate reservoirs, which can be either matrix acidizing or acid fracturing. In both treatments, wormholes can form. In matrix acidizing, wormholing is favorable because the damaged region can be bypassed. In acid fracturing, wormholing is not desired because it can increase fluid loss, which can limit conductive fracture length. Three major processes are involved for wormholing: convection, diffusion and surface reaction. A thorough understanding of these processes is necessary for engineering design. In this paper, we fundamentally explore wormholing mechanisms starting from pore growth. A wormhole forms when larger pores grow in cross-sectional area at a rate that greatly exceeds the growth rate of smaller pores due to surface reaction. This happens when pore growth follows a particular mechanism, which is discussed in this paper. We developed a model to predict wormhole growth behavior. The model uses the mode-size pore in a pore size distribution - the pore size that appears most frequently in a distribution - to predict the growth of the pore. By controlling the acid velocity inside of it, we can make larger pores grow much faster than other smaller pores, thus reaching the most favorable condition for wormholing. This also results in a balance between overall acid/rock reaction and acid flow. By understanding the wormholing mechanism, engineers can select proper treatment fluids and pumping rate for acid stimulation design.",8,9,0
Porous Media,Surface,"Wei, Peng; Pu, Wanfen; Sun, Lin; Zhou, Wei; Ji, Xudong",Foam stabilized by alkyl polyglycoside and isoamyl alcohol for enhancing oil recovery in the low-permeable reservoir,APG foam; Isoamyl alcohol; Surface behavior; Foam stability; Low permeability,HIGH-SALINITY ENVIRONMENTS; AIR-WATER-INTERFACE; POROUS-MEDIA; HIGH-TEMPERATURE; CO2 FOAM; GAS TYPE; SURFACTANT; COALESCENCE; DRAINAGE; FILM,"Few studies have delved into the effect of low molecular alcohol on foam stability. This study firstly investigated the improvement in adsorption behavior and viscoelastic behavior at the surface of the APG solution in the presence of isoamyl alcohol, and then we observed that isoamyl alcohol could hinder the liquid drainage and retard the foam rupture by introducing the stabilization capacity (i.e., reducing the surface tension, increasing the surface viscoelasticity, creating the H-bond and providing the disjoining pressure). Afterwards, the addition of isoamyl alcohol can efficiently diminish the defoaming effect of crude oil and impose a considerable oil resistant in foam system. Finally, the flooding experiments were conducted in the tight formation. The results indicate that APG-alcohol foam presents a fine texture and reaches the maximum apparent viscosity at the transition foam quality of 0.67. As presented in the NMR experiment, APG-alcohol foam can efficiently displace the oil in pores with various sizes and substantially promote the EOR to 30.35%.",8,8,5
Porous Media,Core Flooding,"Zhang, Guowei; Yao, Guangqing; Li, Jiqing; Wu, Hua; Liu, Zhijun; Li, Desheng","A new experimental method for measuring the three-phase relative permeability of oil, gas, and water",Three-phase relative permeability; Saturation history; Archie equation; CT scan; Wettability,RESISTIVITY,"For tertiary oil recovery, the gas drive is often implemented after water flooding. The three-phase flow phenomenon of oil, gas, and water exists during the process of gas injection. The three-phase relative permeability should be measured to further study the flow characteristics of oil, gas, and water in porous media. In this work, the steady-state flow method is adopted to establish a combined experimental method based on the principle of relationship between resistivity and water saturation, and the principle of on-line CT scanning is used to measure the three-phase relative permeability. The relative permeability of oil, gas, and water is measured under different saturation histories, including the water alternating gas flooding, in which water saturation decreases, oil saturation decreases, and gas saturation increases, as well as gas alternating water flooding, in which water saturation increases, oil saturation decreases, and gas saturation decreases. The experimental results show that in a water-wet core, the relative permeability of water is a function of its own saturation, and its isoperms are straight lines. The relative permeability of oil and gas phase is affected by their saturation and other phase saturations. In an oil-wet core, the isoperms of oil, water, and gas are convex to the point of 100% their own saturation, which means the relative permeability of oil, gas and water depend on all the three phase saturations. The saturation histories influence the isoperms of the three phases differently. Compared with the two-phase flow, the three-phase flow is more complex. This new experiment provides an approach and theory for the study of three-phase seepage laws in the gas drive.",1,1,1
Porous Media,Core Flooding,"Orlov, Denis; Koroteev, Dmitry; Sitnikov, Alexander",Self-Colmatation in terrigenic oil reservoirs of Eastern Siberia,Colmatation; Formation damage; Permeability reduction; Water flooding; Fine migration; Rock properties,DEEP BED FILTRATION; POROUS-MEDIA; WATER-SENSITIVITY; FORMATION DAMAGE; FINES; MODEL; MIGRATION; TRANSPORT; SANDSTONE; FLOW,"The main objective of this work is to study formation damage phenomenon associated with in-situ migration of fines in rock samples from terrigenic reservoirs of Eastern Siberia experimentally. Results of oil flooding for the wide range of flow rates and permeabilities show that oil does not lead to fine mobilization and its consequent retention with permeability reduction. The permeability decrease is observed only when water is flowing in the porous space. Water itself is shown to be a strong driver of self-colmatation, which is likely because of its intensive physicochemical reaction with pore surface. Performing multiple core flooding tests and analyzing the data, we define the range of rock properties and flow conditions corresponding to development of the situ formation damage (self-colmatation). We classify self-colmatation over 5 types characterized with different behaviors of permeability decrease. We comprehensively study the dependencies of permeability reduction specifics on rock properties and flooding conditions. The dependencies account for multiple parameters correlated with permeability reduction: absolute permeability, residual oil saturation, three characteristic pore diameters, four characteristic grain diameters and four major minerals within the rock structure. We discovered that the increase of formation damages are associated with high absolute permeability and low residual oil saturations. It was shown that characteristic size of migrating fines is 0.01-0.005 mm and the diameter of pores where these fines can be strained is 12 mu m. We derive a single numerical criterion to estimate the influence of 13 parameters on colmatation process. The absolute permeability and the fraction of pore throats with diameters higher than 30 mu m are shown to be the strongest influencers on colmatation.",2,2,0
Porous Media,Core Flooding,"Alamooti, Amirhossein Mohammdi; Ghazanfari, Mohmmad Hossein; Masihi, Mohsen",Investigating the relative permeability behavior in presence of capillary effects in composite core systems,Composite core systems; Relative permeability; Experimental; Modeling; Layered heterogeneous porous media,DISPLACEMENT EXPERIMENTS,"Successful designs for an injection process to improve reservoir recovery seek more accurate values of saturation dependent functions, including relative permeability curves. The ignorance on underlying heterogeneity (e.g. layering) might lead to inaccurate predicting of flow behavior in layered heterogeneous porous media. Analysis of experimental core flood results in composite core systems (the system) along with numerical simulation at the core scale can provide an insight into this problem, especially when the capillary effects are present. In this study unsteady state two phase displacements have been conducted on the system with different internal arrangements. The main contribution is to compare the relative permeability behavior of composite system against the results of single cores using both explicit as well as implicit methods in the presence of capillary forces. The experimental results showed that fluid flow behavior in the system significantly differs from of the flow characteristics in single cores. The controlling parameters on the relative permeability behavior of whole system include the internal arrangement, permeability values and length of cores. Simulation results showed that in the case of descending ordering (of permeability), the relative permeability of the system is almost independent of the individual cores' length. In contrast, in the case of ascending ordering of core permeability values, it strongly depends on the core structure. When the capillary pressure and relative permeability curves of individual cores are the same, simulation results showed that Huppler arrangement gives the relative permeability of the system close to the behavior of the individual cores. A new correlation set has been developed which predict the relative permeability of whole system based on the relative permeability, internal arrangements, and lengths of single cores with a reasonable agreement.",2,2,0
Porous Media,Core Flooding,"Marandi, Samira Zargari; Salehi, Mahsa Baghban; Moghadam, Asefe Mousavi",Sand control: Experimental performance of polyacrylamide hydrogels,Gelation time; Sand control; Rheology; Gel strength; Coreflooding,WATER SHUTOFF; CONFORMANCE-CONTROL; GEL; POLYMER; FIELDS; PERMEABILITY; GAS,"Improvement of sand consolidation is an impressive process to reduce severe operational problems of sandstone oil reservoirs. In this study, appropriate polymeric hydrogels for the southern Iranian reservoirs was produced and their performance in porous media was studied to reduce the sand production. Designing and producing hydrogel to increase the mechanical strength of reservoir rock and preserving desirable permeability at the same time, is one of the outcomes of the current study. A set of experiments were performed, conducting bottle test, rheology, and coreflooding tests on sandstone core. According to the results, the optimized hydrogel based on maintaining structural strength against stress, temperature and available ions in formation water was approved with 9500 ppm of sulfonated polyacrylamide copolymer, 0.5 wt ratio of Cr(OAc)(3) to copolymer, ultimate elastic modulus of 23 kPa, heat resistant, structural strength at 90 degrees C, and lack of rupture till applying 38700 mu N m torque. Sandstone coreflooding experiment also confirmed a 90% decrease in sand production after the hydrogel injection. Moreover, the water and oil permeabilities were decreased 95 and 7.5 times after the hydrogel injection, respectively. Therefore, the designed hydrogel with the dual function of sand control and relative permeability modification was presented for the field operations.",4,4,1
Porous Media,Core Flooding,"Ghommem, Mehdi; Qiu, Xiangdong; Aidagulov, Gallyam; Abbad, Mustapha",Streaming potential measurements for downhole monitoring of reservoir fluid flows: A laboratory study,Streaming potential; Coreflooding experiments; Flow in porous media; Production and stimulation operations,,"In this paper, we conduct an experimental study to investigate the use of streaming potential measurements for downhole monitoring of fluid flows in porous media for production and stimulation operations. The streaming potential arises from the movement of conductive fluid through a porous medium under an applied pressure gradient. It is generated through a passive electrokinetic process that does not require any electrical power source. Existing coreflooding apparatus is enhanced with capability of streaming potential measurements as oils or brines of different composition and salinity are injected at varying flow rates into carbonate core samples at elevated pressure. The main objective is to establish a correlation between the trend in the variations of the streaming potential and fluid flow in the core and develop the experimental fundamentals within the coreflood equipment. First experimental results are found consistent with previously published data which verifies the new experimental setup. This is followed by performing and analysis of additional experimental cases showing the sensitivity of streaming potential response on the composition of the saturating fluid and the rock permeability. The magnitude of the streaming potential is observed to decrease as the salinity of the brine injected into the core sample is increased and/or rock permeability is higher when maintaining the same fluid injection rate. The streaming potential is also measured for oil-saturated cores while injecting brine. The obtained trend in the streaming potential demonstrates the potential use of such measurements to track the water front during production operations. The goal is to establish experimental fundamentals within the coreflood equipment and this will be used for a further large scale experiment. This is expected to enable a better understanding of the electrokinetic process and alleviate the inherent uncertainties associated with the application of the streaming potential in the field.",8,8,0
Porous Media,Core Flooding,"Foroozesh, Jalal; Jamiolahmady, Mahmoud",The physics of CO2 transfer during carbonated water injection into oil reservoirs: From non-equilibrium core-scale physics to field-scale implication,Carbonated water injection (CWI); Mass transfer; Equilibrium CO2 storage; Core-scale; Reservoir-scale,NONAQUEOUS PHASE LIQUID; SATURATED SUBSURFACE SYSTEMS; MASS-TRANSFER RATES; POROUS-MEDIA; RECOVERY; STORAGE; GAS; DISSOLUTION; DISPLACEMENT; COEFFICIENTS,"CO2 can be dissolved into water to make carbonated water (CW). CW can be injected into oil reservoirs for enhanced oil recovery (EOR) and CO2 sequestration purposes. Carbonated water injection (CWI) technique is a cost-effective CO2 based injection strategy that needs less amount of CO2 as compared to other CO2-EOR techniques. We previously showed that for simulation of CWI coreflood experiments, the kinetics of CO2 transfer between the phases should be considered and we accordingly developed a non-equilibrium based two-phase compositional simulator. We also used the developed simulator to simulate some CWI coreflood experiments. This paper aims to explore the role of mass transfer during simulation of CWI process at field (large)-scale by analysing the data of core-scale simulations. To do so, the results of CWI core-scale simulations obtained from our non-equilibrium based simulator are benchmarked against the results from an equilibrium based simulator and a dimensionless number so-called equilibrium number (Ne) is introduced. It is shown that in a specific range of Ne values, the contact time of the oil and water phases inside the system is large enough that the CO2 can be distributed between the phases based on its equilibrium concentration. Contrary to core-scale simulation, it is concluded that mass transfer kinetics during large-scale simulation of CWI process is not important. Moreover, higher oil recovery factor and CO2 storage are predicted at large-scale (reservoir-scale) as compared to the core-scale's results. The findings of this paper can help to better understand the importance of mass transfer kinetics between the phases in porous media.",8,8,2
Porous Media,Stress,"Yoshida, Takero; Brumby, Paul E.; Oyama, Hiroyuki; Fytianos, Georgios; Sato, Toru; Sakaizawa, Ryosuke; Fuji, Tatsuya; Nagao, Jiro; Tenma, Norio; Narita, Hideo",Modeling of shear stress distribution on mud surface in the subsea sand-mud alternate layer,Sand-mud alternate layer; Mud surface erosion; Sandy porous media; Shear stress distribution; Lattice Boltzmann method; Gamma distribution function,EASTERN NANKAI TROUGH; PRODUCTION TEST-SITE; DAINI-ATSUMI KNOLL; EQUATION; EROSION,"This study aims at showing that the shear stress distribution on a flat surface in the porous media can be expressed by just one probability density function. It is known that methane hydrate exists in the sand layers off Kii Peninsula in Japan within the turbidite sand-mud alternate strata. One of the concerns about gas production from methane hydrate is mud erosion and consequent reservoir clog caused by skin formation. The erosion rate of mud particles depends on the shear stress distribution on the surface of the mud layer in the alternates. The distribution of shear stress should depend on the flow and reservoir properties. Being able to predict the total mass of the eroded mud in advance would definitely be convenient. The objective of this paper is to propose a mathematical model of shear stress distribution on a flat interface between sand and mud layers, because it is believed that the maximum mud-erosion rate is given at the very beginning of the gas production when the mud surface is almost flat. To obtain the shear stress distribution on a flat surface, we conducted pore-scale numerical simulations using computational domains including numerically generated sand-mud beds. Interestingly, we found that the histograms of the shear stresses fit just one curve by means of proper non-dimensionalization. These consistent histograms of the non-dimensional shear stress were then matched with a Gamma distribution function, to develop a mathematical model. This new finding may make possible to predict the maximum rate of mud erosion if we know water flow velocity and reservoir properties, such as porosity and permeability.",0,0,1
Porous Media,Stress,"Marandi, Samira Zargari; Salehi, Mahsa Baghban; Moghadam, Asefe Mousavi",Sand control: Experimental performance of polyacrylamide hydrogels,Gelation time; Sand control; Rheology; Gel strength; Coreflooding,WATER SHUTOFF; CONFORMANCE-CONTROL; GEL; POLYMER; FIELDS; PERMEABILITY; GAS,"Improvement of sand consolidation is an impressive process to reduce severe operational problems of sandstone oil reservoirs. In this study, appropriate polymeric hydrogels for the southern Iranian reservoirs was produced and their performance in porous media was studied to reduce the sand production. Designing and producing hydrogel to increase the mechanical strength of reservoir rock and preserving desirable permeability at the same time, is one of the outcomes of the current study. A set of experiments were performed, conducting bottle test, rheology, and coreflooding tests on sandstone core. According to the results, the optimized hydrogel based on maintaining structural strength against stress, temperature and available ions in formation water was approved with 9500 ppm of sulfonated polyacrylamide copolymer, 0.5 wt ratio of Cr(OAc)(3) to copolymer, ultimate elastic modulus of 23 kPa, heat resistant, structural strength at 90 degrees C, and lack of rupture till applying 38700 mu N m torque. Sandstone coreflooding experiment also confirmed a 90% decrease in sand production after the hydrogel injection. Moreover, the water and oil permeabilities were decreased 95 and 7.5 times after the hydrogel injection, respectively. Therefore, the designed hydrogel with the dual function of sand control and relative permeability modification was presented for the field operations.",4,4,1
Porous Media,Stress,"Liu, Yuetian; Yu, Peng; Ding, Zupeng",Research on stress-sensitivity of fractured porous media,Oil and gas reservoir; Zero-stress model; High dip fracture; Fracture aperture; Fracture permeability,PERMEABILITY; COMPRESSIBILITY; DEFORMATION; BEHAVIOR; POROSITY; WHOLE,"Stress sensitivity parameters of a fracture are often tested under compression on both sides of the fractured medium, which is considered as an elastic solid. However, the elastic solid assumption will fail when two fracture surfaces, if applied to tensile stresses, are out of contact. In such cases, effective stress in the fracture is zero and the change of fracture aperture is not determined by the fracture itself, but by the deformation of the matrix and the overall deformation of the fractured region. This paper proposed a zero-stress model that is applicable after the failure of elastic fracture model as described above. The model analyzes the deformation mechanism of fractures and derives a new equation that can be used to describe the aperture and permeability behavior of a fractured medium under the condition of zero stress. The model is derived for different geometric shapes of fractured region under hydrostatic pressures. The model equations can be used to calculate aperture and permeability changes caused by the production of oil and gas from a reservoir as well as the injection of water or gases for EOR. Sensitivity analysis of the model found that both shape factor of the fractured region and elastic modulus of the surrounding rocks have a significant impact on the outcome of the aperture and permeability forecast as a function of changing pore pressure. The permeability model can also be used in reservoir engineering analysis and reservoir numerical simulation. The new model is joined with the traditional elastic model to better describe the deformation process of fractures.",7,7,3
Porous Media,Stress,"Shovkun, Igor; Espinoza, D. Nicolas",Geomechanical implications of dissolution of mineralized natural fractures in shale formations,Stimulated reservoir volume; Shear failure; Mineral dissolution; Hydraulic fracturing; Acidizing,BARNETT SHALE; GAS-PRODUCTION; POROUS-MEDIA; PERMEABILITY; ROCK; BASIN; FLOW; NETWORKS; MODEL; COAL,"Organic shale reservoirs accommodate large amounts of hydrocarbons in extremely tight rock matrix. Slick water hydraulic fracturing and proppant placement is the most spread stimulating technology for this type of reservoirs. Some shale formations contain a fair amount of easily-dissolvable carbonates, which prompts shale acidizing as a potential method to increase reservoir permeability. Carbonates in shale formations can be present as a part of rock matrix or can be localized in natural fractures - so-called mineral veins. Previous studies investigated the effects of chemical dissolution within the matrix, implying that acidizing can etch the rock, open new conduits for flow, and increase fracture permeability after closure. This study rather focuses on the reservoir-scale geomechanical implications of chemical dissolution of mineral filling in natural fractures. We use a combination of elasto-plastic analytical methods, analogous thermo-elastic numerical solutions, and experimental results to elucidate the impact of veins dissolution on in-situ stresses. Analytical, numerical, and experimental results indicate that mineral dissolution of localized carbonate fractures leads to changes of local in-situ stresses. The direction of stress relaxation strongly depends on the orientation of mineralized fractures. Dissolution of near-vertical mineralized fractures contributes the most to decreases of effective horizontal stress and reduce stress shadow effects in multistage hydraulic fracture completions. Mineral dissolution, similar to pore pressure depletion or thermal cooling/heating, can increase stress anisotropy, which can reactivate critically-oriented natural fractures. In-situ stress chemical manipulation can be used advantageously to enlarge the stimulated reservoir volume.",8,9,1
Porous Media,Formation Damage,"Boaca, Tudor; Boaca, Ioana",A nonlinear single phase mud-filtrate invasion model,Damaged permeability; Incompressible single phase flow; Nonlinear mud-filtrate invasion model; Mudcake formation,ARRAY-INDUCTION MEASUREMENTS; OIL-RESERVOIR PERMEABILITY; RESISTIVITY MEASUREMENT; WELL,In this paper we propose a nonlinear single-phase mud-filtrate invasion model in order to determine the mud-filtrate concentration in the invaded zone and the mudcake thickness. This nonlinear model describes two coupled phenomena that occur during the reservoir invasion: the mudcake formation and the mud-filtrate diffusion through the porous media. The nonlinear model proposed in this paper takes into account the modification of the reservoir permeability due to the invasion phenomenon. We propose a numerical algorithm (based on the successive approximation method) in order to obtain the numerical solution of this nonlinear model. The numerical results obtained with the nonlinear model proposed in this paper are in good agreement with the numerical results from the literature.,2,2,0
Porous Media,Formation Damage,"Orlov, Denis; Koroteev, Dmitry; Sitnikov, Alexander",Self-Colmatation in terrigenic oil reservoirs of Eastern Siberia,Colmatation; Formation damage; Permeability reduction; Water flooding; Fine migration; Rock properties,DEEP BED FILTRATION; POROUS-MEDIA; WATER-SENSITIVITY; FORMATION DAMAGE; FINES; MODEL; MIGRATION; TRANSPORT; SANDSTONE; FLOW,"The main objective of this work is to study formation damage phenomenon associated with in-situ migration of fines in rock samples from terrigenic reservoirs of Eastern Siberia experimentally. Results of oil flooding for the wide range of flow rates and permeabilities show that oil does not lead to fine mobilization and its consequent retention with permeability reduction. The permeability decrease is observed only when water is flowing in the porous space. Water itself is shown to be a strong driver of self-colmatation, which is likely because of its intensive physicochemical reaction with pore surface. Performing multiple core flooding tests and analyzing the data, we define the range of rock properties and flow conditions corresponding to development of the situ formation damage (self-colmatation). We classify self-colmatation over 5 types characterized with different behaviors of permeability decrease. We comprehensively study the dependencies of permeability reduction specifics on rock properties and flooding conditions. The dependencies account for multiple parameters correlated with permeability reduction: absolute permeability, residual oil saturation, three characteristic pore diameters, four characteristic grain diameters and four major minerals within the rock structure. We discovered that the increase of formation damages are associated with high absolute permeability and low residual oil saturations. It was shown that characteristic size of migrating fines is 0.01-0.005 mm and the diameter of pores where these fines can be strained is 12 mu m. We derive a single numerical criterion to estimate the influence of 13 parameters on colmatation process. The absolute permeability and the fraction of pore throats with diameters higher than 30 mu m are shown to be the strongest influencers on colmatation.",2,2,0
Porous Media,Formation Damage,"Hwang, Jongsoo; Sharma, Mukul M.",Generation and filtration of O/W emulsions under near-wellbore flow conditions during produced water re-injection,O/W emulsions; Filtration; Capillary desaturation; Near-well flow conditions; Produced water re-injection; Water injectivity,POROUS-MEDIA; STABLE EMULSIONS; RESIDUAL OIL; WASTE-WATER; MODEL; INJECTIVITY; TRANSPORT; DILUTE,"Produced water in the oilfield contains oil droplets in the form of oil-in-water (O/W) emulsions. These oil droplets cannot be completely separated from the water by surface facilities, and produced water still containing suspended emulsions is re-injected into formations. These oil droplets plug the pore space in the near-wellbore or near-fracture region, resulting in rapid declines in the performance of water injection wells where the remediation processes can be expensive. Displaced oil droplets also contribute to the plugging of pore space near injection wells. These oil droplets are generated by high-velocity flow displacing residual oil in the rock. Because generation and filtration processes occur simultaneously, it is critical to understand both processes at high-velocity flow conditions. This paper experimentally quantifies the rate of generation and filtration of oil droplets in high-velocity flow. For the first time, empirical models were suggested to predict droplet size and rate of generation as a function of trapping number. For the filtration, synthetic dilute O/W emulsions were injected into granular packs to measure the filtration coefficient at various trapping numbers, grain sizes, and fluid velocities. We compared the measurements with known models. Also, filtration mechanisms of straining and interception are explained under high-velocity flow conditions experienced near injection wells. Based on this work, a macroscopic material balance model of O/W emulsion flow in porous media can precisely predict the near-well formation damage and the subsequent performance of injection wells during produced water re-injection (PWRI).",5,4,1
Porous Media,Formation Damage,"Malgaresi, Gabriel V. C.; Vaz, Alexandre S. L., Jr.; Correa, Cleysson C.; Cruz, Georgiana F.; Lomba, Rosana F. T.; Waldmann, Alex",A new crude-glycerin-based drilling fluid,Drilling fluid; Crude glycerin; Dynamic filtration; Return permeability,CROSS-FLOW FILTRATION; POROUS-MEDIA; COLLOIDAL TRANSPORT; HYDROCHLORIC-ACID; FILTER CAKE; PERFORMANCE; DISSOLUTION; SUSPENSIONS; ACIDIZATION; SYSTEM,"A new drilling fluid proposed was obtained by substitution of half of water in water-based drilling fluid by crude glycerine, and matching API properties by regulating the additives. The comparative laboratory study of the new and conventional drilling fluids included the cross-flow mud circulation in the slot with transversal core; it followed by acidizing and return permeability measurements under the reversed flow. A series of six experiments were conducted on Berea sandstone cores to measure the amount of invading fluid and formation damage under different-rate return flow. The glycerine-based and water-based drilling fluids were circulated across the core face. After mud circulation, HCl acid was circulated, and the return permeability was measured under increasing flow rate of the reversed flow. The glycerin-based mud exhibited significantly lower leak-off than the water-based drilling fluid. The filter-cake stabilization time is lower for the glycerin-based drilling fluid. The return permeability is higher for the glycerin-based drilling fluid. The above three items constitute the advantages of a new glycerine-based drilling fluid over the traditional water-based mud.",7,8,0
Porous Media,Porous Medium,"Shahsenov, I. S.; Orujov, G. I.",Modeling of the cementation factor and hydraulic permeability using Mercury Injection Capillary Pressure (MICP) measurements,Cementation factor; Pore size distribution; Mercury Injection Capillary Pressure (MICP); Probabilistic model,POROUS-MEDIA,"Electrical models of the porous medium are widely used for the estimation of the volume fraction of fluids filling in the pore space. One of the input parameters into this type of models is the geometrical factor associated with the complexity of the pore network system also known as ""cementation factor"" used in Archie's saturation model. While this parameter can be measured in the laboratory, the aim of this work is to infer it from the pore size distribution (PSD), which in itself does not bear any information about the geometry of the 3D pore network. The proposed probabilistic model assumes a predefined geometry of the elementary cell, and uses PSD obtained from the Mercury Injection Capillary Pressure (MICP) measurements and porosity to predict the cementation factor. The model achieved a good agreement with an average value of the cementation factor measured on the numerous core samples obtained from the two fields investigated in this study. Geometrical considerations were also investigated through introduction of tortuosity and shape of the capillaries in the model to allow for the potential lithological variations of the reservoir rocks. Similar approach was used to estimate hydraulic permeability using the probabilistic model, and the results were tested against air permeability values measured in the laboratory.",3,3,1
Porous Media,Porous Medium,"Phirani, J.; Roy, S.; Pant, H. J.",Predicting stagnant pore volume in porous media using temporal moments of tracer breakthrough curves,Temporal moments; Coats-Smith model; Porous media; Tracer breakthrough curve,DISPERSION; FLOW; TRANSPORT; BEHAVIOR,"The heterogeneity in complex porous media like oil reservoirs and aquifers many times renders a fraction of fluid in the pores immobile. The tracer breakthrough curves that are used to characterize the porous media are impacted by the immobile volume fraction and show a tailing effect. It is important to first recognize the presence of the immobile volume and quantify it based on a single tracer breakthrough curve in complex geological environments. In this work, we use the method of moments on the tracer breakthrough curve to solve the inverse problem of porous media characterization with stagnant volume fractions. In particular, we use a three parameter model describing the tracer transport in a porous medium with an immobile fluid fraction and solve the forward problem analytically. We derive mean, variance, skewness, and kurtosis of the analytical solution for the exit age density of the injected tracer in the porous medium. We then describe the behavior of the moments in the parameter space of the transport model and relate it with the tracer transport behavior in the porous medium. We then develop the solution for the inverse problem of using these higher order temporal moments of the effluent tracer concentration to estimate the immobile fluid volume in the porous medium.",7,7,2
Porous Media,Porous Medium,"Liu, Yuetian; Yu, Peng; Ding, Zupeng",Research on stress-sensitivity of fractured porous media,Oil and gas reservoir; Zero-stress model; High dip fracture; Fracture aperture; Fracture permeability,PERMEABILITY; COMPRESSIBILITY; DEFORMATION; BEHAVIOR; POROSITY; WHOLE,"Stress sensitivity parameters of a fracture are often tested under compression on both sides of the fractured medium, which is considered as an elastic solid. However, the elastic solid assumption will fail when two fracture surfaces, if applied to tensile stresses, are out of contact. In such cases, effective stress in the fracture is zero and the change of fracture aperture is not determined by the fracture itself, but by the deformation of the matrix and the overall deformation of the fractured region. This paper proposed a zero-stress model that is applicable after the failure of elastic fracture model as described above. The model analyzes the deformation mechanism of fractures and derives a new equation that can be used to describe the aperture and permeability behavior of a fractured medium under the condition of zero stress. The model is derived for different geometric shapes of fractured region under hydrostatic pressures. The model equations can be used to calculate aperture and permeability changes caused by the production of oil and gas from a reservoir as well as the injection of water or gases for EOR. Sensitivity analysis of the model found that both shape factor of the fractured region and elastic modulus of the surrounding rocks have a significant impact on the outcome of the aperture and permeability forecast as a function of changing pore pressure. The permeability model can also be used in reservoir engineering analysis and reservoir numerical simulation. The new model is joined with the traditional elastic model to better describe the deformation process of fractures.",7,7,3
Porous Media,Porous Medium,"Ghommem, Mehdi; Qiu, Xiangdong; Aidagulov, Gallyam; Abbad, Mustapha",Streaming potential measurements for downhole monitoring of reservoir fluid flows: A laboratory study,Streaming potential; Coreflooding experiments; Flow in porous media; Production and stimulation operations,,"In this paper, we conduct an experimental study to investigate the use of streaming potential measurements for downhole monitoring of fluid flows in porous media for production and stimulation operations. The streaming potential arises from the movement of conductive fluid through a porous medium under an applied pressure gradient. It is generated through a passive electrokinetic process that does not require any electrical power source. Existing coreflooding apparatus is enhanced with capability of streaming potential measurements as oils or brines of different composition and salinity are injected at varying flow rates into carbonate core samples at elevated pressure. The main objective is to establish a correlation between the trend in the variations of the streaming potential and fluid flow in the core and develop the experimental fundamentals within the coreflood equipment. First experimental results are found consistent with previously published data which verifies the new experimental setup. This is followed by performing and analysis of additional experimental cases showing the sensitivity of streaming potential response on the composition of the saturating fluid and the rock permeability. The magnitude of the streaming potential is observed to decrease as the salinity of the brine injected into the core sample is increased and/or rock permeability is higher when maintaining the same fluid injection rate. The streaming potential is also measured for oil-saturated cores while injecting brine. The obtained trend in the streaming potential demonstrates the potential use of such measurements to track the water front during production operations. The goal is to establish experimental fundamentals within the coreflood equipment and this will be used for a further large scale experiment. This is expected to enable a better understanding of the electrokinetic process and alleviate the inherent uncertainties associated with the application of the streaming potential in the field.",8,8,0
Porous Media,Mass Transfer,"Jia, Hu; Deng, Li-hui",Non-equilibrium 3-D simulator applied to air injection EOR in light oil reservoirs,,POROUS-MEDIA; NUMERICAL-SIMULATION; CAPILLARY-PRESSURE; RECOVERY; COMBUSTION; PERFORMANCE; PROJECTS; FLOW; PERMEABILITY; MECHANISM,"In this paper, a 3-D simulator based on the assumption of both chemical and thermal non-equilibrium is presented for a more realistic view of non-equilibrium process for simulating air injection EOR (enhanced oil recovery). The mathematical model is based on a non-equilibrium stage with dynamic mass transfer process between different fluid phases and energy transfer process between fluid and matrix (solid). The light crude oil oxidation and air injection process are both simulated by this simulator, through which the pore blocking, gas breakthrough and gas override process are presented through the visualization of oil, gas saturation distributions. The crude oil oxidation is refined as in-phase and interphase reactions to investigate the effect of reactant dispersion caused by the gas-liquid mass transfer. The oxygen dissolution and the evaporation of light components in crude oil are considered in the non-equilibrium process. The results without mass transfer, with dynamic mass transfer and with instantaneous mass transfer between gas and liquid phases are compared through multiplying the gas-liquid interface area 0, 1 and 100 times respectively, and the influence of these different mass transfer conditions on the migration of temperature peak front and oil recovery is revealed. In addition, the effect of local chemical and thermal non-equilibrium in different matrix permeability as well as porosity scenarios is also investigated to obtain non-equilibrium behavior in different reservoir conditions when implementing air injection EOR. In the last section, we investigated the result with different simulation timescale to see if the non-equilibrium behavior can be captured in the simulator used in this paper. This study suggests that the non-equilibrium behavior would show obvious influence on oil recovery for air injection in the lower permeability reservoir. The non-equilibrium behavior is desirable to be considered for simulating air injection EOR in light oil reservoirs. The developed 3-D simulator is robust that can better reflect the mechanism of air injection EOR in light oil reservoirs. We hope this work encouraging more investigations for the simulation side of nonequilibrium phase behavior and energy transfer in the air injection process.",5,5,1
Porous Media,Mass Transfer,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Porous Media,Mass Transfer,"Foroozesh, Jalal; Jamiolahmady, Mahmoud",The physics of CO2 transfer during carbonated water injection into oil reservoirs: From non-equilibrium core-scale physics to field-scale implication,Carbonated water injection (CWI); Mass transfer; Equilibrium CO2 storage; Core-scale; Reservoir-scale,NONAQUEOUS PHASE LIQUID; SATURATED SUBSURFACE SYSTEMS; MASS-TRANSFER RATES; POROUS-MEDIA; RECOVERY; STORAGE; GAS; DISSOLUTION; DISPLACEMENT; COEFFICIENTS,"CO2 can be dissolved into water to make carbonated water (CW). CW can be injected into oil reservoirs for enhanced oil recovery (EOR) and CO2 sequestration purposes. Carbonated water injection (CWI) technique is a cost-effective CO2 based injection strategy that needs less amount of CO2 as compared to other CO2-EOR techniques. We previously showed that for simulation of CWI coreflood experiments, the kinetics of CO2 transfer between the phases should be considered and we accordingly developed a non-equilibrium based two-phase compositional simulator. We also used the developed simulator to simulate some CWI coreflood experiments. This paper aims to explore the role of mass transfer during simulation of CWI process at field (large)-scale by analysing the data of core-scale simulations. To do so, the results of CWI core-scale simulations obtained from our non-equilibrium based simulator are benchmarked against the results from an equilibrium based simulator and a dimensionless number so-called equilibrium number (Ne) is introduced. It is shown that in a specific range of Ne values, the contact time of the oil and water phases inside the system is large enough that the CO2 can be distributed between the phases based on its equilibrium concentration. Contrary to core-scale simulation, it is concluded that mass transfer kinetics during large-scale simulation of CWI process is not important. Moreover, higher oil recovery factor and CO2 storage are predicted at large-scale (reservoir-scale) as compared to the core-scale's results. The findings of this paper can help to better understand the importance of mass transfer kinetics between the phases in porous media.",8,8,2
Porous Media,Salinity,"Bui, Binh T.; Tutuncu, Azra N.",Interfacial tension induced-transport in shale: A pore-scale study,,NETWORK MODELS; POROUS-MEDIA; WETTABILITY; THROAT,"While unconventional reservoirs have quickly become a main contributor to oil and gas production, the transport mechanism in shale is not well understood. Although water does not imbibe into oil-wetted rock matrix, it has been observed in laboratory measurements that it can. The amount of water imbibed into the rock matrix increases when the salinity of the injected water decreases. Wettability alteration is often considered as the main reason for this phenomenon. One of the physical mechanisms for the imbibition of low salinity water into an oil-wetted rock matrix is the variation of the interfacial tension and the contact angle. The change of salinity initiates the change of interfacial tension driving the movement of the interface imbibing water into oil-wetted pores. The imbibition of the water into the rock matrix is a complicated process requiring a comprehensive understanding of the mass transport at pore scale. Hence, pore scale modeling was used in this research study for understanding the physics of transport at pore scale caused by interfacial tension variation or interfacial tension-induced transport. First, a simplified pore-scale model is presented to simulate the imbibition of water into an oil-wetted pore. Next, a numerical solution and procedure are outlined to simulate the transient mass transport in the pore as the result of interfacial tension variation due to salinity. The results indicate that the interfacial tension-induced transport is a very important mechanism for water imbibition into oil-wetted pores. How fast the water imbibes into the pore depends on the salinity gradient and the type of solute used. When salinity at the inlet of the pore is low, more solute diffuses out of the pore resulting in higher cumulative recovery from the pore. Reducing the interfacial tension between oil and water forces oil out of the pores and improve the oil recovery. Hence, low salinity water is recommended for low salinity water injection enhanced oil recovery.",4,4,2
Porous Media,Salinity,"Sivasankar, P.; Kumar, G. Suresh",Modelling the influence of interaction between injection and formation brine salinities on in-situ microbial enhanced oil recovery processes by coupling of multiple-ion exchange transport model with multiphase fluid flow and multi-species reactive transport models,Microbial enhanced oil recovery; Biosurfactant; Brine salinity; Ion exchange; Porous media; Modelling,SATURATED POROUS-MEDIA; BIOSURFACTANT PRODUCTION; PSEUDOMONAS-PUTIDA; NUMERICAL-SIMULATION; GROWTH; RESERVOIRS; WATER; PH; PERFORMANCE; SUBSURFACE,"Interaction between injection water (IW) and formation water (FW) salinities during microbial flooding critically influences the dynamics of in-situ Microbial Enhanced Oil Recovery (MEOR) processes. However, the lack in understanding of the influence of salinity interactions on MEOR processes had led to unreliable prediction of MEOR performance, and non-development of efficient strategies to improve the MEOR performance. Hence, analysing the influence of salinity interactions on MEOR processes would make the prediction of MEOR processes more realistic, and thereby, it could assist in development of suitable strategies to enhance the oil recovery. Thus, in the present study, a novel mathematical model has been developed by coupling the Multiple Ion (Na, Ca, Mg, Cl, SO4) Exchange (MIE) transport model with the MEOR model, and it has been solved numerically by finite volume technique. The MIE transport model simulates the resultant spatial and temporal salinity distribution within the reservoir due to the mixing of IW and FW salinities during microbial flooding. The MEOR model simulates the coupled multiphase fluid (water-oil) flow and multispecies (microbes-nutrients) reactive transport processes within the reservoir, and finally predicts the oil recovery due to microbial flooding. Subsequently, the influence of IW and FW at different salinities on MEOR processes has been investigated. The present numerical results were validated with the experimental and analytical results. The results clearly suggest that the in-situ FW salinity was completely altered to the externally injected IW salinity, and this IW salinity dictates the entire MEOR processes as against the conventionally assumed FW salinity. Further, it is revealed that lowering the IW salinity from 0.5M to 0.1M had recovered 4.5%-14% of Original Oil in Place (OOIP) higher than that of conventionally used IW (sea water) for microbial flooding. Moreover, the MEOR performance could be enhanced significantly in reservoirs with any initial FW salinity by adopting IW salinity closer to the salinity condition at which the microbial growth and biosurfactant production is maximum. Finally, the present work assists in the selection of suitable reservoir, microbes, and IW salinity for attaining maximum oil recovery by microbial flooding. Thus, the present work helps to enhance the performance of MEOR technique.",5,5,0
Porous Media,Salinity,"Ghommem, Mehdi; Qiu, Xiangdong; Aidagulov, Gallyam; Abbad, Mustapha",Streaming potential measurements for downhole monitoring of reservoir fluid flows: A laboratory study,Streaming potential; Coreflooding experiments; Flow in porous media; Production and stimulation operations,,"In this paper, we conduct an experimental study to investigate the use of streaming potential measurements for downhole monitoring of fluid flows in porous media for production and stimulation operations. The streaming potential arises from the movement of conductive fluid through a porous medium under an applied pressure gradient. It is generated through a passive electrokinetic process that does not require any electrical power source. Existing coreflooding apparatus is enhanced with capability of streaming potential measurements as oils or brines of different composition and salinity are injected at varying flow rates into carbonate core samples at elevated pressure. The main objective is to establish a correlation between the trend in the variations of the streaming potential and fluid flow in the core and develop the experimental fundamentals within the coreflood equipment. First experimental results are found consistent with previously published data which verifies the new experimental setup. This is followed by performing and analysis of additional experimental cases showing the sensitivity of streaming potential response on the composition of the saturating fluid and the rock permeability. The magnitude of the streaming potential is observed to decrease as the salinity of the brine injected into the core sample is increased and/or rock permeability is higher when maintaining the same fluid injection rate. The streaming potential is also measured for oil-saturated cores while injecting brine. The obtained trend in the streaming potential demonstrates the potential use of such measurements to track the water front during production operations. The goal is to establish experimental fundamentals within the coreflood equipment and this will be used for a further large scale experiment. This is expected to enable a better understanding of the electrokinetic process and alleviate the inherent uncertainties associated with the application of the streaming potential in the field.",8,8,0
Porous Media,Absolute Permeability,"Orlov, Denis; Koroteev, Dmitry; Sitnikov, Alexander",Self-Colmatation in terrigenic oil reservoirs of Eastern Siberia,Colmatation; Formation damage; Permeability reduction; Water flooding; Fine migration; Rock properties,DEEP BED FILTRATION; POROUS-MEDIA; WATER-SENSITIVITY; FORMATION DAMAGE; FINES; MODEL; MIGRATION; TRANSPORT; SANDSTONE; FLOW,"The main objective of this work is to study formation damage phenomenon associated with in-situ migration of fines in rock samples from terrigenic reservoirs of Eastern Siberia experimentally. Results of oil flooding for the wide range of flow rates and permeabilities show that oil does not lead to fine mobilization and its consequent retention with permeability reduction. The permeability decrease is observed only when water is flowing in the porous space. Water itself is shown to be a strong driver of self-colmatation, which is likely because of its intensive physicochemical reaction with pore surface. Performing multiple core flooding tests and analyzing the data, we define the range of rock properties and flow conditions corresponding to development of the situ formation damage (self-colmatation). We classify self-colmatation over 5 types characterized with different behaviors of permeability decrease. We comprehensively study the dependencies of permeability reduction specifics on rock properties and flooding conditions. The dependencies account for multiple parameters correlated with permeability reduction: absolute permeability, residual oil saturation, three characteristic pore diameters, four characteristic grain diameters and four major minerals within the rock structure. We discovered that the increase of formation damages are associated with high absolute permeability and low residual oil saturations. It was shown that characteristic size of migrating fines is 0.01-0.005 mm and the diameter of pores where these fines can be strained is 12 mu m. We derive a single numerical criterion to estimate the influence of 13 parameters on colmatation process. The absolute permeability and the fraction of pore throats with diameters higher than 30 mu m are shown to be the strongest influencers on colmatation.",2,2,0
Porous Media,Absolute Permeability,"Farahani, Milad; Saki, Mohammad; Ghafouri, Amin; Khaz'ali, Ali Reza",Laboratory measurements of slippage and inertial factors in carbonate porous media: A case study,Absolute permeability measurement; Carbonate rock; Gas permeability; Gas slippage; Inertia factor; Turbulency,NON-DARCY FLOW; WELLS,"Two important issues for accurate modeling of gas reservoir performance are the gas slippage and the inertia flow within porous media. Depending on the flow condition, these factors can make the gas permeability differ from the true (liquid) permeability. Nevertheless, since the gas flow tests are cheaper and less time consuming than the liquid flow tests, a reservoir engineer may choose to estimate the true (liquid) absolute permeability from the results of a single gas permeability test utilizing a valid empirical correlation. Although many such correlations exist in the literature, most of them have been developed for unconsolidated porous media or sandstone core samples. Therefore, using them for a specific formation will result in erroneous predictions. This paper is presented in three parts. In the first part, an empirical equation is developed to estimate the gas slippage factor using the results of laboratory measurements on 49 samples of Iranian carbonate reservoirs of Kangan and Dalan. In the second part, a correlation is developed to estimate the inertia factor for the samples. In the last part of the paper, an equation is derived to estimate maximum allowable pressure drop per length to maintain the laminar (Darcy) flow regime in the samples. The developed models in the first and the second parts of the current paper match the experimental data more accurately than the popular existing correlations. The derived equation in the last part is applicable in proper design of gas flow tests, where a laminar flow must be maintained in porous media.",4,4,0
Porous Media,Absolute Permeability,"Goudarzi, Banafsheh; Mohammadmoradi, Peyman; Kantzas, Apostolos",Direct pore-level examination of hydraulic-electric analogy in unconsolidated porous media,Pore-scale; Tortuosity; Finite element; Electric-Hydraulic; Unconsolidated,KOZENY-CARMAN; FIXED-BEDS; TORTUOSITY; FLOW; PERMEABILITY; DIFFUSION; TRANSPORT; MODEL; SIMULATION; POROSITY,"Taking advantage of the analogy between hydraulic and electrical flows to facilitate the prediction of porous media characteristics is a longstanding practice in engineering and science applications. The relationships between hydraulic and electrical properties are widely used in the characterization of transport phenomena relying on the strong correlation between electric and hydraulic flow conductance. However, due to the lack of small-scale investigations the similarity among their pathways/tortuosities is still unclear. Here a series of direct finite element numerical simulations are conducted within pore-level microstructures to extract and compare the streamlines of both electric and fluid flow currents and examine the accuracy of the hydraulic-electric analogy by predicting the petrophysical characteristics of the case studies. The fluid flow and electric transports are simulated through low-porosity digital unconsolidated packings of polydispersed grains representing the Athabasca oil sands deposit as the second largest oil reserve in the world. The formation factor, porosity, and absolute permeability of the media under consideration are predicted, and consequently, the streamlines of both electric and hydraulic currents are extracted and compared in terms of length, shape, and pathways. According to the results, the fluid flow streamlines are longer and pose differently than the homogeneous electric current streamlines. The average ratio between the hydraulic and electric tortuosities is 1.15 and a local extremum occurs at the porosity of eighteen percent. Pedotransfer functions for tortuosities, dimensionless permeability, and formation factor are proposed underpinning the rigorous relationships between transport processes in porous media.",6,6,0
Porous Media,Drilling Fluid,"Liang, Bo; Lan, Hui-qing; Lin, Nan",Diffusion simulation and safety assessment of oil leaked in the ground,Oil; Leak Multi-phase flow in porous media; Diffusion; Test; Safety assessment,ASSESSING NAPL CONTAMINATION; MULTIPHASE FLOW MODEL; POROUS-MEDIA; GRAVITY CURRENTS; RISK-ASSESSMENT; FRACTURED MEDIA; PERSPECTIVE; SITE,"Oil leaked in the ground causes pollution of land and groundwater, and even leads to an explosion. Therefore, it is significant to make a research on safety assessment of diffusion of oil in the ground after oil leakage accident happened. Taken a perforation-caused leakage accident of oil in buried piping in China as an example, the computational fluid dynamics method of multiphase flow in porous media was used to determine the distribution of leaked oil in the ground in this paper. Then, an onsite drilling test was carried put and it's found that the simulation of distribution of leaked oil agreed with the test result. Finally, on the base of the simulation results, fuzzy synthetic evaluation method was carried out and hazardous areas of oil leaked in the ground were put forward.",5,6,2
Porous Media,Drilling Fluid,"Malgaresi, Gabriel V. C.; Vaz, Alexandre S. L., Jr.; Correa, Cleysson C.; Cruz, Georgiana F.; Lomba, Rosana F. T.; Waldmann, Alex",A new crude-glycerin-based drilling fluid,Drilling fluid; Crude glycerin; Dynamic filtration; Return permeability,CROSS-FLOW FILTRATION; POROUS-MEDIA; COLLOIDAL TRANSPORT; HYDROCHLORIC-ACID; FILTER CAKE; PERFORMANCE; DISSOLUTION; SUSPENSIONS; ACIDIZATION; SYSTEM,"A new drilling fluid proposed was obtained by substitution of half of water in water-based drilling fluid by crude glycerine, and matching API properties by regulating the additives. The comparative laboratory study of the new and conventional drilling fluids included the cross-flow mud circulation in the slot with transversal core; it followed by acidizing and return permeability measurements under the reversed flow. A series of six experiments were conducted on Berea sandstone cores to measure the amount of invading fluid and formation damage under different-rate return flow. The glycerine-based and water-based drilling fluids were circulated across the core face. After mud circulation, HCl acid was circulated, and the return permeability was measured under increasing flow rate of the reversed flow. The glycerin-based mud exhibited significantly lower leak-off than the water-based drilling fluid. The filter-cake stabilization time is lower for the glycerin-based drilling fluid. The return permeability is higher for the glycerin-based drilling fluid. The above three items constitute the advantages of a new glycerine-based drilling fluid over the traditional water-based mud.",7,8,0
Porous Media,Foam,"Djuraev, Ulugbek; Jufar, Shiferaw Regassa; Mahardika, Harry; Ooi, Phey Chee",Numerical simulation of seismoelectric effect for monitoring foam propagation through a reservoir,Seismoelectric effect; Foam propagation; Reservoir monitoring,POROUS-MEDIA; FIELD-MEASUREMENTS; JOINT INVERSION; ELASTIC WAVES; CONVERSIONS; EXPLORATION; EQUATIONS,"The seismoelectric phenomenon describes generation of electromagnetic fields when seismic wave passes through fluid saturated porous media. Discovered in the 1930s, the seismoelectric effect have gained attention only in the last few decades as a tool of great potential in geophysical applications. Despite some usage in mineral exploration and ground water flow, routine field applications of this phenomenon are still under development. Nevertheless, recent advancements show great potential of the seismoelectric method in the oil and gas industry. It is now known that several rock and fluid properties affect the seismoelectric response, hence application of this response may be used for reservoir characterization, subsurface imaging and mapping, and monitoring fluid propagation through a reservoir. In this paper, we numerically studied the prospect of monitoring foam propagation through a reservoir using the seismoelectric phenomenon. The reservoir model used in the study was developed using real field data. The virtual pilot area comprised of a cross-well domain between injector well and producer well, where pre-generated foam was continuously injected into the reservoir for the period of 150 days. The seismoelectric data acquisition was modeled in the domain, where the seismic source was deployed in the injection well, and the receiving stations were installed in production well accordingly. The results of the seismoelectric surveys, with interval of 30 days, produced both seismic and seismoelectric signals received by the stations. The processed data, coupled with the average seismic velocity and arrival times of the seismoelectric conversions, were analyzed with regard to determining the locations of the displacing foam front. Subsequent comparison and analysis showed high accuracy match and consistency between the true front positions obtained from the reservoir simulator and the determined locations produced using the seismoelectric method. Additionally, to demonstrate how the seismoelectric signals can be processed in field trials, we applied noise to the same synthetic data used to estimate the foam front positions. We observed that the occurrence of the seismoelectric signal was imperceptible due to the prevailing noise. Subsequently, we applied a filtering method to reduce the effect of the noise that showed great results in uncovering the presence of the seismoelectric conversion in the electrogram while preserving amplitudes and time arrivals of the seismoelectric, seismic and co-seismic signals. According to the obtained findings, we can state that later computations of locating the foam front would yield results with the same accuracy as the noise-free synthetic signals.",4,4,1
Porous Media,Foam,"Wei, Peng; Pu, Wanfen; Sun, Lin; Zhou, Wei; Ji, Xudong",Foam stabilized by alkyl polyglycoside and isoamyl alcohol for enhancing oil recovery in the low-permeable reservoir,APG foam; Isoamyl alcohol; Surface behavior; Foam stability; Low permeability,HIGH-SALINITY ENVIRONMENTS; AIR-WATER-INTERFACE; POROUS-MEDIA; HIGH-TEMPERATURE; CO2 FOAM; GAS TYPE; SURFACTANT; COALESCENCE; DRAINAGE; FILM,"Few studies have delved into the effect of low molecular alcohol on foam stability. This study firstly investigated the improvement in adsorption behavior and viscoelastic behavior at the surface of the APG solution in the presence of isoamyl alcohol, and then we observed that isoamyl alcohol could hinder the liquid drainage and retard the foam rupture by introducing the stabilization capacity (i.e., reducing the surface tension, increasing the surface viscoelasticity, creating the H-bond and providing the disjoining pressure). Afterwards, the addition of isoamyl alcohol can efficiently diminish the defoaming effect of crude oil and impose a considerable oil resistant in foam system. Finally, the flooding experiments were conducted in the tight formation. The results indicate that APG-alcohol foam presents a fine texture and reaches the maximum apparent viscosity at the transition foam quality of 0.67. As presented in the NMR experiment, APG-alcohol foam can efficiently displace the oil in pores with various sizes and substantially promote the EOR to 30.35%.",8,8,5
Crude Oil,Asphaltene Precipitation,"Borisov, D. N.; Tazeev, D. I.; Milordov, D. V.; Mironov, N. A.; Borisova, Y. Y.; Yakubov, M. R.; Beregovoy, A. N.; Amerkhanov, M. I.; Khisamov, R. S.",Physical modeling of the composite solvent injection to improve the ultra-viscous oil recovery efficiency steam-assisted gravity drainage,Ultra-viscous oil; Heavy oil; Solvent; Reservoir modeling; Thermal enhanced oil recovery techniques; Steam-assisted gravity drainage,ASPHALTENE PRECIPITATION; CRUDE OILS; AGGREGATION; PERFORMANCE; INHIBITION; RESERVOIRS; STABILITY; RESINS; CSI,"The experiments carried out on a physical model of reservoir of ultra-viscous oil have revealed features of oil displacement in various variants of the composite solvent and steam injection. In order to avoid precipitation of asphaltenes, the employment of inhibitors has been rationalized and their minimum fraction in displacement fluid has been determined. The effect of the sequence of solvent and vapor injection on the dynamics of ultra-viscous oil recovery has been investigated. The effect of clay and water in the rock on the rate of oil displacement and the ultimate oil recovery factor has been evaluated.",0,0,2
Crude Oil,Asphaltene Precipitation,"Paridar, Soroush; Nazar, Ali Reza Solaimany; Karimi, Yavar",Experimental evaluation of asphaltene dispersants performance using dynamic light scattering,Asphaltene solid particle; Size distribution; Asphaltene solidification inhibitors,ALKYLBENZENE-DERIVED AMPHIPHILES; PARTICLE-SIZE DISTRIBUTIONS; CRUDE-OIL; HYDROCARBON SOLUTIONS; PRECIPITATION; FLOCCULATION; AGGREGATION; TOLUENE; KINETICS; HEPTANE,"In this study, the asphaltene particle aggregation process is studied and effects of asphaltene concentration, n-heptane to toluene volume ratio, type and concentration of asphaltene aggregation inhibitor are investigated on onset of precipitation and asphaltene particle size distribution (APSD). The measurement of APSD is performed through dynamic light scattering technique. The results show that the concentration of asphaltene doesn't have significant effect on the onset point; however, it leads to form bigger particles. An increase in n-heptane volume ratio leads to increases the asphaltene particles size where 5% of particles are bigger than 6 mu m after 40 min. Dodecyl benzene sulfonic acid component displaces the onset point reasonably and causes 7% rise in the amount of required n-heptane. Dodecyl resorcinol has the best performance at concentration of 50 ppm as an asphaltene dispersant and causes required n-heptane volume increment of 2%. It reduces the asphaltene particles size significantly and delays the asphaltene particles agglomeration process of about 30 min.",3,3,5
Crude Oil,Asphaltene Precipitation,"Bahman, Jalil; Sharifi, Khashayar; Nasiri, Masoud; Asl, Masoud Haghighi",Development of a Log-Log scaling law approach for prediction of asphaltene precipitation from crude oil by n-alkane titration,Asphaltene; Scaling law; Precipitation; Dilution ratio; Modeling,EQUATION; FLOCCULATION; TEMPERATURE; DEPOSITION; PRESSURE; DEPLETION; MODEL,"One of the most significant problems that petroleum and gas industries tend to know much more is the behavior and the weight percent of Asphaltene precipitation in crude oils. A large number of researchers have been scrutinizing to develop new models for estimating Asphaltene precipitation. Of available approaches, scaling law which is not only relatively simple but also faster than other conventional mathematical methods is promising. In this study, the potential of Ashoori's scaling equation was firstly examined in detail. Afterwards, to solve its drawbacks, an alternative model was formulated exploiting the logarithm operator. Indeed, in this communication, the authors tried to drive a polynomial model that can estimate the amount of Asphaltene precipitation at all dilution ratio ranges with higher accuracy. To get proper outputs and to compare its results with Ashoori's and Rassamdana's outcomes, the polynomial function was fitted to experimental data points. The R-2 (R-squared) of the present model, namely Log-Log scaling law, was about 0.999, and the results indicate that the Log-Log scaling law has better performance than that determined by others for prediction of Asphaltene precipitation from crude oil by n-alkane titration.",4,4,0
Crude Oil,Asphaltene Precipitation,"Ekpo, B. O.; Essien, N.; Neji, P. A.; Etsenake, R. O.",Geochemical fingerprinting of western offshore Niger Delta oils,Oil fingerprinting; Organic geochemistry; Niger Delta; Nigeria,CRUDE OILS; PETROLEUM GEOCHEMISTRY; GAS-CHROMATOGRAPHY; SOURCE ROCKS; PART II; BASIN; FIELD; BIODEGRADATION; DISTRIBUTIONS; ASPHALTENES,"This study reports the findings based on analyses of saturated (normal alkanes and aliphatic isoprenoid) hydrocarbons and biomarkers in twenty four (24) crude oil samples from western offshore Niger Delta of Nigeria using gas chromatography (GC), gas chromatography-mass spectrometry (GC-MS) and carbon isotopy. The major objectives were to apply reservoir geochemistry and oil fingerprinting to characterize the oils in order to determine their origin and to identify the existence of reservoir continuity and/or compartmentalization. Results from this study using the distributions of normal alkanes, tricyclic and tetracyclic terpanes as well as source specific maturity and facies controlled biomarker ratios of the oils including pristane/phytane (Pr/Ph), Pr/n-C-17, Ph/n-C-l8, C-31:22S/(22S + 22R) homohopane, C-29:alpha alpha(20S/(20S + 20R)) steranes, moretane/C-30-Hopane and Ts/(Ts + Tm), showed that the entire crude oil samples from three reservoir units are the same, the differences are small. The oils originated from same source rocks which were deposited under oxidizing condition with mixed marine/terrigeneous organic source inputs and thermal maturity. This genetic classification is supported by stable carbon isotopic compositions (delta C-13) of the hydrocarbon fractions and multivariate statistical (Principal Component and Cluster) analyses. Geochemical, fingerprinting and multivariate statistical data provided corroborative evidence of a single compartment with vertical and lateral reservoir continuity across the fault complex within the studied fields. This information can be utilized by geologists and petroleum engineers in solving production related problems such as optimising hydrocarbon production via drilling horizontal wells to arrest the reservoir communication that occurs with existing vertical wells.",4,5,1
Crude Oil,Asphaltene Precipitation,"Hassanpour, Sadegh; Malayeri, Mohammad Reza; Riazi, Masoud; Mousavi, Seyed Mahdi; Negahban, Zahra",On the impact of Co3O4 nanoparticles on interaction of heavy oil and brine mixtures,IFT; Brine solution; Asphaltene precipitation; EOR; Co3O4 nanoparticles,INTERFACIAL-TENSION; CRUDE-OIL; ASPHALTENE; SALINITY; TEMPERATURE; RECOVERY; PRESSURE; WATER; CO2; PRECIPITATION,"Among numerous EOR methods, the injection of brine with different salinities to oil reservoirs has gained attention where its performance would, in turn, depend on interfacial tension (IFT) of oil/brine mixture. The present study investigated the impact of Co3O4 nanoparticles with concentrations of 0.01, 0.1 and 1 wt% on IFT of brine solution (containing NaCl, KCl and CaCl2) and heavy crude oil system. The results confirmed that adding Co3O4 nanoparticles to water, compared to that without nanoparticles, reduced IFT at low (i.e. 0-5000 ppm) and high (i.e. greater than 5000 ppm) brine concentrations, although the propensity of IFT is different for various concentrations. Furthermore, the reduction of IFT for monovalent ions is greater than that for divalent ions. Properties such as high surface activity and higher surface to volume ratio of the Co3O4 nanoparticles should be accounted for profound adsorption of asphaltene onto the surface of nanoparticles. A high suspension of asphaltene at the brine/oil interface also avoided its precipitation in oil causing IFT to reduce in brine/crude mixtures with nanoparticles compared to that without nanoparticles. The extent of IFT reduction changed by using different concentrations of Co3O4 nanoparticles. For the oil/brine system attempted in this study, the optimum concentration of Co3O4 nanoparticles in term of IFT reduction was 0.1 wt%.",4,5,1
Crude Oil,Asphaltene Precipitation,"Larichev, Yu. V.; Martyanov, O. N.",The dynamics of asphaltene aggregates in heavy crude oils on a nanometer scale studied via small-angle X-ray scattering in situ,Asphaltenes; Heavy crude oils; Aggregation; In-situ; SAXS,ELECTRON-SPIN-RESONANCE; N-HEPTANE; LIVE OILS; PRECIPITATION; STABILITY; TEMPERATURE; SOLVENT; RESINS; MODEL,"This work presents the results of the in situ SAXS study of the asphaltene aggregate transformations due to dilution of several heavy crude oils by heptane within the time range from 5 min to 3 days. The main growth of the asphaltene aggregates was usually observed within first minutes. The analysis of the SAXS data obtained in situ for the oils having significantly different relative content of resins showed their great influence on the dynamics of aggregates formation on a nanometer scale. In particular, it has been shown that the resins can prevent the asphaltene aggregation via certain mechanism which usually leads to the high anisotropy of the aggregates. Therefore the relative content of resin and asphaltenes as well as aromatics and aliphatics lead to the asphaltene aggregates with different shapes and different density of deposits.",4,4,3
Crude Oil,Asphaltene Precipitation,"Baek, Kwang Hoon; Arguelles-Vivas, Francisco J.; Okuno, Ryosuke; Sheng, Kai; Sharma, Himanshu; Weerasooriya, Upali P.",Emulsification of Athabasca bitumen by organic alkali: Emulsion phase behavior and viscosity for bitumen/brine/triethylenetetramine,Bitumen; Organic alkali; Natural surfactant; Emulsion phase behavior; Emulsion viscosity,HEAVY OIL-RECOVERY; IN-WATER EMULSIONS; CRUDE-OIL; PIPELINE TRANSPORTATION; NATURAL SURFACTANTS; ASPHALTENE RATIO; STEAM CHAMBER; STABILITY; RHEOLOGY; RESINS,"Recovery of bitumen commonly uses steam assisted-gravity drainage, in which water throughput is intrinsically high. A large amount of condensed water near thermal fronts tends to substantially decrease the effective permeability to bitumen in the conventional gravity drainage process. This research investigates a potential way to use the condensed-water phase as an effective carrier for bitumen by making oil-in-water (o/w) emulsion. The expected mechanism depends on emulsification of bitumen into the water phase by natural surfactants that are generated through reactions of acidic oil components with organic alkali. The main objective of this paper is to study the ability of an organic alkali to create o/w emulsions that are much more mobile than the original bitumen. Triethylenetetramine (TETA) was selected as organic alkali for this paper with no other additives. The main contribution of this paper is a new set of experimental data (phase behavior and viscosities) for emulsions for mixtures of Athabasca bitumen, TETA, and NaCl brine at a wide range of alkali concentrations, salinities, and water-to-oil ratios (WORs) M temperatures up to 373 K. Results show that the o/w emulsions created by TETA can be an effective bitumen carrier with a low viscosity and high bitumen content in the emulsion. It is possible to create o/w emulsions by adding a small amount of TETA to Athabasca bitumen and NaC1 brine. Single-phase o/w emulsions, which are desirable as a bitumen carrier, were observed for TETA concentrations below 5.0 wt% M salinities 0 ppm and 1000 ppm at 373 K. The bitumen content in o/w emulsion was the highest for 2.0 wt% TETA samples, and it increased with increasing temperature. In comparison to the original bitumen, o/w emulsions were 4-5 orders of magnitude less viscous at 298 K, 2 to 3 orders of magnitude less viscous at 323 K, and 1 to 2 orders of magnitude less viscous at 353 K.",5,6,2
Crude Oil,Asphaltene Precipitation,"Sadi, Maryam; Shahrabadi, Abbas",Evolving robust intelligent model based on group method of data handling technique optimized by genetic algorithm to predict asphaltene precipitation,Asphaltene precipitation; Group method of data handling; Genetic algorithm; SARA fractions; Leverage approach,FUZZY INFERENCE SYSTEM; GMDH NEURAL-NETWORK; GAS INJECTION; NATURAL DEPLETION; SCALING EQUATION; HEAVY OILS; DEPOSITION; EQUILIBRIUM; PRESSURE; FLOCCULATION,"Precipitation of asphaltene during primary production of hydrocarbon reservoirs leads to formation damage and well bore plugging. Therefore, proposing an accurate model to estimate asphaltene precipitation under various operating and thermodynamic conditions are crucial. In this study, a new mathematical model based on the integrating group method of data handling (GMDH) with genetic algorithm has been developed to predict asphaltene precipitation as a function of reservoir pressure and temperature, crude oil API, bubble point pressure, Saturated-Aromatic-Resin-Asphaltene (SARA) fractions and mole percent of non-hydrocarbon gases. Genetic algorithm technique has been applied to optimize the most appropriate network structure of GMDH model. In order to accomplish modeling, asphaltene precipitation of different crude oils from a number of Iranian reservoirs at wide ranges of operating conditions have been measured experimentally and applied for network construction. The accuracy of developed model has been evaluated by both statistical and graphical error analysis techniques. The average absolute relative deviation of the proposed model is 3.65%, which indicates model predictions are in excellent agreement with experimental data. Also, the comparison of developed GMDH model with scaling equation and least squares support vector machine (LSSVM) reveals the superiority of the proposed GMDH structure in prediction of asphaltene precipitation over scaling equation and LSSVM technique. In addition, the Leverage approach has been applied to detect suspected data. The results show that all experimental data are reliable and located within the applicable domain of developed model. Finally, a comprehensive sensitivity analysis based on the relevancy factor has been carried out which shows that percentages of resin and saturated components have the largest direct and inverse impacts on asphaltene precipitation, respectively.",7,7,0
Crude Oil,Asphaltene Precipitation,"Zhu, Lijun; Wang, Yongjie; Wang, Shoulong; Huo, Tian; Jing, Xiaohui; Li, Aifen; Xia, Daohong",High viscosity-reducing performance oil-soluble viscosity reduction agents containing acrylic acid ester as monomer for heavy oil with high asphaltene content,Oil soluble viscosity reduction agent; Acrylic acid ester; Heavy oil; Monomer,WAXY CRUDE-OIL; PIPELINE TRANSPORTATION; RHEOLOGICAL PROPERTIES; POLYMERIZATION; TEMPERATURES; AGGREGATION; BITUMEN,"Reducing viscosity of crude oil is a direct means of cutting the cost and increasing the amount of crude oil delivery. It was found that kerosene-dilution can significantly reduce the viscosity of Shengli heavy oil, and the viscosity reduction rate varies little with temperature rises. By measuring the viscosity of the deasphalted oil, it was found that the viscosity of the heavy oil was greatly reduced after deasphalted treatment, and the deasphalted oil showed a good Newtonian fluid, indicating that the high viscosity of the Shengli heavy oil was because of high asphaltene rather than the precipitation of paraffin. Aiming at the high asphaltene of Shengli heavy oil, oil-soluble polymer viscosity reduction agent was used to study the viscosity reduction. Two new monomers, acrylic acid phenethyl alcohol ester and benzyl acrylate were synthesized, and six copolymers were synthesized by free radical copolymerization with styrene, octadecyl acrylate and N-methoxyphenyl maleimide. Through the viscosity-reducing evaluation, the copolymer containing acrylic acid phenethyl alcohol ester and octadecyl acrylate (AD) had best performance. At 70 degrees C, the AD achieved viscosity reduction rate of 61.74%, which is the result of the matching of aromatics and solubility of monomers. And it is found that the monomer cooperation has an important effect on the viscosity reduction. This provided an important guidance to development of oil-soluble viscosity reduction agent.",7,8,18
Crude Oil,Asphaltene Precipitation,"Guan, Q.; Chai, J. C.; Goharzadeh, A.; Vargas, F. M.; Biswal, S. L.; Chapman, W. G.; Zhang, M.; Yap, Y. F.",A unidirectional one-dimensional approach for asphaltene deposition in large length-to-diameter ratios scenarios,Asphaltene deposition; Large length-to-diameter ratios; One-dimensional one-way,2-PHASE FLOW; ADEPT,"Asphaltene deposition in wellbores has been recognized as the cholesterol of petroleum for decades causing billions of dollars in losses to the oil and gas industry every year. This necessitates great efforts in precise and fast forecasting of the production problems induced by asphaltene deposition. From perspective of the large length-to-diameter ratios of wellbores and the unidirectional nature of the crude oil flow, this work presents a numerical procedure to predict the coupled velocity, pressure and concentration distribution in a transient one-dimensional one-way framework. This procedure is general-purpose for flow passages of large aspect ratios with the precipitation rate, aggregation rate and deposition rate embedded in known forms. In this numerical procedure, the governing equations are solved using the finite volume method on a regular mesh arrangement with fully implicit spatial and temporal schemes. For verification purpose, a few cases having exact solutions are studied. Then, application of the presented procedure to capillary asphaltene deposition is illustrated where good agreement is achieved between the simulation results and the experimental measurements. This case demonstrates that the proposed procedure can be used to investigate oilfield asphaltene problems and assist reservoir engineers in assessing the potential asphaltene deposition risk in wellbores.",8,8,0
Crude Oil,Production,"Karimi, Somayeh; Saidian, Milad; Kazemi, Hossein",Experimental study of the effect of aging on fluid distribution in Middle Bakken cores,Wettability; Chemical osmosis; Capillary pressure; Centrifuge; Nuclear magnetic resonance; Pore size distribution,WETTABILITY LITERATURE SURVEY; NUCLEAR-MAGNETIC-RESONANCE; CHEMICAL OSMOSIS; INDEX DETERMINATION; CAPILLARY-PRESSURE; RECOVERY,"Formation wettability is a critical parameter when designing enhanced oil recovery (EOR) for field applications both in conventional and unconventional reservoirs. In this study, we only focused on one unconventional resource-the Bakken. Specifically, we conducted laboratory experiments in five uncleaned Middle Bakken cores with different initial fluid saturations to determine (1) where the fluids reside within the pores, and (2) the effect of aging on wettability change. The experimental protocol included hydrocarbon-saturation of three uncleaned cores with Bakken oil. The cores were aged at 180 degrees F and 2500 psi pressure for four weeks, and stored in crude oil for 1 year at ambient laboratory conditions (about 12 psi and 66 degrees F). Synthetic brine was then used to produce oil from the aged cores by spontaneous imbibition in Amott cell. Additional oil was produced from the cores using a high-speed centrifuge. For the remaining two uncleaned cores, synthetic brine was used to saturate them, and brine was replaced with oil using a centrifuge. The cores were stored in crude oil at ambient laboratory conditions for four months; then, oil recovery from the cores was measured in Amott cell. NMR measurements were conducted on the cores after each fluid saturation/de-saturation experiment to determine the effect of aging time and temperature on the core wettability and fluid distribution in the pores. Also, porosity and permeability of cleaned twin cores were measured at several net confining stresses. The experimental results indicated that hydrocarbon-saturated cores become slightly more oil-wet than brinesaturated cores. NMR measurements indicated that brine resides in smaller pores and as a brine film on grains regardless of aging time, and the core fluids re-distributed with time indicating a strong rock-fluid interaction. Finally, the analysis of oil production indicated the preponderance of chemical osmosis over imbibition as the mechanism of oil displacement in formations with high brine salinity.",4,4,0
Crude Oil,Production,"Gonzalez, Valeska; Taylor, Spencer E.","Physical and chemical aspects of ""precursor films"" spreading on water from natural bitumen",Bitumen; Film pressure; Film thickness; Heteroatom class species; Precursor film spreading,CRUDE-OIL; ELEMENTAL COMPOSITIONS; NAPHTHENIC ACIDS; NEGATIVE-ION; 3-PHASE FLOW; SURFACE; WETTABILITY; COMPONENTS; PETROLEUM; SANDS,"Interfacial chemistry and physics dominate fluid distribution within crude oil reservoirs and the efficiency of hydrocarbon recovery. For improvements to be made in extraction and production processes, it is essential that the complex boundaries between the different reservoir phases are better understood. The purpose of the present paper is to describe a multi-technique study of the spreading behavior and composition of so-called precursor films deriving from natural bitumen extracted from Athabasca oil sands at an air-water interface. Film spreading on deionized water and saline subphases was followed using ellipsometry and film pressure measurements. The films comprise surface-active bitumen components which could potentially influence the surface chemistry of the reservoir, with implications for mineral wettability, hydrocarbon recovery and the formation and stabilization of oil/water emulsions and oil foams during production. Infrared spectroscopy and mass spectrometry identified the presence of carbonyl groups as well as various classes of sulfur and oxygen hetero-species in the precursor films.",4,4,0
Crude Oil,Production,"Ekpo, B. O.; Essien, N.; Neji, P. A.; Etsenake, R. O.",Geochemical fingerprinting of western offshore Niger Delta oils,Oil fingerprinting; Organic geochemistry; Niger Delta; Nigeria,CRUDE OILS; PETROLEUM GEOCHEMISTRY; GAS-CHROMATOGRAPHY; SOURCE ROCKS; PART II; BASIN; FIELD; BIODEGRADATION; DISTRIBUTIONS; ASPHALTENES,"This study reports the findings based on analyses of saturated (normal alkanes and aliphatic isoprenoid) hydrocarbons and biomarkers in twenty four (24) crude oil samples from western offshore Niger Delta of Nigeria using gas chromatography (GC), gas chromatography-mass spectrometry (GC-MS) and carbon isotopy. The major objectives were to apply reservoir geochemistry and oil fingerprinting to characterize the oils in order to determine their origin and to identify the existence of reservoir continuity and/or compartmentalization. Results from this study using the distributions of normal alkanes, tricyclic and tetracyclic terpanes as well as source specific maturity and facies controlled biomarker ratios of the oils including pristane/phytane (Pr/Ph), Pr/n-C-17, Ph/n-C-l8, C-31:22S/(22S + 22R) homohopane, C-29:alpha alpha(20S/(20S + 20R)) steranes, moretane/C-30-Hopane and Ts/(Ts + Tm), showed that the entire crude oil samples from three reservoir units are the same, the differences are small. The oils originated from same source rocks which were deposited under oxidizing condition with mixed marine/terrigeneous organic source inputs and thermal maturity. This genetic classification is supported by stable carbon isotopic compositions (delta C-13) of the hydrocarbon fractions and multivariate statistical (Principal Component and Cluster) analyses. Geochemical, fingerprinting and multivariate statistical data provided corroborative evidence of a single compartment with vertical and lateral reservoir continuity across the fault complex within the studied fields. This information can be utilized by geologists and petroleum engineers in solving production related problems such as optimising hydrocarbon production via drilling horizontal wells to arrest the reservoir communication that occurs with existing vertical wells.",4,5,1
Crude Oil,Production,"Gerevini, Giovani G.; Farenzena, Marcelo; Trierweiler, Jorge O.",Slugging attenuation using Nonlinear Model Predictive Control in offshore oil production,Slug flow; Deepwater; Offshore crude production; Nonlinear model predictive control,MITIGATION; OBSERVER; FLOW,"The increase in oil production in offshore systems can be achieved by active control, as state in the literature. However, the approach based on linear controllers has performance limitations in real applications, because of valve rate of change, as shown in this paper. As an evolution control approach, we show up the advantages of using a Nonlinear Model Predictive Controller (NMPC) by the Local Linearization on the Trajectory (LLT) algorithm, with the Fast Offshore Well Model (FOWM) as internal model, together with a first idea for tuning the controller parameters. Through a monovariable pressure control strategy, manipulating the production choke, we observed a potential production increase around 9.0% using NMPC. In addition, the multivariable advantage of NMPC strategy is stressed including the gas lift flow as a second manipulated variable. With this structure, it is possible to decrease the production choke variation in 76% and the oil production variability by 80% compared to monovariable structure, with similar production gain.",5,5,0
Crude Oil,Production,"Sakthipriya, N.; Doble, Mukesh; Sangwai, Jitendra S.",Kinetic and thermodynamic behavior of the biodegradation of waxy crude oil using Bacillus subtilis,Biodegradation; Biosurfactant; Kinetic modeling; Monod's model; Thermodynamics,BIOSURFACTANT PRODUCTION; AEROBIC BIODEGRADATION; PETROLEUM-HYDROCARBONS; POPULATION-DENSITY; MONOD KINETICS; WASTE-WATER; GROWTH; RECOVERY; PARAMETERS; BACTERIA,"The present work investigates the reaction kinetics of biodegradation of waxy crude oil using Bacillus subtilis YB7, a thermophilic organism. Mathematical modeling of the reaction kinetics of microbial growth together with biosurfactant production and hydrocarbon substrate utilization have been attempted. Although various models, such as Monod's, Logistic, Tessier and Contois were investigated for substrate degradation and biomass production, and compared with the experimental studies, none of them could accurately predict the biosurfactant production in the presence of waxy crude oil. In this study, a new model, which is an extension of Monod's equation, has been developed to predict the observed values of biosurfactant production along with substrate degradation and biomass production in the presence of waxy crude oil satisfactorily. The proposed model has also been tested with various experimental studies carried out in the literature. The proposed model is observed to provide satisfactory model predictions when compared to other models available in literature. This shows that the proposed model can be used to study the reaction kinetics of all types of biodegradation studies to find the optimum parameters for maximum possible biodegradation of hydrocarbon substrates and production of biosurfactant. The positive values of activation energy observed in the study indicates that the process of biodegradation is an endothermic process. The negative values of entropy indicates that the reacting molecule underwent an internal rearrangement to give the activated complex, without a change in the number of molecules. It is believed that this study will be suitable for possible model development for biodegradation of hydrocarbons for oil recovery applications or bioremediation methods.",6,7,2
Crude Oil,Production,"Sadi, Maryam; Shahrabadi, Abbas",Evolving robust intelligent model based on group method of data handling technique optimized by genetic algorithm to predict asphaltene precipitation,Asphaltene precipitation; Group method of data handling; Genetic algorithm; SARA fractions; Leverage approach,FUZZY INFERENCE SYSTEM; GMDH NEURAL-NETWORK; GAS INJECTION; NATURAL DEPLETION; SCALING EQUATION; HEAVY OILS; DEPOSITION; EQUILIBRIUM; PRESSURE; FLOCCULATION,"Precipitation of asphaltene during primary production of hydrocarbon reservoirs leads to formation damage and well bore plugging. Therefore, proposing an accurate model to estimate asphaltene precipitation under various operating and thermodynamic conditions are crucial. In this study, a new mathematical model based on the integrating group method of data handling (GMDH) with genetic algorithm has been developed to predict asphaltene precipitation as a function of reservoir pressure and temperature, crude oil API, bubble point pressure, Saturated-Aromatic-Resin-Asphaltene (SARA) fractions and mole percent of non-hydrocarbon gases. Genetic algorithm technique has been applied to optimize the most appropriate network structure of GMDH model. In order to accomplish modeling, asphaltene precipitation of different crude oils from a number of Iranian reservoirs at wide ranges of operating conditions have been measured experimentally and applied for network construction. The accuracy of developed model has been evaluated by both statistical and graphical error analysis techniques. The average absolute relative deviation of the proposed model is 3.65%, which indicates model predictions are in excellent agreement with experimental data. Also, the comparison of developed GMDH model with scaling equation and least squares support vector machine (LSSVM) reveals the superiority of the proposed GMDH structure in prediction of asphaltene precipitation over scaling equation and LSSVM technique. In addition, the Leverage approach has been applied to detect suspected data. The results show that all experimental data are reliable and located within the applicable domain of developed model. Finally, a comprehensive sensitivity analysis based on the relevancy factor has been carried out which shows that percentages of resin and saturated components have the largest direct and inverse impacts on asphaltene precipitation, respectively.",7,7,0
Crude Oil,Production,"Wu, Fei-peng; Liu, Jing; Wei, Xue-mei; Pu, Chun-sheng",A study on oxygen consumption mechanism of air-foam flooding in low-temperature oil reservoir,Low temperature and permeability oil reservoir; Air injection; Oxygen consumption mechanism; Oxygen consumption rate; Field test,AQUEOUS-SOLUTION; POLYMER GELS; OXIDATION; POLYACRYLAMIDE; INJECTION; DEGRADATION; SOLUBILITY; KINETICS; STABILITY; GAS,"Air flooding/air-foam flooding recovery technology has been attracting attention in oilfield development. The key point to the application of this technology is to ensure that the oxygen injected with the air can be fully dissipated inside the reservoir to lower the explosion risk in production wells and reduce the oxidation of the pipeline. It is generally believed that the oxygen and crude oil can react more in low-temperature-oxidation (LTO) reactions above 80 degrees C. As a large amount of oxygen would be spontaneously consumed at this temperature, this technology is mainly used in reservoirs where the temperature is greater than 80 degrees C. In the fractured low-permeability reservoir of China's Yanchang oilfield, where the reservoir temperature is only approximately 30 degrees C, a wide range of crude oil LTO would not be triggered theoretically. However, we found that the oxygen content of the associated gas in the gas channeling wells is significantly lower than that in the air. This phenomenon suggests that, there are other factors that could consume oxygen apart from the LTO reaction. To verify this assumption, an oxygen dissipation core flooding experiment at 30 degrees C and 80 degrees C was carried out to evaluate the oxygen consumption at different temperatures. At the same time, in order to determine the main controlling factors and dissipation mechanisms of oxygen dissipation, theoretical analyses and experimental studies were carried out from the aspects of reductive mineral oxidation reaction in the rock surface and formation water, the physical absorption of the micropore and the dissolution of the reservoir fluid. The results show that at the same experimental conditions, the oxygen consumption at 30 degrees C is 38.14% lower than that at 80 degrees C. The oxygen consumption factors in the low-temperature reservoir mainly include the chemical reactions between the oxygen and reducing minerals, dissolution and retention of formation water and oil, adsorption of Van der Waals forces in the reservoir and physical electronic adsorption of the hydrogen-sulfur bonds and carbon-sulfur bonds. In Chang 6 Reservoir of Ganguyi oilfield, formation water could theoretically consume 56 mg/L (1.75 mmol/L) oxygen through dissolved Fe2+. The dissolution by formation water could absorb 11.85 mmol/L oxygen (experimental value). The dissolution by oil could absorb 69.25 mmol/L oxygen (experimental test value), and the oxygen physical adsorption rate of rock pore surface was 1.26 mmol/L. Together with the pilot test data, the results show that the LTO reaction of the stratum crude oil barely occurs in the reservoir at low temperature (30 degrees C). However, a large amount of oxygen dissipation could still be achieved. This study demonstrates that air-foam flooding could break the applicable limit temperature and could also be applied in low-temperature reservoirs.",7,7,1
Crude Oil,Production,"Guan, Q.; Chai, J. C.; Goharzadeh, A.; Vargas, F. M.; Biswal, S. L.; Chapman, W. G.; Zhang, M.; Yap, Y. F.",A unidirectional one-dimensional approach for asphaltene deposition in large length-to-diameter ratios scenarios,Asphaltene deposition; Large length-to-diameter ratios; One-dimensional one-way,2-PHASE FLOW; ADEPT,"Asphaltene deposition in wellbores has been recognized as the cholesterol of petroleum for decades causing billions of dollars in losses to the oil and gas industry every year. This necessitates great efforts in precise and fast forecasting of the production problems induced by asphaltene deposition. From perspective of the large length-to-diameter ratios of wellbores and the unidirectional nature of the crude oil flow, this work presents a numerical procedure to predict the coupled velocity, pressure and concentration distribution in a transient one-dimensional one-way framework. This procedure is general-purpose for flow passages of large aspect ratios with the precipitation rate, aggregation rate and deposition rate embedded in known forms. In this numerical procedure, the governing equations are solved using the finite volume method on a regular mesh arrangement with fully implicit spatial and temporal schemes. For verification purpose, a few cases having exact solutions are studied. Then, application of the presented procedure to capillary asphaltene deposition is illustrated where good agreement is achieved between the simulation results and the experimental measurements. This case demonstrates that the proposed procedure can be used to investigate oilfield asphaltene problems and assist reservoir engineers in assessing the potential asphaltene deposition risk in wellbores.",8,8,0
Crude Oil,Production,"Moises, G. V. L.; Alencar, L. S.; Naccache, M. F.; Frigaard, I. A.",The influence of thixotropy in start-up flow of yield stress fluids in a pipe,Viscoplastic fluids; Yield stress; Thixotropy; Start-up flow,WAXY CRUDE OILS; STRUCTURED FLUIDS; INCLINED PIPES; PIPELINES; DISPLACEMENT; LAPONITE; MODEL; BEHAVIOR; RESTART; LIQUID,"In oil production in ultra-deep water fields, difficulties can appear in the transport of oils with high paraffin content. If the production stops and the produced fluid cools down inside the pipeline, paraffin crystals may appear and form an interlocking gel-like structure, usually exhibiting a thixotropic yield-stress behavior. The restart of the production line should be designed with reasonable precision, taking into account the complex behavior of the gel formed. The start-up flow represents the transient response due to a differential pressure applied to a single fluid initially at rest, and is highly dependent on the fluid rheological behavior and other properties. In the present work, we present experimental and numerical results of the start-up flow of yield stress fluids in a horizontal pipe. The experiments are performed using a flow loop and two different fluids, one thixotropic and another non-thixotropic. Rheological data and velocity profiles are obtained and related to the pressure drop, yield stress and thixotropy. Secondly, numerical results are obtained using the finite volume method to solve the mass and momentum conservation equations. A constitutive model based on the Oldroyd-B equation for viscoelastic fluids, is used to describe the thixotropic fluid behavior. The numerical results captured the main physical features of the flow, and showed a fair agreement to the experimental results.",8,8,3
Crude Oil,Behavior,"Bahman, Jalil; Sharifi, Khashayar; Nasiri, Masoud; Asl, Masoud Haghighi",Development of a Log-Log scaling law approach for prediction of asphaltene precipitation from crude oil by n-alkane titration,Asphaltene; Scaling law; Precipitation; Dilution ratio; Modeling,EQUATION; FLOCCULATION; TEMPERATURE; DEPOSITION; PRESSURE; DEPLETION; MODEL,"One of the most significant problems that petroleum and gas industries tend to know much more is the behavior and the weight percent of Asphaltene precipitation in crude oils. A large number of researchers have been scrutinizing to develop new models for estimating Asphaltene precipitation. Of available approaches, scaling law which is not only relatively simple but also faster than other conventional mathematical methods is promising. In this study, the potential of Ashoori's scaling equation was firstly examined in detail. Afterwards, to solve its drawbacks, an alternative model was formulated exploiting the logarithm operator. Indeed, in this communication, the authors tried to drive a polynomial model that can estimate the amount of Asphaltene precipitation at all dilution ratio ranges with higher accuracy. To get proper outputs and to compare its results with Ashoori's and Rassamdana's outcomes, the polynomial function was fitted to experimental data points. The R-2 (R-squared) of the present model, namely Log-Log scaling law, was about 0.999, and the results indicate that the Log-Log scaling law has better performance than that determined by others for prediction of Asphaltene precipitation from crude oil by n-alkane titration.",4,4,0
Crude Oil,Behavior,"Gonzalez, Valeska; Taylor, Spencer E.","Physical and chemical aspects of ""precursor films"" spreading on water from natural bitumen",Bitumen; Film pressure; Film thickness; Heteroatom class species; Precursor film spreading,CRUDE-OIL; ELEMENTAL COMPOSITIONS; NAPHTHENIC ACIDS; NEGATIVE-ION; 3-PHASE FLOW; SURFACE; WETTABILITY; COMPONENTS; PETROLEUM; SANDS,"Interfacial chemistry and physics dominate fluid distribution within crude oil reservoirs and the efficiency of hydrocarbon recovery. For improvements to be made in extraction and production processes, it is essential that the complex boundaries between the different reservoir phases are better understood. The purpose of the present paper is to describe a multi-technique study of the spreading behavior and composition of so-called precursor films deriving from natural bitumen extracted from Athabasca oil sands at an air-water interface. Film spreading on deionized water and saline subphases was followed using ellipsometry and film pressure measurements. The films comprise surface-active bitumen components which could potentially influence the surface chemistry of the reservoir, with implications for mineral wettability, hydrocarbon recovery and the formation and stabilization of oil/water emulsions and oil foams during production. Infrared spectroscopy and mass spectrometry identified the presence of carbonyl groups as well as various classes of sulfur and oxygen hetero-species in the precursor films.",4,4,0
Crude Oil,Behavior,"Jia, Hu; Deng, Li-hui",Non-equilibrium 3-D simulator applied to air injection EOR in light oil reservoirs,,POROUS-MEDIA; NUMERICAL-SIMULATION; CAPILLARY-PRESSURE; RECOVERY; COMBUSTION; PERFORMANCE; PROJECTS; FLOW; PERMEABILITY; MECHANISM,"In this paper, a 3-D simulator based on the assumption of both chemical and thermal non-equilibrium is presented for a more realistic view of non-equilibrium process for simulating air injection EOR (enhanced oil recovery). The mathematical model is based on a non-equilibrium stage with dynamic mass transfer process between different fluid phases and energy transfer process between fluid and matrix (solid). The light crude oil oxidation and air injection process are both simulated by this simulator, through which the pore blocking, gas breakthrough and gas override process are presented through the visualization of oil, gas saturation distributions. The crude oil oxidation is refined as in-phase and interphase reactions to investigate the effect of reactant dispersion caused by the gas-liquid mass transfer. The oxygen dissolution and the evaporation of light components in crude oil are considered in the non-equilibrium process. The results without mass transfer, with dynamic mass transfer and with instantaneous mass transfer between gas and liquid phases are compared through multiplying the gas-liquid interface area 0, 1 and 100 times respectively, and the influence of these different mass transfer conditions on the migration of temperature peak front and oil recovery is revealed. In addition, the effect of local chemical and thermal non-equilibrium in different matrix permeability as well as porosity scenarios is also investigated to obtain non-equilibrium behavior in different reservoir conditions when implementing air injection EOR. In the last section, we investigated the result with different simulation timescale to see if the non-equilibrium behavior can be captured in the simulator used in this paper. This study suggests that the non-equilibrium behavior would show obvious influence on oil recovery for air injection in the lower permeability reservoir. The non-equilibrium behavior is desirable to be considered for simulating air injection EOR in light oil reservoirs. The developed 3-D simulator is robust that can better reflect the mechanism of air injection EOR in light oil reservoirs. We hope this work encouraging more investigations for the simulation side of nonequilibrium phase behavior and energy transfer in the air injection process.",5,5,1
Crude Oil,Behavior,"Baek, Kwang Hoon; Arguelles-Vivas, Francisco J.; Okuno, Ryosuke; Sheng, Kai; Sharma, Himanshu; Weerasooriya, Upali P.",Emulsification of Athabasca bitumen by organic alkali: Emulsion phase behavior and viscosity for bitumen/brine/triethylenetetramine,Bitumen; Organic alkali; Natural surfactant; Emulsion phase behavior; Emulsion viscosity,HEAVY OIL-RECOVERY; IN-WATER EMULSIONS; CRUDE-OIL; PIPELINE TRANSPORTATION; NATURAL SURFACTANTS; ASPHALTENE RATIO; STEAM CHAMBER; STABILITY; RHEOLOGY; RESINS,"Recovery of bitumen commonly uses steam assisted-gravity drainage, in which water throughput is intrinsically high. A large amount of condensed water near thermal fronts tends to substantially decrease the effective permeability to bitumen in the conventional gravity drainage process. This research investigates a potential way to use the condensed-water phase as an effective carrier for bitumen by making oil-in-water (o/w) emulsion. The expected mechanism depends on emulsification of bitumen into the water phase by natural surfactants that are generated through reactions of acidic oil components with organic alkali. The main objective of this paper is to study the ability of an organic alkali to create o/w emulsions that are much more mobile than the original bitumen. Triethylenetetramine (TETA) was selected as organic alkali for this paper with no other additives. The main contribution of this paper is a new set of experimental data (phase behavior and viscosities) for emulsions for mixtures of Athabasca bitumen, TETA, and NaCl brine at a wide range of alkali concentrations, salinities, and water-to-oil ratios (WORs) M temperatures up to 373 K. Results show that the o/w emulsions created by TETA can be an effective bitumen carrier with a low viscosity and high bitumen content in the emulsion. It is possible to create o/w emulsions by adding a small amount of TETA to Athabasca bitumen and NaC1 brine. Single-phase o/w emulsions, which are desirable as a bitumen carrier, were observed for TETA concentrations below 5.0 wt% M salinities 0 ppm and 1000 ppm at 373 K. The bitumen content in o/w emulsion was the highest for 2.0 wt% TETA samples, and it increased with increasing temperature. In comparison to the original bitumen, o/w emulsions were 4-5 orders of magnitude less viscous at 298 K, 2 to 3 orders of magnitude less viscous at 323 K, and 1 to 2 orders of magnitude less viscous at 353 K.",5,6,2
Crude Oil,Behavior,"Sakthipriya, N.; Doble, Mukesh; Sangwai, Jitendra S.",Kinetic and thermodynamic behavior of the biodegradation of waxy crude oil using Bacillus subtilis,Biodegradation; Biosurfactant; Kinetic modeling; Monod's model; Thermodynamics,BIOSURFACTANT PRODUCTION; AEROBIC BIODEGRADATION; PETROLEUM-HYDROCARBONS; POPULATION-DENSITY; MONOD KINETICS; WASTE-WATER; GROWTH; RECOVERY; PARAMETERS; BACTERIA,"The present work investigates the reaction kinetics of biodegradation of waxy crude oil using Bacillus subtilis YB7, a thermophilic organism. Mathematical modeling of the reaction kinetics of microbial growth together with biosurfactant production and hydrocarbon substrate utilization have been attempted. Although various models, such as Monod's, Logistic, Tessier and Contois were investigated for substrate degradation and biomass production, and compared with the experimental studies, none of them could accurately predict the biosurfactant production in the presence of waxy crude oil. In this study, a new model, which is an extension of Monod's equation, has been developed to predict the observed values of biosurfactant production along with substrate degradation and biomass production in the presence of waxy crude oil satisfactorily. The proposed model has also been tested with various experimental studies carried out in the literature. The proposed model is observed to provide satisfactory model predictions when compared to other models available in literature. This shows that the proposed model can be used to study the reaction kinetics of all types of biodegradation studies to find the optimum parameters for maximum possible biodegradation of hydrocarbon substrates and production of biosurfactant. The positive values of activation energy observed in the study indicates that the process of biodegradation is an endothermic process. The negative values of entropy indicates that the reacting molecule underwent an internal rearrangement to give the activated complex, without a change in the number of molecules. It is believed that this study will be suitable for possible model development for biodegradation of hydrocarbons for oil recovery applications or bioremediation methods.",6,7,2
Crude Oil,Behavior,"Moises, G. V. L.; Alencar, L. S.; Naccache, M. F.; Frigaard, I. A.",The influence of thixotropy in start-up flow of yield stress fluids in a pipe,Viscoplastic fluids; Yield stress; Thixotropy; Start-up flow,WAXY CRUDE OILS; STRUCTURED FLUIDS; INCLINED PIPES; PIPELINES; DISPLACEMENT; LAPONITE; MODEL; BEHAVIOR; RESTART; LIQUID,"In oil production in ultra-deep water fields, difficulties can appear in the transport of oils with high paraffin content. If the production stops and the produced fluid cools down inside the pipeline, paraffin crystals may appear and form an interlocking gel-like structure, usually exhibiting a thixotropic yield-stress behavior. The restart of the production line should be designed with reasonable precision, taking into account the complex behavior of the gel formed. The start-up flow represents the transient response due to a differential pressure applied to a single fluid initially at rest, and is highly dependent on the fluid rheological behavior and other properties. In the present work, we present experimental and numerical results of the start-up flow of yield stress fluids in a horizontal pipe. The experiments are performed using a flow loop and two different fluids, one thixotropic and another non-thixotropic. Rheological data and velocity profiles are obtained and related to the pressure drop, yield stress and thixotropy. Secondly, numerical results are obtained using the finite volume method to solve the mass and momentum conservation equations. A constitutive model based on the Oldroyd-B equation for viscoelastic fluids, is used to describe the thixotropic fluid behavior. The numerical results captured the main physical features of the flow, and showed a fair agreement to the experimental results.",8,8,3
Crude Oil,Behavior,"Wei, Peng; Pu, Wanfen; Sun, Lin; Zhou, Wei; Ji, Xudong",Foam stabilized by alkyl polyglycoside and isoamyl alcohol for enhancing oil recovery in the low-permeable reservoir,APG foam; Isoamyl alcohol; Surface behavior; Foam stability; Low permeability,HIGH-SALINITY ENVIRONMENTS; AIR-WATER-INTERFACE; POROUS-MEDIA; HIGH-TEMPERATURE; CO2 FOAM; GAS TYPE; SURFACTANT; COALESCENCE; DRAINAGE; FILM,"Few studies have delved into the effect of low molecular alcohol on foam stability. This study firstly investigated the improvement in adsorption behavior and viscoelastic behavior at the surface of the APG solution in the presence of isoamyl alcohol, and then we observed that isoamyl alcohol could hinder the liquid drainage and retard the foam rupture by introducing the stabilization capacity (i.e., reducing the surface tension, increasing the surface viscoelasticity, creating the H-bond and providing the disjoining pressure). Afterwards, the addition of isoamyl alcohol can efficiently diminish the defoaming effect of crude oil and impose a considerable oil resistant in foam system. Finally, the flooding experiments were conducted in the tight formation. The results indicate that APG-alcohol foam presents a fine texture and reaches the maximum apparent viscosity at the transition foam quality of 0.67. As presented in the NMR experiment, APG-alcohol foam can efficiently displace the oil in pores with various sizes and substantially promote the EOR to 30.35%.",8,8,5
Crude Oil,Behavior,"Ren, Junjie; Guo, Ping",Analytical method for transient flow rate with the effect of the quadratic gradient term,Transient flow rate; Transient pressure; Quadratic gradient term; Material balance; Horizontal well,FRACTURED HORIZONTAL WELLS; SHALE GAS-RESERVOIRS; NEW-TYPE CURVES; PVT PROPERTIES; VOLUME FACTOR; CRUDE OILS; MODEL; BEHAVIOR; COMPRESSIBILITY; PERFORMANCE,"Owing to neglecting the quadratic gradient term (QGT) in the governing equation, the conventional method proposed by van Everdingen and Hurst [Trans. AIME, 1949, 186, 305-324] for obtaining the transient flow rate is inconsistent with material balance and may lead to errors in the prediction of the flow rate for the wells producing at a constant bottomhole pressure. This paper extends the conventional method to consider the effect of the QGT. If the pressure solution in Laplace space under the constant-rate-production condition is known, the flow-rate solution in Laplace space under the constant-pressure-production condition including the effect of the QGT can be determined by the proposed method. Flow-rate solutions for horizontal wells in reservoirs with different lateral outer boundaries under the constant-pressure-production condition are obtained by the proposed method and the conventional method, respectively. The difference between the flow-rate solutions with and without the effect of the QGT is qualitatively and quantitatively analyzed. The proposed method for obtaining the transient flow rate is consistent with material balance, and thus it can be used to obtain more accurate transient flow rate.",9,9,0
Crude Oil,Degrees C,"Golkari, Abdolah; Riazi, Masoud",Comparative study of oil spreading characteristics for water and carbonated water systems using live and dead oils,Carbonated water alternating CO2 injection; Oil swelling phenomena; Oil spreading coefficient (SC); Equilibrium interfacial tension (EIFT); Optimum conditions; Live crude oil,EQUILIBRIUM PHASE COMPOSITIONS; MINIMUM MISCIBILITY PRESSURE; INTERFACIAL-TENSION; CRUDE-OIL; 3-PHASE FLOW; DIOXIDE; CO2; DENSITIES; RESERVOIR; RECOVERY,"In order to investigate the potential of water alternating gas (WAG) and carbonated water alternating gas (CWAG) injection methods, a series of interfacial tension (IFT) experiments for the binary systems of brine/carbonated brine (CB), carbon dioxide (CO2) and live and dead crude oils were performed. The experiments done using the axisymmetric drop shape analysis (ADSA) technique at temperatures of 40 degrees C and 50 degrees C and different pressures up to 13.79 MPa. The IFT results are used to estimate and determine optimum value of spreading coefficient, which is known as a key enhanced oil recovery (EOR) parameter at the pore scale. The experimental results demonstrate that CB decreases the equilibrium IFT of crude oil compared to the brine at the same conditions (for example, the difference of IFT is 5.2 mN/m and 7.6 mN/m at temperature of 40 degrees C and pressures of 2.76 and 13.79 Mpa, respectively). The equilibrium IFT of the live oil-brine/CB system is greater than that of dead oil-brine/CB. The estimated SC shows that the presence of CO2 in the aqueous phase significantly affects the SC value. That is, it becomes positive for the dead/live oil-CB-CO2 system, and improve the performance of EOR process while it is negative for the dead/live oil-brine-CO2 system. The presence of CH4 gas in the oil phase reduces the SC values at different pressure conditions. Moreover, using the SC results are determined the optimum conditions during CWAG injection. Based on the observed results in the dead/live oil-CB systems, swelling phenomena of the dead oil drop be slightly lower than that of the live oil drop.",2,2,1
Crude Oil,Degrees C,"Yuan, Shibao; Jiang, Haiyan; Yang, Fengxiang; Shi, Yaoli; Bai, Yu; Du, Kun",Research on characteristics of fire flooding zones based on core analysis,Fire flooding; Combustion stage; Zone characteristics; Rock and mineral composition,,"In order to better understand the combustion process and the reactions in the process of fire flooding, it is necessary to study the zone characteristics and the advancing law of fire flooding. Firstly, temperature dynamic characteristics of observation well reveal that the combustion of HQ1 fire flooding pilot test is characterized by wet combustion. Then, a series of core tests (rock pyrolysis, mercury intrusion, crude oil group composition analysis, rock and mineral composition) are utilized to analyze the cores from Xinjiang HQ1. By comparing the difference of characteristics between the burned and unburned zone, the result shows that coke deposition occurs under the burning surface, where the coke deposition zone is. And above the burning surface, kaolinite is converted into illite or montmorillonite. There is evidence to show that montmorillonite will converted into illite under a dry combustion condition(350 degrees C). These features of rock and mineral can be used to evaluate fire flooding process.",5,9,0
Crude Oil,Degrees C,"Lele, Pushan; Syed, Abdul Haseeb; Riordon, Jason; Mosavat, Nader; Guerrero, Adriana; Fadaei, Hossein; Sinton, David",Deformation of microdroplets in crude oil for rapid screening of enhanced oil recovery additives,EOR; Droplet deformation; Heavy oil; Interfacial tension; Alkaline flooding,INTERFACIAL-TENSION MEASUREMENT; MICROFLUIDICS-BASED MEASUREMENT; ASSISTED GRAVITY DRAINAGE; ON-A-CHIP; HEAVY OIL; IONIC-STRENGTH; SURFACTANT SOLUTIONS; BITUMEN EXTRACTION; SAGD PROCESSES; SYSTEMS,"We present a microfluidic method to rapidly screen enhanced oil recovery additives based on the deformation of aqueous microdroplets in oil. Conventional methods, such as the pendant drop method, are hindered by large fluid volumes that require several hours to thermally equilibrate between measurements. Here we demonstrate a complementary technology to conventional methods, by which additives can be rapidly screened to select the best candidates for further study. Our glass chip establishes thermal equilibrium (demonstrated at 80 degrees C) of undiluted, highly viscous, crude oil within seconds, and enables the rapid quantification of water-in-crude oil droplet deformation within minutes, at a reservoir-relevant scale. The influence of two alkaline additives, a surfactant and a salt in the injected water phase were quantified, demonstrating the applicability of our method to a variety of recovery strategies.",5,5,2
Crude Oil,Degrees C,"Wu, Fei-peng; Liu, Jing; Wei, Xue-mei; Pu, Chun-sheng",A study on oxygen consumption mechanism of air-foam flooding in low-temperature oil reservoir,Low temperature and permeability oil reservoir; Air injection; Oxygen consumption mechanism; Oxygen consumption rate; Field test,AQUEOUS-SOLUTION; POLYMER GELS; OXIDATION; POLYACRYLAMIDE; INJECTION; DEGRADATION; SOLUBILITY; KINETICS; STABILITY; GAS,"Air flooding/air-foam flooding recovery technology has been attracting attention in oilfield development. The key point to the application of this technology is to ensure that the oxygen injected with the air can be fully dissipated inside the reservoir to lower the explosion risk in production wells and reduce the oxidation of the pipeline. It is generally believed that the oxygen and crude oil can react more in low-temperature-oxidation (LTO) reactions above 80 degrees C. As a large amount of oxygen would be spontaneously consumed at this temperature, this technology is mainly used in reservoirs where the temperature is greater than 80 degrees C. In the fractured low-permeability reservoir of China's Yanchang oilfield, where the reservoir temperature is only approximately 30 degrees C, a wide range of crude oil LTO would not be triggered theoretically. However, we found that the oxygen content of the associated gas in the gas channeling wells is significantly lower than that in the air. This phenomenon suggests that, there are other factors that could consume oxygen apart from the LTO reaction. To verify this assumption, an oxygen dissipation core flooding experiment at 30 degrees C and 80 degrees C was carried out to evaluate the oxygen consumption at different temperatures. At the same time, in order to determine the main controlling factors and dissipation mechanisms of oxygen dissipation, theoretical analyses and experimental studies were carried out from the aspects of reductive mineral oxidation reaction in the rock surface and formation water, the physical absorption of the micropore and the dissolution of the reservoir fluid. The results show that at the same experimental conditions, the oxygen consumption at 30 degrees C is 38.14% lower than that at 80 degrees C. The oxygen consumption factors in the low-temperature reservoir mainly include the chemical reactions between the oxygen and reducing minerals, dissolution and retention of formation water and oil, adsorption of Van der Waals forces in the reservoir and physical electronic adsorption of the hydrogen-sulfur bonds and carbon-sulfur bonds. In Chang 6 Reservoir of Ganguyi oilfield, formation water could theoretically consume 56 mg/L (1.75 mmol/L) oxygen through dissolved Fe2+. The dissolution by formation water could absorb 11.85 mmol/L oxygen (experimental value). The dissolution by oil could absorb 69.25 mmol/L oxygen (experimental test value), and the oxygen physical adsorption rate of rock pore surface was 1.26 mmol/L. Together with the pilot test data, the results show that the LTO reaction of the stratum crude oil barely occurs in the reservoir at low temperature (30 degrees C). However, a large amount of oxygen dissipation could still be achieved. This study demonstrates that air-foam flooding could break the applicable limit temperature and could also be applied in low-temperature reservoirs.",7,7,1
Crude Oil,Degrees C,"Zhu, Lijun; Wang, Yongjie; Wang, Shoulong; Huo, Tian; Jing, Xiaohui; Li, Aifen; Xia, Daohong",High viscosity-reducing performance oil-soluble viscosity reduction agents containing acrylic acid ester as monomer for heavy oil with high asphaltene content,Oil soluble viscosity reduction agent; Acrylic acid ester; Heavy oil; Monomer,WAXY CRUDE-OIL; PIPELINE TRANSPORTATION; RHEOLOGICAL PROPERTIES; POLYMERIZATION; TEMPERATURES; AGGREGATION; BITUMEN,"Reducing viscosity of crude oil is a direct means of cutting the cost and increasing the amount of crude oil delivery. It was found that kerosene-dilution can significantly reduce the viscosity of Shengli heavy oil, and the viscosity reduction rate varies little with temperature rises. By measuring the viscosity of the deasphalted oil, it was found that the viscosity of the heavy oil was greatly reduced after deasphalted treatment, and the deasphalted oil showed a good Newtonian fluid, indicating that the high viscosity of the Shengli heavy oil was because of high asphaltene rather than the precipitation of paraffin. Aiming at the high asphaltene of Shengli heavy oil, oil-soluble polymer viscosity reduction agent was used to study the viscosity reduction. Two new monomers, acrylic acid phenethyl alcohol ester and benzyl acrylate were synthesized, and six copolymers were synthesized by free radical copolymerization with styrene, octadecyl acrylate and N-methoxyphenyl maleimide. Through the viscosity-reducing evaluation, the copolymer containing acrylic acid phenethyl alcohol ester and octadecyl acrylate (AD) had best performance. At 70 degrees C, the AD achieved viscosity reduction rate of 61.74%, which is the result of the matching of aromatics and solubility of monomers. And it is found that the monomer cooperation has an important effect on the viscosity reduction. This provided an important guidance to development of oil-soluble viscosity reduction agent.",7,8,18
Crude Oil,Degrees C,"Chen, Gang; Yuan, Weihua; Zhang, Fan; Gu, Xuefan; Du, Weichao; Zhang, Jie; Li, Jinling; Qu, Chengtun",Application of polymethacrylate from waste organic glass as a pour point depressor in heavy crude oil,Waste organic glass; Polymethyl methacrylate; Polymethacrylate; Crude oil; Pour point depressor,FLOW IMPROVER; ADDITIVES; WAX,"Polymethyl methacrylate (PMMA, organic glass) is widely used as a substitute for glass, known as organic glass. During the processing and after use, there are amount of castoff. Based on the similar framework, PMMA could be useful the feed stock to synthesis polymethacrylate (PMA) used for crude oil additive. In this work PMA was prepared by transesterification of PMMA and aliphatic alcohol catalyzed by a base. The performance of PMA on heavy oil was evaluated as pour point depressant as well as viscosity reducer. The highest pour point reduction depression was achieved as 7.1 degrees C with the dosage of 2000 ppm PMA-1. The viscosity of crude oil was also substantially reduced from 182000 mPa.s to 64500 mPa.s. Differential scanning calorimetry and paraffin crystal morphology studies were clearly reflected that PMA affects the wax crystallization of crude oil. Base on this work, the waste organic glass can be reused as a valuable material in oil field.",8,8,4
Crude Oil,Natural Gas,"Pszonka, Joanna; Goetze, Jens",Quantitative estimate of interstitial clays in sandstones using Nomarski differential interference contrast (DIC) microscopy and image analysis,Nomarski DIC microscopy; Image analysis; Sandstone; Matrix; Clay; Flysch Carpathians,CATHODOLUMINESCENCE,"The Nomarski differential interference contrast (DIC) microscopy in the reflected-light visualizes a virtual surface relief of rock components through varying resistance to grinding and polishing of different mineral phases. In the case of sandstones, illustrated here with an example of the Cergowa sandstones ( Lower Oligocene) from the Flysch Carpathians, the used analytical technique depicts a homogeneity with no or very weak relief in the surface morphology of all components besides clay particles, where a virtual relief is observed. Thereby, the Nomarski DIC imaging proved to be very useful in a distinction between an interstitial matrix and other binders of sedimentary rocks. Such separation with standard petrographic examinations is often far from clear which causes usually an overstatement of the matrix content and an incorrect rock classification. Such monotonous picture of sandstones as from the Nomarski DIC microscopy seems to be easy to apply in an image analysis. In the case of the Cergowa sandstones, an automatic extraction of clay matrix in an image analysis was disturbed by numerous replacements of some minerals ( especially feldspars) by clay minerals that were detected as a matrix with an illusory relief. The applied manual approach in the ImageJ analysis programme pointed out: two of six analysed images were overestimated by means of the polarising microscopy. In both cases, the matrix content was estimated >15%, whilst in the Nomarski DIC images showed contents of 10.5% and 10.2%, what classifies them as arenites, not wackes. The presence of clay matrix in sandstones has a great influence on their petrophysical properties, including the most important porosity and permeability, a sufficient amount of which permits to accumulate crude oil or natural gas under adequate trapping conditions. Therefore, their correct extraction and measurement is so substantial.",2,2,1
Crude Oil,Natural Gas,"Quan, Qing; Ran, Wen; Yang, Lu; Gao, Ge; Wang, Shouxi; Gong, Jing",The effect of pressure on wax deposition from wax-solvent mixtures with natural gas,Wax deposition; Pressure; Natural gas; Cold-finger,CRUDE-OIL; SHEAR; WATER,"deposition reduces the effective flow area of the pipelines, leading to a significant pressure drop, which increases the transportation consumption and leads eventually to complete blockage. Most wax deposition studies have neglected the influence of natural gas, but natural gas is present in the actual pipelines and must be accounted for in field operations. A self-developed cold-finger apparatus was used to investigate the effects of pressure on wax deposition with natural gas (with 89.01% methane). The wax solvent mixtures consisted of a wax (C-22-C-37) dissolved in a paraffinic solvent (C-11-C-15). The wax deposition experiments were performed with 5, 7, and 10 mass percent wax solutions, for pressures ranging from 0.1 MPa to 6 MPa. The experimental results indicated that the maximum amount of wax is deposited at ordinary pressure. The amount of wax deposited increased at pressures ranging from 1 MPa to 2 MPa and decreased thereafter (at pressures ranging from 2 MPa to 6 MPa). In addition, the pressure corresponding to the maximum wax deposition varied with the wax content. Furthermore, the wax crystal morphology was observed using a polarizing microscope, and the morphology was quantitatively described via the fractal dimension. The analysis showed that the fractal dimension decreased with increasing pressure. This study confirms that natural gas plays a vital role in wax deposition studies, especially those aimed at predicting the wax deposition in actual pipelines, using a wax deposition model based on the laboratory experiments.",2,2,2
Crude Oil,Natural Gas,"Schumann, Heiner; Fossen, Martin","Oil-water dispersion formation, development and stability studied in a wheel-shaped flow loop",Oil-water flow; Oil-water dispersion; Flow development; Wheel flow loop,EMULSIONS; VISCOSITY,"The work describes how a quasi-endless wheel flow loop can be used to study dispersion formation, development and stability at different pressures and temperatures. The so-called Wheel Flow Loop consists of a wheel-shaped closed pipe section that can be filled with gas, oil and water. By rotating the device in vertical orientation, a gravity driven flow is initiated. Several different flow conditions were simulated by varying the rotational speed. Onset of dispersion and the stability of emulsions formed was identified by interpreting torque profiles supported by visual observations. Two fluid systems, a realistic fluid system consisting of a light crude oil, synthetic natural gas and brine, and a model system consisting of a mineral oil, tap water and nitrogen as gas phase were investigated. Furthermore, the effect of temperature, pressure and water cut on dispersion properties was demonstrated. The sensitivity of the results indicated that the wheel qualifies as a characterization tool for dispersion properties. Furthermore, agreement in dispersion behaviour was found when straight pipe flow experiments were compared with the wheel matching the energy dissipation rate.",4,4,1
Crude Oil,Natural Gas,"Sadi, Maryam; Shahrabadi, Abbas",Evolving robust intelligent model based on group method of data handling technique optimized by genetic algorithm to predict asphaltene precipitation,Asphaltene precipitation; Group method of data handling; Genetic algorithm; SARA fractions; Leverage approach,FUZZY INFERENCE SYSTEM; GMDH NEURAL-NETWORK; GAS INJECTION; NATURAL DEPLETION; SCALING EQUATION; HEAVY OILS; DEPOSITION; EQUILIBRIUM; PRESSURE; FLOCCULATION,"Precipitation of asphaltene during primary production of hydrocarbon reservoirs leads to formation damage and well bore plugging. Therefore, proposing an accurate model to estimate asphaltene precipitation under various operating and thermodynamic conditions are crucial. In this study, a new mathematical model based on the integrating group method of data handling (GMDH) with genetic algorithm has been developed to predict asphaltene precipitation as a function of reservoir pressure and temperature, crude oil API, bubble point pressure, Saturated-Aromatic-Resin-Asphaltene (SARA) fractions and mole percent of non-hydrocarbon gases. Genetic algorithm technique has been applied to optimize the most appropriate network structure of GMDH model. In order to accomplish modeling, asphaltene precipitation of different crude oils from a number of Iranian reservoirs at wide ranges of operating conditions have been measured experimentally and applied for network construction. The accuracy of developed model has been evaluated by both statistical and graphical error analysis techniques. The average absolute relative deviation of the proposed model is 3.65%, which indicates model predictions are in excellent agreement with experimental data. Also, the comparison of developed GMDH model with scaling equation and least squares support vector machine (LSSVM) reveals the superiority of the proposed GMDH structure in prediction of asphaltene precipitation over scaling equation and LSSVM technique. In addition, the Leverage approach has been applied to detect suspected data. The results show that all experimental data are reliable and located within the applicable domain of developed model. Finally, a comprehensive sensitivity analysis based on the relevancy factor has been carried out which shows that percentages of resin and saturated components have the largest direct and inverse impacts on asphaltene precipitation, respectively.",7,7,0
Crude Oil,Natural Gas,"Guan, Q.; Chai, J. C.; Goharzadeh, A.; Vargas, F. M.; Biswal, S. L.; Chapman, W. G.; Zhang, M.; Yap, Y. F.",A unidirectional one-dimensional approach for asphaltene deposition in large length-to-diameter ratios scenarios,Asphaltene deposition; Large length-to-diameter ratios; One-dimensional one-way,2-PHASE FLOW; ADEPT,"Asphaltene deposition in wellbores has been recognized as the cholesterol of petroleum for decades causing billions of dollars in losses to the oil and gas industry every year. This necessitates great efforts in precise and fast forecasting of the production problems induced by asphaltene deposition. From perspective of the large length-to-diameter ratios of wellbores and the unidirectional nature of the crude oil flow, this work presents a numerical procedure to predict the coupled velocity, pressure and concentration distribution in a transient one-dimensional one-way framework. This procedure is general-purpose for flow passages of large aspect ratios with the precipitation rate, aggregation rate and deposition rate embedded in known forms. In this numerical procedure, the governing equations are solved using the finite volume method on a regular mesh arrangement with fully implicit spatial and temporal schemes. For verification purpose, a few cases having exact solutions are studied. Then, application of the presented procedure to capillary asphaltene deposition is illustrated where good agreement is achieved between the simulation results and the experimental measurements. This case demonstrates that the proposed procedure can be used to investigate oilfield asphaltene problems and assist reservoir engineers in assessing the potential asphaltene deposition risk in wellbores.",8,8,0
Crude Oil,Transient Flow,"Bao, Youquan; Zhang, Jinjun; Wang, Xinyi; Li, Xueyi; Hou, Hao; Yu, Bo",Applicability of quasi-steady assumption during the numerical simulation of the start-up of weakly compressible Herschel-Bulkley fluids in pipelines,Herschel-Bulkley fluid; Quasi-steady assumption; Scale analysis; Start-up flow,WAXY CRUDE-OIL; FLOW; RESTART; MODEL; VISCOSITY,"In the numerical study of the start-up of viscoplastic fluids in pipelines, the quasi-steady assumption, i.e., the assumption of a linear radial distribution of shear stress, is widely introduced into the governing equations to capture the radial position of the yield surface. However, few studies in the existing literature have examined the condition that the quasi-steady assumption is applicable. In the present work, we define a dimensionless number Ut for the start-up of weakly compressible Herschel-Bulkley fluids in pipelines. Ut increases with increasing pipeline aspect ratio, Reynolds number and flow index, and decreases with increasing fluid compressibility and Bingham number. Scale analysis and numerical studies show that the effect of these five parameters on the applicability of the quasi-steady assumption depends only on the value of Ut. The smaller the value of Ut is, the less likely the quasi-steady assumption would affect the simulation results. When Ut < 0.065, the difference in the time it takes for the outlet fluid starts to flow computed with and without the quasi-steady assumption is below 2%, and the difference in the outlet velocity during its recovery process computed with and without the quasi-steady assumption is below 1%. Moreover, the computed deviations slowly decrease as Ut decreases. Conversely, when Ut > 0.065, the quasi-steady assumption shortens the computed time it takes for the outlet fluid starts to flow and intensifies the computed transient processes of the velocities and pressures.",0,1,0
Crude Oil,Transient Flow,"Guan, Q.; Chai, J. C.; Goharzadeh, A.; Vargas, F. M.; Biswal, S. L.; Chapman, W. G.; Zhang, M.; Yap, Y. F.",A unidirectional one-dimensional approach for asphaltene deposition in large length-to-diameter ratios scenarios,Asphaltene deposition; Large length-to-diameter ratios; One-dimensional one-way,2-PHASE FLOW; ADEPT,"Asphaltene deposition in wellbores has been recognized as the cholesterol of petroleum for decades causing billions of dollars in losses to the oil and gas industry every year. This necessitates great efforts in precise and fast forecasting of the production problems induced by asphaltene deposition. From perspective of the large length-to-diameter ratios of wellbores and the unidirectional nature of the crude oil flow, this work presents a numerical procedure to predict the coupled velocity, pressure and concentration distribution in a transient one-dimensional one-way framework. This procedure is general-purpose for flow passages of large aspect ratios with the precipitation rate, aggregation rate and deposition rate embedded in known forms. In this numerical procedure, the governing equations are solved using the finite volume method on a regular mesh arrangement with fully implicit spatial and temporal schemes. For verification purpose, a few cases having exact solutions are studied. Then, application of the presented procedure to capillary asphaltene deposition is illustrated where good agreement is achieved between the simulation results and the experimental measurements. This case demonstrates that the proposed procedure can be used to investigate oilfield asphaltene problems and assist reservoir engineers in assessing the potential asphaltene deposition risk in wellbores.",8,8,0
Crude Oil,Transient Flow,"Moises, G. V. L.; Alencar, L. S.; Naccache, M. F.; Frigaard, I. A.",The influence of thixotropy in start-up flow of yield stress fluids in a pipe,Viscoplastic fluids; Yield stress; Thixotropy; Start-up flow,WAXY CRUDE OILS; STRUCTURED FLUIDS; INCLINED PIPES; PIPELINES; DISPLACEMENT; LAPONITE; MODEL; BEHAVIOR; RESTART; LIQUID,"In oil production in ultra-deep water fields, difficulties can appear in the transport of oils with high paraffin content. If the production stops and the produced fluid cools down inside the pipeline, paraffin crystals may appear and form an interlocking gel-like structure, usually exhibiting a thixotropic yield-stress behavior. The restart of the production line should be designed with reasonable precision, taking into account the complex behavior of the gel formed. The start-up flow represents the transient response due to a differential pressure applied to a single fluid initially at rest, and is highly dependent on the fluid rheological behavior and other properties. In the present work, we present experimental and numerical results of the start-up flow of yield stress fluids in a horizontal pipe. The experiments are performed using a flow loop and two different fluids, one thixotropic and another non-thixotropic. Rheological data and velocity profiles are obtained and related to the pressure drop, yield stress and thixotropy. Secondly, numerical results are obtained using the finite volume method to solve the mass and momentum conservation equations. A constitutive model based on the Oldroyd-B equation for viscoelastic fluids, is used to describe the thixotropic fluid behavior. The numerical results captured the main physical features of the flow, and showed a fair agreement to the experimental results.",8,8,3
Crude Oil,Transient Flow,"Ren, Junjie; Guo, Ping",Analytical method for transient flow rate with the effect of the quadratic gradient term,Transient flow rate; Transient pressure; Quadratic gradient term; Material balance; Horizontal well,FRACTURED HORIZONTAL WELLS; SHALE GAS-RESERVOIRS; NEW-TYPE CURVES; PVT PROPERTIES; VOLUME FACTOR; CRUDE OILS; MODEL; BEHAVIOR; COMPRESSIBILITY; PERFORMANCE,"Owing to neglecting the quadratic gradient term (QGT) in the governing equation, the conventional method proposed by van Everdingen and Hurst [Trans. AIME, 1949, 186, 305-324] for obtaining the transient flow rate is inconsistent with material balance and may lead to errors in the prediction of the flow rate for the wells producing at a constant bottomhole pressure. This paper extends the conventional method to consider the effect of the QGT. If the pressure solution in Laplace space under the constant-rate-production condition is known, the flow-rate solution in Laplace space under the constant-pressure-production condition including the effect of the QGT can be determined by the proposed method. Flow-rate solutions for horizontal wells in reservoirs with different lateral outer boundaries under the constant-pressure-production condition are obtained by the proposed method and the conventional method, respectively. The difference between the flow-rate solutions with and without the effect of the QGT is qualitatively and quantitatively analyzed. The proposed method for obtaining the transient flow rate is consistent with material balance, and thus it can be used to obtain more accurate transient flow rate.",9,9,0
Crude Oil,Source Rocks,"Ekpo, B. O.; Essien, N.; Neji, P. A.; Etsenake, R. O.",Geochemical fingerprinting of western offshore Niger Delta oils,Oil fingerprinting; Organic geochemistry; Niger Delta; Nigeria,CRUDE OILS; PETROLEUM GEOCHEMISTRY; GAS-CHROMATOGRAPHY; SOURCE ROCKS; PART II; BASIN; FIELD; BIODEGRADATION; DISTRIBUTIONS; ASPHALTENES,"This study reports the findings based on analyses of saturated (normal alkanes and aliphatic isoprenoid) hydrocarbons and biomarkers in twenty four (24) crude oil samples from western offshore Niger Delta of Nigeria using gas chromatography (GC), gas chromatography-mass spectrometry (GC-MS) and carbon isotopy. The major objectives were to apply reservoir geochemistry and oil fingerprinting to characterize the oils in order to determine their origin and to identify the existence of reservoir continuity and/or compartmentalization. Results from this study using the distributions of normal alkanes, tricyclic and tetracyclic terpanes as well as source specific maturity and facies controlled biomarker ratios of the oils including pristane/phytane (Pr/Ph), Pr/n-C-17, Ph/n-C-l8, C-31:22S/(22S + 22R) homohopane, C-29:alpha alpha(20S/(20S + 20R)) steranes, moretane/C-30-Hopane and Ts/(Ts + Tm), showed that the entire crude oil samples from three reservoir units are the same, the differences are small. The oils originated from same source rocks which were deposited under oxidizing condition with mixed marine/terrigeneous organic source inputs and thermal maturity. This genetic classification is supported by stable carbon isotopic compositions (delta C-13) of the hydrocarbon fractions and multivariate statistical (Principal Component and Cluster) analyses. Geochemical, fingerprinting and multivariate statistical data provided corroborative evidence of a single compartment with vertical and lateral reservoir continuity across the fault complex within the studied fields. This information can be utilized by geologists and petroleum engineers in solving production related problems such as optimising hydrocarbon production via drilling horizontal wells to arrest the reservoir communication that occurs with existing vertical wells.",4,5,1
Crude Oil,Source Rocks,"Niu, Jun; Huang, Haiping; Jiang, Wenlong","Geochemical characteristics and correlation of continuous charge mixing and biodegradation of heavy oil in southeastern Dongying Sag, Bohai Bay basin, China",Bohai Bay basin; Dongying Sag; Charge mixing; Biodegradation; Heavy oil,NIUZHUANG SOUTH SLOPE; CRUDE OILS; ORGANIC GEOCHEMISTRY; EASTERN CHINA; AEROBIC BIODEGRADATION; DEEP SUBSURFACE; RESERVOIR GEOCHEMISTRY; PETROLEUM RESERVOIRS; GEOLOGICAL PROVINCE; PART 1,"The Paleogene Shahejie Formation is the main source rock and reservoir in the Jiyang Depression, Bohai Bay Basin, East China. An organic geochemical analysis study was performed on nine oil samples and forty-three core extracted samples from Shahejie Formation reservoirs by GC-MS to elucidate the influence of biodegradation and charge mixing on molecular compositions. Biodegradation impacts many classes of compounds, but the ultimate compositions and physical properties of the oil are influenced strongly by mixing with later oil charge and biodegradation. All samples display biodegradation signatures, and continuous charge mixing is characterized by the relationship between n-alkanes to hopanes and hopanes to 25-norhopanes (25-NHs). The occurrence of nalkanes in oil samples suggests multiple episodes of charging and that the petroleum accumulated in Caoqiao is mainly a mixture of previously biodegraded oils and later migrated fresh oils. Conventional geochemical diagnostic parameters in the saturated hydrocarbon fraction are affected by biodegradation. Based on the intensity of n-alkanes, hopanes and 25-NHs, many samples from Caoqiao appear to have experienced both biodegradation and continuous charge. A wide range of geochemical parameter values from different components point to multiple oil charge mixing. The relationship between the absolute concentrations of n-alkanes to hopanes and hopanes to 25-NHs of the samples can qualitatively differentiate whether oil charge mixing occurs in reservoirs or not. The cross plot of n-alkanes and hopanes dynamically describes the processes of continuous charge mixing and biodegradation. The positive correlation between the concentrations of hopanes and 25-NHs may suggest that oil charge mixing and biodegradation proceed continuously, while the negative correlation may indicate charge stops due to some geological factors.",5,6,1
Crude Oil,Source Rocks,"Kong, Ting; Zhang, Min",Effects of depositional environment on rearranged hopanes in lacustrine and coal measure rocks,Rearranged hopanes; Depositional environment; Lacustrine source rocks; Coal measure rocks,HYDROCARBON SOURCE ROCKS; LISHU FAULT DEPRESSION; SOUTH CHINA SEA; SONGLIAO BASIN; CRUDE OILS; NE CHINA; GEOCHEMICAL CHARACTERISTICS; CLAY-MINERALS; PETROLEUM; TRITERPANES,"On the basis of GC-MS analysis, a suite of 97 lacustrine and coal measure rocks from the Songliao Basin, Ordos Basin and Tarim Basin were found to contain abundant rearranged hopanes. Except for peak ratios, the absolute concentrations of rearranged hopanes were determined based on addition of an internal standard (5 alpha-androstane) normalized to bitumen ""A"", which in lacustrine source rocks are far more than those in coal measure rocks. To examine the effects of depositional environment on relative abundance and absolute concentration of rearranged hopanes, the clay content, redox condition and water salinity of sedimentary rocks from two sample sets were analyzed. The results reveal that the acidic clay acted as clay-mediated acidic catalysis in the formation and degradation of rearranged hopanes, but there is no positive correlation between clay content and rearranged hopanes in lacustrine source rocks. In contrast, the absolute concentrations of rearranged hopanes in coal measure rocks, show a general increase with clay content. Some molecular parameters, such as pristane/phytane (Pr/Ph), C-35 homohopane index and gammacerane index, were found to change as a function of depositional environment. With increasing Pr/Ph, C-35 homohopane index and gammacerane index, the ratios of C-30 diahopane/C-30 hopane and C29Ts/C-29 hopane display an initial increase and subsequent decrease trend. The absolute concentrations of C-30 diahopane and C29Ts in lacustrine source rocks also increase at first, followed by a decrease at the largest value. Whereas the absolute concentrations of rearranged hopanes in coal measure rocks show an apparent positive correlation with some depositional environmental parameters. On the whole, abundant rearranged hopanes in lacustrine source rocks appear to be distributed in suboxic-weak reduction and fresh-brackish condition, while abundant rearranged hopanes in coal measure rocks appear to be present in oxic and fresh condition.",5,5,4
Crude Oil,WAXY Crude,"Sakthipriya, N.; Doble, Mukesh; Sangwai, Jitendra S.",Kinetic and thermodynamic behavior of the biodegradation of waxy crude oil using Bacillus subtilis,Biodegradation; Biosurfactant; Kinetic modeling; Monod's model; Thermodynamics,BIOSURFACTANT PRODUCTION; AEROBIC BIODEGRADATION; PETROLEUM-HYDROCARBONS; POPULATION-DENSITY; MONOD KINETICS; WASTE-WATER; GROWTH; RECOVERY; PARAMETERS; BACTERIA,"The present work investigates the reaction kinetics of biodegradation of waxy crude oil using Bacillus subtilis YB7, a thermophilic organism. Mathematical modeling of the reaction kinetics of microbial growth together with biosurfactant production and hydrocarbon substrate utilization have been attempted. Although various models, such as Monod's, Logistic, Tessier and Contois were investigated for substrate degradation and biomass production, and compared with the experimental studies, none of them could accurately predict the biosurfactant production in the presence of waxy crude oil. In this study, a new model, which is an extension of Monod's equation, has been developed to predict the observed values of biosurfactant production along with substrate degradation and biomass production in the presence of waxy crude oil satisfactorily. The proposed model has also been tested with various experimental studies carried out in the literature. The proposed model is observed to provide satisfactory model predictions when compared to other models available in literature. This shows that the proposed model can be used to study the reaction kinetics of all types of biodegradation studies to find the optimum parameters for maximum possible biodegradation of hydrocarbon substrates and production of biosurfactant. The positive values of activation energy observed in the study indicates that the process of biodegradation is an endothermic process. The negative values of entropy indicates that the reacting molecule underwent an internal rearrangement to give the activated complex, without a change in the number of molecules. It is believed that this study will be suitable for possible model development for biodegradation of hydrocarbons for oil recovery applications or bioremediation methods.",6,7,2
Crude Oil,WAXY Crude,"Zhu, Lijun; Wang, Yongjie; Wang, Shoulong; Huo, Tian; Jing, Xiaohui; Li, Aifen; Xia, Daohong",High viscosity-reducing performance oil-soluble viscosity reduction agents containing acrylic acid ester as monomer for heavy oil with high asphaltene content,Oil soluble viscosity reduction agent; Acrylic acid ester; Heavy oil; Monomer,WAXY CRUDE-OIL; PIPELINE TRANSPORTATION; RHEOLOGICAL PROPERTIES; POLYMERIZATION; TEMPERATURES; AGGREGATION; BITUMEN,"Reducing viscosity of crude oil is a direct means of cutting the cost and increasing the amount of crude oil delivery. It was found that kerosene-dilution can significantly reduce the viscosity of Shengli heavy oil, and the viscosity reduction rate varies little with temperature rises. By measuring the viscosity of the deasphalted oil, it was found that the viscosity of the heavy oil was greatly reduced after deasphalted treatment, and the deasphalted oil showed a good Newtonian fluid, indicating that the high viscosity of the Shengli heavy oil was because of high asphaltene rather than the precipitation of paraffin. Aiming at the high asphaltene of Shengli heavy oil, oil-soluble polymer viscosity reduction agent was used to study the viscosity reduction. Two new monomers, acrylic acid phenethyl alcohol ester and benzyl acrylate were synthesized, and six copolymers were synthesized by free radical copolymerization with styrene, octadecyl acrylate and N-methoxyphenyl maleimide. Through the viscosity-reducing evaluation, the copolymer containing acrylic acid phenethyl alcohol ester and octadecyl acrylate (AD) had best performance. At 70 degrees C, the AD achieved viscosity reduction rate of 61.74%, which is the result of the matching of aromatics and solubility of monomers. And it is found that the monomer cooperation has an important effect on the viscosity reduction. This provided an important guidance to development of oil-soluble viscosity reduction agent.",7,8,18
Crude Oil,WAXY Crude,"Moises, G. V. L.; Alencar, L. S.; Naccache, M. F.; Frigaard, I. A.",The influence of thixotropy in start-up flow of yield stress fluids in a pipe,Viscoplastic fluids; Yield stress; Thixotropy; Start-up flow,WAXY CRUDE OILS; STRUCTURED FLUIDS; INCLINED PIPES; PIPELINES; DISPLACEMENT; LAPONITE; MODEL; BEHAVIOR; RESTART; LIQUID,"In oil production in ultra-deep water fields, difficulties can appear in the transport of oils with high paraffin content. If the production stops and the produced fluid cools down inside the pipeline, paraffin crystals may appear and form an interlocking gel-like structure, usually exhibiting a thixotropic yield-stress behavior. The restart of the production line should be designed with reasonable precision, taking into account the complex behavior of the gel formed. The start-up flow represents the transient response due to a differential pressure applied to a single fluid initially at rest, and is highly dependent on the fluid rheological behavior and other properties. In the present work, we present experimental and numerical results of the start-up flow of yield stress fluids in a horizontal pipe. The experiments are performed using a flow loop and two different fluids, one thixotropic and another non-thixotropic. Rheological data and velocity profiles are obtained and related to the pressure drop, yield stress and thixotropy. Secondly, numerical results are obtained using the finite volume method to solve the mass and momentum conservation equations. A constitutive model based on the Oldroyd-B equation for viscoelastic fluids, is used to describe the thixotropic fluid behavior. The numerical results captured the main physical features of the flow, and showed a fair agreement to the experimental results.",8,8,3
Crude Oil,Air Injection,"Jia, Hu; Deng, Li-hui",Non-equilibrium 3-D simulator applied to air injection EOR in light oil reservoirs,,POROUS-MEDIA; NUMERICAL-SIMULATION; CAPILLARY-PRESSURE; RECOVERY; COMBUSTION; PERFORMANCE; PROJECTS; FLOW; PERMEABILITY; MECHANISM,"In this paper, a 3-D simulator based on the assumption of both chemical and thermal non-equilibrium is presented for a more realistic view of non-equilibrium process for simulating air injection EOR (enhanced oil recovery). The mathematical model is based on a non-equilibrium stage with dynamic mass transfer process between different fluid phases and energy transfer process between fluid and matrix (solid). The light crude oil oxidation and air injection process are both simulated by this simulator, through which the pore blocking, gas breakthrough and gas override process are presented through the visualization of oil, gas saturation distributions. The crude oil oxidation is refined as in-phase and interphase reactions to investigate the effect of reactant dispersion caused by the gas-liquid mass transfer. The oxygen dissolution and the evaporation of light components in crude oil are considered in the non-equilibrium process. The results without mass transfer, with dynamic mass transfer and with instantaneous mass transfer between gas and liquid phases are compared through multiplying the gas-liquid interface area 0, 1 and 100 times respectively, and the influence of these different mass transfer conditions on the migration of temperature peak front and oil recovery is revealed. In addition, the effect of local chemical and thermal non-equilibrium in different matrix permeability as well as porosity scenarios is also investigated to obtain non-equilibrium behavior in different reservoir conditions when implementing air injection EOR. In the last section, we investigated the result with different simulation timescale to see if the non-equilibrium behavior can be captured in the simulator used in this paper. This study suggests that the non-equilibrium behavior would show obvious influence on oil recovery for air injection in the lower permeability reservoir. The non-equilibrium behavior is desirable to be considered for simulating air injection EOR in light oil reservoirs. The developed 3-D simulator is robust that can better reflect the mechanism of air injection EOR in light oil reservoirs. We hope this work encouraging more investigations for the simulation side of nonequilibrium phase behavior and energy transfer in the air injection process.",5,5,1
Crude Oil,Air Injection,"Wu, Fei-peng; Liu, Jing; Wei, Xue-mei; Pu, Chun-sheng",A study on oxygen consumption mechanism of air-foam flooding in low-temperature oil reservoir,Low temperature and permeability oil reservoir; Air injection; Oxygen consumption mechanism; Oxygen consumption rate; Field test,AQUEOUS-SOLUTION; POLYMER GELS; OXIDATION; POLYACRYLAMIDE; INJECTION; DEGRADATION; SOLUBILITY; KINETICS; STABILITY; GAS,"Air flooding/air-foam flooding recovery technology has been attracting attention in oilfield development. The key point to the application of this technology is to ensure that the oxygen injected with the air can be fully dissipated inside the reservoir to lower the explosion risk in production wells and reduce the oxidation of the pipeline. It is generally believed that the oxygen and crude oil can react more in low-temperature-oxidation (LTO) reactions above 80 degrees C. As a large amount of oxygen would be spontaneously consumed at this temperature, this technology is mainly used in reservoirs where the temperature is greater than 80 degrees C. In the fractured low-permeability reservoir of China's Yanchang oilfield, where the reservoir temperature is only approximately 30 degrees C, a wide range of crude oil LTO would not be triggered theoretically. However, we found that the oxygen content of the associated gas in the gas channeling wells is significantly lower than that in the air. This phenomenon suggests that, there are other factors that could consume oxygen apart from the LTO reaction. To verify this assumption, an oxygen dissipation core flooding experiment at 30 degrees C and 80 degrees C was carried out to evaluate the oxygen consumption at different temperatures. At the same time, in order to determine the main controlling factors and dissipation mechanisms of oxygen dissipation, theoretical analyses and experimental studies were carried out from the aspects of reductive mineral oxidation reaction in the rock surface and formation water, the physical absorption of the micropore and the dissolution of the reservoir fluid. The results show that at the same experimental conditions, the oxygen consumption at 30 degrees C is 38.14% lower than that at 80 degrees C. The oxygen consumption factors in the low-temperature reservoir mainly include the chemical reactions between the oxygen and reducing minerals, dissolution and retention of formation water and oil, adsorption of Van der Waals forces in the reservoir and physical electronic adsorption of the hydrogen-sulfur bonds and carbon-sulfur bonds. In Chang 6 Reservoir of Ganguyi oilfield, formation water could theoretically consume 56 mg/L (1.75 mmol/L) oxygen through dissolved Fe2+. The dissolution by formation water could absorb 11.85 mmol/L oxygen (experimental value). The dissolution by oil could absorb 69.25 mmol/L oxygen (experimental test value), and the oxygen physical adsorption rate of rock pore surface was 1.26 mmol/L. Together with the pilot test data, the results show that the LTO reaction of the stratum crude oil barely occurs in the reservoir at low temperature (30 degrees C). However, a large amount of oxygen dissipation could still be achieved. This study demonstrates that air-foam flooding could break the applicable limit temperature and could also be applied in low-temperature reservoirs.",7,7,1
Crude Oil,Oxygen Consumption,"Yoo, Kuy Hun Koh; Sampaio, Luiz Bittencourt; Gerritsen, Margot; Kovscek, Anthony R.",An optimization algorithm for evaluation of kinetic parameters for crude oil combustion,In situ combustion; Ramped temperature oxidation; Oxidation kinetics,IN-SITU-COMBUSTION; FIELD-SCALE; PREDICTABILITY,"The design of enhanced oil recovery processes that employ in-situ combustion requires high-fidelity simulation models that accurately describe the physics and chemistry of reactive, exothermic multiphase fluid flow. Therefore, a detailed description of oil combustion kinetics is required. The goal of this work is to present and apply a workflow to define and match pseudo-kinetic reaction models based on Arrhenius kinetics. These models are meant to be used at the laboratory scale with high-resolution, fully-resolved simulation models as a tool to generate high density data required by upscaled models at reservoir scale. The workflow starts by performing ramped temperature oxidation (RTO) experiments for a wide range of heating rates. New experimental equipment has allowed us to obtain data for large heating rates (>15 degrees C/min) that were not achievable in the past. A subset of the experiments are selected to match the oxygen consumption curves by tuning kinetic parameters of several global reaction models using pattern search optimization. Those models that obtain a match are validated by predicting a second subset of the data that was not considered during the optimization. The workflow is tested using a heavy oil and two satisfactory matches with two different global reaction models are obtained.",4,4,0
Crude Oil,Oxygen Consumption,"Wu, Fei-peng; Liu, Jing; Wei, Xue-mei; Pu, Chun-sheng",A study on oxygen consumption mechanism of air-foam flooding in low-temperature oil reservoir,Low temperature and permeability oil reservoir; Air injection; Oxygen consumption mechanism; Oxygen consumption rate; Field test,AQUEOUS-SOLUTION; POLYMER GELS; OXIDATION; POLYACRYLAMIDE; INJECTION; DEGRADATION; SOLUBILITY; KINETICS; STABILITY; GAS,"Air flooding/air-foam flooding recovery technology has been attracting attention in oilfield development. The key point to the application of this technology is to ensure that the oxygen injected with the air can be fully dissipated inside the reservoir to lower the explosion risk in production wells and reduce the oxidation of the pipeline. It is generally believed that the oxygen and crude oil can react more in low-temperature-oxidation (LTO) reactions above 80 degrees C. As a large amount of oxygen would be spontaneously consumed at this temperature, this technology is mainly used in reservoirs where the temperature is greater than 80 degrees C. In the fractured low-permeability reservoir of China's Yanchang oilfield, where the reservoir temperature is only approximately 30 degrees C, a wide range of crude oil LTO would not be triggered theoretically. However, we found that the oxygen content of the associated gas in the gas channeling wells is significantly lower than that in the air. This phenomenon suggests that, there are other factors that could consume oxygen apart from the LTO reaction. To verify this assumption, an oxygen dissipation core flooding experiment at 30 degrees C and 80 degrees C was carried out to evaluate the oxygen consumption at different temperatures. At the same time, in order to determine the main controlling factors and dissipation mechanisms of oxygen dissipation, theoretical analyses and experimental studies were carried out from the aspects of reductive mineral oxidation reaction in the rock surface and formation water, the physical absorption of the micropore and the dissolution of the reservoir fluid. The results show that at the same experimental conditions, the oxygen consumption at 30 degrees C is 38.14% lower than that at 80 degrees C. The oxygen consumption factors in the low-temperature reservoir mainly include the chemical reactions between the oxygen and reducing minerals, dissolution and retention of formation water and oil, adsorption of Van der Waals forces in the reservoir and physical electronic adsorption of the hydrogen-sulfur bonds and carbon-sulfur bonds. In Chang 6 Reservoir of Ganguyi oilfield, formation water could theoretically consume 56 mg/L (1.75 mmol/L) oxygen through dissolved Fe2+. The dissolution by formation water could absorb 11.85 mmol/L oxygen (experimental value). The dissolution by oil could absorb 69.25 mmol/L oxygen (experimental test value), and the oxygen physical adsorption rate of rock pore surface was 1.26 mmol/L. Together with the pilot test data, the results show that the LTO reaction of the stratum crude oil barely occurs in the reservoir at low temperature (30 degrees C). However, a large amount of oxygen dissipation could still be achieved. This study demonstrates that air-foam flooding could break the applicable limit temperature and could also be applied in low-temperature reservoirs.",7,7,1
Crude Oil,Flow Loop,"Schumann, Heiner; Fossen, Martin","Oil-water dispersion formation, development and stability studied in a wheel-shaped flow loop",Oil-water flow; Oil-water dispersion; Flow development; Wheel flow loop,EMULSIONS; VISCOSITY,"The work describes how a quasi-endless wheel flow loop can be used to study dispersion formation, development and stability at different pressures and temperatures. The so-called Wheel Flow Loop consists of a wheel-shaped closed pipe section that can be filled with gas, oil and water. By rotating the device in vertical orientation, a gravity driven flow is initiated. Several different flow conditions were simulated by varying the rotational speed. Onset of dispersion and the stability of emulsions formed was identified by interpreting torque profiles supported by visual observations. Two fluid systems, a realistic fluid system consisting of a light crude oil, synthetic natural gas and brine, and a model system consisting of a mineral oil, tap water and nitrogen as gas phase were investigated. Furthermore, the effect of temperature, pressure and water cut on dispersion properties was demonstrated. The sensitivity of the results indicated that the wheel qualifies as a characterization tool for dispersion properties. Furthermore, agreement in dispersion behaviour was found when straight pipe flow experiments were compared with the wheel matching the energy dissipation rate.",4,4,1
Crude Oil,Flow Loop,"Moises, G. V. L.; Alencar, L. S.; Naccache, M. F.; Frigaard, I. A.",The influence of thixotropy in start-up flow of yield stress fluids in a pipe,Viscoplastic fluids; Yield stress; Thixotropy; Start-up flow,WAXY CRUDE OILS; STRUCTURED FLUIDS; INCLINED PIPES; PIPELINES; DISPLACEMENT; LAPONITE; MODEL; BEHAVIOR; RESTART; LIQUID,"In oil production in ultra-deep water fields, difficulties can appear in the transport of oils with high paraffin content. If the production stops and the produced fluid cools down inside the pipeline, paraffin crystals may appear and form an interlocking gel-like structure, usually exhibiting a thixotropic yield-stress behavior. The restart of the production line should be designed with reasonable precision, taking into account the complex behavior of the gel formed. The start-up flow represents the transient response due to a differential pressure applied to a single fluid initially at rest, and is highly dependent on the fluid rheological behavior and other properties. In the present work, we present experimental and numerical results of the start-up flow of yield stress fluids in a horizontal pipe. The experiments are performed using a flow loop and two different fluids, one thixotropic and another non-thixotropic. Rheological data and velocity profiles are obtained and related to the pressure drop, yield stress and thixotropy. Secondly, numerical results are obtained using the finite volume method to solve the mass and momentum conservation equations. A constitutive model based on the Oldroyd-B equation for viscoelastic fluids, is used to describe the thixotropic fluid behavior. The numerical results captured the main physical features of the flow, and showed a fair agreement to the experimental results.",8,8,3
Crude Oil,Image Analysis,"Pszonka, Joanna; Goetze, Jens",Quantitative estimate of interstitial clays in sandstones using Nomarski differential interference contrast (DIC) microscopy and image analysis,Nomarski DIC microscopy; Image analysis; Sandstone; Matrix; Clay; Flysch Carpathians,CATHODOLUMINESCENCE,"The Nomarski differential interference contrast (DIC) microscopy in the reflected-light visualizes a virtual surface relief of rock components through varying resistance to grinding and polishing of different mineral phases. In the case of sandstones, illustrated here with an example of the Cergowa sandstones ( Lower Oligocene) from the Flysch Carpathians, the used analytical technique depicts a homogeneity with no or very weak relief in the surface morphology of all components besides clay particles, where a virtual relief is observed. Thereby, the Nomarski DIC imaging proved to be very useful in a distinction between an interstitial matrix and other binders of sedimentary rocks. Such separation with standard petrographic examinations is often far from clear which causes usually an overstatement of the matrix content and an incorrect rock classification. Such monotonous picture of sandstones as from the Nomarski DIC microscopy seems to be easy to apply in an image analysis. In the case of the Cergowa sandstones, an automatic extraction of clay matrix in an image analysis was disturbed by numerous replacements of some minerals ( especially feldspars) by clay minerals that were detected as a matrix with an illusory relief. The applied manual approach in the ImageJ analysis programme pointed out: two of six analysed images were overestimated by means of the polarising microscopy. In both cases, the matrix content was estimated >15%, whilst in the Nomarski DIC images showed contents of 10.5% and 10.2%, what classifies them as arenites, not wackes. The presence of clay matrix in sandstones has a great influence on their petrophysical properties, including the most important porosity and permeability, a sufficient amount of which permits to accumulate crude oil or natural gas under adequate trapping conditions. Therefore, their correct extraction and measurement is so substantial.",2,2,1
Crude Oil,Image Analysis,"Fan, Jingjing; Sappington, Emily N.; Rifai, Hanadi S.; Rodrigues, Debora F.",Confocal microscopy as a new real-time quantification method for oil content in produced water,"Confocal laser fluorescence microscopy; EPA 1664 method; Produced water, oil, and grease",FLUORESCENCE SPECTROSCOPY; WASTE-WATER; CRUDE OILS; HYDROCARBONS; COALESCENCE; EMULSIONS; DROPLETS; GREASE,"This research proposes confocal laser fluorescence microscopy (CLFM) as an enabling technology to quantify oil prior to produced water disposal. This method takes advantage of the self-fluorescing properties of oil to visualize and quantify in 3D oil droplets in water in real-time. This investigation initially involves the identification and optimization of parameters affecting CLFM oil measurements in synthetically prepared produced water, followed by validation of the optimum CLFM parameters for oil quantification in real produced water. This study demonstrated that the optimized excitation wavelength, z-step size, image analysis threshold value, and minimum sampling size parameters for the CLFM method are suitable for different types of oil. The optimum amount of time for analysis, however, changed for oils with different densities due to different oil upward movement velocities. The detection range of the CLFM was determined to be between 1 and 250 ppm. The quantification of oil content in three different produced water samples were also investigated with the CLFM method and results were compared with the standard EPA 1664 method. The results for both methods correlated well, which suggests that the CLFM has potential to be used as an initial real-time screening of the oil quantities of treated produced water prior to environmental releases in water streams. This technique has several advantages over other methods, such as does not require hazardous solvents for oil extraction, is less labor intensive, and can be automated for real-time online applications, such as subsea systems.",3,3,1
Crude Oil,Nanoparticles,"Hassanpour, Sadegh; Malayeri, Mohammad Reza; Riazi, Masoud; Mousavi, Seyed Mahdi; Negahban, Zahra",On the impact of Co3O4 nanoparticles on interaction of heavy oil and brine mixtures,IFT; Brine solution; Asphaltene precipitation; EOR; Co3O4 nanoparticles,INTERFACIAL-TENSION; CRUDE-OIL; ASPHALTENE; SALINITY; TEMPERATURE; RECOVERY; PRESSURE; WATER; CO2; PRECIPITATION,"Among numerous EOR methods, the injection of brine with different salinities to oil reservoirs has gained attention where its performance would, in turn, depend on interfacial tension (IFT) of oil/brine mixture. The present study investigated the impact of Co3O4 nanoparticles with concentrations of 0.01, 0.1 and 1 wt% on IFT of brine solution (containing NaCl, KCl and CaCl2) and heavy crude oil system. The results confirmed that adding Co3O4 nanoparticles to water, compared to that without nanoparticles, reduced IFT at low (i.e. 0-5000 ppm) and high (i.e. greater than 5000 ppm) brine concentrations, although the propensity of IFT is different for various concentrations. Furthermore, the reduction of IFT for monovalent ions is greater than that for divalent ions. Properties such as high surface activity and higher surface to volume ratio of the Co3O4 nanoparticles should be accounted for profound adsorption of asphaltene onto the surface of nanoparticles. A high suspension of asphaltene at the brine/oil interface also avoided its precipitation in oil causing IFT to reduce in brine/crude mixtures with nanoparticles compared to that without nanoparticles. The extent of IFT reduction changed by using different concentrations of Co3O4 nanoparticles. For the oil/brine system attempted in this study, the optimum concentration of Co3O4 nanoparticles in term of IFT reduction was 0.1 wt%.",4,5,1
Crude Oil,Nanoparticles,"Akhmadiyarov, Aydar A.; Rakipov, Ilnaz T.; Khachatrian, Artashes A.; Petrov, Artem A.; Sitnov, Sergei A.; Gerasimov, Alexander V.; Osin, Yury N.; Varfolomeev, Mikhail A.",Thermocatalytic upgrading of heavy oil by iron oxides nanoparticles synthesized by oil-soluble precursors,Thermocatalytic upgrading; Heavy oil; Viscosity; Reservoir temperature and pressure; Catalysis,HIGH-TEMPERATURE; AQUATHERMOLYSIS; TETRAHYDROTHIOPHENE; CHEMISTRY; THIOPHENE; VISCOSITY; RECOVERY; MINERALS; SQUALANE; STEAM,"Thermocatalytic upgrading of heavy crude oil at reservoir temperature and pressure has been studied. The objective of the present work was to investigate the efficiency of the compounds based on iron (iron carbonyls, iron oxide, metallic iron) on thermocatalytic upgrading process of heavy crude oil at reservoir temperature and pressure (5.0 MPa and up to 523.15 K). The viscosity reducing was used as the main parameter for determination of the efficiency of thermocatalytic upgrading. The effect of structure of the catalyst precursor on the composition of SARA fractions after thermal catalytic upgrading of crude oil was analyzed. A destruction of mainly resin fraction was found to occur during thermocatalytic upgrading of heavy crude oil. The composition and structure of catalysts after crude oil upgrading were determined by the X-powder diffraction and SEM methods. An impact of catalyst (Fe3O4) particle size on the efficiency of crude oil thermocatalytic upgrading process was revealed.",4,5,4
Heavy Oil,Degrees C,"Brito, Adriana; Guzman, Nolides; Rojas-Solorzano, Luis; Zambrano, Tibisay",Rheological study of two- and three-phase highly viscous fluid flow in pipelines,Foam rheology; Foamed emulsion; Two-phase flow; Three-phase flow; Flow patterns; Pressure drop model,GAS-LIQUID FLOW; HORIZONTAL PIPES; 2-PHASE FLOW; FOAMS; TRANSPORT; STABILITY,"The study of highly viscous multiphase flow systems is of fundamental interest in the oil industry. Most of the Venezuelan oil fields produce heavy oil with other production fluids, such as water and gas, and sand particles flowing from the reservoir to the surface facilities. A fraction of these phases flows fully separated, while another one flows as a dispersed system composed by water/oil emulsion with gas bubbles dispersed as a foamed emulsion. With the objective to understand and characterize this latter complex system, new experiments have been performed in 0.0243-m and 0.0508-m horizontal pipelines, for air/highly-viscous oil of 0.430 Pa s at 20 degrees C, and water/air/oil mixture with a water-in-oil emulsion of 0.560 Pa s at 20 degrees C. The three-phase flow pressure gradient was found to be approximately 15% higher than for the two-phase system, at similar gas and liquid superficial velocities. The air/oil and air/oil/water foamed emulsion behaved as non-Newtonian fluids, when these are considered as pseudo-homogeneous systems. A model to predict the flow pattern and pressure drop in horizontal pipelines was developed with an extensive database of 2167 experimental points, including new data and information collected and processed from different sources. A performance factor of 0.41 for Brito's three-phase (TM) model was consistently better than the performance factor obtained for other models commonly used by the oil and gas industry in similar multiphase flow systems.",3,3,0
Heavy Oil,Degrees C,"Guo, Jixiang; Yang, Yuqi; Zhang, Shuai; Zhang, Dengshan; Cao, Chang; Ren, Bo; Liu, Lei; Xing, Yu; Xiong, Ruiying",Heavy oil-water flow patterns in a small diameter vertical pipe under high temperature/pressure conditions,Upward oil-water flows; Flow patterns; High pressure; High temperature; Heavy oil,NATURAL CIRCULATION LOOP; LIQUID ANNULAR-FLOW; 2-PHASE FLOW; PRESSURE-DROP; INTERFACIAL-TENSION; HORIZONTAL PIPES; PHASE INVERSION; VOLUME FRACTION; DISPERSED FLOW; OPTICAL PROBE,"Experimental measurements were conducted to investigate the upward oil-water flow patterns in a small diameter vertical pipe (0.01m I.D.) under high temperatures up to 130 degrees C and high pressures up to 20 MPa. The viscosity of the oil sample was 584.24 mPa s and the density was 1.899 g/cm(3) at 30 degrees C. The effects of pressure, temperature, input water fraction (IWF) and mixture velocity on the flow patterns were systematically investigated. The observed flow patterns were plotted on a flow pattern map in which input water fraction was used as the y-axis and the mixture velocity was used as the x-axis. Based on the measurement results, the following flow patterns were observed: water-in-oil dispersed flow (D w/o), water-in-oil bubbly flow (B w/o), water-in-oil slug flow (S w/o), water-in-oil creep flow (CE w/o), churn flow (Churn) and core annual flow (AF). Phase inversion was not observed in this work. With an increase in temperature at a given input water fraction, S w/o, CE w/o and Churn flow with large water drops tended to transform into B w/o and D w/o with smaller water drops, the CE w/o disappears gradually, and the boundaries in the flow pattern maps tend to occur at lower input water fraction values. The effect of pressure on the flow patterns was found to be opposite to that of temperature. The possible causes leading to the changes in the flow patterns subjected to pressure/temperature variations were provided in terms of changes in density ratio, interfacial tension, and viscosity ratio of oil and water.",3,4,3
Heavy Oil,Degrees C,"Wang, Kongyang; Yan, Wei; Deng, Jingen; Tian, Hao; Li, Wenbo; Wang, Yangang; Wang, Luyao; Ye, Sutao",Experimental study on H2S and CO2 generation capacities of the Bohai bay heavy oil,Heavy oil; Thermal recovery; Pyrolysis; H2S and CO2 generation; Partial pressure,CYMBOPOGON FLEXUOSUS BIOFUEL; FIREFLOOD FIELD PROJECTS; DIESEL-ENGINE; EMISSION CHARACTERISTICS; RECOVERY STRATEGIES; GRAVITY DRAINAGE; BIODIESEL BLEND; PERFORMANCE; COMBUSTION; RESERVOIRS,"Thermal recovery is a conventional technology for heavy oil development. During thermal oil recovery the reservoir could generate H2S and CO2. They will potentially threat the safety of downhole tubing regarding the sweet or sour corrosion. In some Bohai heavy oil fields CO2 and H2S under thermal recovery conditions lead to some corrosion problems of the tubing and equipment. Therefore, to determine the corrosive gas generation capacity is crucial for anti-corrosion design of downhole tubing and casing. Heavy oil samples from Bohai, China were experimentally studied for their pyrolysis characteristics using high-temperature-high-pressure autoclaves. The gases were collected when autoclaves cooled down to the in situ formation temperature. Effects of temperature, water chemistry and core mineral on corrosive gas generation were investigated. The results show that total pressure increase significantly when temperature reached 250 degrees C-280 degrees C under the single heavy oil condition. The additional water facilitates the reaction process, after more SO42- added in the mimic formation water, higher H2S content is obtained. Under the condition of multiphase of oil, formation water and cores, both of the H2S and CO2 content increase obviously, and the cores' effect on CO2 is greater than H2S. Anti-corrosion design usually concerns only the highest corrosive gas concentration without further analysis. The highest concentration does not always correspond to the best corrosive gases generation capacities of heavy oil. Comprehensive analysis of both the total pressure of reaction process and the quality of the reaction heavy oil is carried out, then the corrosive gases volume per unit mass of heavy oil is calculated. These can determine the strongest corrosive formation environment and the maximum gases generation capacities of heavy oil.",4,4,3
Heavy Oil,Degrees C,"Leyva-Gomez, H.; Babadagli, Tayfun",Efficiency of heavy-oil/bitumen recovery from fractured carbonates by hot-solvent injection,Injection parameters optimization; Heavy oil; Hot solvent; Fractured carbonate reservoirs; Oil dilution,RESERVOIRS SOS-FR; OIL-RECOVERY; BITUMEN RECOVERY; ASPHALTENE DEPOSITION; VAPOR EXTRACTION; AIDED PROCESS; STEAM; SIMULATION; SANDS; PILOT,"This paper presents an extensive analysis of three different solvents injected through two different rock types under dynamic conditions, at elevated temperatures, to recover heavy-oil/bitumen from fractured carbonates. The main idea was to identify the optimal temperatures needed for maximal recovery by hot solvent injection for a wide range of solvents. We also considered the optimal conditions for effective solvent retrieval for the economics of this type recovery approach. In order to represent a wide range of carbon number solvents, heptane and naphtha were injected at atmospheric pressure and temperatures ranging from 70 to 120 degrees C and 21.5-100 degrees C, respectively. Propane was injected at a pressure of 1483-1511 kPa and a temperature ranging from 22 to 60 degrees C to be in the liquid phase. Indiana limestone (outcrop) and vuggy naturally fractured carbonate samples (outcrop core samples from a producing formation in Mexico) were selected as core samples. Hot solvent was injected continuously through artificially fractured cores followed by hot water (or steam injection) phase for solvent retrieval. The optimal temperatures for heavy oil recovery and solvent retrieval, in the subsequent hot water injection, for each kind of rock sample and type of solvent were determined. The results revealed that heavy oil recovery increase with the solvent carbon number used. Also, it was observed that when the temperature is higher than the saturation value for the given pressure curve, the recovery decreases and the lightest component of the heavy oil are dragged by the gas stream.",5,5,1
Heavy Oil,Degrees C,"Lele, Pushan; Syed, Abdul Haseeb; Riordon, Jason; Mosavat, Nader; Guerrero, Adriana; Fadaei, Hossein; Sinton, David",Deformation of microdroplets in crude oil for rapid screening of enhanced oil recovery additives,EOR; Droplet deformation; Heavy oil; Interfacial tension; Alkaline flooding,INTERFACIAL-TENSION MEASUREMENT; MICROFLUIDICS-BASED MEASUREMENT; ASSISTED GRAVITY DRAINAGE; ON-A-CHIP; HEAVY OIL; IONIC-STRENGTH; SURFACTANT SOLUTIONS; BITUMEN EXTRACTION; SAGD PROCESSES; SYSTEMS,"We present a microfluidic method to rapidly screen enhanced oil recovery additives based on the deformation of aqueous microdroplets in oil. Conventional methods, such as the pendant drop method, are hindered by large fluid volumes that require several hours to thermally equilibrate between measurements. Here we demonstrate a complementary technology to conventional methods, by which additives can be rapidly screened to select the best candidates for further study. Our glass chip establishes thermal equilibrium (demonstrated at 80 degrees C) of undiluted, highly viscous, crude oil within seconds, and enables the rapid quantification of water-in-crude oil droplet deformation within minutes, at a reservoir-relevant scale. The influence of two alkaline additives, a surfactant and a salt in the injected water phase were quantified, demonstrating the applicability of our method to a variety of recovery strategies.",5,5,2
Heavy Oil,Degrees C,"Yang, Shangyu; Han, Lihong; Feng, Chun; Wang, Hang; Feng, Yaorong; Wu, Xingru",Mechanical performance of casing in in-situ combustion thermal recovery,Casing performance; Heavy oil; In-situ combustion; Casing design; Steam flooding,OIL; WELLS,"In-situ combustion is often used to develop heavy oil as it has multiple advantages over alternative thermal methods. However, the wellbore integrity can be compromised if the casing is not properly designed or manufactured. Based on the fundamentals of heat transfer, a mathematical model with multiphysics is built to study the temperature and pressure distributions surrounding the wellbore during in-situ combustion. In laboratory, real casings and coupons with grades of N80, P110, and 3Cr110 were tested under high temperature to study their mechanical performances in the in-situ combustion recovery. From the modeling and laboratory testing results, we propose the casing design and manufacture protocols for thermal recovery of heavy oil. Field applications in Liaohe oil field, Du-66 Block, shows that the mechanical deterioration of P110 and 3Cr110 is less than that of N80 and the mechanical performance stability of 3Cr110 is better than others when the temperature is less than 600 degrees C. When the temperature is above 600 degrees C for more than 10 h, the mechanical performance of all casing grades declines quickly. Applying finite element analysis, we recommend a safety factor of 1.1 for designing casing at the temperatures of 250 degrees C,480 degrees C and 485 degrees C. The finding of this study provides fundamentals for the casing design and material selection for in-situ combustion recovery.",6,6,0
Heavy Oil,Degrees C,"Zhu, Lijun; Wang, Yongjie; Wang, Shoulong; Huo, Tian; Jing, Xiaohui; Li, Aifen; Xia, Daohong",High viscosity-reducing performance oil-soluble viscosity reduction agents containing acrylic acid ester as monomer for heavy oil with high asphaltene content,Oil soluble viscosity reduction agent; Acrylic acid ester; Heavy oil; Monomer,WAXY CRUDE-OIL; PIPELINE TRANSPORTATION; RHEOLOGICAL PROPERTIES; POLYMERIZATION; TEMPERATURES; AGGREGATION; BITUMEN,"Reducing viscosity of crude oil is a direct means of cutting the cost and increasing the amount of crude oil delivery. It was found that kerosene-dilution can significantly reduce the viscosity of Shengli heavy oil, and the viscosity reduction rate varies little with temperature rises. By measuring the viscosity of the deasphalted oil, it was found that the viscosity of the heavy oil was greatly reduced after deasphalted treatment, and the deasphalted oil showed a good Newtonian fluid, indicating that the high viscosity of the Shengli heavy oil was because of high asphaltene rather than the precipitation of paraffin. Aiming at the high asphaltene of Shengli heavy oil, oil-soluble polymer viscosity reduction agent was used to study the viscosity reduction. Two new monomers, acrylic acid phenethyl alcohol ester and benzyl acrylate were synthesized, and six copolymers were synthesized by free radical copolymerization with styrene, octadecyl acrylate and N-methoxyphenyl maleimide. Through the viscosity-reducing evaluation, the copolymer containing acrylic acid phenethyl alcohol ester and octadecyl acrylate (AD) had best performance. At 70 degrees C, the AD achieved viscosity reduction rate of 61.74%, which is the result of the matching of aromatics and solubility of monomers. And it is found that the monomer cooperation has an important effect on the viscosity reduction. This provided an important guidance to development of oil-soluble viscosity reduction agent.",7,8,18
Heavy Oil,Degrees C,"Zhong, Xun; Liu, Dexin; Shi, Xiaofei; Zhao, Hongtao; Pei, Chun; Zhu, Tongyu; Shao, Minglu; Zhang, Fang",Characteristics and functional mechanisms of clay-cement stabilized three-phase nitrogen foam for heavy oil reservoir,Heavy oil reservoir; Clay-cement three-phase foam; High stability; Water shutoff agent,HYDROPHOBIC NANOPARTICLES; DILATIONAL PROPERTIES; NANO-PARTICLES; AQUEOUS FOAMS; DEMULSIFIERS; RECOVERY; BUBBLES,"The large-scale application of two-phase foam flooding in heavy oil reservoirs was restricted due to the instability of foam itself. However, the developed clay-cement three-phase nitrogen foam can make up for the short broad effectively, which benefits from very good thermal stability, salt resistance, oil sensitivity and excellent plugging performance. In this paper, 8.0 wt% clay, 0.50 wt% cement particles and 1.0 wt% foaming agent were used to generate clay-cement nitrogen foam. The synergistic effects of clay/cement reaction products, particle adsorption layer and steric network contribute to a desirable protective sheath covered compact three-phase foam system with high stability and strength, the half-life of which was 42.0 min at 95 degrees C. Moreover, it became more stable when formation sands exist. Generally, clay-cement three-phase nitrogen foam has three kinds of plugging form owing to different formation permeability. In less permeable formations, most foam would separate into two parts, with particles stacking at the entry end and two-phase foam moving forward. While in formations with higher permeability, all foam would flow out directly without effective plugging. Only when it comes to the formations with proper permeability can this foam achieve impressive plugging strength under the effects of Jamin and particle plugging. In addition, the foaming formula can be modified by adjusting particle-surfactant concentrations to fit various formations. Therefore, it is a promising and widely applicable water shutoff agent for heavy oil reservoirs.",8,9,1
Heavy Oil,Degrees C,"Chen, Gang; Yuan, Weihua; Zhang, Fan; Gu, Xuefan; Du, Weichao; Zhang, Jie; Li, Jinling; Qu, Chengtun",Application of polymethacrylate from waste organic glass as a pour point depressor in heavy crude oil,Waste organic glass; Polymethyl methacrylate; Polymethacrylate; Crude oil; Pour point depressor,FLOW IMPROVER; ADDITIVES; WAX,"Polymethyl methacrylate (PMMA, organic glass) is widely used as a substitute for glass, known as organic glass. During the processing and after use, there are amount of castoff. Based on the similar framework, PMMA could be useful the feed stock to synthesis polymethacrylate (PMA) used for crude oil additive. In this work PMA was prepared by transesterification of PMMA and aliphatic alcohol catalyzed by a base. The performance of PMA on heavy oil was evaluated as pour point depressant as well as viscosity reducer. The highest pour point reduction depression was achieved as 7.1 degrees C with the dosage of 2000 ppm PMA-1. The viscosity of crude oil was also substantially reduced from 182000 mPa.s to 64500 mPa.s. Differential scanning calorimetry and paraffin crystal morphology studies were clearly reflected that PMA affects the wax crystallization of crude oil. Base on this work, the waste organic glass can be reused as a valuable material in oil field.",8,8,4
Heavy Oil,Degrees C,"Liu, Pengcheng; Yuan, Zhe; Zhang, Shengfei; Xu, Zhenhua; Li, Xiuluan",Experimental study of the steam distillation mechanism during the steam injection process for heavy oil recovery,Heavy oil; Steam distillation; Distillation rate; Superheated steam; Degree of superheating,SIMULATION; SOLVENT; DRIVE; FIELD,"Steam distillation can effectively enhance heavy oil recovery during steam injection process in heavy oil reservoirs. However, the mechanism of steam distillation is complex, and the changes in oil properties during distillation remain unclear. In this study, three comparative steam distillation experiments were designed and conducted, including distillation processes employing saturated steam, steam superheated by 10 degrees C, and steam superheated by 40 degrees C. Heavy oil samples were derived from the Jin-1 Block in a typical heavy oilfield, in China. The density, viscosity, SARA fractions, and carbon number distribution of the residual oil were compared to those obtained before conducting steam distillation experiments. The steam distillation rates obtained with steam superheated by 40 degrees C, steam superheated by 10 degrees C, and saturated steam were 11.158%, 10.903% and 10.423%, respectively. The results indicate that the steam distillation rate of heavy oil increases significantly with increasing degree of superheating. During the steam distillation process, the density and viscosity of residual oil increase, the contents of saturated hydrocarbons and resin decrease, and the contents of aromatic hydrocarbons and asphaltenes increase. In addition, analysis of the distilled components indicates that lightweight components with smaller carbon numbers are removed firstly by steam distillation, followed by heavier components with larger carbon numbers. Moreover, all hydrocarbons with carbon numbers less than C-22 are removed from heavy oil in the distillation process, while the maximum carbon number of the distilled components was C-34. This study is favorable for understanding the changes in the properties of residual oil after distillation during the steam injection process for heavy oil recovery.",8,8,7
Heavy Oil,Steam,"Mohammadzadeh, Omid; Giesy, John P.",The effect of IPC formulation on bitumen properties - An experimental study,,SA-SAGD PROCESS; HEAVY OIL; RECOVERY; STEAM,"Use of chemicals as an additive during steam-based bitumen recovery processes has been an active topic for research and development in the last four decades. In this study, thermo-physical properties of mixtures of bitumen with a newly developed chemical are reported. This new chemical technology (i.e. IPC as referred in this paper) is a proprietary mixture of surfactants that has been used in several techniques associated with surface extraction as well as in-situ recovery of heavy oil and bitumen. This formulation of solvents and surfactants is reusable, low foaming, non-flammable, not acutely toxic and non-carcinogenic. A series of tests were conducted to measure density and viscosity of a bitumen, IPC, and different mixtures of bitumen-IPC at several pressure, temperature and chemical composition conditions. It was observed that solubility of IPC in bitumen was small, and its effects on the oil phase viscosity and density could not be separated from its effects on bulk properties caused by dispersed emulsified droplets of IPC. The impact of IPC on viscosity of mixture was more pronounced than its effect on mixture density. A very complex emulsion was formed upon contact of IPC with bitumen. The results of these tests will be useful in designing a steam-based bitumen recovery process with IPC as the chemical additive. Details of thermal stability analysis of IPC are also presented.",0,0,0
Heavy Oil,Steam,"Borisov, D. N.; Tazeev, D. I.; Milordov, D. V.; Mironov, N. A.; Borisova, Y. Y.; Yakubov, M. R.; Beregovoy, A. N.; Amerkhanov, M. I.; Khisamov, R. S.",Physical modeling of the composite solvent injection to improve the ultra-viscous oil recovery efficiency steam-assisted gravity drainage,Ultra-viscous oil; Heavy oil; Solvent; Reservoir modeling; Thermal enhanced oil recovery techniques; Steam-assisted gravity drainage,ASPHALTENE PRECIPITATION; CRUDE OILS; AGGREGATION; PERFORMANCE; INHIBITION; RESERVOIRS; STABILITY; RESINS; CSI,"The experiments carried out on a physical model of reservoir of ultra-viscous oil have revealed features of oil displacement in various variants of the composite solvent and steam injection. In order to avoid precipitation of asphaltenes, the employment of inhibitors has been rationalized and their minimum fraction in displacement fluid has been determined. The effect of the sequence of solvent and vapor injection on the dynamics of ultra-viscous oil recovery has been investigated. The effect of clay and water in the rock on the rate of oil displacement and the ultimate oil recovery factor has been evaluated.",0,0,2
Heavy Oil,Steam,"Marotto, Tamires A.; Pires, Adolfo P.",Mathematical model for one-dimensional oil displacement by steam injection with solvent addition,Enhanced oil recovery; Thermal methods; Steam flooding; Solvent and steam co-injection,FRICTION THEORY; HOT FLUID,"Recently, co-injection of steam and solvent has shown to be an attractive technique to increase oil recovery, combining the advantages of viscosity reduction due to the heat transfer achieved from steam injection with the benefits of mass transfer obtained from miscible flooding. In this work, the problem of one-dimensional displacement of oil by steam injection combined with solvent is analyzed. The mathematical model is based on the mass conservation of components oil and solvent, and conservation of system energy. The solution, composed by shock and rarefaction waves and constant states, is obtained using the method of characteristics. Different solution structures were found for particular sets of reservoir-fluid system parameters, which are defined by the ratio between the value of Henry's constant and the system pressure. The results presented here may be used for fast and efficient evaluation of technical aspects of the best Enhanced Oil Recovery method for a particular field, specially for thin shallow viscous heavy oil reservoirs. This model is also useful for the development of streamlines simulators, where gravity and capillary effects are neglected.",3,3,1
Heavy Oil,Steam,"You, J.; Rahnema, H.",Numerical modeling of multiphase steam flow in wellbore,Thermal wellbore simulation; Unsteady state; Heat transmission; Steam injection; Multiphase flow,INJECTION WELLS; PRESSURE-DROP; RESERVOIR SIMULATION; HEAT TRANSMISSION; 2-PHASE FLOW; HOT-WATER; PREDICTION; LOSSES,"Steam injection is applied as a technique to extract heavy oil due to the fact that thermal energy carried by steam can heat reservoir and hence significantly lowering oil viscosity. One important thing in steam injection is to ensure more heat injected can reach perforation interval but not lost to surrounding formation when steam flows through wellbore tubing. In other words, steam quality is demanded to be as high as possible when steam reaches reservoir. In addition, more studies are required on unsteady state (transient) flowing process, since the rapid temperature and pressure change in unsteady state flowing process may make pipe components work under a severe condition and increasing the risk of mechanical damage. In this work, a fully-implicit numerical model is developed to predict steam quality, temperature and pressure profiles along a vertical steam injection well. The model includes wellbore section and surrounding formation and employing a heat transfer coefficient to calculate heat loss from wellbore to formation. In wellbore section, detailed mass balance equation, momentum balance equation and energy balance equation are utilized as governing equations and a drift-flux model is integrated to simulate the multiphase steam flow. Heat transmission inside formation section is expressed by a two-dimensional Fourier heat conduction equation. The whole system of differential equations are discretized by refined grids and solved implicitly by Newton-Rapson method. Formulation of complete governing equations (e.g. accumulation terms are not neglected) enables this mode can correctly simulates steam flowing in both unsteady state and steady state process. Simulation results are then compared with field data, which concludes that this numerical model is able to predict steam quality and pressure change along a vertical well and temperature variation inside tubing and within formation with high accuracy. This model is also applied under varying operational conditions to extend its feasibility to handle different problems. A multiple injection steam qualities case and a multiple injection rates case are studied and results indicate that this model can work under complex and variable operational constraints. This model is specifically designed to simulate steam injection cases with varying conditions, such as Cyclic Steam Stimulation (CSS). By using this model, better understanding can be obtained in how pressure/temperature and steam quality profiles change and it will assist engineers in well design and optimizing production operations.",4,4,1
Heavy Oil,Steam,"Akhmadiyarov, Aydar A.; Rakipov, Ilnaz T.; Khachatrian, Artashes A.; Petrov, Artem A.; Sitnov, Sergei A.; Gerasimov, Alexander V.; Osin, Yury N.; Varfolomeev, Mikhail A.",Thermocatalytic upgrading of heavy oil by iron oxides nanoparticles synthesized by oil-soluble precursors,Thermocatalytic upgrading; Heavy oil; Viscosity; Reservoir temperature and pressure; Catalysis,HIGH-TEMPERATURE; AQUATHERMOLYSIS; TETRAHYDROTHIOPHENE; CHEMISTRY; THIOPHENE; VISCOSITY; RECOVERY; MINERALS; SQUALANE; STEAM,"Thermocatalytic upgrading of heavy crude oil at reservoir temperature and pressure has been studied. The objective of the present work was to investigate the efficiency of the compounds based on iron (iron carbonyls, iron oxide, metallic iron) on thermocatalytic upgrading process of heavy crude oil at reservoir temperature and pressure (5.0 MPa and up to 523.15 K). The viscosity reducing was used as the main parameter for determination of the efficiency of thermocatalytic upgrading. The effect of structure of the catalyst precursor on the composition of SARA fractions after thermal catalytic upgrading of crude oil was analyzed. A destruction of mainly resin fraction was found to occur during thermocatalytic upgrading of heavy crude oil. The composition and structure of catalysts after crude oil upgrading were determined by the X-powder diffraction and SEM methods. An impact of catalyst (Fe3O4) particle size on the efficiency of crude oil thermocatalytic upgrading process was revealed.",4,5,4
Heavy Oil,Steam,"Leyva-Gomez, H.; Babadagli, Tayfun",Efficiency of heavy-oil/bitumen recovery from fractured carbonates by hot-solvent injection,Injection parameters optimization; Heavy oil; Hot solvent; Fractured carbonate reservoirs; Oil dilution,RESERVOIRS SOS-FR; OIL-RECOVERY; BITUMEN RECOVERY; ASPHALTENE DEPOSITION; VAPOR EXTRACTION; AIDED PROCESS; STEAM; SIMULATION; SANDS; PILOT,"This paper presents an extensive analysis of three different solvents injected through two different rock types under dynamic conditions, at elevated temperatures, to recover heavy-oil/bitumen from fractured carbonates. The main idea was to identify the optimal temperatures needed for maximal recovery by hot solvent injection for a wide range of solvents. We also considered the optimal conditions for effective solvent retrieval for the economics of this type recovery approach. In order to represent a wide range of carbon number solvents, heptane and naphtha were injected at atmospheric pressure and temperatures ranging from 70 to 120 degrees C and 21.5-100 degrees C, respectively. Propane was injected at a pressure of 1483-1511 kPa and a temperature ranging from 22 to 60 degrees C to be in the liquid phase. Indiana limestone (outcrop) and vuggy naturally fractured carbonate samples (outcrop core samples from a producing formation in Mexico) were selected as core samples. Hot solvent was injected continuously through artificially fractured cores followed by hot water (or steam injection) phase for solvent retrieval. The optimal temperatures for heavy oil recovery and solvent retrieval, in the subsequent hot water injection, for each kind of rock sample and type of solvent were determined. The results revealed that heavy oil recovery increase with the solvent carbon number used. Also, it was observed that when the temperature is higher than the saturation value for the given pressure curve, the recovery decreases and the lightest component of the heavy oil are dragged by the gas stream.",5,5,1
Heavy Oil,Steam,"Baek, Kwang Hoon; Arguelles-Vivas, Francisco J.; Okuno, Ryosuke; Sheng, Kai; Sharma, Himanshu; Weerasooriya, Upali P.",Emulsification of Athabasca bitumen by organic alkali: Emulsion phase behavior and viscosity for bitumen/brine/triethylenetetramine,Bitumen; Organic alkali; Natural surfactant; Emulsion phase behavior; Emulsion viscosity,HEAVY OIL-RECOVERY; IN-WATER EMULSIONS; CRUDE-OIL; PIPELINE TRANSPORTATION; NATURAL SURFACTANTS; ASPHALTENE RATIO; STEAM CHAMBER; STABILITY; RHEOLOGY; RESINS,"Recovery of bitumen commonly uses steam assisted-gravity drainage, in which water throughput is intrinsically high. A large amount of condensed water near thermal fronts tends to substantially decrease the effective permeability to bitumen in the conventional gravity drainage process. This research investigates a potential way to use the condensed-water phase as an effective carrier for bitumen by making oil-in-water (o/w) emulsion. The expected mechanism depends on emulsification of bitumen into the water phase by natural surfactants that are generated through reactions of acidic oil components with organic alkali. The main objective of this paper is to study the ability of an organic alkali to create o/w emulsions that are much more mobile than the original bitumen. Triethylenetetramine (TETA) was selected as organic alkali for this paper with no other additives. The main contribution of this paper is a new set of experimental data (phase behavior and viscosities) for emulsions for mixtures of Athabasca bitumen, TETA, and NaCl brine at a wide range of alkali concentrations, salinities, and water-to-oil ratios (WORs) M temperatures up to 373 K. Results show that the o/w emulsions created by TETA can be an effective bitumen carrier with a low viscosity and high bitumen content in the emulsion. It is possible to create o/w emulsions by adding a small amount of TETA to Athabasca bitumen and NaC1 brine. Single-phase o/w emulsions, which are desirable as a bitumen carrier, were observed for TETA concentrations below 5.0 wt% M salinities 0 ppm and 1000 ppm at 373 K. The bitumen content in o/w emulsion was the highest for 2.0 wt% TETA samples, and it increased with increasing temperature. In comparison to the original bitumen, o/w emulsions were 4-5 orders of magnitude less viscous at 298 K, 2 to 3 orders of magnitude less viscous at 323 K, and 1 to 2 orders of magnitude less viscous at 353 K.",5,6,2
Heavy Oil,Steam,"Yang, Shangyu; Han, Lihong; Feng, Chun; Wang, Hang; Feng, Yaorong; Wu, Xingru",Mechanical performance of casing in in-situ combustion thermal recovery,Casing performance; Heavy oil; In-situ combustion; Casing design; Steam flooding,OIL; WELLS,"In-situ combustion is often used to develop heavy oil as it has multiple advantages over alternative thermal methods. However, the wellbore integrity can be compromised if the casing is not properly designed or manufactured. Based on the fundamentals of heat transfer, a mathematical model with multiphysics is built to study the temperature and pressure distributions surrounding the wellbore during in-situ combustion. In laboratory, real casings and coupons with grades of N80, P110, and 3Cr110 were tested under high temperature to study their mechanical performances in the in-situ combustion recovery. From the modeling and laboratory testing results, we propose the casing design and manufacture protocols for thermal recovery of heavy oil. Field applications in Liaohe oil field, Du-66 Block, shows that the mechanical deterioration of P110 and 3Cr110 is less than that of N80 and the mechanical performance stability of 3Cr110 is better than others when the temperature is less than 600 degrees C. When the temperature is above 600 degrees C for more than 10 h, the mechanical performance of all casing grades declines quickly. Applying finite element analysis, we recommend a safety factor of 1.1 for designing casing at the temperatures of 250 degrees C,480 degrees C and 485 degrees C. The finding of this study provides fundamentals for the casing design and material selection for in-situ combustion recovery.",6,6,0
Heavy Oil,Steam,"Guo, Yujia; Roostaei, Morteza; Nouri, Alireza; Fattahpour, Vahidoddin; Mahmoudi, Mahdi; Jung, Heeseok",Effect of stress build-up around standalone screens on the screen performance in SAGD wells,SAGD; Sand retention test; Slotted liner; Sand control,OIL,"Steam Assisted Gravity Drainage (SAGD) is the primary thermal recovery technology currently employed to extract heavy oil and high-viscosity bitumen from Alberta oil sands. In the near-wellbore region, the initial stresses are nearly zero, and as the SAGD chamber grows, the stresses tend to build up due to the thermal expansion of the formation. Also, melting of the bitumen and subsequent loss of the bonding between the grains leads to the collapse of the gap between the formation and sand control liner over time. The result will be effective stress buildup and gradual compaction of the oil sands around the liner. Slotted liners have been extensively used as a sand control device in SAGD wells. Slotted liners must allow free flow through the slots with minimal plugging and acceptable amounts of sand production. In our study, large-scale unconsolidated sand was packed over a multi-slot coupon of the slotted liner. The sand-pack was subjected to several stress conditions corresponding to the evolving stress conditions during the life cycle of a SAGD producer well. The testing program employed several multi-slot coupons to examine the flow performance under typical encountered stresses in SAGD wells. Cumulative produced sand was measured at the end of testing as an indicator of the sand control performance. The permeability evolution of the sand in the near-coupon zone was calculated by measurements of pressure differentials and considered as a measure of screen flow performance. Fines/clay concentration along the sand-pack was also quantified after the test to investigate the fines migration, a phenomenon which is considered to be the main reason for reduced wellbore productivity. Experimental results show that the liner performance is significantly affected by the normal stress buildup on the liner. Experimental observations indicate sand-pack compaction due to the increase of effective stress around the liner leads to a lower porosity and permeability. The situation near the liner is further complicated by the fines accumulation that results in pore plugging and further permeability reduction. When it comes to sanding, however, higher stresses help stabilize the sand bridges behind the slots, leading to less sand production. As for the design criteria, the lower and upper bounds of the slot size are governed by plugging and sand production, respectively. Considering the stress effect on plugging and sanding, testing data indicate that both the lower and upper bounds should be revised to larger slot aperture sizes.",8,8,2
Heavy Oil,Steam,"Liu, Pengcheng; Yuan, Zhe; Zhang, Shengfei; Xu, Zhenhua; Li, Xiuluan",Experimental study of the steam distillation mechanism during the steam injection process for heavy oil recovery,Heavy oil; Steam distillation; Distillation rate; Superheated steam; Degree of superheating,SIMULATION; SOLVENT; DRIVE; FIELD,"Steam distillation can effectively enhance heavy oil recovery during steam injection process in heavy oil reservoirs. However, the mechanism of steam distillation is complex, and the changes in oil properties during distillation remain unclear. In this study, three comparative steam distillation experiments were designed and conducted, including distillation processes employing saturated steam, steam superheated by 10 degrees C, and steam superheated by 40 degrees C. Heavy oil samples were derived from the Jin-1 Block in a typical heavy oilfield, in China. The density, viscosity, SARA fractions, and carbon number distribution of the residual oil were compared to those obtained before conducting steam distillation experiments. The steam distillation rates obtained with steam superheated by 40 degrees C, steam superheated by 10 degrees C, and saturated steam were 11.158%, 10.903% and 10.423%, respectively. The results indicate that the steam distillation rate of heavy oil increases significantly with increasing degree of superheating. During the steam distillation process, the density and viscosity of residual oil increase, the contents of saturated hydrocarbons and resin decrease, and the contents of aromatic hydrocarbons and asphaltenes increase. In addition, analysis of the distilled components indicates that lightweight components with smaller carbon numbers are removed firstly by steam distillation, followed by heavier components with larger carbon numbers. Moreover, all hydrocarbons with carbon numbers less than C-22 are removed from heavy oil in the distillation process, while the maximum carbon number of the distilled components was C-34. This study is favorable for understanding the changes in the properties of residual oil after distillation during the steam injection process for heavy oil recovery.",8,8,7
Heavy Oil,Enhanced Oil-recovery,"Borisov, D. N.; Tazeev, D. I.; Milordov, D. V.; Mironov, N. A.; Borisova, Y. Y.; Yakubov, M. R.; Beregovoy, A. N.; Amerkhanov, M. I.; Khisamov, R. S.",Physical modeling of the composite solvent injection to improve the ultra-viscous oil recovery efficiency steam-assisted gravity drainage,Ultra-viscous oil; Heavy oil; Solvent; Reservoir modeling; Thermal enhanced oil recovery techniques; Steam-assisted gravity drainage,ASPHALTENE PRECIPITATION; CRUDE OILS; AGGREGATION; PERFORMANCE; INHIBITION; RESERVOIRS; STABILITY; RESINS; CSI,"The experiments carried out on a physical model of reservoir of ultra-viscous oil have revealed features of oil displacement in various variants of the composite solvent and steam injection. In order to avoid precipitation of asphaltenes, the employment of inhibitors has been rationalized and their minimum fraction in displacement fluid has been determined. The effect of the sequence of solvent and vapor injection on the dynamics of ultra-viscous oil recovery has been investigated. The effect of clay and water in the rock on the rate of oil displacement and the ultimate oil recovery factor has been evaluated.",0,0,2
Heavy Oil,Enhanced Oil-recovery,"Zhao, Renbao; Li, Bochun; Yang, Xiaoying; Yang, Jie; Yu, Shuai; Jin, Jun; Zhang, Jianhua",Analysis of a feasible field THAI pattern by the derivation of scaling criteria and combustion experiments,In-situ combustion; Toe-to-heel air injection process; Scaling criteria; Three dimensional cylindrical model,HEAVY OIL; SIMULATION,"Toe-to-heel air injection (THAI) process is considered as a potential enhanced oil recovery (EOR) method for heavy oil production. For physical simulation of THAI process in laboratory conditions, the simplified scaling criteria of THAI process were derived and a novel three-dimensional cylindrical apparatus was used to construct the new THAI pattern in this study. Equation analysis and dimensional analysis (Buckingham at-theorem) were applied to deduce the whole dimensionless groups, and sensitivity of the coefficients described with their distortion coefficients were used to obtain the influential weights and the simplified scaling criteria. STARS module in Computer Modeling Group (CMG) was used to verify the feasibility of the THAI pattern by two models, which represent the reservoir prototype and the 3D apparatus respectively. With an effective simulation of experimental results, a reasonable data set was obtained, and then those values were upscaled for simulation of field THAI process by the simplified scaling criteria. The experiment results showed that the horizontal well was well protected by a slant distribution of coke zone and the other parameters about oil production (such as the high temperature swept volume, oil production rate and recovery) were still satisfactory. The similarity of variation process of temperature field, oil saturation distribution and production performance between the laboratory results and THAI simulation in reservoir prototype showed the validity of the scaling criteria and indicated that a feasible field THAI process with a large combustion chamber upon horizontal well can be predicted to achieve.",0,0,3
Heavy Oil,Enhanced Oil-recovery,"Ma, Hongze; Yu, Gaoming; She, Yuehui; Gu, Yongan",A new hybrid production optimization algorithm for the combined CO2-cyclic solvent injection (CO2-CSI) and water/gas flooding in the post-CHOPS reservoirs,Well-control optimization; Steepest ascent-particle swarm optimization (SA-PSO); CO2-Cyclic solvent injection (CO2-CSI); CHOPS reservoir; Foamy-oil flow,PARTICLE SWARM OPTIMIZATION; HEAVY OIL PRODUCTION; RECOVERY; MODEL,"In this paper, a new hybrid production optimization algorithm, namely, the steepest ascent. particle swarm optimization (SA. PSO), is developed to optimize the combined CO2-cyclic solvent injection (CO2-CSI) and waterflooding (WF) or gasflooding (GF) in the post cold heavy oil production with sand (CHOPS) reservoirs. The field-scale CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF performances are predicted by upscaling the laboratory tests and using the numerical simulations with the considerations of the wormholes propagation and foamy-oil flow. The net present value (NPV) is chosen as an objective function and maximized by adjusting the well controls, such as the bottom-hole pressure (BHP) and water/gas injection rate. The efficacies of the following three optimization methods are evaluated and compared: the steepest ascent (SA) method, particle swarm optimization (PSO), and SA-PSO. It is found that the SA. PSO gives a higher global optimum NPV than the SA algorithm and requires fewer numerical simulation runs than the PSO. It combines the fast convergence of the SA algorithm and the global search of the PSO. It is also found that the CO2-CSI + GF has the highest NPV in the post-CHOPS reservoir among the three enhanced oil recovery (EOR) processes. For the CO2-CSI + GF, the gas injector should inject CO2 at the highest injection rate during the early cycles to displace the foamy oil but should be shut in during the late cycles to control the gas channeling. The optimum NPVs of the CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF are achieved when the BHPs of the producers are maintained at the lowest pressure. It is uneconomical to apply the WF immediately after the CO2-CSI due to the early water breakthrough.",1,1,3
Heavy Oil,Enhanced Oil-recovery,"Marotto, Tamires A.; Pires, Adolfo P.",Mathematical model for one-dimensional oil displacement by steam injection with solvent addition,Enhanced oil recovery; Thermal methods; Steam flooding; Solvent and steam co-injection,FRICTION THEORY; HOT FLUID,"Recently, co-injection of steam and solvent has shown to be an attractive technique to increase oil recovery, combining the advantages of viscosity reduction due to the heat transfer achieved from steam injection with the benefits of mass transfer obtained from miscible flooding. In this work, the problem of one-dimensional displacement of oil by steam injection combined with solvent is analyzed. The mathematical model is based on the mass conservation of components oil and solvent, and conservation of system energy. The solution, composed by shock and rarefaction waves and constant states, is obtained using the method of characteristics. Different solution structures were found for particular sets of reservoir-fluid system parameters, which are defined by the ratio between the value of Henry's constant and the system pressure. The results presented here may be used for fast and efficient evaluation of technical aspects of the best Enhanced Oil Recovery method for a particular field, specially for thin shallow viscous heavy oil reservoirs. This model is also useful for the development of streamlines simulators, where gravity and capillary effects are neglected.",3,3,1
Heavy Oil,Enhanced Oil-recovery,"Ansah, Eric O.; Sugai, Yuichi; Nguele, Ronald; Sasaki, Kyuro",Integrated microbial enhanced oil recovery (MEOR) simulation: Main influencing parameters and uncertainty assessment,Artificial intelligence; Capillary number; Enthalpy; Microbial enhanced oil recovery; Monte Carlo simulation; Response surface methodology,HEAVY OIL; TEMPERATURE; RESERVOIR; GROWTH; MECHANISMS; BACTERIA; FIELD,"The present study investigated the ability of a thermophilic anaerobic microbe (herein coded as AR80) for MEOR with the further objective to quantify the uncertainty of production forecast in terms of the cumulative probability distribution. A series of core flood experiments conducted in water-flooded Berea sandstone showed that up to 51% of initial oil-in-place was recovered when the plugs were treated with AR80 and shut-in for 14 days. Mainly, the oil recovery mechanisms were attributed to viscosity enhancement, wettability changes, permeability and flow effects. Matching the laboratory data using artificial intelligence: the optimized cumulative oil recovery could be achieved at an enthalpy of 894.2 J/gmol, Arrhenius frequency of 8.3, residual oil saturation of 20%, log of capillary number at microbe flooding stage of -1.26, and also depicted a history match error less than 3%. Therefrom, a sensitivity analysis conducted on reservoir shut-in period effect on oil recovery revealed that a relatively shorter shut-in period is recommended to warrant early incremental oil recovery effect for economical purposes. In addition, MEOR could enhance the oil recovery significantly if a larger capillary number (between 10(-5) and 10(-3.5)) is attained. Per probabilistic estimation, MEOR could sustain already water-flooded well for a set period of time. This study showed that there is a 20% frequency of increasing the oil recovery by above 20% when a mature water-flooded reservoir is further flooded with AR80 for 2 additional years. Lastly, it was demonstrated herein that increasing the nutrient (yeast extract) concentration (from 0.1 to 1% weight) had less or no significant effect on the oil viscosity and subsequent recovery.",4,4,0
Heavy Oil,Enhanced Oil-recovery,"Yoo, Kuy Hun Koh; Sampaio, Luiz Bittencourt; Gerritsen, Margot; Kovscek, Anthony R.",An optimization algorithm for evaluation of kinetic parameters for crude oil combustion,In situ combustion; Ramped temperature oxidation; Oxidation kinetics,IN-SITU-COMBUSTION; FIELD-SCALE; PREDICTABILITY,"The design of enhanced oil recovery processes that employ in-situ combustion requires high-fidelity simulation models that accurately describe the physics and chemistry of reactive, exothermic multiphase fluid flow. Therefore, a detailed description of oil combustion kinetics is required. The goal of this work is to present and apply a workflow to define and match pseudo-kinetic reaction models based on Arrhenius kinetics. These models are meant to be used at the laboratory scale with high-resolution, fully-resolved simulation models as a tool to generate high density data required by upscaled models at reservoir scale. The workflow starts by performing ramped temperature oxidation (RTO) experiments for a wide range of heating rates. New experimental equipment has allowed us to obtain data for large heating rates (>15 degrees C/min) that were not achievable in the past. A subset of the experiments are selected to match the oxygen consumption curves by tuning kinetic parameters of several global reaction models using pattern search optimization. Those models that obtain a match are validated by predicting a second subset of the data that was not considered during the optimization. The workflow is tested using a heavy oil and two satisfactory matches with two different global reaction models are obtained.",4,4,0
Heavy Oil,Enhanced Oil-recovery,"Lele, Pushan; Syed, Abdul Haseeb; Riordon, Jason; Mosavat, Nader; Guerrero, Adriana; Fadaei, Hossein; Sinton, David",Deformation of microdroplets in crude oil for rapid screening of enhanced oil recovery additives,EOR; Droplet deformation; Heavy oil; Interfacial tension; Alkaline flooding,INTERFACIAL-TENSION MEASUREMENT; MICROFLUIDICS-BASED MEASUREMENT; ASSISTED GRAVITY DRAINAGE; ON-A-CHIP; HEAVY OIL; IONIC-STRENGTH; SURFACTANT SOLUTIONS; BITUMEN EXTRACTION; SAGD PROCESSES; SYSTEMS,"We present a microfluidic method to rapidly screen enhanced oil recovery additives based on the deformation of aqueous microdroplets in oil. Conventional methods, such as the pendant drop method, are hindered by large fluid volumes that require several hours to thermally equilibrate between measurements. Here we demonstrate a complementary technology to conventional methods, by which additives can be rapidly screened to select the best candidates for further study. Our glass chip establishes thermal equilibrium (demonstrated at 80 degrees C) of undiluted, highly viscous, crude oil within seconds, and enables the rapid quantification of water-in-crude oil droplet deformation within minutes, at a reservoir-relevant scale. The influence of two alkaline additives, a surfactant and a salt in the injected water phase were quantified, demonstrating the applicability of our method to a variety of recovery strategies.",5,5,2
Heavy Oil,Enhanced Oil-recovery,"Lamas, Luis Fernando; Botechia, Vinicius Eduardo; Correia, Manuel Gomes; Schiozer, Denis Jose; Delshad, Mojdeh",Influence of polymer properties on selection of production strategy for a heavy oil field,Polymer flooding; Production strategy selection; Reservoir numerical simulation; Reservoir engineering; Chemical enhanced oil recovery; Reservoir management,,"Polymer flooding is an enhanced oil recovery method (EOR) where water-soluble polymer is added to the injection brine. This increases brine viscosity and reduces water mobility, aiming to increase volumetric sweep and thus oil recovery. Selection and development of a production strategy for oil field is a complex task. Polymer properties bring additional complexity to this process and it is important that each of them is properly treated and considered. This paper discusses the selection of production strategy considering different approaches: (1) water flooding, (2) ideal polymer (only viscosifying effect of polymer) and (3) polymer flooding, including separately four of the most influencing polymer properties i.e. retention, viscoelasticity, salinity and degradation. The analysis is extended to a probabilistic point of view, where scenarios were generated combining geological and polymer uncertainties. Selected production strategies are compared to quantify the impact of each property on field indicators. Comparisons were made in terms of net present value (NPV), produced oil, injected and produced water, oil recovery factor and polymer mass. Two different situations were considered: (1) to optimize considering each property since beginning (design thorn control variables, meaning development, and management stages) and (2) considering design variables (development stage) for ideal polymer, optimizing only control variables (management stage) for each property. The methodology is applied to a synthetic field, based on characteristics of an offshore field with high permeability (similar to 1 000 mD) and containing heavy and viscous oil (similar to 100 cP, 14 degrees API). Ranking the properties according to overall impact on the project NPV, it was found the impact of each variable in a descending order: degradation, salinity, viscoelasticity, and retention. Water and ideal polymer strategies limit indicators results, giving an idea of the performance of strategies. Considering the key polymer properties from the beginning of optimization process resulted in similar values in terms of NPV when compared with strategies that considered ideal polymer in the selection of project variables. Risk curves show that conclusions can be extended to a probabilistic point of view. The results allow a comprehensive understanding of the influence of each polymer property on selection of production strategy considering uncertainties. The results also show that it is possible to select a good strategy using Ideal polymer model. Finally, results show that strategies selected for water and for ideal polymer model act as lower and upper limits of performance for the field, giving valuable information to the decision maker, even before accurate data about polymer is available.",6,6,2
Heavy Oil,Enhanced Oil-recovery,"Liu, Pengcheng; Yuan, Zhe; Zhang, Shengfei; Xu, Zhenhua; Li, Xiuluan",Experimental study of the steam distillation mechanism during the steam injection process for heavy oil recovery,Heavy oil; Steam distillation; Distillation rate; Superheated steam; Degree of superheating,SIMULATION; SOLVENT; DRIVE; FIELD,"Steam distillation can effectively enhance heavy oil recovery during steam injection process in heavy oil reservoirs. However, the mechanism of steam distillation is complex, and the changes in oil properties during distillation remain unclear. In this study, three comparative steam distillation experiments were designed and conducted, including distillation processes employing saturated steam, steam superheated by 10 degrees C, and steam superheated by 40 degrees C. Heavy oil samples were derived from the Jin-1 Block in a typical heavy oilfield, in China. The density, viscosity, SARA fractions, and carbon number distribution of the residual oil were compared to those obtained before conducting steam distillation experiments. The steam distillation rates obtained with steam superheated by 40 degrees C, steam superheated by 10 degrees C, and saturated steam were 11.158%, 10.903% and 10.423%, respectively. The results indicate that the steam distillation rate of heavy oil increases significantly with increasing degree of superheating. During the steam distillation process, the density and viscosity of residual oil increase, the contents of saturated hydrocarbons and resin decrease, and the contents of aromatic hydrocarbons and asphaltenes increase. In addition, analysis of the distilled components indicates that lightweight components with smaller carbon numbers are removed firstly by steam distillation, followed by heavier components with larger carbon numbers. Moreover, all hydrocarbons with carbon numbers less than C-22 are removed from heavy oil in the distillation process, while the maximum carbon number of the distilled components was C-34. This study is favorable for understanding the changes in the properties of residual oil after distillation during the steam injection process for heavy oil recovery.",8,8,7
Heavy Oil,Gas,"Zhang, Boyang; Daigle, Hugh",Oil-soluble contrast agents for NMR,NMR; Relaxation; Contrast agents; Hydrophobic; Fluid typing,IRON-OXIDE NANOPARTICLES; THERMAL-STABILITY; ADSORPTION; SILICA; SPIONS,"In well logging applications, nuclear magnetic resonance (NMR) is recognized as a powerful tool to differentiate various fluids inside porous media. However, it can be challenging to do so in complex situations, e.g. when fluid peaks overlap with each other. Water-soluble contrast agents, such as MnCl2 or Gd-EDTA, have been proposed for use to accelerate the water relaxation, thus separating the water signal from those of other fluids. Together with these contrast agents, the log-inject-log method is used and the difference between the two logs is attributed to the doped water phase. This application only works with water-based mud. To extend its use to oil-based mud (OBM), it is desirable to find alternatives to water-soluble contrast agents that are compatible with OBM. In this work, we introduce a new group of doping agents: oil-soluble contrast agents. We selected several iron-based complex compounds that are oil-soluble, and tested and evaluated their effects on oil signal relaxation using a laboratory NMR apparatus. We also tested hydrophobic iron oxide nanoparticles as a contrast agent. The results showed that both the complex compounds and nanoparticles were able to reduce the transverse relaxation time of oil from longer than 2 s to less than 20 ms. To demonstrate their applicability in porous media, we injected doped oil into gas-saturated Berea sandstone and limestone core plugs. With conventional 1D NMR measurements or the use of water-soluble contrast agents, it is not straightforward to discern the gas signal from the OBM signal. Our experiments showed that the gas signal could be easily identified in the presence of doped oil via simple T-2 scans. We also performed experiments to demonstrate that the peaks of water and doped oil could be readily differentiated. The use of oil-soluble doping agents can significantly enhance the contrast of the NMR signals originated from different formation fluids, thus facilitating the fluid typing process. It provides a key alternative to the current water-doping technique. It is particularly advantageous when changing the oil relaxation is desired, such as for eliminating signal interferences from OBM invasion and differentiating heavy oil from clay-bound water. It also provides the possibility of speeding up the logging process by dramatically reducing the oil relaxation time. In addition, they can be employed in the laboratory for various purposes such as water saturation determination and fluid displacement monitoring. These contrast agents can also be of useful when oil-soluble contrast agents are desired in other fields, such as medical imaging applications.",1,1,1
Heavy Oil,Gas,"Ma, Hongze; Yu, Gaoming; She, Yuehui; Gu, Yongan",A new hybrid production optimization algorithm for the combined CO2-cyclic solvent injection (CO2-CSI) and water/gas flooding in the post-CHOPS reservoirs,Well-control optimization; Steepest ascent-particle swarm optimization (SA-PSO); CO2-Cyclic solvent injection (CO2-CSI); CHOPS reservoir; Foamy-oil flow,PARTICLE SWARM OPTIMIZATION; HEAVY OIL PRODUCTION; RECOVERY; MODEL,"In this paper, a new hybrid production optimization algorithm, namely, the steepest ascent. particle swarm optimization (SA. PSO), is developed to optimize the combined CO2-cyclic solvent injection (CO2-CSI) and waterflooding (WF) or gasflooding (GF) in the post cold heavy oil production with sand (CHOPS) reservoirs. The field-scale CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF performances are predicted by upscaling the laboratory tests and using the numerical simulations with the considerations of the wormholes propagation and foamy-oil flow. The net present value (NPV) is chosen as an objective function and maximized by adjusting the well controls, such as the bottom-hole pressure (BHP) and water/gas injection rate. The efficacies of the following three optimization methods are evaluated and compared: the steepest ascent (SA) method, particle swarm optimization (PSO), and SA-PSO. It is found that the SA. PSO gives a higher global optimum NPV than the SA algorithm and requires fewer numerical simulation runs than the PSO. It combines the fast convergence of the SA algorithm and the global search of the PSO. It is also found that the CO2-CSI + GF has the highest NPV in the post-CHOPS reservoir among the three enhanced oil recovery (EOR) processes. For the CO2-CSI + GF, the gas injector should inject CO2 at the highest injection rate during the early cycles to displace the foamy oil but should be shut in during the late cycles to control the gas channeling. The optimum NPVs of the CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF are achieved when the BHPs of the producers are maintained at the lowest pressure. It is uneconomical to apply the WF immediately after the CO2-CSI due to the early water breakthrough.",1,1,3
Heavy Oil,Gas,"Brito, Adriana; Guzman, Nolides; Rojas-Solorzano, Luis; Zambrano, Tibisay",Rheological study of two- and three-phase highly viscous fluid flow in pipelines,Foam rheology; Foamed emulsion; Two-phase flow; Three-phase flow; Flow patterns; Pressure drop model,GAS-LIQUID FLOW; HORIZONTAL PIPES; 2-PHASE FLOW; FOAMS; TRANSPORT; STABILITY,"The study of highly viscous multiphase flow systems is of fundamental interest in the oil industry. Most of the Venezuelan oil fields produce heavy oil with other production fluids, such as water and gas, and sand particles flowing from the reservoir to the surface facilities. A fraction of these phases flows fully separated, while another one flows as a dispersed system composed by water/oil emulsion with gas bubbles dispersed as a foamed emulsion. With the objective to understand and characterize this latter complex system, new experiments have been performed in 0.0243-m and 0.0508-m horizontal pipelines, for air/highly-viscous oil of 0.430 Pa s at 20 degrees C, and water/air/oil mixture with a water-in-oil emulsion of 0.560 Pa s at 20 degrees C. The three-phase flow pressure gradient was found to be approximately 15% higher than for the two-phase system, at similar gas and liquid superficial velocities. The air/oil and air/oil/water foamed emulsion behaved as non-Newtonian fluids, when these are considered as pseudo-homogeneous systems. A model to predict the flow pattern and pressure drop in horizontal pipelines was developed with an extensive database of 2167 experimental points, including new data and information collected and processed from different sources. A performance factor of 0.41 for Brito's three-phase (TM) model was consistently better than the performance factor obtained for other models commonly used by the oil and gas industry in similar multiphase flow systems.",3,3,0
Heavy Oil,Gas,"Wang, Kongyang; Yan, Wei; Deng, Jingen; Tian, Hao; Li, Wenbo; Wang, Yangang; Wang, Luyao; Ye, Sutao",Experimental study on H2S and CO2 generation capacities of the Bohai bay heavy oil,Heavy oil; Thermal recovery; Pyrolysis; H2S and CO2 generation; Partial pressure,CYMBOPOGON FLEXUOSUS BIOFUEL; FIREFLOOD FIELD PROJECTS; DIESEL-ENGINE; EMISSION CHARACTERISTICS; RECOVERY STRATEGIES; GRAVITY DRAINAGE; BIODIESEL BLEND; PERFORMANCE; COMBUSTION; RESERVOIRS,"Thermal recovery is a conventional technology for heavy oil development. During thermal oil recovery the reservoir could generate H2S and CO2. They will potentially threat the safety of downhole tubing regarding the sweet or sour corrosion. In some Bohai heavy oil fields CO2 and H2S under thermal recovery conditions lead to some corrosion problems of the tubing and equipment. Therefore, to determine the corrosive gas generation capacity is crucial for anti-corrosion design of downhole tubing and casing. Heavy oil samples from Bohai, China were experimentally studied for their pyrolysis characteristics using high-temperature-high-pressure autoclaves. The gases were collected when autoclaves cooled down to the in situ formation temperature. Effects of temperature, water chemistry and core mineral on corrosive gas generation were investigated. The results show that total pressure increase significantly when temperature reached 250 degrees C-280 degrees C under the single heavy oil condition. The additional water facilitates the reaction process, after more SO42- added in the mimic formation water, higher H2S content is obtained. Under the condition of multiphase of oil, formation water and cores, both of the H2S and CO2 content increase obviously, and the cores' effect on CO2 is greater than H2S. Anti-corrosion design usually concerns only the highest corrosive gas concentration without further analysis. The highest concentration does not always correspond to the best corrosive gases generation capacities of heavy oil. Comprehensive analysis of both the total pressure of reaction process and the quality of the reaction heavy oil is carried out, then the corrosive gases volume per unit mass of heavy oil is calculated. These can determine the strongest corrosive formation environment and the maximum gases generation capacities of heavy oil.",4,4,3
Heavy Oil,Gas,"Babadagli, T.; Cao, N.",Can water-alternating-solvent injection be an option for efficient heavy-oil recovery?: An experimental analysis for different reservoir conditions,Heavy-oil recovery optimization; Solvent injection; WAG design; Injection sequence and slug size; Wettability,VAPOR EXTRACTION,"We performed a set of experiments on vertically situated sandpack models. Different slug sizes of water and solvent (heptane used in the experiments) were tested for 2000 cp heavy-oil. As a benchmark, tests were also performed for 14 cp light oil for comparative analysis. In addition to the technical feasibility, an economic analysis was performed considering the amount of solvent injected and oil and solvent recovered. Experiments were repeated for oil-wet systems. For both light and heavy oils, starting the process with the solvent was feasible in the short run technically and economically. If the process starts with water, excess amount of it occupies the largest pores and hinders solvent-oil interaction for mixing and oil displacement. This was true especially if the rock is oil-wet and oil is heavy, which yielded faster recovery and higher ultimate recovery than the water-wet case. The time for switching to solvent injection is more critical in the heavy-oil case as it is more sensitive to the amount of existing water in the system. As oil becomes heavier and if the rock is water-wet, starting the process with waterflooding is not suggested. In this case, more solvent needs to be injected in the first cycle compared to oil-wet systems. Due to partial miscibility and more gravity stable nature, solvent retrieval and sweep with water can be more effective in case of heavy-oil compared to light oil (fully miscible case) and, as a result, can be even more profitable. This is highly critical in exploitation of heavy-oil reservoirs if thermal options are limited and greenhouse gas emission is a concern.",4,4,3
Heavy Oil,Gas,"Leyva-Gomez, H.; Babadagli, Tayfun",Efficiency of heavy-oil/bitumen recovery from fractured carbonates by hot-solvent injection,Injection parameters optimization; Heavy oil; Hot solvent; Fractured carbonate reservoirs; Oil dilution,RESERVOIRS SOS-FR; OIL-RECOVERY; BITUMEN RECOVERY; ASPHALTENE DEPOSITION; VAPOR EXTRACTION; AIDED PROCESS; STEAM; SIMULATION; SANDS; PILOT,"This paper presents an extensive analysis of three different solvents injected through two different rock types under dynamic conditions, at elevated temperatures, to recover heavy-oil/bitumen from fractured carbonates. The main idea was to identify the optimal temperatures needed for maximal recovery by hot solvent injection for a wide range of solvents. We also considered the optimal conditions for effective solvent retrieval for the economics of this type recovery approach. In order to represent a wide range of carbon number solvents, heptane and naphtha were injected at atmospheric pressure and temperatures ranging from 70 to 120 degrees C and 21.5-100 degrees C, respectively. Propane was injected at a pressure of 1483-1511 kPa and a temperature ranging from 22 to 60 degrees C to be in the liquid phase. Indiana limestone (outcrop) and vuggy naturally fractured carbonate samples (outcrop core samples from a producing formation in Mexico) were selected as core samples. Hot solvent was injected continuously through artificially fractured cores followed by hot water (or steam injection) phase for solvent retrieval. The optimal temperatures for heavy oil recovery and solvent retrieval, in the subsequent hot water injection, for each kind of rock sample and type of solvent were determined. The results revealed that heavy oil recovery increase with the solvent carbon number used. Also, it was observed that when the temperature is higher than the saturation value for the given pressure curve, the recovery decreases and the lightest component of the heavy oil are dragged by the gas stream.",5,5,1
Heavy Oil,Gas,"Lee, Kyung Jae; Finsterle, Stefan; Moridis, George J.",Analyzing the impact of reaction models on the production of hydrocarbons from thermally upgraded oil shales,In-situ upgrading; Oil shale; Numerical simulation; Sensitivity analysis; Uncertainty prediction; Data-worth analysis,SIMPLE KINETIC-MODELS; NUMERICAL-SIMULATION; PETROLEUM FORMATION; GAS GENERATION; POROUS-MEDIA; EXPULSION; CRACKING; EQUATION,"Reaction parameters significantly affect oil production from shales by means of heating and in-situ upgrading. In this study, we perform numerical simulations of two chemical reaction models, which are mainly used in the research of kerogen pyrolysis and subsequent hydrocarbon decomposition in organic-rich porous media. They are the Braun and Burnham model and Wellington model. In these forward numerical simulations, we present the influence of the two reaction models on hydrocarbon production. The Braun and Burnham reaction model shows more vigorous kerogen and subsequent decomposition reactions and more hydrocarbon production than the Wellington model. A local sensitivity analysis identifies the reaction parameters with the highest influence on productivity, and the most sensitive outputs. A data-worth analysis identifies the most valuable observation data to be measured for the best prediction of total hydrocarbon production. We find that the most valuable observation data is the cumulative production of heavy oil in the Braun and Burnham model and of light oil in the Wellington model, respectively. Once we determine the maximum allowable prediction uncertainty and the expected measurement uncertainty, the observation data to be measured for the minimization of prediction uncertainty can be obtained.",6,6,0
Heavy Oil,Gas,"Soh, Ye Ji; Babadagli, Tayfun",Use of air to improve the efficiency of foamy flow and reservoir pressurization in heavy oil recovery,Cyclic solvent injection; Post-CHOPS EOR; Methane and CO2; Air injection; Foamy oil corefloods,INJECTION; TEMPERATURE,"Primary recovery of heavy-oil is remarkably low due to high viscosity and low energy by solution gas exsolution to drive the oil. Gas injection to improve foamy flow and also to dilute the oil in such reservoirs has been proposed as a secondary recovery method. However, because of the high costs of injected gases, efforts are needed to optimize the process by selection of proper gas type (or gas combinations) and suitable injection scheme. To achieve this goal, an experimental procedure was followed with rigorous analyses of the output. A 1.5m long and 5 cm diameter sand-pack was first saturated with brine, which was replaced with dead oil. Then, gas solvents were injected to dead-oil containing core-holder until nearly reaching 500 psi followed by a two-day soaking period. Pressures all along the sand-pack were recorded with eight pressure transducers. Different combinations of various gas solvents (methane, CO2, and air) aiming to select the most competitive and economic formula were tested with a certain set of pressure depletion rates. The physics of the foamy oil flow for different solvent mixtures and depletion conditions were analyzed using pressure profiles acquired, recorded oil/gas data with time, and gas chromatography and SARA analyses of the produced gas and oil. Three huff-n-puff cycles were applied. Compared with other light hydrocarbon solvents and carbon dioxide, air has a significant advantage in terms of accessibility and lowered cost. Hence, attention was given to air mainly used to pressurize the system and increase oil viscosity due to oxidation process with an expectation of better foam quality when injected with other gases such as CO2 and methane. Methane (CH4) yielded the quickest response in terms of gas drive but, in the long run, CO2 was observed to be more effective technically. Air was observed to be effective if mixed with CO2 or methane from an economics point of view. To sum up the results, air Huff-n-Puff (HnP) followed by 2-cycles of CH4 HnP yielded 36.21% recovery, while air HnP followed by 2-cycles of CO2 HnP delivered 30.36% oil. When the gases are co-injected, air 50%-CO2 50% and air 50%-CH4 50% recovered 29.85% and 23.74% of total oil-in-place, respectively.",6,6,0
Heavy Oil,Gas,"Sadi, Maryam; Shahrabadi, Abbas",Evolving robust intelligent model based on group method of data handling technique optimized by genetic algorithm to predict asphaltene precipitation,Asphaltene precipitation; Group method of data handling; Genetic algorithm; SARA fractions; Leverage approach,FUZZY INFERENCE SYSTEM; GMDH NEURAL-NETWORK; GAS INJECTION; NATURAL DEPLETION; SCALING EQUATION; HEAVY OILS; DEPOSITION; EQUILIBRIUM; PRESSURE; FLOCCULATION,"Precipitation of asphaltene during primary production of hydrocarbon reservoirs leads to formation damage and well bore plugging. Therefore, proposing an accurate model to estimate asphaltene precipitation under various operating and thermodynamic conditions are crucial. In this study, a new mathematical model based on the integrating group method of data handling (GMDH) with genetic algorithm has been developed to predict asphaltene precipitation as a function of reservoir pressure and temperature, crude oil API, bubble point pressure, Saturated-Aromatic-Resin-Asphaltene (SARA) fractions and mole percent of non-hydrocarbon gases. Genetic algorithm technique has been applied to optimize the most appropriate network structure of GMDH model. In order to accomplish modeling, asphaltene precipitation of different crude oils from a number of Iranian reservoirs at wide ranges of operating conditions have been measured experimentally and applied for network construction. The accuracy of developed model has been evaluated by both statistical and graphical error analysis techniques. The average absolute relative deviation of the proposed model is 3.65%, which indicates model predictions are in excellent agreement with experimental data. Also, the comparison of developed GMDH model with scaling equation and least squares support vector machine (LSSVM) reveals the superiority of the proposed GMDH structure in prediction of asphaltene precipitation over scaling equation and LSSVM technique. In addition, the Leverage approach has been applied to detect suspected data. The results show that all experimental data are reliable and located within the applicable domain of developed model. Finally, a comprehensive sensitivity analysis based on the relevancy factor has been carried out which shows that percentages of resin and saturated components have the largest direct and inverse impacts on asphaltene precipitation, respectively.",7,7,0
Heavy Oil,Asphaltene Precipitation,"Borisov, D. N.; Tazeev, D. I.; Milordov, D. V.; Mironov, N. A.; Borisova, Y. Y.; Yakubov, M. R.; Beregovoy, A. N.; Amerkhanov, M. I.; Khisamov, R. S.",Physical modeling of the composite solvent injection to improve the ultra-viscous oil recovery efficiency steam-assisted gravity drainage,Ultra-viscous oil; Heavy oil; Solvent; Reservoir modeling; Thermal enhanced oil recovery techniques; Steam-assisted gravity drainage,ASPHALTENE PRECIPITATION; CRUDE OILS; AGGREGATION; PERFORMANCE; INHIBITION; RESERVOIRS; STABILITY; RESINS; CSI,"The experiments carried out on a physical model of reservoir of ultra-viscous oil have revealed features of oil displacement in various variants of the composite solvent and steam injection. In order to avoid precipitation of asphaltenes, the employment of inhibitors has been rationalized and their minimum fraction in displacement fluid has been determined. The effect of the sequence of solvent and vapor injection on the dynamics of ultra-viscous oil recovery has been investigated. The effect of clay and water in the rock on the rate of oil displacement and the ultimate oil recovery factor has been evaluated.",0,0,2
Heavy Oil,Asphaltene Precipitation,"Hassanpour, Sadegh; Malayeri, Mohammad Reza; Riazi, Masoud; Mousavi, Seyed Mahdi; Negahban, Zahra",On the impact of Co3O4 nanoparticles on interaction of heavy oil and brine mixtures,IFT; Brine solution; Asphaltene precipitation; EOR; Co3O4 nanoparticles,INTERFACIAL-TENSION; CRUDE-OIL; ASPHALTENE; SALINITY; TEMPERATURE; RECOVERY; PRESSURE; WATER; CO2; PRECIPITATION,"Among numerous EOR methods, the injection of brine with different salinities to oil reservoirs has gained attention where its performance would, in turn, depend on interfacial tension (IFT) of oil/brine mixture. The present study investigated the impact of Co3O4 nanoparticles with concentrations of 0.01, 0.1 and 1 wt% on IFT of brine solution (containing NaCl, KCl and CaCl2) and heavy crude oil system. The results confirmed that adding Co3O4 nanoparticles to water, compared to that without nanoparticles, reduced IFT at low (i.e. 0-5000 ppm) and high (i.e. greater than 5000 ppm) brine concentrations, although the propensity of IFT is different for various concentrations. Furthermore, the reduction of IFT for monovalent ions is greater than that for divalent ions. Properties such as high surface activity and higher surface to volume ratio of the Co3O4 nanoparticles should be accounted for profound adsorption of asphaltene onto the surface of nanoparticles. A high suspension of asphaltene at the brine/oil interface also avoided its precipitation in oil causing IFT to reduce in brine/crude mixtures with nanoparticles compared to that without nanoparticles. The extent of IFT reduction changed by using different concentrations of Co3O4 nanoparticles. For the oil/brine system attempted in this study, the optimum concentration of Co3O4 nanoparticles in term of IFT reduction was 0.1 wt%.",4,5,1
Heavy Oil,Asphaltene Precipitation,"Larichev, Yu. V.; Martyanov, O. N.",The dynamics of asphaltene aggregates in heavy crude oils on a nanometer scale studied via small-angle X-ray scattering in situ,Asphaltenes; Heavy crude oils; Aggregation; In-situ; SAXS,ELECTRON-SPIN-RESONANCE; N-HEPTANE; LIVE OILS; PRECIPITATION; STABILITY; TEMPERATURE; SOLVENT; RESINS; MODEL,"This work presents the results of the in situ SAXS study of the asphaltene aggregate transformations due to dilution of several heavy crude oils by heptane within the time range from 5 min to 3 days. The main growth of the asphaltene aggregates was usually observed within first minutes. The analysis of the SAXS data obtained in situ for the oils having significantly different relative content of resins showed their great influence on the dynamics of aggregates formation on a nanometer scale. In particular, it has been shown that the resins can prevent the asphaltene aggregation via certain mechanism which usually leads to the high anisotropy of the aggregates. Therefore the relative content of resin and asphaltenes as well as aromatics and aliphatics lead to the asphaltene aggregates with different shapes and different density of deposits.",4,4,3
Heavy Oil,Asphaltene Precipitation,"Sadi, Maryam; Shahrabadi, Abbas",Evolving robust intelligent model based on group method of data handling technique optimized by genetic algorithm to predict asphaltene precipitation,Asphaltene precipitation; Group method of data handling; Genetic algorithm; SARA fractions; Leverage approach,FUZZY INFERENCE SYSTEM; GMDH NEURAL-NETWORK; GAS INJECTION; NATURAL DEPLETION; SCALING EQUATION; HEAVY OILS; DEPOSITION; EQUILIBRIUM; PRESSURE; FLOCCULATION,"Precipitation of asphaltene during primary production of hydrocarbon reservoirs leads to formation damage and well bore plugging. Therefore, proposing an accurate model to estimate asphaltene precipitation under various operating and thermodynamic conditions are crucial. In this study, a new mathematical model based on the integrating group method of data handling (GMDH) with genetic algorithm has been developed to predict asphaltene precipitation as a function of reservoir pressure and temperature, crude oil API, bubble point pressure, Saturated-Aromatic-Resin-Asphaltene (SARA) fractions and mole percent of non-hydrocarbon gases. Genetic algorithm technique has been applied to optimize the most appropriate network structure of GMDH model. In order to accomplish modeling, asphaltene precipitation of different crude oils from a number of Iranian reservoirs at wide ranges of operating conditions have been measured experimentally and applied for network construction. The accuracy of developed model has been evaluated by both statistical and graphical error analysis techniques. The average absolute relative deviation of the proposed model is 3.65%, which indicates model predictions are in excellent agreement with experimental data. Also, the comparison of developed GMDH model with scaling equation and least squares support vector machine (LSSVM) reveals the superiority of the proposed GMDH structure in prediction of asphaltene precipitation over scaling equation and LSSVM technique. In addition, the Leverage approach has been applied to detect suspected data. The results show that all experimental data are reliable and located within the applicable domain of developed model. Finally, a comprehensive sensitivity analysis based on the relevancy factor has been carried out which shows that percentages of resin and saturated components have the largest direct and inverse impacts on asphaltene precipitation, respectively.",7,7,0
Heavy Oil,Asphaltene Precipitation,"Zhu, Lijun; Wang, Yongjie; Wang, Shoulong; Huo, Tian; Jing, Xiaohui; Li, Aifen; Xia, Daohong",High viscosity-reducing performance oil-soluble viscosity reduction agents containing acrylic acid ester as monomer for heavy oil with high asphaltene content,Oil soluble viscosity reduction agent; Acrylic acid ester; Heavy oil; Monomer,WAXY CRUDE-OIL; PIPELINE TRANSPORTATION; RHEOLOGICAL PROPERTIES; POLYMERIZATION; TEMPERATURES; AGGREGATION; BITUMEN,"Reducing viscosity of crude oil is a direct means of cutting the cost and increasing the amount of crude oil delivery. It was found that kerosene-dilution can significantly reduce the viscosity of Shengli heavy oil, and the viscosity reduction rate varies little with temperature rises. By measuring the viscosity of the deasphalted oil, it was found that the viscosity of the heavy oil was greatly reduced after deasphalted treatment, and the deasphalted oil showed a good Newtonian fluid, indicating that the high viscosity of the Shengli heavy oil was because of high asphaltene rather than the precipitation of paraffin. Aiming at the high asphaltene of Shengli heavy oil, oil-soluble polymer viscosity reduction agent was used to study the viscosity reduction. Two new monomers, acrylic acid phenethyl alcohol ester and benzyl acrylate were synthesized, and six copolymers were synthesized by free radical copolymerization with styrene, octadecyl acrylate and N-methoxyphenyl maleimide. Through the viscosity-reducing evaluation, the copolymer containing acrylic acid phenethyl alcohol ester and octadecyl acrylate (AD) had best performance. At 70 degrees C, the AD achieved viscosity reduction rate of 61.74%, which is the result of the matching of aromatics and solubility of monomers. And it is found that the monomer cooperation has an important effect on the viscosity reduction. This provided an important guidance to development of oil-soluble viscosity reduction agent.",7,8,18
Heavy Oil,Hydrocarbon,"Niu, Jun; Huang, Haiping; Jiang, Wenlong","Geochemical characteristics and correlation of continuous charge mixing and biodegradation of heavy oil in southeastern Dongying Sag, Bohai Bay basin, China",Bohai Bay basin; Dongying Sag; Charge mixing; Biodegradation; Heavy oil,NIUZHUANG SOUTH SLOPE; CRUDE OILS; ORGANIC GEOCHEMISTRY; EASTERN CHINA; AEROBIC BIODEGRADATION; DEEP SUBSURFACE; RESERVOIR GEOCHEMISTRY; PETROLEUM RESERVOIRS; GEOLOGICAL PROVINCE; PART 1,"The Paleogene Shahejie Formation is the main source rock and reservoir in the Jiyang Depression, Bohai Bay Basin, East China. An organic geochemical analysis study was performed on nine oil samples and forty-three core extracted samples from Shahejie Formation reservoirs by GC-MS to elucidate the influence of biodegradation and charge mixing on molecular compositions. Biodegradation impacts many classes of compounds, but the ultimate compositions and physical properties of the oil are influenced strongly by mixing with later oil charge and biodegradation. All samples display biodegradation signatures, and continuous charge mixing is characterized by the relationship between n-alkanes to hopanes and hopanes to 25-norhopanes (25-NHs). The occurrence of nalkanes in oil samples suggests multiple episodes of charging and that the petroleum accumulated in Caoqiao is mainly a mixture of previously biodegraded oils and later migrated fresh oils. Conventional geochemical diagnostic parameters in the saturated hydrocarbon fraction are affected by biodegradation. Based on the intensity of n-alkanes, hopanes and 25-NHs, many samples from Caoqiao appear to have experienced both biodegradation and continuous charge. A wide range of geochemical parameter values from different components point to multiple oil charge mixing. The relationship between the absolute concentrations of n-alkanes to hopanes and hopanes to 25-NHs of the samples can qualitatively differentiate whether oil charge mixing occurs in reservoirs or not. The cross plot of n-alkanes and hopanes dynamically describes the processes of continuous charge mixing and biodegradation. The positive correlation between the concentrations of hopanes and 25-NHs may suggest that oil charge mixing and biodegradation proceed continuously, while the negative correlation may indicate charge stops due to some geological factors.",5,6,1
Heavy Oil,Hydrocarbon,"Lee, Kyung Jae; Finsterle, Stefan; Moridis, George J.",Analyzing the impact of reaction models on the production of hydrocarbons from thermally upgraded oil shales,In-situ upgrading; Oil shale; Numerical simulation; Sensitivity analysis; Uncertainty prediction; Data-worth analysis,SIMPLE KINETIC-MODELS; NUMERICAL-SIMULATION; PETROLEUM FORMATION; GAS GENERATION; POROUS-MEDIA; EXPULSION; CRACKING; EQUATION,"Reaction parameters significantly affect oil production from shales by means of heating and in-situ upgrading. In this study, we perform numerical simulations of two chemical reaction models, which are mainly used in the research of kerogen pyrolysis and subsequent hydrocarbon decomposition in organic-rich porous media. They are the Braun and Burnham model and Wellington model. In these forward numerical simulations, we present the influence of the two reaction models on hydrocarbon production. The Braun and Burnham reaction model shows more vigorous kerogen and subsequent decomposition reactions and more hydrocarbon production than the Wellington model. A local sensitivity analysis identifies the reaction parameters with the highest influence on productivity, and the most sensitive outputs. A data-worth analysis identifies the most valuable observation data to be measured for the best prediction of total hydrocarbon production. We find that the most valuable observation data is the cumulative production of heavy oil in the Braun and Burnham model and of light oil in the Wellington model, respectively. Once we determine the maximum allowable prediction uncertainty and the expected measurement uncertainty, the observation data to be measured for the minimization of prediction uncertainty can be obtained.",6,6,0
Heavy Oil,Hydrocarbon,"Soh, Ye Ji; Babadagli, Tayfun",Use of air to improve the efficiency of foamy flow and reservoir pressurization in heavy oil recovery,Cyclic solvent injection; Post-CHOPS EOR; Methane and CO2; Air injection; Foamy oil corefloods,INJECTION; TEMPERATURE,"Primary recovery of heavy-oil is remarkably low due to high viscosity and low energy by solution gas exsolution to drive the oil. Gas injection to improve foamy flow and also to dilute the oil in such reservoirs has been proposed as a secondary recovery method. However, because of the high costs of injected gases, efforts are needed to optimize the process by selection of proper gas type (or gas combinations) and suitable injection scheme. To achieve this goal, an experimental procedure was followed with rigorous analyses of the output. A 1.5m long and 5 cm diameter sand-pack was first saturated with brine, which was replaced with dead oil. Then, gas solvents were injected to dead-oil containing core-holder until nearly reaching 500 psi followed by a two-day soaking period. Pressures all along the sand-pack were recorded with eight pressure transducers. Different combinations of various gas solvents (methane, CO2, and air) aiming to select the most competitive and economic formula were tested with a certain set of pressure depletion rates. The physics of the foamy oil flow for different solvent mixtures and depletion conditions were analyzed using pressure profiles acquired, recorded oil/gas data with time, and gas chromatography and SARA analyses of the produced gas and oil. Three huff-n-puff cycles were applied. Compared with other light hydrocarbon solvents and carbon dioxide, air has a significant advantage in terms of accessibility and lowered cost. Hence, attention was given to air mainly used to pressurize the system and increase oil viscosity due to oxidation process with an expectation of better foam quality when injected with other gases such as CO2 and methane. Methane (CH4) yielded the quickest response in terms of gas drive but, in the long run, CO2 was observed to be more effective technically. Air was observed to be effective if mixed with CO2 or methane from an economics point of view. To sum up the results, air Huff-n-Puff (HnP) followed by 2-cycles of CH4 HnP yielded 36.21% recovery, while air HnP followed by 2-cycles of CO2 HnP delivered 30.36% oil. When the gases are co-injected, air 50%-CO2 50% and air 50%-CH4 50% recovered 29.85% and 23.74% of total oil-in-place, respectively.",6,6,0
Heavy Oil,Hydrocarbon,"Sadi, Maryam; Shahrabadi, Abbas",Evolving robust intelligent model based on group method of data handling technique optimized by genetic algorithm to predict asphaltene precipitation,Asphaltene precipitation; Group method of data handling; Genetic algorithm; SARA fractions; Leverage approach,FUZZY INFERENCE SYSTEM; GMDH NEURAL-NETWORK; GAS INJECTION; NATURAL DEPLETION; SCALING EQUATION; HEAVY OILS; DEPOSITION; EQUILIBRIUM; PRESSURE; FLOCCULATION,"Precipitation of asphaltene during primary production of hydrocarbon reservoirs leads to formation damage and well bore plugging. Therefore, proposing an accurate model to estimate asphaltene precipitation under various operating and thermodynamic conditions are crucial. In this study, a new mathematical model based on the integrating group method of data handling (GMDH) with genetic algorithm has been developed to predict asphaltene precipitation as a function of reservoir pressure and temperature, crude oil API, bubble point pressure, Saturated-Aromatic-Resin-Asphaltene (SARA) fractions and mole percent of non-hydrocarbon gases. Genetic algorithm technique has been applied to optimize the most appropriate network structure of GMDH model. In order to accomplish modeling, asphaltene precipitation of different crude oils from a number of Iranian reservoirs at wide ranges of operating conditions have been measured experimentally and applied for network construction. The accuracy of developed model has been evaluated by both statistical and graphical error analysis techniques. The average absolute relative deviation of the proposed model is 3.65%, which indicates model predictions are in excellent agreement with experimental data. Also, the comparison of developed GMDH model with scaling equation and least squares support vector machine (LSSVM) reveals the superiority of the proposed GMDH structure in prediction of asphaltene precipitation over scaling equation and LSSVM technique. In addition, the Leverage approach has been applied to detect suspected data. The results show that all experimental data are reliable and located within the applicable domain of developed model. Finally, a comprehensive sensitivity analysis based on the relevancy factor has been carried out which shows that percentages of resin and saturated components have the largest direct and inverse impacts on asphaltene precipitation, respectively.",7,7,0
Heavy Oil,Hydrocarbon,"Liu, Pengcheng; Yuan, Zhe; Zhang, Shengfei; Xu, Zhenhua; Li, Xiuluan",Experimental study of the steam distillation mechanism during the steam injection process for heavy oil recovery,Heavy oil; Steam distillation; Distillation rate; Superheated steam; Degree of superheating,SIMULATION; SOLVENT; DRIVE; FIELD,"Steam distillation can effectively enhance heavy oil recovery during steam injection process in heavy oil reservoirs. However, the mechanism of steam distillation is complex, and the changes in oil properties during distillation remain unclear. In this study, three comparative steam distillation experiments were designed and conducted, including distillation processes employing saturated steam, steam superheated by 10 degrees C, and steam superheated by 40 degrees C. Heavy oil samples were derived from the Jin-1 Block in a typical heavy oilfield, in China. The density, viscosity, SARA fractions, and carbon number distribution of the residual oil were compared to those obtained before conducting steam distillation experiments. The steam distillation rates obtained with steam superheated by 40 degrees C, steam superheated by 10 degrees C, and saturated steam were 11.158%, 10.903% and 10.423%, respectively. The results indicate that the steam distillation rate of heavy oil increases significantly with increasing degree of superheating. During the steam distillation process, the density and viscosity of residual oil increase, the contents of saturated hydrocarbons and resin decrease, and the contents of aromatic hydrocarbons and asphaltenes increase. In addition, analysis of the distilled components indicates that lightweight components with smaller carbon numbers are removed firstly by steam distillation, followed by heavier components with larger carbon numbers. Moreover, all hydrocarbons with carbon numbers less than C-22 are removed from heavy oil in the distillation process, while the maximum carbon number of the distilled components was C-34. This study is favorable for understanding the changes in the properties of residual oil after distillation during the steam injection process for heavy oil recovery.",8,8,7
Heavy Oil,Flow Patterns,"Brito, Adriana; Guzman, Nolides; Rojas-Solorzano, Luis; Zambrano, Tibisay",Rheological study of two- and three-phase highly viscous fluid flow in pipelines,Foam rheology; Foamed emulsion; Two-phase flow; Three-phase flow; Flow patterns; Pressure drop model,GAS-LIQUID FLOW; HORIZONTAL PIPES; 2-PHASE FLOW; FOAMS; TRANSPORT; STABILITY,"The study of highly viscous multiphase flow systems is of fundamental interest in the oil industry. Most of the Venezuelan oil fields produce heavy oil with other production fluids, such as water and gas, and sand particles flowing from the reservoir to the surface facilities. A fraction of these phases flows fully separated, while another one flows as a dispersed system composed by water/oil emulsion with gas bubbles dispersed as a foamed emulsion. With the objective to understand and characterize this latter complex system, new experiments have been performed in 0.0243-m and 0.0508-m horizontal pipelines, for air/highly-viscous oil of 0.430 Pa s at 20 degrees C, and water/air/oil mixture with a water-in-oil emulsion of 0.560 Pa s at 20 degrees C. The three-phase flow pressure gradient was found to be approximately 15% higher than for the two-phase system, at similar gas and liquid superficial velocities. The air/oil and air/oil/water foamed emulsion behaved as non-Newtonian fluids, when these are considered as pseudo-homogeneous systems. A model to predict the flow pattern and pressure drop in horizontal pipelines was developed with an extensive database of 2167 experimental points, including new data and information collected and processed from different sources. A performance factor of 0.41 for Brito's three-phase (TM) model was consistently better than the performance factor obtained for other models commonly used by the oil and gas industry in similar multiphase flow systems.",3,3,0
Heavy Oil,Flow Patterns,"Guo, Jixiang; Yang, Yuqi; Zhang, Shuai; Zhang, Dengshan; Cao, Chang; Ren, Bo; Liu, Lei; Xing, Yu; Xiong, Ruiying",Heavy oil-water flow patterns in a small diameter vertical pipe under high temperature/pressure conditions,Upward oil-water flows; Flow patterns; High pressure; High temperature; Heavy oil,NATURAL CIRCULATION LOOP; LIQUID ANNULAR-FLOW; 2-PHASE FLOW; PRESSURE-DROP; INTERFACIAL-TENSION; HORIZONTAL PIPES; PHASE INVERSION; VOLUME FRACTION; DISPERSED FLOW; OPTICAL PROBE,"Experimental measurements were conducted to investigate the upward oil-water flow patterns in a small diameter vertical pipe (0.01m I.D.) under high temperatures up to 130 degrees C and high pressures up to 20 MPa. The viscosity of the oil sample was 584.24 mPa s and the density was 1.899 g/cm(3) at 30 degrees C. The effects of pressure, temperature, input water fraction (IWF) and mixture velocity on the flow patterns were systematically investigated. The observed flow patterns were plotted on a flow pattern map in which input water fraction was used as the y-axis and the mixture velocity was used as the x-axis. Based on the measurement results, the following flow patterns were observed: water-in-oil dispersed flow (D w/o), water-in-oil bubbly flow (B w/o), water-in-oil slug flow (S w/o), water-in-oil creep flow (CE w/o), churn flow (Churn) and core annual flow (AF). Phase inversion was not observed in this work. With an increase in temperature at a given input water fraction, S w/o, CE w/o and Churn flow with large water drops tended to transform into B w/o and D w/o with smaller water drops, the CE w/o disappears gradually, and the boundaries in the flow pattern maps tend to occur at lower input water fraction values. The effect of pressure on the flow patterns was found to be opposite to that of temperature. The possible causes leading to the changes in the flow patterns subjected to pressure/temperature variations were provided in terms of changes in density ratio, interfacial tension, and viscosity ratio of oil and water.",3,4,3
Heavy Oil,Flow Patterns,"Yoo, Kuy Hun Koh; Sampaio, Luiz Bittencourt; Gerritsen, Margot; Kovscek, Anthony R.",An optimization algorithm for evaluation of kinetic parameters for crude oil combustion,In situ combustion; Ramped temperature oxidation; Oxidation kinetics,IN-SITU-COMBUSTION; FIELD-SCALE; PREDICTABILITY,"The design of enhanced oil recovery processes that employ in-situ combustion requires high-fidelity simulation models that accurately describe the physics and chemistry of reactive, exothermic multiphase fluid flow. Therefore, a detailed description of oil combustion kinetics is required. The goal of this work is to present and apply a workflow to define and match pseudo-kinetic reaction models based on Arrhenius kinetics. These models are meant to be used at the laboratory scale with high-resolution, fully-resolved simulation models as a tool to generate high density data required by upscaled models at reservoir scale. The workflow starts by performing ramped temperature oxidation (RTO) experiments for a wide range of heating rates. New experimental equipment has allowed us to obtain data for large heating rates (>15 degrees C/min) that were not achievable in the past. A subset of the experiments are selected to match the oxygen consumption curves by tuning kinetic parameters of several global reaction models using pattern search optimization. Those models that obtain a match are validated by predicting a second subset of the data that was not considered during the optimization. The workflow is tested using a heavy oil and two satisfactory matches with two different global reaction models are obtained.",4,4,0
Heavy Oil,Pressure Gradient,"Brito, Adriana; Guzman, Nolides; Rojas-Solorzano, Luis; Zambrano, Tibisay",Rheological study of two- and three-phase highly viscous fluid flow in pipelines,Foam rheology; Foamed emulsion; Two-phase flow; Three-phase flow; Flow patterns; Pressure drop model,GAS-LIQUID FLOW; HORIZONTAL PIPES; 2-PHASE FLOW; FOAMS; TRANSPORT; STABILITY,"The study of highly viscous multiphase flow systems is of fundamental interest in the oil industry. Most of the Venezuelan oil fields produce heavy oil with other production fluids, such as water and gas, and sand particles flowing from the reservoir to the surface facilities. A fraction of these phases flows fully separated, while another one flows as a dispersed system composed by water/oil emulsion with gas bubbles dispersed as a foamed emulsion. With the objective to understand and characterize this latter complex system, new experiments have been performed in 0.0243-m and 0.0508-m horizontal pipelines, for air/highly-viscous oil of 0.430 Pa s at 20 degrees C, and water/air/oil mixture with a water-in-oil emulsion of 0.560 Pa s at 20 degrees C. The three-phase flow pressure gradient was found to be approximately 15% higher than for the two-phase system, at similar gas and liquid superficial velocities. The air/oil and air/oil/water foamed emulsion behaved as non-Newtonian fluids, when these are considered as pseudo-homogeneous systems. A model to predict the flow pattern and pressure drop in horizontal pipelines was developed with an extensive database of 2167 experimental points, including new data and information collected and processed from different sources. A performance factor of 0.41 for Brito's three-phase (TM) model was consistently better than the performance factor obtained for other models commonly used by the oil and gas industry in similar multiphase flow systems.",3,3,0
Heavy Oil,Pressure Gradient,"Nie, Ren-Shi; Wang, Yi-Min; Kang, Yi-Li; Jia, Yong-Lu",Modeling the characteristics of Bingham porous-flow mechanics for a horizontal well in a heavy oil reservoir,Hydrodynamic characteristics; Non-Newtonian fluid; Bingham fluid; Pressure and pressure derivative curves; Threshold pressure gradient,TRANSIENT FLOW; PRESSURE; FLUIDS; BEHAVIOR; AQUIFER; SYSTEM,"In order to investigate hydrodynamic characteristics of Bingham porous-flow mechanics in a heavy oil reservoir, this paper originally proposes a physical model of Bingham fluid flow for a horizontal well in a heavy oil reservoir. A corresponding mathematical model is established and solved. A series of typical pressure and pressure derivative curves are drawn by the use of the semi-analytical solution of the mathematical model. Hydrodynamic flow characteristics of Bingham fluid are thoroughly analyzed. Through the recognition of flow regimes from the typical curves, it is found that the flow process of Bingham fluid mainly includes the early radial flow regime, linear flow regime and late pseudo-radial flow regime. The curves controlled by different boundary conditions are especially studied, and it is found that the late curve shape, especially the shape of pressure derivative curve, differs completely for the various property of boundary. The curve sensitivity to different model parameters, such as dimensionless threshold pressure gradient and horizontal wellbore length, is deeply discussed. The findings are as follow: except the pure wellbore storage regime, the threshold pressure gradient influences the hydrodynamic flow behavior in all the regimes; the curve of Bingham fluid governed by the threshold pressure gradient upward deviates from that of Newtonian fluid; and the deviation of the curves increases with the increase of the threshold pressure gradient and the elapsed time. The research results of this paper sufficiently demonstrate the essential property of non-Newtonian porous-flow mechanics.",7,7,2
Heavy Oil,Reaction Models,"Yoo, Kuy Hun Koh; Sampaio, Luiz Bittencourt; Gerritsen, Margot; Kovscek, Anthony R.",An optimization algorithm for evaluation of kinetic parameters for crude oil combustion,In situ combustion; Ramped temperature oxidation; Oxidation kinetics,IN-SITU-COMBUSTION; FIELD-SCALE; PREDICTABILITY,"The design of enhanced oil recovery processes that employ in-situ combustion requires high-fidelity simulation models that accurately describe the physics and chemistry of reactive, exothermic multiphase fluid flow. Therefore, a detailed description of oil combustion kinetics is required. The goal of this work is to present and apply a workflow to define and match pseudo-kinetic reaction models based on Arrhenius kinetics. These models are meant to be used at the laboratory scale with high-resolution, fully-resolved simulation models as a tool to generate high density data required by upscaled models at reservoir scale. The workflow starts by performing ramped temperature oxidation (RTO) experiments for a wide range of heating rates. New experimental equipment has allowed us to obtain data for large heating rates (>15 degrees C/min) that were not achievable in the past. A subset of the experiments are selected to match the oxygen consumption curves by tuning kinetic parameters of several global reaction models using pattern search optimization. Those models that obtain a match are validated by predicting a second subset of the data that was not considered during the optimization. The workflow is tested using a heavy oil and two satisfactory matches with two different global reaction models are obtained.",4,4,0
Heavy Oil,Reaction Models,"Lee, Kyung Jae; Finsterle, Stefan; Moridis, George J.",Analyzing the impact of reaction models on the production of hydrocarbons from thermally upgraded oil shales,In-situ upgrading; Oil shale; Numerical simulation; Sensitivity analysis; Uncertainty prediction; Data-worth analysis,SIMPLE KINETIC-MODELS; NUMERICAL-SIMULATION; PETROLEUM FORMATION; GAS GENERATION; POROUS-MEDIA; EXPULSION; CRACKING; EQUATION,"Reaction parameters significantly affect oil production from shales by means of heating and in-situ upgrading. In this study, we perform numerical simulations of two chemical reaction models, which are mainly used in the research of kerogen pyrolysis and subsequent hydrocarbon decomposition in organic-rich porous media. They are the Braun and Burnham model and Wellington model. In these forward numerical simulations, we present the influence of the two reaction models on hydrocarbon production. The Braun and Burnham reaction model shows more vigorous kerogen and subsequent decomposition reactions and more hydrocarbon production than the Wellington model. A local sensitivity analysis identifies the reaction parameters with the highest influence on productivity, and the most sensitive outputs. A data-worth analysis identifies the most valuable observation data to be measured for the best prediction of total hydrocarbon production. We find that the most valuable observation data is the cumulative production of heavy oil in the Braun and Burnham model and of light oil in the Wellington model, respectively. Once we determine the maximum allowable prediction uncertainty and the expected measurement uncertainty, the observation data to be measured for the minimization of prediction uncertainty can be obtained.",6,6,0
Heavy Oil,Air,"Zhao, Renbao; Li, Bochun; Yang, Xiaoying; Yang, Jie; Yu, Shuai; Jin, Jun; Zhang, Jianhua",Analysis of a feasible field THAI pattern by the derivation of scaling criteria and combustion experiments,In-situ combustion; Toe-to-heel air injection process; Scaling criteria; Three dimensional cylindrical model,HEAVY OIL; SIMULATION,"Toe-to-heel air injection (THAI) process is considered as a potential enhanced oil recovery (EOR) method for heavy oil production. For physical simulation of THAI process in laboratory conditions, the simplified scaling criteria of THAI process were derived and a novel three-dimensional cylindrical apparatus was used to construct the new THAI pattern in this study. Equation analysis and dimensional analysis (Buckingham at-theorem) were applied to deduce the whole dimensionless groups, and sensitivity of the coefficients described with their distortion coefficients were used to obtain the influential weights and the simplified scaling criteria. STARS module in Computer Modeling Group (CMG) was used to verify the feasibility of the THAI pattern by two models, which represent the reservoir prototype and the 3D apparatus respectively. With an effective simulation of experimental results, a reasonable data set was obtained, and then those values were upscaled for simulation of field THAI process by the simplified scaling criteria. The experiment results showed that the horizontal well was well protected by a slant distribution of coke zone and the other parameters about oil production (such as the high temperature swept volume, oil production rate and recovery) were still satisfactory. The similarity of variation process of temperature field, oil saturation distribution and production performance between the laboratory results and THAI simulation in reservoir prototype showed the validity of the scaling criteria and indicated that a feasible field THAI process with a large combustion chamber upon horizontal well can be predicted to achieve.",0,0,3
Heavy Oil,Air,"Soh, Ye Ji; Babadagli, Tayfun",Use of air to improve the efficiency of foamy flow and reservoir pressurization in heavy oil recovery,Cyclic solvent injection; Post-CHOPS EOR; Methane and CO2; Air injection; Foamy oil corefloods,INJECTION; TEMPERATURE,"Primary recovery of heavy-oil is remarkably low due to high viscosity and low energy by solution gas exsolution to drive the oil. Gas injection to improve foamy flow and also to dilute the oil in such reservoirs has been proposed as a secondary recovery method. However, because of the high costs of injected gases, efforts are needed to optimize the process by selection of proper gas type (or gas combinations) and suitable injection scheme. To achieve this goal, an experimental procedure was followed with rigorous analyses of the output. A 1.5m long and 5 cm diameter sand-pack was first saturated with brine, which was replaced with dead oil. Then, gas solvents were injected to dead-oil containing core-holder until nearly reaching 500 psi followed by a two-day soaking period. Pressures all along the sand-pack were recorded with eight pressure transducers. Different combinations of various gas solvents (methane, CO2, and air) aiming to select the most competitive and economic formula were tested with a certain set of pressure depletion rates. The physics of the foamy oil flow for different solvent mixtures and depletion conditions were analyzed using pressure profiles acquired, recorded oil/gas data with time, and gas chromatography and SARA analyses of the produced gas and oil. Three huff-n-puff cycles were applied. Compared with other light hydrocarbon solvents and carbon dioxide, air has a significant advantage in terms of accessibility and lowered cost. Hence, attention was given to air mainly used to pressurize the system and increase oil viscosity due to oxidation process with an expectation of better foam quality when injected with other gases such as CO2 and methane. Methane (CH4) yielded the quickest response in terms of gas drive but, in the long run, CO2 was observed to be more effective technically. Air was observed to be effective if mixed with CO2 or methane from an economics point of view. To sum up the results, air Huff-n-Puff (HnP) followed by 2-cycles of CH4 HnP yielded 36.21% recovery, while air HnP followed by 2-cycles of CO2 HnP delivered 30.36% oil. When the gases are co-injected, air 50%-CO2 50% and air 50%-CH4 50% recovered 29.85% and 23.74% of total oil-in-place, respectively.",6,6,0
Heavy Oil,Berea Sandstone,"Zhang, Boyang; Daigle, Hugh",Oil-soluble contrast agents for NMR,NMR; Relaxation; Contrast agents; Hydrophobic; Fluid typing,IRON-OXIDE NANOPARTICLES; THERMAL-STABILITY; ADSORPTION; SILICA; SPIONS,"In well logging applications, nuclear magnetic resonance (NMR) is recognized as a powerful tool to differentiate various fluids inside porous media. However, it can be challenging to do so in complex situations, e.g. when fluid peaks overlap with each other. Water-soluble contrast agents, such as MnCl2 or Gd-EDTA, have been proposed for use to accelerate the water relaxation, thus separating the water signal from those of other fluids. Together with these contrast agents, the log-inject-log method is used and the difference between the two logs is attributed to the doped water phase. This application only works with water-based mud. To extend its use to oil-based mud (OBM), it is desirable to find alternatives to water-soluble contrast agents that are compatible with OBM. In this work, we introduce a new group of doping agents: oil-soluble contrast agents. We selected several iron-based complex compounds that are oil-soluble, and tested and evaluated their effects on oil signal relaxation using a laboratory NMR apparatus. We also tested hydrophobic iron oxide nanoparticles as a contrast agent. The results showed that both the complex compounds and nanoparticles were able to reduce the transverse relaxation time of oil from longer than 2 s to less than 20 ms. To demonstrate their applicability in porous media, we injected doped oil into gas-saturated Berea sandstone and limestone core plugs. With conventional 1D NMR measurements or the use of water-soluble contrast agents, it is not straightforward to discern the gas signal from the OBM signal. Our experiments showed that the gas signal could be easily identified in the presence of doped oil via simple T-2 scans. We also performed experiments to demonstrate that the peaks of water and doped oil could be readily differentiated. The use of oil-soluble doping agents can significantly enhance the contrast of the NMR signals originated from different formation fluids, thus facilitating the fluid typing process. It provides a key alternative to the current water-doping technique. It is particularly advantageous when changing the oil relaxation is desired, such as for eliminating signal interferences from OBM invasion and differentiating heavy oil from clay-bound water. It also provides the possibility of speeding up the logging process by dramatically reducing the oil relaxation time. In addition, they can be employed in the laboratory for various purposes such as water saturation determination and fluid displacement monitoring. These contrast agents can also be of useful when oil-soluble contrast agents are desired in other fields, such as medical imaging applications.",1,1,1
Heavy Oil,Berea Sandstone,"Ansah, Eric O.; Sugai, Yuichi; Nguele, Ronald; Sasaki, Kyuro",Integrated microbial enhanced oil recovery (MEOR) simulation: Main influencing parameters and uncertainty assessment,Artificial intelligence; Capillary number; Enthalpy; Microbial enhanced oil recovery; Monte Carlo simulation; Response surface methodology,HEAVY OIL; TEMPERATURE; RESERVOIR; GROWTH; MECHANISMS; BACTERIA; FIELD,"The present study investigated the ability of a thermophilic anaerobic microbe (herein coded as AR80) for MEOR with the further objective to quantify the uncertainty of production forecast in terms of the cumulative probability distribution. A series of core flood experiments conducted in water-flooded Berea sandstone showed that up to 51% of initial oil-in-place was recovered when the plugs were treated with AR80 and shut-in for 14 days. Mainly, the oil recovery mechanisms were attributed to viscosity enhancement, wettability changes, permeability and flow effects. Matching the laboratory data using artificial intelligence: the optimized cumulative oil recovery could be achieved at an enthalpy of 894.2 J/gmol, Arrhenius frequency of 8.3, residual oil saturation of 20%, log of capillary number at microbe flooding stage of -1.26, and also depicted a history match error less than 3%. Therefrom, a sensitivity analysis conducted on reservoir shut-in period effect on oil recovery revealed that a relatively shorter shut-in period is recommended to warrant early incremental oil recovery effect for economical purposes. In addition, MEOR could enhance the oil recovery significantly if a larger capillary number (between 10(-5) and 10(-3.5)) is attained. Per probabilistic estimation, MEOR could sustain already water-flooded well for a set period of time. This study showed that there is a 20% frequency of increasing the oil recovery by above 20% when a mature water-flooded reservoir is further flooded with AR80 for 2 additional years. Lastly, it was demonstrated herein that increasing the nutrient (yeast extract) concentration (from 0.1 to 1% weight) had less or no significant effect on the oil viscosity and subsequent recovery.",4,4,0
Heavy Oil,Iron Oxide,"Zhang, Boyang; Daigle, Hugh",Oil-soluble contrast agents for NMR,NMR; Relaxation; Contrast agents; Hydrophobic; Fluid typing,IRON-OXIDE NANOPARTICLES; THERMAL-STABILITY; ADSORPTION; SILICA; SPIONS,"In well logging applications, nuclear magnetic resonance (NMR) is recognized as a powerful tool to differentiate various fluids inside porous media. However, it can be challenging to do so in complex situations, e.g. when fluid peaks overlap with each other. Water-soluble contrast agents, such as MnCl2 or Gd-EDTA, have been proposed for use to accelerate the water relaxation, thus separating the water signal from those of other fluids. Together with these contrast agents, the log-inject-log method is used and the difference between the two logs is attributed to the doped water phase. This application only works with water-based mud. To extend its use to oil-based mud (OBM), it is desirable to find alternatives to water-soluble contrast agents that are compatible with OBM. In this work, we introduce a new group of doping agents: oil-soluble contrast agents. We selected several iron-based complex compounds that are oil-soluble, and tested and evaluated their effects on oil signal relaxation using a laboratory NMR apparatus. We also tested hydrophobic iron oxide nanoparticles as a contrast agent. The results showed that both the complex compounds and nanoparticles were able to reduce the transverse relaxation time of oil from longer than 2 s to less than 20 ms. To demonstrate their applicability in porous media, we injected doped oil into gas-saturated Berea sandstone and limestone core plugs. With conventional 1D NMR measurements or the use of water-soluble contrast agents, it is not straightforward to discern the gas signal from the OBM signal. Our experiments showed that the gas signal could be easily identified in the presence of doped oil via simple T-2 scans. We also performed experiments to demonstrate that the peaks of water and doped oil could be readily differentiated. The use of oil-soluble doping agents can significantly enhance the contrast of the NMR signals originated from different formation fluids, thus facilitating the fluid typing process. It provides a key alternative to the current water-doping technique. It is particularly advantageous when changing the oil relaxation is desired, such as for eliminating signal interferences from OBM invasion and differentiating heavy oil from clay-bound water. It also provides the possibility of speeding up the logging process by dramatically reducing the oil relaxation time. In addition, they can be employed in the laboratory for various purposes such as water saturation determination and fluid displacement monitoring. These contrast agents can also be of useful when oil-soluble contrast agents are desired in other fields, such as medical imaging applications.",1,1,1
Heavy Oil,Iron Oxide,"Akhmadiyarov, Aydar A.; Rakipov, Ilnaz T.; Khachatrian, Artashes A.; Petrov, Artem A.; Sitnov, Sergei A.; Gerasimov, Alexander V.; Osin, Yury N.; Varfolomeev, Mikhail A.",Thermocatalytic upgrading of heavy oil by iron oxides nanoparticles synthesized by oil-soluble precursors,Thermocatalytic upgrading; Heavy oil; Viscosity; Reservoir temperature and pressure; Catalysis,HIGH-TEMPERATURE; AQUATHERMOLYSIS; TETRAHYDROTHIOPHENE; CHEMISTRY; THIOPHENE; VISCOSITY; RECOVERY; MINERALS; SQUALANE; STEAM,"Thermocatalytic upgrading of heavy crude oil at reservoir temperature and pressure has been studied. The objective of the present work was to investigate the efficiency of the compounds based on iron (iron carbonyls, iron oxide, metallic iron) on thermocatalytic upgrading process of heavy crude oil at reservoir temperature and pressure (5.0 MPa and up to 523.15 K). The viscosity reducing was used as the main parameter for determination of the efficiency of thermocatalytic upgrading. The effect of structure of the catalyst precursor on the composition of SARA fractions after thermal catalytic upgrading of crude oil was analyzed. A destruction of mainly resin fraction was found to occur during thermocatalytic upgrading of heavy crude oil. The composition and structure of catalysts after crude oil upgrading were determined by the X-powder diffraction and SEM methods. An impact of catalyst (Fe3O4) particle size on the efficiency of crude oil thermocatalytic upgrading process was revealed.",4,5,4
Degrees C.,High Temperature,"Li, Zhiyong; Wang, Sunan; Tao, Ye; Ma, Hongtao; Wu, Jiang",Research and application of the HTHS anti-H2S gel valve for underbalanced drilling,Underbalanced drilling (UBD); Gel valve; High temperature; Anti-H2S; High strength; Performance evaluation,,"Nowadays the whole underbalanced status of the well during underbalanced drilling process needs to be realized to a great extent, and gel valve is helpful to achieve it. However, there is occasionally H2S in the formation during underbalanced drilling (Hereinafter abbreviated as UBD), which will seriously affect the performance and lifetime of gel valve. Thus, in this paper, a formula of high temperature high strength (HTHS) anti-H2S gel valve was developed based on the optimization of different additives, such as hydrolyzed polyacryamide (HPAM), organic crosslinking agents, sulfur removal agents, etc., which could withstand temperature up to 320 degrees F(160 degrees C). The gel valve was made by crosslinking reaction at high temperature to form strong chemical bonds of spatial network structure. With its own strength and adhesion to the casing wall after gelation, the gel valve could meet the requirements for sealing. The properties of the final formula were evaluated, including viscosity, temperature stability, anti-H2S performance, gel sealing pressure, gel strength gel breaking performance, etc. In addition, a new evaluation apparatus for high toxic H2S invasion was designed specifically. The results show that the gel viscosity is around 50 mPa . s before being pumped into well, meaning a good fluidity. Its sealing pressure is high enough to balance downhole pressure and resist invasion of 10,000 ppm H2S after gelation. In addition, the gel valve can be completely broken after adding 10% breaking agents for 60 min, meaning it can easily flow back and does not influence the subsequent normal operations. Field application shows that the gel valve had good sealing property, peak of total hydrocarbon in gas logging increased from 0 to 66.6% before and after the gel broken. The gel flowed out completely after it was broken and there was successful ignition at the well site. Thus, the HTHS anti-H2S gel valve can effectively meet the operational requirements, and is an alternative method to achieve the target of the whole process of UBD operations.",2,3,0
Degrees C.,High Temperature,"Guo, Jixiang; Yang, Yuqi; Zhang, Shuai; Zhang, Dengshan; Cao, Chang; Ren, Bo; Liu, Lei; Xing, Yu; Xiong, Ruiying",Heavy oil-water flow patterns in a small diameter vertical pipe under high temperature/pressure conditions,Upward oil-water flows; Flow patterns; High pressure; High temperature; Heavy oil,NATURAL CIRCULATION LOOP; LIQUID ANNULAR-FLOW; 2-PHASE FLOW; PRESSURE-DROP; INTERFACIAL-TENSION; HORIZONTAL PIPES; PHASE INVERSION; VOLUME FRACTION; DISPERSED FLOW; OPTICAL PROBE,"Experimental measurements were conducted to investigate the upward oil-water flow patterns in a small diameter vertical pipe (0.01m I.D.) under high temperatures up to 130 degrees C and high pressures up to 20 MPa. The viscosity of the oil sample was 584.24 mPa s and the density was 1.899 g/cm(3) at 30 degrees C. The effects of pressure, temperature, input water fraction (IWF) and mixture velocity on the flow patterns were systematically investigated. The observed flow patterns were plotted on a flow pattern map in which input water fraction was used as the y-axis and the mixture velocity was used as the x-axis. Based on the measurement results, the following flow patterns were observed: water-in-oil dispersed flow (D w/o), water-in-oil bubbly flow (B w/o), water-in-oil slug flow (S w/o), water-in-oil creep flow (CE w/o), churn flow (Churn) and core annual flow (AF). Phase inversion was not observed in this work. With an increase in temperature at a given input water fraction, S w/o, CE w/o and Churn flow with large water drops tended to transform into B w/o and D w/o with smaller water drops, the CE w/o disappears gradually, and the boundaries in the flow pattern maps tend to occur at lower input water fraction values. The effect of pressure on the flow patterns was found to be opposite to that of temperature. The possible causes leading to the changes in the flow patterns subjected to pressure/temperature variations were provided in terms of changes in density ratio, interfacial tension, and viscosity ratio of oil and water.",3,4,3
Degrees C.,High Temperature,"Zhu, Dongya; Meng, Qingqiang; Liu, Quanyou; Zhou, Bing; Jin, Zhijun; Hu, Wenxuan",Natural enhancement and mobility of oil reservoirs by supercritical CO2 and implication for vertical multi-trap CO2 geological storage,Supercritical CO2; Reservoir enhancement; Dawsonite; Geological storage; Huangqiao reservoir,RARE-EARTH-ELEMENT; CARBON-DIOXIDE; FLUID INCLUSIONS; SALINE AQUIFERS; BASIN; SEQUESTRATION; ACCUMULATION; GAS; RECOVERY; MODEL,"The accumulation and production of both deep mantle-derived CO2 and light oil were discovered in the Huangqiao reservoir, which is located in the Subei Basin, East China. The Huangqiao reservoir shows that both CO2 and oil are entrapped in and produced from vertical multi-traps. The effects of deep CO2 on the accumulation and production of oil under natural conditions and the implications for CO2 geological storage are investigated in detail. The fluid inclusions in quartz or calcite veins from the Silurian Fentou Formation (S(2-3)f), Permian Longtan Formation (P(2)l) and Triassic Qinglong Formation (T(1)q) have homogenization temperatures (Ths) that display peak ranges of 180 degrees C-190 degrees C, 170 degrees C-180 degrees C and 150 degrees C-160 degrees C, respectively. The Ths are higher than the formation temperatures. The calcite veins have light carbon and oxygen isotope compositions and have high Sr-87/Sr-86 ratios and positive Eu anomalies. These characteristics reveal the activities of deep CO2-rich hydrothermal fluids in the basin strata. The feldspar in the S(2-3)f and P(2)l sandstone reservoirs underwent significant dissolution because of the presence of CO2-rich fluids, forming of a large amount of secondary pores in the sandstone reservoirs and enhancing the reservoirs' physical properties. The measured porosity reaches 12.3%. CO2 in a supercritical state extracted or dissolved light petroleum components out of sedimentary rocks and then carried them towards reservoirs. Thus, CO2 and oil co-accumulated in the enhanced reservoirs, e.g. S(2-3)f, P(2)l and T(1)q. During drilling development, this supercritical CO2 naturally increased the mobility of oil, resulting in the co-production of highly pure CO2 and light oil. Based on the unique features of the Huangqiao CO2-oil reservoir, we propose a new CO2 geological storage model, namely, a vertical multi-trap geological storage model, which can either entrap large volumes of CO2 or lower the risk of long-term storage.",5,7,4
Degrees C.,High Temperature,"Yang, Shangyu; Han, Lihong; Feng, Chun; Wang, Hang; Feng, Yaorong; Wu, Xingru",Mechanical performance of casing in in-situ combustion thermal recovery,Casing performance; Heavy oil; In-situ combustion; Casing design; Steam flooding,OIL; WELLS,"In-situ combustion is often used to develop heavy oil as it has multiple advantages over alternative thermal methods. However, the wellbore integrity can be compromised if the casing is not properly designed or manufactured. Based on the fundamentals of heat transfer, a mathematical model with multiphysics is built to study the temperature and pressure distributions surrounding the wellbore during in-situ combustion. In laboratory, real casings and coupons with grades of N80, P110, and 3Cr110 were tested under high temperature to study their mechanical performances in the in-situ combustion recovery. From the modeling and laboratory testing results, we propose the casing design and manufacture protocols for thermal recovery of heavy oil. Field applications in Liaohe oil field, Du-66 Block, shows that the mechanical deterioration of P110 and 3Cr110 is less than that of N80 and the mechanical performance stability of 3Cr110 is better than others when the temperature is less than 600 degrees C. When the temperature is above 600 degrees C for more than 10 h, the mechanical performance of all casing grades declines quickly. Applying finite element analysis, we recommend a safety factor of 1.1 for designing casing at the temperatures of 250 degrees C,480 degrees C and 485 degrees C. The finding of this study provides fundamentals for the casing design and material selection for in-situ combustion recovery.",6,6,0
Degrees C.,High Temperature,"Karimi, Masoud; Shirazi, Meisam Mohammadzadeh; Ayatollahi, Shahab",Investigating the effects of rock and fluid properties in Iranian carbonate matrix acidizing during pre-flush stage,Matrix acidizing; Pre-flush fluid; Wettability alteration; IFT reduction; Dissolution rate,WETTABILITY ALTERATION; OIL-WET; INTERFACIAL-TENSION; REACTION-KINETICS; HIGH-TEMPERATURE; ACID; SURFACTANT; DISSOLUTION; STIMULATION; ACIDIZATION,"Acidizing of carbonate oil-wet rocks saturated with oil and saline formation water is subjected failure in some cases due to acid-induced damage such as sludge and emulsion formations. This condition may also lead to mineral precipitation, oil film barrier between acid and rock and diversion chemical malfunctions. Therefore, pre-flush process has been proposed as one of the most efficient stage for oil-wells matrix acidizing to reduce these challenges significantly. Besides, the pre-flush stage would result in more clean rock as the reservoir fluids are pushed back from the near wellbore regions, restoring rock wettability to more water wet state, preventing direct acid-oil contact and cooling rock surface to control acid-rock reaction at high temperature reservoir. This laboratory work is designed to study the effectiveness of three different pre-flush fluids and assess their ability in reducing interfacial tension (IFT) to displace original reservoir fluids around the wellbore as well as changing the rock wettability to increase rock dissolution rate. The results showed that a 0.5% wt of C16TAB aqueous solution (cationic surfactant additive) has passed successfully the pre-flush optimization criteria which can be utilized as pre-flush fluid of the carbonate oil-wet acidizing. It was shown that the wettability and IFT were changed quickly as it is requested for the pre-flush stage. The contact angle was decreased from 172 degrees to 33 degrees in two hours period and the IFT was reduced from 8.9 to 0.62 (dyne/cm) at reservoir condition (P = 4000 psia, T = 85 degrees C). In addition, the dissolution rate of dolomite rock from an Iranian oil reservoir at three different states of oil-wet, water-wet and pre-flush treated with 15% HCl was measured and compared. The measured dissolution rate of initially water-wet rock was measured to be 1 x 10(-4) mol/cm(2).s which is the same as the dissolution rate measured for C16TAB treated oil wet rock. This confirms the suitable wettability alteration through C16TAB pre-flush.",6,6,1
Degrees C.,High Temperature,"Zhao, Jinzhou; Chen, Pengfei; Liu, Youquan; Mao, Jincheng",Development of an LPG fracturing fluid with improved temperature stability,Unconventional; Liquefied petroleum gas; Fracturing fluid; Crosslinking agent; Optimization,,"Continued exploitation of unconventional reservoirs using conventional hydraulic fracturing fluid technologies requires large volumes of water, which may lead to water resource shortage and environmental pollution problems. To mitigate these issues, we have developed a waterless fracturing fluid system, an LPG (Liquefied Petroleum Gas) fracturing fluid, which exhibits excellent rheological properties, at high temperatures. In order to develop this high-performance LPG fracturing fluid, two series of metal cross-linkers (aluminum cross-linkers and iron cross-linkers) were formulated. Crosslinking performance was examined via visual observation at room temperature and by rheological testing at raised temperatures. After optimizing the crosslinker formulation, the breaking performance and the regain permeability of the new LPG fracturing fluid were also examined. The new LPG fracturing fluid breaks almost completely at 90 degrees C and achieves an average regain permeability of 96.97% even at 25 degrees C, suggesting low damage in the field applications. A fracturing fluid with such good performance can satisfy the requirements of unconventional reservoir operations. Also, as far as we know, it is the first time that all of the important characteristics of an LPG fracturing fluid are reported.",7,7,8
Degrees C.,High Temperature,"Zhu, Lijun; Wang, Yongjie; Wang, Shoulong; Huo, Tian; Jing, Xiaohui; Li, Aifen; Xia, Daohong",High viscosity-reducing performance oil-soluble viscosity reduction agents containing acrylic acid ester as monomer for heavy oil with high asphaltene content,Oil soluble viscosity reduction agent; Acrylic acid ester; Heavy oil; Monomer,WAXY CRUDE-OIL; PIPELINE TRANSPORTATION; RHEOLOGICAL PROPERTIES; POLYMERIZATION; TEMPERATURES; AGGREGATION; BITUMEN,"Reducing viscosity of crude oil is a direct means of cutting the cost and increasing the amount of crude oil delivery. It was found that kerosene-dilution can significantly reduce the viscosity of Shengli heavy oil, and the viscosity reduction rate varies little with temperature rises. By measuring the viscosity of the deasphalted oil, it was found that the viscosity of the heavy oil was greatly reduced after deasphalted treatment, and the deasphalted oil showed a good Newtonian fluid, indicating that the high viscosity of the Shengli heavy oil was because of high asphaltene rather than the precipitation of paraffin. Aiming at the high asphaltene of Shengli heavy oil, oil-soluble polymer viscosity reduction agent was used to study the viscosity reduction. Two new monomers, acrylic acid phenethyl alcohol ester and benzyl acrylate were synthesized, and six copolymers were synthesized by free radical copolymerization with styrene, octadecyl acrylate and N-methoxyphenyl maleimide. Through the viscosity-reducing evaluation, the copolymer containing acrylic acid phenethyl alcohol ester and octadecyl acrylate (AD) had best performance. At 70 degrees C, the AD achieved viscosity reduction rate of 61.74%, which is the result of the matching of aromatics and solubility of monomers. And it is found that the monomer cooperation has an important effect on the viscosity reduction. This provided an important guidance to development of oil-soluble viscosity reduction agent.",7,8,18
Degrees C.,High Temperature,"Sandengen, K.; Meldahl, M. M.; Gjersvold, B.; Molesworth, P.; Gaillard, N.; Braun, O.; Antignard, S.",Long term stability of ATBS type polymers for enhanced oil recovery,,C-13 NMR-SPECTROSCOPY; ELEVATED-TEMPERATURE; AQUEOUS-SOLUTION; HYDROLYSIS; POLYACRYLAMIDE; COPOLYMERS; OXYGEN; IRON,"In offshore enhanced oil recovery (EOR) applications polymer residence time within the reservoir could be many years. Long term stability (preservation of solution viscosity) within the anaerobic reservoir is a fundamental property of the polymer chemical and consequently highly important for choosing a proper product. For high temperature and/or high salinity reservoirs co-polymers of acrylamide (AM) and acrylamide tertiary butyl sulfonic acid (ATBS) have become common in the industry. The present work aimed at developing generic stability diagrams for such polymers dissolved in seawater (SW). Herein a two-step approach was attempted where stability versus ATBS content was measured at elevated temperature. Thereafter these data were extrapolated to lower temperature. To arrive at a sound extrapolation knowledge of hydrolysis kinetics for the two species, AM and ATBS, was needed. Aqueous solutions of AM-ATBS and AA-ATBS co-polymers were therefore stored at elevated temperature (82-140 degrees C) and progressive changes in microstructure followed by use of C-13 NMR spectroscopy. A steady increase in polymer stability with ATBS content was observed up to around 70 mol%. From 70 to 80 mol% the robustness sharply improved. A striking observation was that stability loss, defined as < 80% remaining viscosity, occurred before significant amounts of ATBS had reacted even at the highest ATBS contents. Acrylamide (AM) hydrolysis was found to be inhibited by the presence of ATBS. This reduced AM conversion rate was believed to be the main reason for increased stability. For the brines tested herein hydrolysis rate was virtually uninfluenced by hardness/salinity, while viscosity was largely impacted. Hence it was concluded that different viscosity loss in various brines stems from carboxylate complexation equilibria and not altered hydrolysis rates. Temperature extrapolation was found to fit a simple Arrhenius approach and it has been suggested that the function should be sound up to around 70 mol% ATBS. With this methodology, the current dataset enabled the construction of a stability diagram for ATBS polymers (0-70 mol% ATBS) dissolved in seawater.",8,8,1
Degrees C.,High Temperature,"Ghasemi, M.; Astutik, W.; Alavian, S. A.; Whitson, C. H.; Sigalas, L.; Olsen, D.; Suicmez, V. S.",Impact of pressure on tertiary-CO2 flooding in a fractured chalk reservoir,Outcrop chalk: sea-water flooding; Single-fracture/matrix system; Tertiary-CF at high pressure; Diffusion,INJECTION,"The purpose of this study is to present the numerical and experimental evaluation of tertiary-CO2 flooding (CF) at high operating pressure and temperature conditions. In this study, water flooding is followed by CO2 injection into an outcrop chalk core with a centralized fracture. Our validated numerical models reproduce the results of core flooding experiments. The experiments used an outcrop core which is vertically placed in the core-holder with the total length of 28 cm and the diameter of 12.3 cm. The axial ""fracture"" is represented by a centralized hole with the diameter of 2.2 cm. We utilize the Wood's Metal technique to initially saturate the chalk core with the North-Sea-Chalk-Field (NSCF) live oil. The core sample is aged to restore the original chalk wettability at the operating conditions. Then, the water flooding (WF) is performed by injecting brine from the bottom of the fracture and producing the oil from the top. After no additional produced oil is observed, the WF is stopped. A ""shut-in"" period follows, which allows preparing the rig for tertiary-CO2 flooding. CO2 is then injected from the top and the hydrocarbon streams are produced from the bottom of the fracture. The whole core flooding is operated at constant reservoir conditions of 300 bara and 110 degrees C, which is higher than the initial NSCF reservoir pressure (258 bara and 110 degrees C). This allows us to investigate the efficiency of the tertiary-CF at a higher operating pressure condition. We employ a compositional reservoir simulation with a developed equation of state (EOS) to model the experiment. An automated history matching procedure is developed to match the experimental results. The modeling workflow is capable of taking into account the significant vaporization effect observed during CF when the rich-CO2 enters the three-phase separator. We accurately model the WF experiment through tuning the oil-water capillary pressure and relative permeability data. The numerical model is capable of reproducing the CF lab results by employing the best match multi-component diffusion coefficients. Moreover, we successfully model the excessive water production during CO2 injection by taking into account the hysteresis effect in water-oil capillary pressure and relative permeability. Comparing these results with our previous work at lower reservoir pressure shows the positive effect of pressure on increasing the efficiency of the tertiary-CF in recovering more oil from a matrix-fracture system. Also, the tuned capillary pressure and relative permeability during WF indicate an active imbibition drive and a strongly water-wet system. Our findings are an important step towards modeling the tertiary-CO2 flooding in an actual fracture-chalk system.",8,8,2
Degrees C.,Flow,"Li, Zhiyong; Wang, Sunan; Tao, Ye; Ma, Hongtao; Wu, Jiang",Research and application of the HTHS anti-H2S gel valve for underbalanced drilling,Underbalanced drilling (UBD); Gel valve; High temperature; Anti-H2S; High strength; Performance evaluation,,"Nowadays the whole underbalanced status of the well during underbalanced drilling process needs to be realized to a great extent, and gel valve is helpful to achieve it. However, there is occasionally H2S in the formation during underbalanced drilling (Hereinafter abbreviated as UBD), which will seriously affect the performance and lifetime of gel valve. Thus, in this paper, a formula of high temperature high strength (HTHS) anti-H2S gel valve was developed based on the optimization of different additives, such as hydrolyzed polyacryamide (HPAM), organic crosslinking agents, sulfur removal agents, etc., which could withstand temperature up to 320 degrees F(160 degrees C). The gel valve was made by crosslinking reaction at high temperature to form strong chemical bonds of spatial network structure. With its own strength and adhesion to the casing wall after gelation, the gel valve could meet the requirements for sealing. The properties of the final formula were evaluated, including viscosity, temperature stability, anti-H2S performance, gel sealing pressure, gel strength gel breaking performance, etc. In addition, a new evaluation apparatus for high toxic H2S invasion was designed specifically. The results show that the gel viscosity is around 50 mPa . s before being pumped into well, meaning a good fluidity. Its sealing pressure is high enough to balance downhole pressure and resist invasion of 10,000 ppm H2S after gelation. In addition, the gel valve can be completely broken after adding 10% breaking agents for 60 min, meaning it can easily flow back and does not influence the subsequent normal operations. Field application shows that the gel valve had good sealing property, peak of total hydrocarbon in gas logging increased from 0 to 66.6% before and after the gel broken. The gel flowed out completely after it was broken and there was successful ignition at the well site. Thus, the HTHS anti-H2S gel valve can effectively meet the operational requirements, and is an alternative method to achieve the target of the whole process of UBD operations.",2,3,0
Degrees C.,Flow,"Golkari, Abdolah; Riazi, Masoud",Comparative study of oil spreading characteristics for water and carbonated water systems using live and dead oils,Carbonated water alternating CO2 injection; Oil swelling phenomena; Oil spreading coefficient (SC); Equilibrium interfacial tension (EIFT); Optimum conditions; Live crude oil,EQUILIBRIUM PHASE COMPOSITIONS; MINIMUM MISCIBILITY PRESSURE; INTERFACIAL-TENSION; CRUDE-OIL; 3-PHASE FLOW; DIOXIDE; CO2; DENSITIES; RESERVOIR; RECOVERY,"In order to investigate the potential of water alternating gas (WAG) and carbonated water alternating gas (CWAG) injection methods, a series of interfacial tension (IFT) experiments for the binary systems of brine/carbonated brine (CB), carbon dioxide (CO2) and live and dead crude oils were performed. The experiments done using the axisymmetric drop shape analysis (ADSA) technique at temperatures of 40 degrees C and 50 degrees C and different pressures up to 13.79 MPa. The IFT results are used to estimate and determine optimum value of spreading coefficient, which is known as a key enhanced oil recovery (EOR) parameter at the pore scale. The experimental results demonstrate that CB decreases the equilibrium IFT of crude oil compared to the brine at the same conditions (for example, the difference of IFT is 5.2 mN/m and 7.6 mN/m at temperature of 40 degrees C and pressures of 2.76 and 13.79 Mpa, respectively). The equilibrium IFT of the live oil-brine/CB system is greater than that of dead oil-brine/CB. The estimated SC shows that the presence of CO2 in the aqueous phase significantly affects the SC value. That is, it becomes positive for the dead/live oil-CB-CO2 system, and improve the performance of EOR process while it is negative for the dead/live oil-brine-CO2 system. The presence of CH4 gas in the oil phase reduces the SC values at different pressure conditions. Moreover, using the SC results are determined the optimum conditions during CWAG injection. Based on the observed results in the dead/live oil-CB systems, swelling phenomena of the dead oil drop be slightly lower than that of the live oil drop.",2,2,1
Degrees C.,Flow,"Okereke, N. U.; Omotara, O. O.",Combining self-lift and gas-lift: A new approach to slug mitigation in deepwater pipeline-riser systems,Severe slugging; Self-lift; Gas-lift; Riser column; By-pass internal diameter,,"Recent slugging studies have identified the need to develop new and optimal slug mitigation strategies as the key gap in slugging studies. This paper focused on combining the self-lift and gas-lift slug mitigation strategies for slugging mitigation in deepwater scenarios. The Self-Lift Slug mitigation Strategy is a novel approach that involves tapping off gas via a by-pass pipe along the pipeline upstream of the riser. The gas is then re-introduced into the riser column via an injection point on the riser, to break the liquid slugs within the riser and mitigate severe slugging. This research investigated the performance of the Self-Lift Strategy when adapted to a deepwater oil field case scenario via OLGA simulation. An alternative scenario of combining self-lift and gas lift was also investigated. The approach for this study involved a robust methodology of firstly validating the field data by comparing pressure field data with OLGA simulation of the input data from the field. The field case consists of a 2712 m pipeline section and a 1513 m riser section. In this study, the severe slugging scenario was first run at the following flow conditions: well X1 was set up at 72.2 degrees C temperature and mass flow of 3.25 kg/s, well X2 was set up at 70.5 degrees C and 12.13 kg/s mass flow rate and the outlet section set up at 65.5 degrees C and pressure 20 bara. Self-lift was able to reduce holdup within the riser column, however pressure behaviour at the riser column was observed to be over 20 bara which is the design pressure for the inlets of the separator. Further studies involving a combination of Self-lift and gas lift at 8 kg/s and 2 inches by-pass internal diameter, indicated that the pressure at the riser column was reduced to 20 bara, allowing for stable flow into the separator.",2,2,2
Degrees C.,Flow,"Brito, Adriana; Guzman, Nolides; Rojas-Solorzano, Luis; Zambrano, Tibisay",Rheological study of two- and three-phase highly viscous fluid flow in pipelines,Foam rheology; Foamed emulsion; Two-phase flow; Three-phase flow; Flow patterns; Pressure drop model,GAS-LIQUID FLOW; HORIZONTAL PIPES; 2-PHASE FLOW; FOAMS; TRANSPORT; STABILITY,"The study of highly viscous multiphase flow systems is of fundamental interest in the oil industry. Most of the Venezuelan oil fields produce heavy oil with other production fluids, such as water and gas, and sand particles flowing from the reservoir to the surface facilities. A fraction of these phases flows fully separated, while another one flows as a dispersed system composed by water/oil emulsion with gas bubbles dispersed as a foamed emulsion. With the objective to understand and characterize this latter complex system, new experiments have been performed in 0.0243-m and 0.0508-m horizontal pipelines, for air/highly-viscous oil of 0.430 Pa s at 20 degrees C, and water/air/oil mixture with a water-in-oil emulsion of 0.560 Pa s at 20 degrees C. The three-phase flow pressure gradient was found to be approximately 15% higher than for the two-phase system, at similar gas and liquid superficial velocities. The air/oil and air/oil/water foamed emulsion behaved as non-Newtonian fluids, when these are considered as pseudo-homogeneous systems. A model to predict the flow pattern and pressure drop in horizontal pipelines was developed with an extensive database of 2167 experimental points, including new data and information collected and processed from different sources. A performance factor of 0.41 for Brito's three-phase (TM) model was consistently better than the performance factor obtained for other models commonly used by the oil and gas industry in similar multiphase flow systems.",3,3,0
Degrees C.,Flow,"Guo, Jixiang; Yang, Yuqi; Zhang, Shuai; Zhang, Dengshan; Cao, Chang; Ren, Bo; Liu, Lei; Xing, Yu; Xiong, Ruiying",Heavy oil-water flow patterns in a small diameter vertical pipe under high temperature/pressure conditions,Upward oil-water flows; Flow patterns; High pressure; High temperature; Heavy oil,NATURAL CIRCULATION LOOP; LIQUID ANNULAR-FLOW; 2-PHASE FLOW; PRESSURE-DROP; INTERFACIAL-TENSION; HORIZONTAL PIPES; PHASE INVERSION; VOLUME FRACTION; DISPERSED FLOW; OPTICAL PROBE,"Experimental measurements were conducted to investigate the upward oil-water flow patterns in a small diameter vertical pipe (0.01m I.D.) under high temperatures up to 130 degrees C and high pressures up to 20 MPa. The viscosity of the oil sample was 584.24 mPa s and the density was 1.899 g/cm(3) at 30 degrees C. The effects of pressure, temperature, input water fraction (IWF) and mixture velocity on the flow patterns were systematically investigated. The observed flow patterns were plotted on a flow pattern map in which input water fraction was used as the y-axis and the mixture velocity was used as the x-axis. Based on the measurement results, the following flow patterns were observed: water-in-oil dispersed flow (D w/o), water-in-oil bubbly flow (B w/o), water-in-oil slug flow (S w/o), water-in-oil creep flow (CE w/o), churn flow (Churn) and core annual flow (AF). Phase inversion was not observed in this work. With an increase in temperature at a given input water fraction, S w/o, CE w/o and Churn flow with large water drops tended to transform into B w/o and D w/o with smaller water drops, the CE w/o disappears gradually, and the boundaries in the flow pattern maps tend to occur at lower input water fraction values. The effect of pressure on the flow patterns was found to be opposite to that of temperature. The possible causes leading to the changes in the flow patterns subjected to pressure/temperature variations were provided in terms of changes in density ratio, interfacial tension, and viscosity ratio of oil and water.",3,4,3
Degrees C.,Flow,"Zhong, Xun; Liu, Dexin; Shi, Xiaofei; Zhao, Hongtao; Pei, Chun; Zhu, Tongyu; Shao, Minglu; Zhang, Fang",Characteristics and functional mechanisms of clay-cement stabilized three-phase nitrogen foam for heavy oil reservoir,Heavy oil reservoir; Clay-cement three-phase foam; High stability; Water shutoff agent,HYDROPHOBIC NANOPARTICLES; DILATIONAL PROPERTIES; NANO-PARTICLES; AQUEOUS FOAMS; DEMULSIFIERS; RECOVERY; BUBBLES,"The large-scale application of two-phase foam flooding in heavy oil reservoirs was restricted due to the instability of foam itself. However, the developed clay-cement three-phase nitrogen foam can make up for the short broad effectively, which benefits from very good thermal stability, salt resistance, oil sensitivity and excellent plugging performance. In this paper, 8.0 wt% clay, 0.50 wt% cement particles and 1.0 wt% foaming agent were used to generate clay-cement nitrogen foam. The synergistic effects of clay/cement reaction products, particle adsorption layer and steric network contribute to a desirable protective sheath covered compact three-phase foam system with high stability and strength, the half-life of which was 42.0 min at 95 degrees C. Moreover, it became more stable when formation sands exist. Generally, clay-cement three-phase nitrogen foam has three kinds of plugging form owing to different formation permeability. In less permeable formations, most foam would separate into two parts, with particles stacking at the entry end and two-phase foam moving forward. While in formations with higher permeability, all foam would flow out directly without effective plugging. Only when it comes to the formations with proper permeability can this foam achieve impressive plugging strength under the effects of Jamin and particle plugging. In addition, the foaming formula can be modified by adjusting particle-surfactant concentrations to fit various formations. Therefore, it is a promising and widely applicable water shutoff agent for heavy oil reservoirs.",8,9,1
Degrees C.,Flow,"Chen, Gang; Yuan, Weihua; Zhang, Fan; Gu, Xuefan; Du, Weichao; Zhang, Jie; Li, Jinling; Qu, Chengtun",Application of polymethacrylate from waste organic glass as a pour point depressor in heavy crude oil,Waste organic glass; Polymethyl methacrylate; Polymethacrylate; Crude oil; Pour point depressor,FLOW IMPROVER; ADDITIVES; WAX,"Polymethyl methacrylate (PMMA, organic glass) is widely used as a substitute for glass, known as organic glass. During the processing and after use, there are amount of castoff. Based on the similar framework, PMMA could be useful the feed stock to synthesis polymethacrylate (PMA) used for crude oil additive. In this work PMA was prepared by transesterification of PMMA and aliphatic alcohol catalyzed by a base. The performance of PMA on heavy oil was evaluated as pour point depressant as well as viscosity reducer. The highest pour point reduction depression was achieved as 7.1 degrees C with the dosage of 2000 ppm PMA-1. The viscosity of crude oil was also substantially reduced from 182000 mPa.s to 64500 mPa.s. Differential scanning calorimetry and paraffin crystal morphology studies were clearly reflected that PMA affects the wax crystallization of crude oil. Base on this work, the waste organic glass can be reused as a valuable material in oil field.",8,8,4
Degrees C.,Interfacial Tension,"Golkari, Abdolah; Riazi, Masoud",Comparative study of oil spreading characteristics for water and carbonated water systems using live and dead oils,Carbonated water alternating CO2 injection; Oil swelling phenomena; Oil spreading coefficient (SC); Equilibrium interfacial tension (EIFT); Optimum conditions; Live crude oil,EQUILIBRIUM PHASE COMPOSITIONS; MINIMUM MISCIBILITY PRESSURE; INTERFACIAL-TENSION; CRUDE-OIL; 3-PHASE FLOW; DIOXIDE; CO2; DENSITIES; RESERVOIR; RECOVERY,"In order to investigate the potential of water alternating gas (WAG) and carbonated water alternating gas (CWAG) injection methods, a series of interfacial tension (IFT) experiments for the binary systems of brine/carbonated brine (CB), carbon dioxide (CO2) and live and dead crude oils were performed. The experiments done using the axisymmetric drop shape analysis (ADSA) technique at temperatures of 40 degrees C and 50 degrees C and different pressures up to 13.79 MPa. The IFT results are used to estimate and determine optimum value of spreading coefficient, which is known as a key enhanced oil recovery (EOR) parameter at the pore scale. The experimental results demonstrate that CB decreases the equilibrium IFT of crude oil compared to the brine at the same conditions (for example, the difference of IFT is 5.2 mN/m and 7.6 mN/m at temperature of 40 degrees C and pressures of 2.76 and 13.79 Mpa, respectively). The equilibrium IFT of the live oil-brine/CB system is greater than that of dead oil-brine/CB. The estimated SC shows that the presence of CO2 in the aqueous phase significantly affects the SC value. That is, it becomes positive for the dead/live oil-CB-CO2 system, and improve the performance of EOR process while it is negative for the dead/live oil-brine-CO2 system. The presence of CH4 gas in the oil phase reduces the SC values at different pressure conditions. Moreover, using the SC results are determined the optimum conditions during CWAG injection. Based on the observed results in the dead/live oil-CB systems, swelling phenomena of the dead oil drop be slightly lower than that of the live oil drop.",2,2,1
Degrees C.,Interfacial Tension,"Guo, Jixiang; Yang, Yuqi; Zhang, Shuai; Zhang, Dengshan; Cao, Chang; Ren, Bo; Liu, Lei; Xing, Yu; Xiong, Ruiying",Heavy oil-water flow patterns in a small diameter vertical pipe under high temperature/pressure conditions,Upward oil-water flows; Flow patterns; High pressure; High temperature; Heavy oil,NATURAL CIRCULATION LOOP; LIQUID ANNULAR-FLOW; 2-PHASE FLOW; PRESSURE-DROP; INTERFACIAL-TENSION; HORIZONTAL PIPES; PHASE INVERSION; VOLUME FRACTION; DISPERSED FLOW; OPTICAL PROBE,"Experimental measurements were conducted to investigate the upward oil-water flow patterns in a small diameter vertical pipe (0.01m I.D.) under high temperatures up to 130 degrees C and high pressures up to 20 MPa. The viscosity of the oil sample was 584.24 mPa s and the density was 1.899 g/cm(3) at 30 degrees C. The effects of pressure, temperature, input water fraction (IWF) and mixture velocity on the flow patterns were systematically investigated. The observed flow patterns were plotted on a flow pattern map in which input water fraction was used as the y-axis and the mixture velocity was used as the x-axis. Based on the measurement results, the following flow patterns were observed: water-in-oil dispersed flow (D w/o), water-in-oil bubbly flow (B w/o), water-in-oil slug flow (S w/o), water-in-oil creep flow (CE w/o), churn flow (Churn) and core annual flow (AF). Phase inversion was not observed in this work. With an increase in temperature at a given input water fraction, S w/o, CE w/o and Churn flow with large water drops tended to transform into B w/o and D w/o with smaller water drops, the CE w/o disappears gradually, and the boundaries in the flow pattern maps tend to occur at lower input water fraction values. The effect of pressure on the flow patterns was found to be opposite to that of temperature. The possible causes leading to the changes in the flow patterns subjected to pressure/temperature variations were provided in terms of changes in density ratio, interfacial tension, and viscosity ratio of oil and water.",3,4,3
Degrees C.,Interfacial Tension,"Lele, Pushan; Syed, Abdul Haseeb; Riordon, Jason; Mosavat, Nader; Guerrero, Adriana; Fadaei, Hossein; Sinton, David",Deformation of microdroplets in crude oil for rapid screening of enhanced oil recovery additives,EOR; Droplet deformation; Heavy oil; Interfacial tension; Alkaline flooding,INTERFACIAL-TENSION MEASUREMENT; MICROFLUIDICS-BASED MEASUREMENT; ASSISTED GRAVITY DRAINAGE; ON-A-CHIP; HEAVY OIL; IONIC-STRENGTH; SURFACTANT SOLUTIONS; BITUMEN EXTRACTION; SAGD PROCESSES; SYSTEMS,"We present a microfluidic method to rapidly screen enhanced oil recovery additives based on the deformation of aqueous microdroplets in oil. Conventional methods, such as the pendant drop method, are hindered by large fluid volumes that require several hours to thermally equilibrate between measurements. Here we demonstrate a complementary technology to conventional methods, by which additives can be rapidly screened to select the best candidates for further study. Our glass chip establishes thermal equilibrium (demonstrated at 80 degrees C) of undiluted, highly viscous, crude oil within seconds, and enables the rapid quantification of water-in-crude oil droplet deformation within minutes, at a reservoir-relevant scale. The influence of two alkaline additives, a surfactant and a salt in the injected water phase were quantified, demonstrating the applicability of our method to a variety of recovery strategies.",5,5,2
Degrees C.,Interfacial Tension,"Karimi, Masoud; Shirazi, Meisam Mohammadzadeh; Ayatollahi, Shahab",Investigating the effects of rock and fluid properties in Iranian carbonate matrix acidizing during pre-flush stage,Matrix acidizing; Pre-flush fluid; Wettability alteration; IFT reduction; Dissolution rate,WETTABILITY ALTERATION; OIL-WET; INTERFACIAL-TENSION; REACTION-KINETICS; HIGH-TEMPERATURE; ACID; SURFACTANT; DISSOLUTION; STIMULATION; ACIDIZATION,"Acidizing of carbonate oil-wet rocks saturated with oil and saline formation water is subjected failure in some cases due to acid-induced damage such as sludge and emulsion formations. This condition may also lead to mineral precipitation, oil film barrier between acid and rock and diversion chemical malfunctions. Therefore, pre-flush process has been proposed as one of the most efficient stage for oil-wells matrix acidizing to reduce these challenges significantly. Besides, the pre-flush stage would result in more clean rock as the reservoir fluids are pushed back from the near wellbore regions, restoring rock wettability to more water wet state, preventing direct acid-oil contact and cooling rock surface to control acid-rock reaction at high temperature reservoir. This laboratory work is designed to study the effectiveness of three different pre-flush fluids and assess their ability in reducing interfacial tension (IFT) to displace original reservoir fluids around the wellbore as well as changing the rock wettability to increase rock dissolution rate. The results showed that a 0.5% wt of C16TAB aqueous solution (cationic surfactant additive) has passed successfully the pre-flush optimization criteria which can be utilized as pre-flush fluid of the carbonate oil-wet acidizing. It was shown that the wettability and IFT were changed quickly as it is requested for the pre-flush stage. The contact angle was decreased from 172 degrees to 33 degrees in two hours period and the IFT was reduced from 8.9 to 0.62 (dyne/cm) at reservoir condition (P = 4000 psia, T = 85 degrees C). In addition, the dissolution rate of dolomite rock from an Iranian oil reservoir at three different states of oil-wet, water-wet and pre-flush treated with 15% HCl was measured and compared. The measured dissolution rate of initially water-wet rock was measured to be 1 x 10(-4) mol/cm(2).s which is the same as the dissolution rate measured for C16TAB treated oil wet rock. This confirms the suitable wettability alteration through C16TAB pre-flush.",6,6,1
Degrees C.,CO2,"Golkari, Abdolah; Riazi, Masoud",Comparative study of oil spreading characteristics for water and carbonated water systems using live and dead oils,Carbonated water alternating CO2 injection; Oil swelling phenomena; Oil spreading coefficient (SC); Equilibrium interfacial tension (EIFT); Optimum conditions; Live crude oil,EQUILIBRIUM PHASE COMPOSITIONS; MINIMUM MISCIBILITY PRESSURE; INTERFACIAL-TENSION; CRUDE-OIL; 3-PHASE FLOW; DIOXIDE; CO2; DENSITIES; RESERVOIR; RECOVERY,"In order to investigate the potential of water alternating gas (WAG) and carbonated water alternating gas (CWAG) injection methods, a series of interfacial tension (IFT) experiments for the binary systems of brine/carbonated brine (CB), carbon dioxide (CO2) and live and dead crude oils were performed. The experiments done using the axisymmetric drop shape analysis (ADSA) technique at temperatures of 40 degrees C and 50 degrees C and different pressures up to 13.79 MPa. The IFT results are used to estimate and determine optimum value of spreading coefficient, which is known as a key enhanced oil recovery (EOR) parameter at the pore scale. The experimental results demonstrate that CB decreases the equilibrium IFT of crude oil compared to the brine at the same conditions (for example, the difference of IFT is 5.2 mN/m and 7.6 mN/m at temperature of 40 degrees C and pressures of 2.76 and 13.79 Mpa, respectively). The equilibrium IFT of the live oil-brine/CB system is greater than that of dead oil-brine/CB. The estimated SC shows that the presence of CO2 in the aqueous phase significantly affects the SC value. That is, it becomes positive for the dead/live oil-CB-CO2 system, and improve the performance of EOR process while it is negative for the dead/live oil-brine-CO2 system. The presence of CH4 gas in the oil phase reduces the SC values at different pressure conditions. Moreover, using the SC results are determined the optimum conditions during CWAG injection. Based on the observed results in the dead/live oil-CB systems, swelling phenomena of the dead oil drop be slightly lower than that of the live oil drop.",2,2,1
Degrees C.,CO2,"Wang, Kongyang; Yan, Wei; Deng, Jingen; Tian, Hao; Li, Wenbo; Wang, Yangang; Wang, Luyao; Ye, Sutao",Experimental study on H2S and CO2 generation capacities of the Bohai bay heavy oil,Heavy oil; Thermal recovery; Pyrolysis; H2S and CO2 generation; Partial pressure,CYMBOPOGON FLEXUOSUS BIOFUEL; FIREFLOOD FIELD PROJECTS; DIESEL-ENGINE; EMISSION CHARACTERISTICS; RECOVERY STRATEGIES; GRAVITY DRAINAGE; BIODIESEL BLEND; PERFORMANCE; COMBUSTION; RESERVOIRS,"Thermal recovery is a conventional technology for heavy oil development. During thermal oil recovery the reservoir could generate H2S and CO2. They will potentially threat the safety of downhole tubing regarding the sweet or sour corrosion. In some Bohai heavy oil fields CO2 and H2S under thermal recovery conditions lead to some corrosion problems of the tubing and equipment. Therefore, to determine the corrosive gas generation capacity is crucial for anti-corrosion design of downhole tubing and casing. Heavy oil samples from Bohai, China were experimentally studied for their pyrolysis characteristics using high-temperature-high-pressure autoclaves. The gases were collected when autoclaves cooled down to the in situ formation temperature. Effects of temperature, water chemistry and core mineral on corrosive gas generation were investigated. The results show that total pressure increase significantly when temperature reached 250 degrees C-280 degrees C under the single heavy oil condition. The additional water facilitates the reaction process, after more SO42- added in the mimic formation water, higher H2S content is obtained. Under the condition of multiphase of oil, formation water and cores, both of the H2S and CO2 content increase obviously, and the cores' effect on CO2 is greater than H2S. Anti-corrosion design usually concerns only the highest corrosive gas concentration without further analysis. The highest concentration does not always correspond to the best corrosive gases generation capacities of heavy oil. Comprehensive analysis of both the total pressure of reaction process and the quality of the reaction heavy oil is carried out, then the corrosive gases volume per unit mass of heavy oil is calculated. These can determine the strongest corrosive formation environment and the maximum gases generation capacities of heavy oil.",4,4,3
Degrees C.,CO2,"Zhu, Dongya; Meng, Qingqiang; Liu, Quanyou; Zhou, Bing; Jin, Zhijun; Hu, Wenxuan",Natural enhancement and mobility of oil reservoirs by supercritical CO2 and implication for vertical multi-trap CO2 geological storage,Supercritical CO2; Reservoir enhancement; Dawsonite; Geological storage; Huangqiao reservoir,RARE-EARTH-ELEMENT; CARBON-DIOXIDE; FLUID INCLUSIONS; SALINE AQUIFERS; BASIN; SEQUESTRATION; ACCUMULATION; GAS; RECOVERY; MODEL,"The accumulation and production of both deep mantle-derived CO2 and light oil were discovered in the Huangqiao reservoir, which is located in the Subei Basin, East China. The Huangqiao reservoir shows that both CO2 and oil are entrapped in and produced from vertical multi-traps. The effects of deep CO2 on the accumulation and production of oil under natural conditions and the implications for CO2 geological storage are investigated in detail. The fluid inclusions in quartz or calcite veins from the Silurian Fentou Formation (S(2-3)f), Permian Longtan Formation (P(2)l) and Triassic Qinglong Formation (T(1)q) have homogenization temperatures (Ths) that display peak ranges of 180 degrees C-190 degrees C, 170 degrees C-180 degrees C and 150 degrees C-160 degrees C, respectively. The Ths are higher than the formation temperatures. The calcite veins have light carbon and oxygen isotope compositions and have high Sr-87/Sr-86 ratios and positive Eu anomalies. These characteristics reveal the activities of deep CO2-rich hydrothermal fluids in the basin strata. The feldspar in the S(2-3)f and P(2)l sandstone reservoirs underwent significant dissolution because of the presence of CO2-rich fluids, forming of a large amount of secondary pores in the sandstone reservoirs and enhancing the reservoirs' physical properties. The measured porosity reaches 12.3%. CO2 in a supercritical state extracted or dissolved light petroleum components out of sedimentary rocks and then carried them towards reservoirs. Thus, CO2 and oil co-accumulated in the enhanced reservoirs, e.g. S(2-3)f, P(2)l and T(1)q. During drilling development, this supercritical CO2 naturally increased the mobility of oil, resulting in the co-production of highly pure CO2 and light oil. Based on the unique features of the Huangqiao CO2-oil reservoir, we propose a new CO2 geological storage model, namely, a vertical multi-trap geological storage model, which can either entrap large volumes of CO2 or lower the risk of long-term storage.",5,7,4
Degrees C.,CO2,"Ghasemi, M.; Astutik, W.; Alavian, S. A.; Whitson, C. H.; Sigalas, L.; Olsen, D.; Suicmez, V. S.",Impact of pressure on tertiary-CO2 flooding in a fractured chalk reservoir,Outcrop chalk: sea-water flooding; Single-fracture/matrix system; Tertiary-CF at high pressure; Diffusion,INJECTION,"The purpose of this study is to present the numerical and experimental evaluation of tertiary-CO2 flooding (CF) at high operating pressure and temperature conditions. In this study, water flooding is followed by CO2 injection into an outcrop chalk core with a centralized fracture. Our validated numerical models reproduce the results of core flooding experiments. The experiments used an outcrop core which is vertically placed in the core-holder with the total length of 28 cm and the diameter of 12.3 cm. The axial ""fracture"" is represented by a centralized hole with the diameter of 2.2 cm. We utilize the Wood's Metal technique to initially saturate the chalk core with the North-Sea-Chalk-Field (NSCF) live oil. The core sample is aged to restore the original chalk wettability at the operating conditions. Then, the water flooding (WF) is performed by injecting brine from the bottom of the fracture and producing the oil from the top. After no additional produced oil is observed, the WF is stopped. A ""shut-in"" period follows, which allows preparing the rig for tertiary-CO2 flooding. CO2 is then injected from the top and the hydrocarbon streams are produced from the bottom of the fracture. The whole core flooding is operated at constant reservoir conditions of 300 bara and 110 degrees C, which is higher than the initial NSCF reservoir pressure (258 bara and 110 degrees C). This allows us to investigate the efficiency of the tertiary-CF at a higher operating pressure condition. We employ a compositional reservoir simulation with a developed equation of state (EOS) to model the experiment. An automated history matching procedure is developed to match the experimental results. The modeling workflow is capable of taking into account the significant vaporization effect observed during CF when the rich-CO2 enters the three-phase separator. We accurately model the WF experiment through tuning the oil-water capillary pressure and relative permeability data. The numerical model is capable of reproducing the CF lab results by employing the best match multi-component diffusion coefficients. Moreover, we successfully model the excessive water production during CO2 injection by taking into account the hysteresis effect in water-oil capillary pressure and relative permeability. Comparing these results with our previous work at lower reservoir pressure shows the positive effect of pressure on increasing the efficiency of the tertiary-CF in recovering more oil from a matrix-fracture system. Also, the tuned capillary pressure and relative permeability during WF indicate an active imbibition drive and a strongly water-wet system. Our findings are an important step towards modeling the tertiary-CO2 flooding in an actual fracture-chalk system.",8,8,2
Degrees C.,Steam,"da Silva, Italo Batista; Martinelli, Antonio Eduardo; Medeiros de Souza, Wendell Rossine; de Oliveira Freitas, Julio Cezar; Felipe Rodrigues, Marcos Alysson",Dilatometric behavior and crystallographic characterization of Portland-polyurethane composites for oilwell high-temperature cementing applications,Oilwell cementing; Portland cement; Polyurethane and thermal expansion,THERMAL-EXPANSION; WELL CEMENT; HYDRATION,"In order to improve the behavior of Portland-based oilwell sheath to high-temperature applications and the corresponding thermal gradients, polymeric admixtures can be added. Steam injection, for instance, raises the cement sheath-steel casing interface temperature to similar to 300 degrees C which can be deleterious to the mechanical stability and zonal isolation provided by the cement sheath as a result of cracking of the cement. Polyurethane can be added to the cement to improve its plastic behavior and reduce the thermal expansion mismatch between casing and sheath. However, the use polymeric admixtures, especially as aqueous dispersion, can affect the kinetics of the hydration reactions and, as a consequence, the crystallographic composition and coefficient of thermal expansion of the material. Therefore, the present study aimed at evaluating the effects of the addition of different concentrations of polyurethane on the thermomechanical properties of Portland cement pastes cured at 300 degrees C from 14 to 90 days. Formulations containing 1 gpc (0.052 kg), 2 gpc (0.102 kg) and 3 gpc (0.153 kg) of polyurethane, respectively named PU1, PU2 and PU3 were prepared according to the American Petroleum Institute guidelines. A standard PU-free slurry was also prepared. X-ray diffraction and dry dilatometric tests were carried out. The results revealed that the curing time does affect the kinetics of hydration of Portland-polyurethane composites, retarding the formation of high-temperature stable phases, i.e., tobermorite and xonotlite. Moreover, longer curing times were necessary to reveal the improved expansion of the composites with respect to the standard sample. The addition of polyurethane can be pointed as an approach to high-temperature oilwell cement applications, since it reduces the thermal mismatch between cement sheath and steel casing for and retards but do not prevent the formation of xonotlite.",4,4,0
Degrees C.,Steam,"Leyva-Gomez, H.; Babadagli, Tayfun",Efficiency of heavy-oil/bitumen recovery from fractured carbonates by hot-solvent injection,Injection parameters optimization; Heavy oil; Hot solvent; Fractured carbonate reservoirs; Oil dilution,RESERVOIRS SOS-FR; OIL-RECOVERY; BITUMEN RECOVERY; ASPHALTENE DEPOSITION; VAPOR EXTRACTION; AIDED PROCESS; STEAM; SIMULATION; SANDS; PILOT,"This paper presents an extensive analysis of three different solvents injected through two different rock types under dynamic conditions, at elevated temperatures, to recover heavy-oil/bitumen from fractured carbonates. The main idea was to identify the optimal temperatures needed for maximal recovery by hot solvent injection for a wide range of solvents. We also considered the optimal conditions for effective solvent retrieval for the economics of this type recovery approach. In order to represent a wide range of carbon number solvents, heptane and naphtha were injected at atmospheric pressure and temperatures ranging from 70 to 120 degrees C and 21.5-100 degrees C, respectively. Propane was injected at a pressure of 1483-1511 kPa and a temperature ranging from 22 to 60 degrees C to be in the liquid phase. Indiana limestone (outcrop) and vuggy naturally fractured carbonate samples (outcrop core samples from a producing formation in Mexico) were selected as core samples. Hot solvent was injected continuously through artificially fractured cores followed by hot water (or steam injection) phase for solvent retrieval. The optimal temperatures for heavy oil recovery and solvent retrieval, in the subsequent hot water injection, for each kind of rock sample and type of solvent were determined. The results revealed that heavy oil recovery increase with the solvent carbon number used. Also, it was observed that when the temperature is higher than the saturation value for the given pressure curve, the recovery decreases and the lightest component of the heavy oil are dragged by the gas stream.",5,5,1
Degrees C.,Steam,"Yang, Shangyu; Han, Lihong; Feng, Chun; Wang, Hang; Feng, Yaorong; Wu, Xingru",Mechanical performance of casing in in-situ combustion thermal recovery,Casing performance; Heavy oil; In-situ combustion; Casing design; Steam flooding,OIL; WELLS,"In-situ combustion is often used to develop heavy oil as it has multiple advantages over alternative thermal methods. However, the wellbore integrity can be compromised if the casing is not properly designed or manufactured. Based on the fundamentals of heat transfer, a mathematical model with multiphysics is built to study the temperature and pressure distributions surrounding the wellbore during in-situ combustion. In laboratory, real casings and coupons with grades of N80, P110, and 3Cr110 were tested under high temperature to study their mechanical performances in the in-situ combustion recovery. From the modeling and laboratory testing results, we propose the casing design and manufacture protocols for thermal recovery of heavy oil. Field applications in Liaohe oil field, Du-66 Block, shows that the mechanical deterioration of P110 and 3Cr110 is less than that of N80 and the mechanical performance stability of 3Cr110 is better than others when the temperature is less than 600 degrees C. When the temperature is above 600 degrees C for more than 10 h, the mechanical performance of all casing grades declines quickly. Applying finite element analysis, we recommend a safety factor of 1.1 for designing casing at the temperatures of 250 degrees C,480 degrees C and 485 degrees C. The finding of this study provides fundamentals for the casing design and material selection for in-situ combustion recovery.",6,6,0
Degrees C.,Steam,"Liu, Pengcheng; Yuan, Zhe; Zhang, Shengfei; Xu, Zhenhua; Li, Xiuluan",Experimental study of the steam distillation mechanism during the steam injection process for heavy oil recovery,Heavy oil; Steam distillation; Distillation rate; Superheated steam; Degree of superheating,SIMULATION; SOLVENT; DRIVE; FIELD,"Steam distillation can effectively enhance heavy oil recovery during steam injection process in heavy oil reservoirs. However, the mechanism of steam distillation is complex, and the changes in oil properties during distillation remain unclear. In this study, three comparative steam distillation experiments were designed and conducted, including distillation processes employing saturated steam, steam superheated by 10 degrees C, and steam superheated by 40 degrees C. Heavy oil samples were derived from the Jin-1 Block in a typical heavy oilfield, in China. The density, viscosity, SARA fractions, and carbon number distribution of the residual oil were compared to those obtained before conducting steam distillation experiments. The steam distillation rates obtained with steam superheated by 40 degrees C, steam superheated by 10 degrees C, and saturated steam were 11.158%, 10.903% and 10.423%, respectively. The results indicate that the steam distillation rate of heavy oil increases significantly with increasing degree of superheating. During the steam distillation process, the density and viscosity of residual oil increase, the contents of saturated hydrocarbons and resin decrease, and the contents of aromatic hydrocarbons and asphaltenes increase. In addition, analysis of the distilled components indicates that lightweight components with smaller carbon numbers are removed firstly by steam distillation, followed by heavier components with larger carbon numbers. Moreover, all hydrocarbons with carbon numbers less than C-22 are removed from heavy oil in the distillation process, while the maximum carbon number of the distilled components was C-34. This study is favorable for understanding the changes in the properties of residual oil after distillation during the steam injection process for heavy oil recovery.",8,8,7
Degrees C.,Oxygen,"Zhu, Dongya; Meng, Qingqiang; Liu, Quanyou; Zhou, Bing; Jin, Zhijun; Hu, Wenxuan",Natural enhancement and mobility of oil reservoirs by supercritical CO2 and implication for vertical multi-trap CO2 geological storage,Supercritical CO2; Reservoir enhancement; Dawsonite; Geological storage; Huangqiao reservoir,RARE-EARTH-ELEMENT; CARBON-DIOXIDE; FLUID INCLUSIONS; SALINE AQUIFERS; BASIN; SEQUESTRATION; ACCUMULATION; GAS; RECOVERY; MODEL,"The accumulation and production of both deep mantle-derived CO2 and light oil were discovered in the Huangqiao reservoir, which is located in the Subei Basin, East China. The Huangqiao reservoir shows that both CO2 and oil are entrapped in and produced from vertical multi-traps. The effects of deep CO2 on the accumulation and production of oil under natural conditions and the implications for CO2 geological storage are investigated in detail. The fluid inclusions in quartz or calcite veins from the Silurian Fentou Formation (S(2-3)f), Permian Longtan Formation (P(2)l) and Triassic Qinglong Formation (T(1)q) have homogenization temperatures (Ths) that display peak ranges of 180 degrees C-190 degrees C, 170 degrees C-180 degrees C and 150 degrees C-160 degrees C, respectively. The Ths are higher than the formation temperatures. The calcite veins have light carbon and oxygen isotope compositions and have high Sr-87/Sr-86 ratios and positive Eu anomalies. These characteristics reveal the activities of deep CO2-rich hydrothermal fluids in the basin strata. The feldspar in the S(2-3)f and P(2)l sandstone reservoirs underwent significant dissolution because of the presence of CO2-rich fluids, forming of a large amount of secondary pores in the sandstone reservoirs and enhancing the reservoirs' physical properties. The measured porosity reaches 12.3%. CO2 in a supercritical state extracted or dissolved light petroleum components out of sedimentary rocks and then carried them towards reservoirs. Thus, CO2 and oil co-accumulated in the enhanced reservoirs, e.g. S(2-3)f, P(2)l and T(1)q. During drilling development, this supercritical CO2 naturally increased the mobility of oil, resulting in the co-production of highly pure CO2 and light oil. Based on the unique features of the Huangqiao CO2-oil reservoir, we propose a new CO2 geological storage model, namely, a vertical multi-trap geological storage model, which can either entrap large volumes of CO2 or lower the risk of long-term storage.",5,7,4
Degrees C.,Oxygen,"Wu, Fei-peng; Liu, Jing; Wei, Xue-mei; Pu, Chun-sheng",A study on oxygen consumption mechanism of air-foam flooding in low-temperature oil reservoir,Low temperature and permeability oil reservoir; Air injection; Oxygen consumption mechanism; Oxygen consumption rate; Field test,AQUEOUS-SOLUTION; POLYMER GELS; OXIDATION; POLYACRYLAMIDE; INJECTION; DEGRADATION; SOLUBILITY; KINETICS; STABILITY; GAS,"Air flooding/air-foam flooding recovery technology has been attracting attention in oilfield development. The key point to the application of this technology is to ensure that the oxygen injected with the air can be fully dissipated inside the reservoir to lower the explosion risk in production wells and reduce the oxidation of the pipeline. It is generally believed that the oxygen and crude oil can react more in low-temperature-oxidation (LTO) reactions above 80 degrees C. As a large amount of oxygen would be spontaneously consumed at this temperature, this technology is mainly used in reservoirs where the temperature is greater than 80 degrees C. In the fractured low-permeability reservoir of China's Yanchang oilfield, where the reservoir temperature is only approximately 30 degrees C, a wide range of crude oil LTO would not be triggered theoretically. However, we found that the oxygen content of the associated gas in the gas channeling wells is significantly lower than that in the air. This phenomenon suggests that, there are other factors that could consume oxygen apart from the LTO reaction. To verify this assumption, an oxygen dissipation core flooding experiment at 30 degrees C and 80 degrees C was carried out to evaluate the oxygen consumption at different temperatures. At the same time, in order to determine the main controlling factors and dissipation mechanisms of oxygen dissipation, theoretical analyses and experimental studies were carried out from the aspects of reductive mineral oxidation reaction in the rock surface and formation water, the physical absorption of the micropore and the dissolution of the reservoir fluid. The results show that at the same experimental conditions, the oxygen consumption at 30 degrees C is 38.14% lower than that at 80 degrees C. The oxygen consumption factors in the low-temperature reservoir mainly include the chemical reactions between the oxygen and reducing minerals, dissolution and retention of formation water and oil, adsorption of Van der Waals forces in the reservoir and physical electronic adsorption of the hydrogen-sulfur bonds and carbon-sulfur bonds. In Chang 6 Reservoir of Ganguyi oilfield, formation water could theoretically consume 56 mg/L (1.75 mmol/L) oxygen through dissolved Fe2+. The dissolution by formation water could absorb 11.85 mmol/L oxygen (experimental value). The dissolution by oil could absorb 69.25 mmol/L oxygen (experimental test value), and the oxygen physical adsorption rate of rock pore surface was 1.26 mmol/L. Together with the pilot test data, the results show that the LTO reaction of the stratum crude oil barely occurs in the reservoir at low temperature (30 degrees C). However, a large amount of oxygen dissipation could still be achieved. This study demonstrates that air-foam flooding could break the applicable limit temperature and could also be applied in low-temperature reservoirs.",7,7,1
Degrees C.,Oxygen,"Sandengen, K.; Meldahl, M. M.; Gjersvold, B.; Molesworth, P.; Gaillard, N.; Braun, O.; Antignard, S.",Long term stability of ATBS type polymers for enhanced oil recovery,,C-13 NMR-SPECTROSCOPY; ELEVATED-TEMPERATURE; AQUEOUS-SOLUTION; HYDROLYSIS; POLYACRYLAMIDE; COPOLYMERS; OXYGEN; IRON,"In offshore enhanced oil recovery (EOR) applications polymer residence time within the reservoir could be many years. Long term stability (preservation of solution viscosity) within the anaerobic reservoir is a fundamental property of the polymer chemical and consequently highly important for choosing a proper product. For high temperature and/or high salinity reservoirs co-polymers of acrylamide (AM) and acrylamide tertiary butyl sulfonic acid (ATBS) have become common in the industry. The present work aimed at developing generic stability diagrams for such polymers dissolved in seawater (SW). Herein a two-step approach was attempted where stability versus ATBS content was measured at elevated temperature. Thereafter these data were extrapolated to lower temperature. To arrive at a sound extrapolation knowledge of hydrolysis kinetics for the two species, AM and ATBS, was needed. Aqueous solutions of AM-ATBS and AA-ATBS co-polymers were therefore stored at elevated temperature (82-140 degrees C) and progressive changes in microstructure followed by use of C-13 NMR spectroscopy. A steady increase in polymer stability with ATBS content was observed up to around 70 mol%. From 70 to 80 mol% the robustness sharply improved. A striking observation was that stability loss, defined as < 80% remaining viscosity, occurred before significant amounts of ATBS had reacted even at the highest ATBS contents. Acrylamide (AM) hydrolysis was found to be inhibited by the presence of ATBS. This reduced AM conversion rate was believed to be the main reason for increased stability. For the brines tested herein hydrolysis rate was virtually uninfluenced by hardness/salinity, while viscosity was largely impacted. Hence it was concluded that different viscosity loss in various brines stems from carboxylate complexation equilibria and not altered hydrolysis rates. Temperature extrapolation was found to fit a simple Arrhenius approach and it has been suggested that the function should be sound up to around 70 mol% ATBS. With this methodology, the current dataset enabled the construction of a stability diagram for ATBS polymers (0-70 mol% ATBS) dissolved in seawater.",8,8,1
Degrees C.,Sand Control,"Qi, Ning; Li, Boyang; Cai, Wenbin; Li, Xiaqing; Gao, Chengyuan",An optimal degrading agent formulation for detachable packing screens applicable for screenless sand control,Detachable packing screen; Degradation agent; Degradation degree; Degradation rate; Screenless sand control,DEGRADATION,"A new detachable packing screen used for sand control in oilfields has been designed. The key technology is to achieve rapid and effective downhole detachment of PLA-T (a polylactic acid material) tubing. An optimal formulation of the degradation agent was proposed considering the degradation degree and degradation rate of PLA-T materials. The temperature, salt and dilution tolerance of such degradation agent was evaluated under conditions simulating the in-situ reservoir environment. The degradation mechanism of the PLA-T was analyzed through scanning electron microscope (SEM) on the PLA-T surface during the reaction process. It is shown that the optimal formulation is that acetone: dimethylformamide: ethylenediamine ratio equals to 3: 2: 5. Under reservoir conditions with temperatures from 50 degrees C to 80 degrees C, water salinities from 10,000 mg/L to 100,000 mg/L and diluted concentrations from 70% to 90% of the original concentration, the degradation time of the PLA-T tubing ranges from 6 min to 92 min. This system maintains its excellent degradation capability under the complex downhole situation. The SEM tests show that the surface structure of the PLA-T changes gradually from the smooth surface, to cracks, then fractures, irregular fractures and finally the fracture-hole structure, and correspondingly the degradation rate of PLA-T first increases and then drops. The proposed high-efficiency degradation agent can achieve effective detachment of the downhole packing screen by rapidly degrading the PLA-T tubing, which enables screenless sand control of the unconsolidated sandstone reservoirs.",2,2,0
Degrees C.,Sand Control,"Marandi, Samira Zargari; Salehi, Mahsa Baghban; Moghadam, Asefe Mousavi",Sand control: Experimental performance of polyacrylamide hydrogels,Gelation time; Sand control; Rheology; Gel strength; Coreflooding,WATER SHUTOFF; CONFORMANCE-CONTROL; GEL; POLYMER; FIELDS; PERMEABILITY; GAS,"Improvement of sand consolidation is an impressive process to reduce severe operational problems of sandstone oil reservoirs. In this study, appropriate polymeric hydrogels for the southern Iranian reservoirs was produced and their performance in porous media was studied to reduce the sand production. Designing and producing hydrogel to increase the mechanical strength of reservoir rock and preserving desirable permeability at the same time, is one of the outcomes of the current study. A set of experiments were performed, conducting bottle test, rheology, and coreflooding tests on sandstone core. According to the results, the optimized hydrogel based on maintaining structural strength against stress, temperature and available ions in formation water was approved with 9500 ppm of sulfonated polyacrylamide copolymer, 0.5 wt ratio of Cr(OAc)(3) to copolymer, ultimate elastic modulus of 23 kPa, heat resistant, structural strength at 90 degrees C, and lack of rupture till applying 38700 mu N m torque. Sandstone coreflooding experiment also confirmed a 90% decrease in sand production after the hydrogel injection. Moreover, the water and oil permeabilities were decreased 95 and 7.5 times after the hydrogel injection, respectively. Therefore, the designed hydrogel with the dual function of sand control and relative permeability modification was presented for the field operations.",4,4,1
Degrees C.,Residual Oil,"Silva, Mario; Stray, Helge; Bjornstad, Tor",Stability assessment of PITT tracer candidate compounds: The case of benzyl alcohols,Partitioning tracers; Inter-well; Residual oil saturation; Stability; New compounds,OIL-FIELD; SATURATION; ADSORPTION; OXIDATION; RESERVOIR,"The selection of compounds used as inter-well tracers has traditionally been done taking into consideration the goal of the test and the ease in analyzing the chemicals used. This often led to improper selection of the tracers and insufficient knowledge about their behavior under typical reservoir conditions, resulting in several unsuccessful inter-well tracer tests. One of the critical characteristics of any conservative tracer is its stability under various reservoir conditions. In this document we present the study methodology and the findings from stability experiments carried out on 5 benzyl alcohols investigated as oil/water partitioning tracers for partitioning inter-well tracer tests (PITT). This is the first of three documents reporting such studies on 3 families of chemicals. A PITT consists of the simultaneous injection of one or more mass-conservative passive and phase-partitioning (one type of active) tracers. PITT is primarily conceived for mature water-flooded oil fields and measures the residual (or even remaining) oil saturation (S-OR) in the swept volumes between wells. Knowledge of SOR may be used to identify EOR targets, assess efficiency of EOR operations, and the efficiency of volumetric sweep between wells. This is important information, in particular for the increasing number of mature oil-fields where EOR projects are under consideration and/or development. A thorough knowledge about the static and dynamic properties of the tracers under reservoir conditions is required both to ensure successful field tests, and also to increase accuracy of the data obtained from them. 4-Chlorobenzyl alcohol, 2,6-Dichlorobenzyl alcohol, 4-Methoxybenzyl alcohol, 3,4-Dimethoxybenzyl alcohol, and 4-Hydroxybenzyl alcohol were tested in brine under simulated reservoir conditions with temperatures up to 150 degrees C during 12 weeks, at different pH values, and in the presence of typical sedimentary basin rock materials, sandstone, carbonate rock (limestone), and clay (kaolinite). 4-Chlorobenzyl alcohol and 2,6-Dichlorobenzyl alcohol were found to be fully stable at all tested conditions. 4-Methoxybenzyl alcohol and 3,4-Dimethoxybenzyl alcohol exhibit thermally induced degradation above 125 degrees C, but may still be considered for use below this temperature. 4-Hydroxybenzyl alcohol exhibits thermally induced degradation which was found to follow a first order kinetics. The apparent activation energy and pre-exponential constant in the Arrhenius law for the degradation reaction were determined and a kinetic model built. This opens the possibility for use of 4-Hydroxybenzyl alcohol as a non-conservative reservoir tracer to measure temperature or detect thermal fronts.",3,3,1
Degrees C.,Residual Oil,"Liu, Pengcheng; Yuan, Zhe; Zhang, Shengfei; Xu, Zhenhua; Li, Xiuluan",Experimental study of the steam distillation mechanism during the steam injection process for heavy oil recovery,Heavy oil; Steam distillation; Distillation rate; Superheated steam; Degree of superheating,SIMULATION; SOLVENT; DRIVE; FIELD,"Steam distillation can effectively enhance heavy oil recovery during steam injection process in heavy oil reservoirs. However, the mechanism of steam distillation is complex, and the changes in oil properties during distillation remain unclear. In this study, three comparative steam distillation experiments were designed and conducted, including distillation processes employing saturated steam, steam superheated by 10 degrees C, and steam superheated by 40 degrees C. Heavy oil samples were derived from the Jin-1 Block in a typical heavy oilfield, in China. The density, viscosity, SARA fractions, and carbon number distribution of the residual oil were compared to those obtained before conducting steam distillation experiments. The steam distillation rates obtained with steam superheated by 40 degrees C, steam superheated by 10 degrees C, and saturated steam were 11.158%, 10.903% and 10.423%, respectively. The results indicate that the steam distillation rate of heavy oil increases significantly with increasing degree of superheating. During the steam distillation process, the density and viscosity of residual oil increase, the contents of saturated hydrocarbons and resin decrease, and the contents of aromatic hydrocarbons and asphaltenes increase. In addition, analysis of the distilled components indicates that lightweight components with smaller carbon numbers are removed firstly by steam distillation, followed by heavier components with larger carbon numbers. Moreover, all hydrocarbons with carbon numbers less than C-22 are removed from heavy oil in the distillation process, while the maximum carbon number of the distilled components was C-34. This study is favorable for understanding the changes in the properties of residual oil after distillation during the steam injection process for heavy oil recovery.",8,8,7
Degrees C.,Gas Generation,"Wang, Kongyang; Yan, Wei; Deng, Jingen; Tian, Hao; Li, Wenbo; Wang, Yangang; Wang, Luyao; Ye, Sutao",Experimental study on H2S and CO2 generation capacities of the Bohai bay heavy oil,Heavy oil; Thermal recovery; Pyrolysis; H2S and CO2 generation; Partial pressure,CYMBOPOGON FLEXUOSUS BIOFUEL; FIREFLOOD FIELD PROJECTS; DIESEL-ENGINE; EMISSION CHARACTERISTICS; RECOVERY STRATEGIES; GRAVITY DRAINAGE; BIODIESEL BLEND; PERFORMANCE; COMBUSTION; RESERVOIRS,"Thermal recovery is a conventional technology for heavy oil development. During thermal oil recovery the reservoir could generate H2S and CO2. They will potentially threat the safety of downhole tubing regarding the sweet or sour corrosion. In some Bohai heavy oil fields CO2 and H2S under thermal recovery conditions lead to some corrosion problems of the tubing and equipment. Therefore, to determine the corrosive gas generation capacity is crucial for anti-corrosion design of downhole tubing and casing. Heavy oil samples from Bohai, China were experimentally studied for their pyrolysis characteristics using high-temperature-high-pressure autoclaves. The gases were collected when autoclaves cooled down to the in situ formation temperature. Effects of temperature, water chemistry and core mineral on corrosive gas generation were investigated. The results show that total pressure increase significantly when temperature reached 250 degrees C-280 degrees C under the single heavy oil condition. The additional water facilitates the reaction process, after more SO42- added in the mimic formation water, higher H2S content is obtained. Under the condition of multiphase of oil, formation water and cores, both of the H2S and CO2 content increase obviously, and the cores' effect on CO2 is greater than H2S. Anti-corrosion design usually concerns only the highest corrosive gas concentration without further analysis. The highest concentration does not always correspond to the best corrosive gases generation capacities of heavy oil. Comprehensive analysis of both the total pressure of reaction process and the quality of the reaction heavy oil is carried out, then the corrosive gases volume per unit mass of heavy oil is calculated. These can determine the strongest corrosive formation environment and the maximum gases generation capacities of heavy oil.",4,4,3
Degrees C.,Gas Generation,"Wu, Yuandong; Zhang, Zhongning; Sun, Lina; Li, Yuanju; Su, Long; Li, Xingpeng; Xu, Hao; Tu, Yang",The effect of pressure and hydrocarbon expulsion on hydrocarbon generation during pyrolyzing of continental type-III kerogen source rocks,Pressure; Hydrocarbon expulsion; Continental type-III kerogen; Semi-closed condition,INDIVIDUAL N-ALKANES; BOHAI BAY BASIN; PETROLEUM GENERATION; CONFINED PYROLYSIS; THERMAL-CRACKING; GAS GENERATION; DEEP PETROLEUM; WATER-PRESSURE; LIAOHE BASIN; OIL CRACKING,"In order to define the roles of water and lithostatic pressure in petroleum formation of continental type-III kerogen source rocks, semi-closed hydrous pyrolysis experiments were conducted under with 50-1200 bar water pressure and 125-2000 bar lithostatic pressure at 480 degrees C. Our results will be of great benefit to the exploration of shale gas and deep petroleum in China. Increasing water pressure from 50 to 325 bar did not affect the yields of gaseous hydrocarbons, oil and bitumen, but increasing water pressure leads the more oil and less gaseous hydrocarbons from continental type-III kerogen in the 325-1200 bar water pressure range under semi-closed conditions. The decreasing yields of gaseous hydrocarbons, dryness of gaseous hydrocarbons and primary hydrogen together confirm that increasing water pressure promotes the primary reaction but decreases the cracking rate of oil. The decreasing values of S-2, HI and H/C in the pyrolysed samples confirm that high water pressure can increase the efficiency of hydrocarbon generation from continental type-III kerogen, while the maturation of kerogen correspondingly increases as shown by increasing values of VR and Tmax. In the 125-625 bar lithostatic pressure range, oil cracking and primary reaction of type-III kerogen may have contributed to the decreasing effect of hydrocarbon expulsion. The increasing hydrogen and gaseous hydrocarbon yields also confirm that the cracking of oil is enhanced within this pressure range. The decreasing trends of oil and gaseous hydrocarbon yields indicate that hydrocarbon generation rate was reduced by the high lithostatic pressure in the 625-2000 bar pressure range. The increasing values of S-2, HI and H/C, and decreasing values of VR and Tmax of pyrolysed samples confirm the retardation effect of highlithostatic pressure on the efficiency of hydrocarbon generation and maturation. In addition, the results also indicate that expelling hydrocarbons strongly promotes further hydrocarbon generation and retards the cracking of oil from continental type-III kerogen in source rocks.",9,10,0
Degrees C.,Storage,"Zhu, Dongya; Meng, Qingqiang; Liu, Quanyou; Zhou, Bing; Jin, Zhijun; Hu, Wenxuan",Natural enhancement and mobility of oil reservoirs by supercritical CO2 and implication for vertical multi-trap CO2 geological storage,Supercritical CO2; Reservoir enhancement; Dawsonite; Geological storage; Huangqiao reservoir,RARE-EARTH-ELEMENT; CARBON-DIOXIDE; FLUID INCLUSIONS; SALINE AQUIFERS; BASIN; SEQUESTRATION; ACCUMULATION; GAS; RECOVERY; MODEL,"The accumulation and production of both deep mantle-derived CO2 and light oil were discovered in the Huangqiao reservoir, which is located in the Subei Basin, East China. The Huangqiao reservoir shows that both CO2 and oil are entrapped in and produced from vertical multi-traps. The effects of deep CO2 on the accumulation and production of oil under natural conditions and the implications for CO2 geological storage are investigated in detail. The fluid inclusions in quartz or calcite veins from the Silurian Fentou Formation (S(2-3)f), Permian Longtan Formation (P(2)l) and Triassic Qinglong Formation (T(1)q) have homogenization temperatures (Ths) that display peak ranges of 180 degrees C-190 degrees C, 170 degrees C-180 degrees C and 150 degrees C-160 degrees C, respectively. The Ths are higher than the formation temperatures. The calcite veins have light carbon and oxygen isotope compositions and have high Sr-87/Sr-86 ratios and positive Eu anomalies. These characteristics reveal the activities of deep CO2-rich hydrothermal fluids in the basin strata. The feldspar in the S(2-3)f and P(2)l sandstone reservoirs underwent significant dissolution because of the presence of CO2-rich fluids, forming of a large amount of secondary pores in the sandstone reservoirs and enhancing the reservoirs' physical properties. The measured porosity reaches 12.3%. CO2 in a supercritical state extracted or dissolved light petroleum components out of sedimentary rocks and then carried them towards reservoirs. Thus, CO2 and oil co-accumulated in the enhanced reservoirs, e.g. S(2-3)f, P(2)l and T(1)q. During drilling development, this supercritical CO2 naturally increased the mobility of oil, resulting in the co-production of highly pure CO2 and light oil. Based on the unique features of the Huangqiao CO2-oil reservoir, we propose a new CO2 geological storage model, namely, a vertical multi-trap geological storage model, which can either entrap large volumes of CO2 or lower the risk of long-term storage.",5,7,4
Degrees C.,Storage,"Qiu, Liewei; Shen, Yiding; Wang, Chen",pH- and KCl-induced formation of worm-like micelle viscoelastic fluids based on a simple tertiary amine surfactant,pH-responsive surfactant; Micelle transition; Rheological behaviors; Acidic fracturing fluid,SMART USE; RHEOLOGY; SUSPENSIONS; PARTICLES; EMULSIONS; SHEAR,"To explore the application of pH-responsive surfactant, a pH-responsive N, N-dimethyl-erucamide-propylamine (DEAPA) self-assembly system was prepared and characterized. The rheological property and structural transformation of DEAPA molecular aggregations were comprehensively discussed with decreasing pH or increasing of Cl- concentration using rheology, dynamic light scattering (DLS), ultraviolet-visible (UV) spectrophotometry, and cryo-transmission electron microscopy (cryo-TEM). The properties of the DEAPA-KCl viscoelastic fluid used as the fracturing fluid were discussed in terms of the viscoelasticity, temperature-tolerance, and shear-tolerance, proppant suspension, and core permeability damage at pH 1.5. Results revealed that the microstructure of the DEAPA micelle first transformed from vesicles to spherical micelles, and finally changed to worm-like micelles when HCl solution was added. In addition, on increasing the KCl concentration, the system transforms from spherical micelles to worm-like micelles. When the Cl- concentration was increased to 0.50 mol/L (pH = 1.5), the storage modulus (G') of the DEAPA-KCl fluid became over 15 Pa and loss modulus (G '') was over 5 Pa, which suggests that elasticity is the predominant property of these worm-like micelles. Also, the viscosity of the DEAPAKCl fracturing fluid was constant at about 110 mPa s at 80 degrees C and shear rate of 170 s(-1). The settling velocity of the DEAPA-KCl fluid was lower than 0.004 mm/s at 60 degrees C, and the core permeability damage was 6.75%. Therefore, the DEAPA-KCl system is suitable for use as an acidic viscoelastic fracturing fluid.",8,8,8
Degrees C.,Yield,"Wu, Yuandong; Zhang, Zhongning; Sun, Lina; Li, Yuanju; Su, Long; Li, Xingpeng; Xu, Hao; Tu, Yang",The effect of pressure and hydrocarbon expulsion on hydrocarbon generation during pyrolyzing of continental type-III kerogen source rocks,Pressure; Hydrocarbon expulsion; Continental type-III kerogen; Semi-closed condition,INDIVIDUAL N-ALKANES; BOHAI BAY BASIN; PETROLEUM GENERATION; CONFINED PYROLYSIS; THERMAL-CRACKING; GAS GENERATION; DEEP PETROLEUM; WATER-PRESSURE; LIAOHE BASIN; OIL CRACKING,"In order to define the roles of water and lithostatic pressure in petroleum formation of continental type-III kerogen source rocks, semi-closed hydrous pyrolysis experiments were conducted under with 50-1200 bar water pressure and 125-2000 bar lithostatic pressure at 480 degrees C. Our results will be of great benefit to the exploration of shale gas and deep petroleum in China. Increasing water pressure from 50 to 325 bar did not affect the yields of gaseous hydrocarbons, oil and bitumen, but increasing water pressure leads the more oil and less gaseous hydrocarbons from continental type-III kerogen in the 325-1200 bar water pressure range under semi-closed conditions. The decreasing yields of gaseous hydrocarbons, dryness of gaseous hydrocarbons and primary hydrogen together confirm that increasing water pressure promotes the primary reaction but decreases the cracking rate of oil. The decreasing values of S-2, HI and H/C in the pyrolysed samples confirm that high water pressure can increase the efficiency of hydrocarbon generation from continental type-III kerogen, while the maturation of kerogen correspondingly increases as shown by increasing values of VR and Tmax. In the 125-625 bar lithostatic pressure range, oil cracking and primary reaction of type-III kerogen may have contributed to the decreasing effect of hydrocarbon expulsion. The increasing hydrogen and gaseous hydrocarbon yields also confirm that the cracking of oil is enhanced within this pressure range. The decreasing trends of oil and gaseous hydrocarbon yields indicate that hydrocarbon generation rate was reduced by the high lithostatic pressure in the 625-2000 bar pressure range. The increasing values of S-2, HI and H/C, and decreasing values of VR and Tmax of pyrolysed samples confirm the retardation effect of highlithostatic pressure on the efficiency of hydrocarbon generation and maturation. In addition, the results also indicate that expelling hydrocarbons strongly promotes further hydrocarbon generation and retards the cracking of oil from continental type-III kerogen in source rocks.",9,10,0
Degrees C.,Yield,"Gautam, Sidharth; Guria, Chandan; Rajak, Dilip K.; Pathak, Akhilendra K.",Functionalization of fly ash for the substitution of bentonite in drilling fluid,Alpha-glycol and amine substituted fly ash; API-Grade drilling bentonite; Surface characterization; Rheology; Frictional and filtration behavior,,"Oil exploration activities have increased the demand for American Petroleum Institute (API-) grade drilling bentonite leading to a significant increase in the cost of naturally occurring bentonite and overall cost of the drilling operations. In this work, fly ash (FA) was functionalized to replace API- grade drilling bentonite for drilling of wells. Epichlorohydrin and aminopropyl triethoxysilane were used to functionalize the ultrafine-structured planetary ball-milled FA. The morphology, mineralogy, structure and specific surface area of the functionalized FA were determined by the field emission scanning electron microscopy, energy dispersive X-ray spectroscopy, X-ray diffractometry and Brunauer-Emmett-Teller analysis, respectively, to determine the efficacy of functionalized FA as a colloidal base in aqueous suspension. Fourier-transform infrared spectrometer and X-ray photoelectron spectroscopy analysis was used to confirm the grafting of alpha-glycol and amine functional group on FA surface and quantified by iodometric and acid-base titration method, respectively. The zeta potential and cation-exchange capacity of functionalized FA were found to be -47.1 to -68.1 mV in pH range 8-12 and similar to 68.0 meq/100 g of functionalized FA, respectively, and were found comparable to API- grade drilling bentonite. Rheological behavior and filtration loss properties of the functionalized FA in aqueous suspension were determined and compared with the API- grade drilling bentonite yielding similar results. The performance of the functionalized FA-based drilling mud system involving tamarind gum and polyanionic cellulose was evaluated by determining the thermal stability, cuttings transportation ability, friction and shelf-life properties under the downhole condition at 75 degrees C and 100 psig and the results were compared against the existing drilling mud system, yielding the comparable performance. Finally, the functionalized FA was found to be cost-effective over API- grade bentonite.",9,9,0
Degrees C.,Cracking,"da Silva, Italo Batista; Martinelli, Antonio Eduardo; Medeiros de Souza, Wendell Rossine; de Oliveira Freitas, Julio Cezar; Felipe Rodrigues, Marcos Alysson",Dilatometric behavior and crystallographic characterization of Portland-polyurethane composites for oilwell high-temperature cementing applications,Oilwell cementing; Portland cement; Polyurethane and thermal expansion,THERMAL-EXPANSION; WELL CEMENT; HYDRATION,"In order to improve the behavior of Portland-based oilwell sheath to high-temperature applications and the corresponding thermal gradients, polymeric admixtures can be added. Steam injection, for instance, raises the cement sheath-steel casing interface temperature to similar to 300 degrees C which can be deleterious to the mechanical stability and zonal isolation provided by the cement sheath as a result of cracking of the cement. Polyurethane can be added to the cement to improve its plastic behavior and reduce the thermal expansion mismatch between casing and sheath. However, the use polymeric admixtures, especially as aqueous dispersion, can affect the kinetics of the hydration reactions and, as a consequence, the crystallographic composition and coefficient of thermal expansion of the material. Therefore, the present study aimed at evaluating the effects of the addition of different concentrations of polyurethane on the thermomechanical properties of Portland cement pastes cured at 300 degrees C from 14 to 90 days. Formulations containing 1 gpc (0.052 kg), 2 gpc (0.102 kg) and 3 gpc (0.153 kg) of polyurethane, respectively named PU1, PU2 and PU3 were prepared according to the American Petroleum Institute guidelines. A standard PU-free slurry was also prepared. X-ray diffraction and dry dilatometric tests were carried out. The results revealed that the curing time does affect the kinetics of hydration of Portland-polyurethane composites, retarding the formation of high-temperature stable phases, i.e., tobermorite and xonotlite. Moreover, longer curing times were necessary to reveal the improved expansion of the composites with respect to the standard sample. The addition of polyurethane can be pointed as an approach to high-temperature oilwell cement applications, since it reduces the thermal mismatch between cement sheath and steel casing for and retards but do not prevent the formation of xonotlite.",4,4,0
Degrees C.,Cracking,"Wu, Yuandong; Zhang, Zhongning; Sun, Lina; Li, Yuanju; Su, Long; Li, Xingpeng; Xu, Hao; Tu, Yang",The effect of pressure and hydrocarbon expulsion on hydrocarbon generation during pyrolyzing of continental type-III kerogen source rocks,Pressure; Hydrocarbon expulsion; Continental type-III kerogen; Semi-closed condition,INDIVIDUAL N-ALKANES; BOHAI BAY BASIN; PETROLEUM GENERATION; CONFINED PYROLYSIS; THERMAL-CRACKING; GAS GENERATION; DEEP PETROLEUM; WATER-PRESSURE; LIAOHE BASIN; OIL CRACKING,"In order to define the roles of water and lithostatic pressure in petroleum formation of continental type-III kerogen source rocks, semi-closed hydrous pyrolysis experiments were conducted under with 50-1200 bar water pressure and 125-2000 bar lithostatic pressure at 480 degrees C. Our results will be of great benefit to the exploration of shale gas and deep petroleum in China. Increasing water pressure from 50 to 325 bar did not affect the yields of gaseous hydrocarbons, oil and bitumen, but increasing water pressure leads the more oil and less gaseous hydrocarbons from continental type-III kerogen in the 325-1200 bar water pressure range under semi-closed conditions. The decreasing yields of gaseous hydrocarbons, dryness of gaseous hydrocarbons and primary hydrogen together confirm that increasing water pressure promotes the primary reaction but decreases the cracking rate of oil. The decreasing values of S-2, HI and H/C in the pyrolysed samples confirm that high water pressure can increase the efficiency of hydrocarbon generation from continental type-III kerogen, while the maturation of kerogen correspondingly increases as shown by increasing values of VR and Tmax. In the 125-625 bar lithostatic pressure range, oil cracking and primary reaction of type-III kerogen may have contributed to the decreasing effect of hydrocarbon expulsion. The increasing hydrogen and gaseous hydrocarbon yields also confirm that the cracking of oil is enhanced within this pressure range. The decreasing trends of oil and gaseous hydrocarbon yields indicate that hydrocarbon generation rate was reduced by the high lithostatic pressure in the 625-2000 bar pressure range. The increasing values of S-2, HI and H/C, and decreasing values of VR and Tmax of pyrolysed samples confirm the retardation effect of highlithostatic pressure on the efficiency of hydrocarbon generation and maturation. In addition, the results also indicate that expelling hydrocarbons strongly promotes further hydrocarbon generation and retards the cracking of oil from continental type-III kerogen in source rocks.",9,10,0
Degrees C.,Stage,"Yuan, Shibao; Jiang, Haiyan; Yang, Fengxiang; Shi, Yaoli; Bai, Yu; Du, Kun",Research on characteristics of fire flooding zones based on core analysis,Fire flooding; Combustion stage; Zone characteristics; Rock and mineral composition,,"In order to better understand the combustion process and the reactions in the process of fire flooding, it is necessary to study the zone characteristics and the advancing law of fire flooding. Firstly, temperature dynamic characteristics of observation well reveal that the combustion of HQ1 fire flooding pilot test is characterized by wet combustion. Then, a series of core tests (rock pyrolysis, mercury intrusion, crude oil group composition analysis, rock and mineral composition) are utilized to analyze the cores from Xinjiang HQ1. By comparing the difference of characteristics between the burned and unburned zone, the result shows that coke deposition occurs under the burning surface, where the coke deposition zone is. And above the burning surface, kaolinite is converted into illite or montmorillonite. There is evidence to show that montmorillonite will converted into illite under a dry combustion condition(350 degrees C). These features of rock and mineral can be used to evaluate fire flooding process.",5,9,0
Degrees C.,Stage,"Karimi, Masoud; Shirazi, Meisam Mohammadzadeh; Ayatollahi, Shahab",Investigating the effects of rock and fluid properties in Iranian carbonate matrix acidizing during pre-flush stage,Matrix acidizing; Pre-flush fluid; Wettability alteration; IFT reduction; Dissolution rate,WETTABILITY ALTERATION; OIL-WET; INTERFACIAL-TENSION; REACTION-KINETICS; HIGH-TEMPERATURE; ACID; SURFACTANT; DISSOLUTION; STIMULATION; ACIDIZATION,"Acidizing of carbonate oil-wet rocks saturated with oil and saline formation water is subjected failure in some cases due to acid-induced damage such as sludge and emulsion formations. This condition may also lead to mineral precipitation, oil film barrier between acid and rock and diversion chemical malfunctions. Therefore, pre-flush process has been proposed as one of the most efficient stage for oil-wells matrix acidizing to reduce these challenges significantly. Besides, the pre-flush stage would result in more clean rock as the reservoir fluids are pushed back from the near wellbore regions, restoring rock wettability to more water wet state, preventing direct acid-oil contact and cooling rock surface to control acid-rock reaction at high temperature reservoir. This laboratory work is designed to study the effectiveness of three different pre-flush fluids and assess their ability in reducing interfacial tension (IFT) to displace original reservoir fluids around the wellbore as well as changing the rock wettability to increase rock dissolution rate. The results showed that a 0.5% wt of C16TAB aqueous solution (cationic surfactant additive) has passed successfully the pre-flush optimization criteria which can be utilized as pre-flush fluid of the carbonate oil-wet acidizing. It was shown that the wettability and IFT were changed quickly as it is requested for the pre-flush stage. The contact angle was decreased from 172 degrees to 33 degrees in two hours period and the IFT was reduced from 8.9 to 0.62 (dyne/cm) at reservoir condition (P = 4000 psia, T = 85 degrees C). In addition, the dissolution rate of dolomite rock from an Iranian oil reservoir at three different states of oil-wet, water-wet and pre-flush treated with 15% HCl was measured and compared. The measured dissolution rate of initially water-wet rock was measured to be 1 x 10(-4) mol/cm(2).s which is the same as the dissolution rate measured for C16TAB treated oil wet rock. This confirms the suitable wettability alteration through C16TAB pre-flush.",6,6,1
Finite Element,Formation,"Li, Binglin; Su, Yuliang; Zhan, Shiyuan; Yao, Wei; Hu, Yangming; Wang, Wendong",Temporal scale analysis of two phase flow in fractured well,Fractured well; Two phase flow; Temporal scale analysis; Time lag effect,CAPACITANCE-RESISTANCE MODEL; SHALE RESERVOIRS; PERMEABILITY; PROPAGATION; SIMULATION; BEHAVIOR; VOLUME; FIELD,"Two phase flow between two fractures commonly exists around fractured wells. Due to the fracture network, the flow velocity is extremely variable in different regions and it can be described by the temporal scale analysis. The flow velocity also changes with time during the change in water saturation, but these changes cannot be captured by the conventional temporal scale analysis. The temporal scales are obtained based on a principal equation, so it is difficult to accurately estimate the formation properties and to determine the exploitation scheme. In this study, the two phase flow model between two fractures has been proposed for the temporal scale description. The impact of reservoir heterogeneity on the temporal scales is considered in the model. Due to the tortuous flow channel shape between the fractures, the flow pressure affects the fluid flow afterwards. This is explained by the time lag effect in the model. The temporal scales are obtained by using finite element method and Laplace transformation at all time points with these considerations. Moreover, the well is soaked intermittently. The soaking duration is chosen based on temporal scales, and then discussed in terms of efficiency and recovery factor. The results showed that the water saturation profile position is reflected by the temporal scales, the flow resistance and the flow velocity are represented by their zero status response contributions, while the initial flow pressure is described by their zero input contribution. The highest zero status response contribution is different for different properties. Moreover, the time lag effect promotes the initial pressure fluctuation, and also upscales the fluid flow in tortuous channels. Finally, the soaking duration is an approximation of the time required to reduce the fracture flow pressure.",1,1,0
Finite Element,Formation,"Ghimire, Bishwas; Daigle, Hugh; Gray, Ken E.",Modeling formation resistivity changes due to invasion and deformation during initial leak-off test build-up,Leak-off test; Invasion; Formation resistivity,SIMULATION; PERMEABILITY; LOG,"Leak-off tests (LOTs) are performed to determine the strength of a newly drilled formation below a cased interval and to characterize the upper bound of mud weight that can be safely used while drilling the next section, without risk of formation breakdown and lost circulation. In an LOT, drilling mud is pumped into the wellbore, causing the wellbore pressure to increase and exceed the formation pore pressure. During the initial LOT build up, excess pressure in the wellbore causes the surrounding rock to deform and mud filtrate to invade into the formation via porous flow. In this paper, change in formation resistivity around a wellbore during initial LOT build-up has been investigated. Invasion is modeled assuming two-phase radial Darcy flow and deformation using a 3D finite element model. Invasion may result in an exchange of conductive ions between water-based drilling mud and formation water both by diffusion in the direction favored by the concentration gradient of the ions and by convective transport. This process is incorporated into the model by solving the radial convection-diffusion equation for the aqueous phase using a finite difference method. Archie's law is used to determine the formation resistivity. Findings show that the direct effect of deformation on porosity, therefore on formation resistivity during an LOT, is negligibly small even when the formation rock is highly compressible with compressibility in the order of 10(-3) psi(-1). While salinity solely controls formation resistivity during an LOT conducted in a fully water-saturated interval, water saturation change and salinity change compete to produce a compound effect on formation resistivity of an oil-bearing zone where water saturation varies dynamically due to displacement of formation fluids. Unlike compressibility, the effect of permeability on formation resistivity response is found to be evident and readily observable. While analyzing the formation resistivity responses at various depths of investigation (DOIs), it is found that the effect of DOI on resistivity response can be useful in studying invasion and assessing formation damage during an LOT. In addition to this, through comparing time-lapse resistivity logs at multiple DOIs during an LOT with numerically synthesized resistivity responses, the model promises a novel approach towards determining the permeability of a freshly drilled and unaltered interval.",2,2,1
Finite Element,Formation,"Goudarzi, Banafsheh; Mohammadmoradi, Peyman; Kantzas, Apostolos",Direct pore-level examination of hydraulic-electric analogy in unconsolidated porous media,Pore-scale; Tortuosity; Finite element; Electric-Hydraulic; Unconsolidated,KOZENY-CARMAN; FIXED-BEDS; TORTUOSITY; FLOW; PERMEABILITY; DIFFUSION; TRANSPORT; MODEL; SIMULATION; POROSITY,"Taking advantage of the analogy between hydraulic and electrical flows to facilitate the prediction of porous media characteristics is a longstanding practice in engineering and science applications. The relationships between hydraulic and electrical properties are widely used in the characterization of transport phenomena relying on the strong correlation between electric and hydraulic flow conductance. However, due to the lack of small-scale investigations the similarity among their pathways/tortuosities is still unclear. Here a series of direct finite element numerical simulations are conducted within pore-level microstructures to extract and compare the streamlines of both electric and fluid flow currents and examine the accuracy of the hydraulic-electric analogy by predicting the petrophysical characteristics of the case studies. The fluid flow and electric transports are simulated through low-porosity digital unconsolidated packings of polydispersed grains representing the Athabasca oil sands deposit as the second largest oil reserve in the world. The formation factor, porosity, and absolute permeability of the media under consideration are predicted, and consequently, the streamlines of both electric and hydraulic currents are extracted and compared in terms of length, shape, and pathways. According to the results, the fluid flow streamlines are longer and pose differently than the homogeneous electric current streamlines. The average ratio between the hydraulic and electric tortuosities is 1.15 and a local extremum occurs at the porosity of eighteen percent. Pedotransfer functions for tortuosities, dimensionless permeability, and formation factor are proposed underpinning the rigorous relationships between transport processes in porous media.",6,6,0
Finite Element,Formation,"Bautista, J. F.; Taleghani, A. Dahi",Prediction of formation damage at water injection wells due to channelization in unconsolidated formations,,FLUID INJECTION; FIBER BEDS; FLOW,"Formation damage due to chemical reactions or mechanical failure of the rock is a well-known issue in the oil and gas industry. In this paper, we look at injectivity changes of water injectors targeting unconsolidated formations as a result of sand channelization. In this situation, sand particles migrate from the formation matrix toward the wellbore and consequently affect permeability of the formation and completion components like frac-packs or gravel-packs. To simulate this phenomenon, we propose a model that decomposes the sand matrix into two different phases by means of their volumetric fractions. The first phase consists of the immobile granular phase while the other is the fraction of grains that are detached from the matrix and carried away by the fluid. The ratio of these two phases evolves over time by means of erosion and deposition. A finite element code for this model is developed and implemented for different reservoir conditions. The results show how local porosity evolves over time around the wellbore by the formation of channels that enhance the flow; however, upon well shut-in, flowback induced by the water hammer effect brings large amounts of sand into the well and fills it up. A study of the effect of frac-packs which are typical completions for wells targeting soft formations is performed to demonstrate potential damage of repetitive shut-ins on injectivity in these wells. The presented model appears as a robust tool to predict sand production for different completion systems to achieve more sustainable injection operations.",6,5,1
Finite Element,Approach,"Ghimire, Bishwas; Daigle, Hugh; Gray, Ken E.",Modeling formation resistivity changes due to invasion and deformation during initial leak-off test build-up,Leak-off test; Invasion; Formation resistivity,SIMULATION; PERMEABILITY; LOG,"Leak-off tests (LOTs) are performed to determine the strength of a newly drilled formation below a cased interval and to characterize the upper bound of mud weight that can be safely used while drilling the next section, without risk of formation breakdown and lost circulation. In an LOT, drilling mud is pumped into the wellbore, causing the wellbore pressure to increase and exceed the formation pore pressure. During the initial LOT build up, excess pressure in the wellbore causes the surrounding rock to deform and mud filtrate to invade into the formation via porous flow. In this paper, change in formation resistivity around a wellbore during initial LOT build-up has been investigated. Invasion is modeled assuming two-phase radial Darcy flow and deformation using a 3D finite element model. Invasion may result in an exchange of conductive ions between water-based drilling mud and formation water both by diffusion in the direction favored by the concentration gradient of the ions and by convective transport. This process is incorporated into the model by solving the radial convection-diffusion equation for the aqueous phase using a finite difference method. Archie's law is used to determine the formation resistivity. Findings show that the direct effect of deformation on porosity, therefore on formation resistivity during an LOT, is negligibly small even when the formation rock is highly compressible with compressibility in the order of 10(-3) psi(-1). While salinity solely controls formation resistivity during an LOT conducted in a fully water-saturated interval, water saturation change and salinity change compete to produce a compound effect on formation resistivity of an oil-bearing zone where water saturation varies dynamically due to displacement of formation fluids. Unlike compressibility, the effect of permeability on formation resistivity response is found to be evident and readily observable. While analyzing the formation resistivity responses at various depths of investigation (DOIs), it is found that the effect of DOI on resistivity response can be useful in studying invasion and assessing formation damage during an LOT. In addition to this, through comparing time-lapse resistivity logs at multiple DOIs during an LOT with numerically synthesized resistivity responses, the model promises a novel approach towards determining the permeability of a freshly drilled and unaltered interval.",2,2,1
Finite Element,Approach,"Moosavi, Seyedeh Robab; Vaferi, Behzad; Wood, David A.",Applying orthogonal collocation for rapid and reliable solutions of transient flow in naturally fractured reservoirs,Naturally fractured reservoir; Pseudo-steady state; Orthogonal collocation method; Parametric analyses; Pressure transient response,DIFFUSIVITY EQUATION; PRESSURE RESPONSE; ELEMENT SOLUTION; WELL; SIMULATION,"Naturally fractured reservoirs (NFR) contain a significant portion of the worldwide oil and gas reserves. Pressure transient analysis is the most well-established methodology for characterizing these heterogeneous reservoirs based upon well-test data. Pressure transient responses (PTR) of oil and gas reservoirs to various production/injection scenarios is widely used for forecasting and optimizing their production performance and ultimate resource recoveries. In this study, orthogonal collocation (OC) which is a straightforward and very efficient approximate approach for solving differential equations is employed as a novel approach to simulate the PTR of NFRs. The governing equations describe fluid flow in NFR for pseudo-steady state conditions. Constant production rate from a wellbore and circular no-flow are employed as an inner and outer boundary conditions, respectively. The results of OC are verified with exact analytical solutions using the Laplace transform. Thereafter, the effects of three parameters (storativity ratio, interporosity flow coefficient, and radial distance of the outer boundary from the wellbore) are studied using pressure-derivative plots. Employing the superposition theorem, the pressure response of NFR to the multi-rate production from the wellbore is calculated. The results indicate that this approximate approach can predict the pressure transient response of NFRs with an acceptable accuracy, i.e., absolute average relative deviation (AARD) of 0.16%. The equations can be adapted to deal with other flow conditions, boundary conditions and fracture stimulated reservoirs. The proposed method provides a straightforward, faster and more accurate solution in comparison with other methods commonly used. As the OC method is simpler to execute than analytical solutions (e.g. Laplace Transform), it is easier to modify and expand for addressing more complex reservoir scenarios. Likewise, the numerical methods (e.g. finite difference and finite elements) commonly applied to model fractured reservoirs involve significantly more time-consuming calculations, making them more cumbersome to use in reservoir simulations than the proposed orthogonal collocation method.",3,4,0
Finite Element,Approach,"Voyiadjis, George Z.; Zhou, Yaneng",Time-dependent modeling of subsidence due to drainage in bounding shales: Application to a depleted gas field in Louisiana,Subsidence; Compaction; Viscoplasticity; Hydrocarbon production; Drainage,LAND SUBSIDENCE; CONSTITUTIVE APPROACH; SIMULATION; COMPACTION; OIL,"Hydrocarbon production is an important process contributing to the subsidence in Louisiana. Releveling data from National Geodetic Survey show that subsidence along several major oil and gas fields accelerated after production when reservoirs were nearly depleted. The Valentine gas field in coastal Louisiana is chosen to analyze the subsidence during and after production based on three-dimensional finite element modeling. An elasticviscoplastic constitutive model is adopted to interpret the accelerated postdepletion subsidence by overcoming the limitation of traditional theories within the framework of poroelatsicity and poroplasticity. The elasticviscoplastic model integrates a failure envelope, an elliptical cap yield function, and Perzyna's theory of overstress viscoplasticity. The elastic-viscoplastic model is applied to both the simplified disc-shaped reservoir and the bounding shales. The material properties of the elastic-viscoplastic model are calibrated based on a computational technique along with available laboratory and field data from the literature. The numerical modeling results can approximately reproduce both the observed subsidence during production and the delayed subsidence after production using the calibrated material properties. The time-dependent subsidence is predominantly attributed to the delayed compaction that arises from the slow pore pressure diffusion in the bounding shales after the reservoir is depleted. The calibrated finite element model is capable of predicting the time-dependent compaction and subsidence, along with the three-dimensional temporal and spatial distribution of pore pressure, void ratio, vertical strain, and vertical displacement in the bounding shales. The pore pressure diffusion and the time-dependent subsidence are influenced by the permeability of both the reservoir sand and bounding shale. Even though permeability generally increases with damage, and decreases with increased effective stress and reduced porosity, typical constant values of permeability are used for simplicity. The local maximum subsidence is predicted to be 28 cm during 30 years (1982-2012) after the Valentine field is depleted.",5,5,0
Finite Element,Approach,"Li, Yilun; Guo, Shuangxi; Chen, Weimin",Analysis on multi-frequency vortex-induced vibration and mode competition of flexible deep-ocean riser in sheared fluid fields,Vortex-induced vibration; Multi-frequency; Mode competition; Fluid-solid coupling; Long flexible riser,DYNAMIC CHARACTERISTICS; FORCE DISTRIBUTION; CIRCULAR-CYLINDER; VIV,"Multi-frequency vortex-induced vibration of flexible riser in lineally sheared fluid fields with different shearing parameters is explored by using the numerical approach. By combining the finite element method with a hydrodynamic model, the approach can consider mode competition based on modal energy and can carry out nonlinearly simultaneously dynamic response in time domain. Our analysis shows that multi-frequency VIV may occur both in non-uniform and uniform fluid fields. And, the behaviors of multi-frequency VIV are different from single-frequency VIV. Because several modes are involved and compete with each other, and consequently the determination of modal excitation region become more complicated. As the towing speed (or the shearing parameter) increases in sheared flow, the average RMS displacement does not regularly rise (or drop), but slightly fluctuates owing to changes of the participating mode and its excitation region. On the other hand, the average RMS stress gradually rises owing to higher-order modes being included. Moreover, it is found that the dominant frequency distributing along structural span significantly changes with the towing speed, and the length of the first dominant frequency gets smaller due to larger shearing parameter along with more intense competition between the participating modes.",5,6,2
Finite Element,Approach,"Bruch, A.; Maghous, S.; Ribeiro, F. L. B.; Dormieux, L.",A thermo-poro-mechanical constitutive and numerical model for deformation in sedimentary basins,Sedimentary basin; Mechanical compaction; Chemo-mechanical compaction; Thermo-poroplasticity; Thermo-poroviscoplasticity; Finite element approach,PRESSURE SOLUTION; ELASTIC PROPERTIES; COMPACTION MODEL; HEAT-FLOW; NORTH-SEA; OVERPRESSURE; EVOLUTION; CONSOLIDATION; PERMEABILITY; TEMPERATURE,"Comprehensive modeling of sedimentary basins should integrate the coupled nature of different phenomena such as sediment compaction, pore-fluid flow and heat transport. In this context, the thermal evolution of the basin plays an important role in the mechanical and chemo-mechanical deformation processes as heat modifies fluids viscosity and minerals physicochemical properties, thus affecting pore fluid expulsion and mineral stability. The present paper describes a three-dimensional constitutive and numerical model specifically devised for dealing with thermo-poromechanical deformation processes during diagenesis. The sedimentary basin is modeled as a fully saturated thermo-poro-elastoplastic-viscoplastic medium undergoing large strains. A key feature of the model is related to the evolution of the sediment material properties associated with temperature and large irreversible porosity changes. The computational model, which integrates both poroplastic and poroviscoplastic components of deformation at large strains, relies upon a parallel implementation of the finite element method with a shared memory multiprocessing interface. Numerical simulations of gravitational compaction during the sediment accretion phase as well as along geological period of pore pressure dissipation are performed in the context of oedometric setting. Special emphasis is given to temperature effects on the deformation history of the basin.",6,6,2
Finite Element,Case,"Deng, Kuanhai; Liu, Wanying; Lin, Yuanhua; Zeng, Dezhi; Zhang, Jichuan; Xiang, Junke",Experimental and numerical investigation on repairing process of cement-casing repaired by rolling reshaper,Rolling reshaper; Repairing process; Experiment; Finite element model; Cement-casing; Repairing force,,"In oil field, the bit weight (repairing force) and torque are always determined by experience when the rolling reshaper is used to repair the deformed casing. However, if the repairing force and torque are unreasonable, it will easily give rise to the secondary damage of deformed casing and surrounding cement sheath as well as pipe sticking. Hence, based on the elastic-plastic theory, the three-dimensional finite element model which can simulate the repairing process of cemented casing repaired by rolling reshaper has been presented in this paper by adopting the finite element method. Based on this model, the whole repairing process of cemented casing with elliptic section has been simulated, by which the deformation law of cemented casing, the repairing force and torque required to repair the cemented casing have been obtained in the repairing process. Meanwhile, based on self-developed testing equipment, the full-scale repairing experiment of cemented casing has been conducted by using rolling reshapser, and the correlations between deformation laws of cemented casing and repairing force and torque have been analyzed. As the test results are consistent with the simulation results, it indicates that the finite element model is accurate and reliable so that the research results can provide important reference for design and optimization of technological parameters.",3,3,2
Finite Element,Case,"Chen, Wei; Di, Qinfeng; Zhang, He; Chen, Feng; Wang, Wenchang",The sealing mechanism of tubing and casing premium threaded connections under complex loads,Premium threaded connections; Three-dimensional finite element analysis; Sealing mechanism; Analytical method; Complex loads,,"With the increase of ultra-deep and extended reach wells, the premium threaded connections (PTCs) of tubing and casing have to withstand extremely high level of combined loads, and often occurs sealing failure under complex loads. In order to solve this problem, the sealing mechanism of PTCs should be analyzed in depth. The existing analytical method can provide the contact stress formula for PTCs, but the extremely nonlinear mechanics of thread interactions under complex load states cannot be captured due to the stringent assumptions. In this article, a nonlinear 3D elastic-plastic finite element model for 7. casing buttress PTCs with the helix angle is established to analyze the stress distribution characteristics on the sealing surface, shoulder and thread. The results show that the preload has important influence on the sealing characteristics of the PTCs, and the sealing performance of the joint depends on the contact stress on the thread, sealing surface and shoulder. The axial tensile load will increase the sealing performance on the thread and weaken the sealing performance on the shoulder and the sealing surface. When a bending moment is applied on the tool joint, the contact stress increases in the compressed side while decreases in the stretched side, and the contact stress and sealing band width of the sealing surface decline, which indicates that the complex loads greatly affect the sealing performance of the sealing surface. Especially, the sealing surface width and the stress obtained with the three-dimensional finite element model are more reasonable than the analytical method due to the consideration of the helix angle of thread and the elastic-plastic characteristics of the material.",5,8,2
Finite Element,Case,"Goudarzi, Banafsheh; Mohammadmoradi, Peyman; Kantzas, Apostolos",Direct pore-level examination of hydraulic-electric analogy in unconsolidated porous media,Pore-scale; Tortuosity; Finite element; Electric-Hydraulic; Unconsolidated,KOZENY-CARMAN; FIXED-BEDS; TORTUOSITY; FLOW; PERMEABILITY; DIFFUSION; TRANSPORT; MODEL; SIMULATION; POROSITY,"Taking advantage of the analogy between hydraulic and electrical flows to facilitate the prediction of porous media characteristics is a longstanding practice in engineering and science applications. The relationships between hydraulic and electrical properties are widely used in the characterization of transport phenomena relying on the strong correlation between electric and hydraulic flow conductance. However, due to the lack of small-scale investigations the similarity among their pathways/tortuosities is still unclear. Here a series of direct finite element numerical simulations are conducted within pore-level microstructures to extract and compare the streamlines of both electric and fluid flow currents and examine the accuracy of the hydraulic-electric analogy by predicting the petrophysical characteristics of the case studies. The fluid flow and electric transports are simulated through low-porosity digital unconsolidated packings of polydispersed grains representing the Athabasca oil sands deposit as the second largest oil reserve in the world. The formation factor, porosity, and absolute permeability of the media under consideration are predicted, and consequently, the streamlines of both electric and hydraulic currents are extracted and compared in terms of length, shape, and pathways. According to the results, the fluid flow streamlines are longer and pose differently than the homogeneous electric current streamlines. The average ratio between the hydraulic and electric tortuosities is 1.15 and a local extremum occurs at the porosity of eighteen percent. Pedotransfer functions for tortuosities, dimensionless permeability, and formation factor are proposed underpinning the rigorous relationships between transport processes in porous media.",6,6,0
Finite Element,Case,"Yang, Shangyu; Han, Lihong; Feng, Chun; Wang, Hang; Feng, Yaorong; Wu, Xingru",Mechanical performance of casing in in-situ combustion thermal recovery,Casing performance; Heavy oil; In-situ combustion; Casing design; Steam flooding,OIL; WELLS,"In-situ combustion is often used to develop heavy oil as it has multiple advantages over alternative thermal methods. However, the wellbore integrity can be compromised if the casing is not properly designed or manufactured. Based on the fundamentals of heat transfer, a mathematical model with multiphysics is built to study the temperature and pressure distributions surrounding the wellbore during in-situ combustion. In laboratory, real casings and coupons with grades of N80, P110, and 3Cr110 were tested under high temperature to study their mechanical performances in the in-situ combustion recovery. From the modeling and laboratory testing results, we propose the casing design and manufacture protocols for thermal recovery of heavy oil. Field applications in Liaohe oil field, Du-66 Block, shows that the mechanical deterioration of P110 and 3Cr110 is less than that of N80 and the mechanical performance stability of 3Cr110 is better than others when the temperature is less than 600 degrees C. When the temperature is above 600 degrees C for more than 10 h, the mechanical performance of all casing grades declines quickly. Applying finite element analysis, we recommend a safety factor of 1.1 for designing casing at the temperatures of 250 degrees C,480 degrees C and 485 degrees C. The finding of this study provides fundamentals for the casing design and material selection for in-situ combustion recovery.",6,6,0
Finite Element,Laplace Transformation,"Li, Binglin; Su, Yuliang; Zhan, Shiyuan; Yao, Wei; Hu, Yangming; Wang, Wendong",Temporal scale analysis of two phase flow in fractured well,Fractured well; Two phase flow; Temporal scale analysis; Time lag effect,CAPACITANCE-RESISTANCE MODEL; SHALE RESERVOIRS; PERMEABILITY; PROPAGATION; SIMULATION; BEHAVIOR; VOLUME; FIELD,"Two phase flow between two fractures commonly exists around fractured wells. Due to the fracture network, the flow velocity is extremely variable in different regions and it can be described by the temporal scale analysis. The flow velocity also changes with time during the change in water saturation, but these changes cannot be captured by the conventional temporal scale analysis. The temporal scales are obtained based on a principal equation, so it is difficult to accurately estimate the formation properties and to determine the exploitation scheme. In this study, the two phase flow model between two fractures has been proposed for the temporal scale description. The impact of reservoir heterogeneity on the temporal scales is considered in the model. Due to the tortuous flow channel shape between the fractures, the flow pressure affects the fluid flow afterwards. This is explained by the time lag effect in the model. The temporal scales are obtained by using finite element method and Laplace transformation at all time points with these considerations. Moreover, the well is soaked intermittently. The soaking duration is chosen based on temporal scales, and then discussed in terms of efficiency and recovery factor. The results showed that the water saturation profile position is reflected by the temporal scales, the flow resistance and the flow velocity are represented by their zero status response contributions, while the initial flow pressure is described by their zero input contribution. The highest zero status response contribution is different for different properties. Moreover, the time lag effect promotes the initial pressure fluctuation, and also upscales the fluid flow in tortuous channels. Finally, the soaking duration is an approximation of the time required to reduce the fracture flow pressure.",1,1,0
Finite Element,Laplace Transformation,"Moosavi, Seyedeh Robab; Vaferi, Behzad; Wood, David A.",Applying orthogonal collocation for rapid and reliable solutions of transient flow in naturally fractured reservoirs,Naturally fractured reservoir; Pseudo-steady state; Orthogonal collocation method; Parametric analyses; Pressure transient response,DIFFUSIVITY EQUATION; PRESSURE RESPONSE; ELEMENT SOLUTION; WELL; SIMULATION,"Naturally fractured reservoirs (NFR) contain a significant portion of the worldwide oil and gas reserves. Pressure transient analysis is the most well-established methodology for characterizing these heterogeneous reservoirs based upon well-test data. Pressure transient responses (PTR) of oil and gas reservoirs to various production/injection scenarios is widely used for forecasting and optimizing their production performance and ultimate resource recoveries. In this study, orthogonal collocation (OC) which is a straightforward and very efficient approximate approach for solving differential equations is employed as a novel approach to simulate the PTR of NFRs. The governing equations describe fluid flow in NFR for pseudo-steady state conditions. Constant production rate from a wellbore and circular no-flow are employed as an inner and outer boundary conditions, respectively. The results of OC are verified with exact analytical solutions using the Laplace transform. Thereafter, the effects of three parameters (storativity ratio, interporosity flow coefficient, and radial distance of the outer boundary from the wellbore) are studied using pressure-derivative plots. Employing the superposition theorem, the pressure response of NFR to the multi-rate production from the wellbore is calculated. The results indicate that this approximate approach can predict the pressure transient response of NFRs with an acceptable accuracy, i.e., absolute average relative deviation (AARD) of 0.16%. The equations can be adapted to deal with other flow conditions, boundary conditions and fracture stimulated reservoirs. The proposed method provides a straightforward, faster and more accurate solution in comparison with other methods commonly used. As the OC method is simpler to execute than analytical solutions (e.g. Laplace Transform), it is easier to modify and expand for addressing more complex reservoir scenarios. Likewise, the numerical methods (e.g. finite difference and finite elements) commonly applied to model fractured reservoirs involve significantly more time-consuming calculations, making them more cumbersome to use in reservoir simulations than the proposed orthogonal collocation method.",3,4,0
Finite Element,Laplace Transformation,"Abbasi, Mahdi; Rostami, Peyman; Moraveji, Mostafa Keshavarz; Sharifi, Mohammad",Generalized analytical solution for gravity drainage phenomena in finite matrix block with arbitrary time dependent inlet boundary condition and variable matrix block size,Gravity drainage; Finite matrix block; Analytical solution; Numerical method,NATURALLY-FRACTURED RESERVOIRS; POROUS-MEDIA; OIL-RECOVERY; CAPILLARY-PRESSURE; MASS-TRANSFER; INFILTRATION; COEFFICIENT; PREDICTION; MODEL,"Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks.Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery.",8,8,0
Finite Element,Fluid Injection,"Gajo, Alessandro; Cecinato, Francesco; Loret, Benjamin",A computational framework for immiscible three-phase flow in deformable porous media,Immiscible fluids; Capillary pressures; Relative permeabilities; Gas injection; Imbibition; Finite element; Time marching scheme,SEMIDISCRETE FORMULATIONS; MULTIPHASE FLOW; MODEL; PERFORMANCE; TRANSPORT; FLUIDS,"Several soil decontamination processes and enhanced oil recovery techniques involve the co-existence of three immiscible fluids, such as water, a nonaqueous phase liquid and a gas. In this work, a computational framework based on the individual mass balance of each phase is developed, aimed at simulating three-phase flow in a deformable rock through the finite element method, without resorting to specific simplifications that are usually required by standard numerical schemes. Key ingredients of the model are: expression of the residual in terms of mass contents, consistent lumping of the storage terms in the residual and algorithmic (tangent) matrix, consistent integration rules, the use of a minimum relative permeability and a time marching scheme based on trapezoidal integration. Special convective boundary conditions are adopted for pressures to be consistent with the assumed rock wettability properties during co-current imbibition. The resulting numerical scheme can deal with arbitrary saturation and/or pressure boundary conditions. The model is tested by simulating gas injection tests, and both co- and counter-current water imbibition tests, in a deformable core. To assess the performance and robustness of the whole framework, sensitivity analyses are performed upon varying key constitutive, loading and numerical parameters.",2,2,0
Finite Element,Fluid Injection,"Bautista, J. F.; Taleghani, A. Dahi",Prediction of formation damage at water injection wells due to channelization in unconsolidated formations,,FLUID INJECTION; FIBER BEDS; FLOW,"Formation damage due to chemical reactions or mechanical failure of the rock is a well-known issue in the oil and gas industry. In this paper, we look at injectivity changes of water injectors targeting unconsolidated formations as a result of sand channelization. In this situation, sand particles migrate from the formation matrix toward the wellbore and consequently affect permeability of the formation and completion components like frac-packs or gravel-packs. To simulate this phenomenon, we propose a model that decomposes the sand matrix into two different phases by means of their volumetric fractions. The first phase consists of the immobile granular phase while the other is the fraction of grains that are detached from the matrix and carried away by the fluid. The ratio of these two phases evolves over time by means of erosion and deposition. A finite element code for this model is developed and implemented for different reservoir conditions. The results show how local porosity evolves over time around the wellbore by the formation of channels that enhance the flow; however, upon well shut-in, flowback induced by the water hammer effect brings large amounts of sand into the well and fills it up. A study of the effect of frac-packs which are typical completions for wells targeting soft formations is performed to demonstrate potential damage of repetitive shut-ins on injectivity in these wells. The presented model appears as a robust tool to predict sand production for different completion systems to achieve more sustainable injection operations.",6,5,1
Finite Element,Fluid Injection,"Wu, Rui; Deng, Jingen; Liu, Wei; Mao, Shaowen; Sun, Jin; Yan, Min; Li, Ming; Li, Yao",Numerical investigation of fluid injection into poorly consolidated geomaterial considering shear dilation and compaction,Fluid injection; Poorly consolidated geomaterial; Poroelastoplasticity; Cohesive zone model; Shear dilation; Compaction failure,CAM-CLAY PLASTICITY; HYDRAULIC FRACTURE PROBLEM; BOUNDING SURFACE MODEL; IMPLICIT INTEGRATION; LABORATORY EXPERIMENTS; UNCONSOLIDATED-SAND; SOIL; STRESS; FLOW; SIMULATION,"We present a fully coupled poroelastoplastic finite element model to simulate micro-fracture evolution, cornpaction failure and tensile fracture propagation during fluid injection into poorly consolidated geomaterial. The model includes shear dilation, strain hardening and fracture process zone with permeability evolution. We investigated the effects of geomechanics (stress anisotropy) and fluid injection (fluid rheology) on rock deformation and fracture behavior. Results indicate that fluid rheology dominate the rock failure. Pore pressure increase and water wedge effect can cause two kinds of shear dilation which are prior to tensile failure. The effect of compaction is significant to tensile fracture geometries, which differ from those under elastic and poroelastic conditions. The difference between shear band and compaction zone is the transition of fracture regime from the leak-off dominated to the storage dominated governed by fluid injection.",6,6,1
Finite Element,Compaction,"Voyiadjis, George Z.; Zhou, Yaneng",Time-dependent modeling of subsidence due to drainage in bounding shales: Application to a depleted gas field in Louisiana,Subsidence; Compaction; Viscoplasticity; Hydrocarbon production; Drainage,LAND SUBSIDENCE; CONSTITUTIVE APPROACH; SIMULATION; COMPACTION; OIL,"Hydrocarbon production is an important process contributing to the subsidence in Louisiana. Releveling data from National Geodetic Survey show that subsidence along several major oil and gas fields accelerated after production when reservoirs were nearly depleted. The Valentine gas field in coastal Louisiana is chosen to analyze the subsidence during and after production based on three-dimensional finite element modeling. An elasticviscoplastic constitutive model is adopted to interpret the accelerated postdepletion subsidence by overcoming the limitation of traditional theories within the framework of poroelatsicity and poroplasticity. The elasticviscoplastic model integrates a failure envelope, an elliptical cap yield function, and Perzyna's theory of overstress viscoplasticity. The elastic-viscoplastic model is applied to both the simplified disc-shaped reservoir and the bounding shales. The material properties of the elastic-viscoplastic model are calibrated based on a computational technique along with available laboratory and field data from the literature. The numerical modeling results can approximately reproduce both the observed subsidence during production and the delayed subsidence after production using the calibrated material properties. The time-dependent subsidence is predominantly attributed to the delayed compaction that arises from the slow pore pressure diffusion in the bounding shales after the reservoir is depleted. The calibrated finite element model is capable of predicting the time-dependent compaction and subsidence, along with the three-dimensional temporal and spatial distribution of pore pressure, void ratio, vertical strain, and vertical displacement in the bounding shales. The pore pressure diffusion and the time-dependent subsidence are influenced by the permeability of both the reservoir sand and bounding shale. Even though permeability generally increases with damage, and decreases with increased effective stress and reduced porosity, typical constant values of permeability are used for simplicity. The local maximum subsidence is predicted to be 28 cm during 30 years (1982-2012) after the Valentine field is depleted.",5,5,0
Finite Element,Compaction,"Wu, Rui; Deng, Jingen; Liu, Wei; Mao, Shaowen; Sun, Jin; Yan, Min; Li, Ming; Li, Yao",Numerical investigation of fluid injection into poorly consolidated geomaterial considering shear dilation and compaction,Fluid injection; Poorly consolidated geomaterial; Poroelastoplasticity; Cohesive zone model; Shear dilation; Compaction failure,CAM-CLAY PLASTICITY; HYDRAULIC FRACTURE PROBLEM; BOUNDING SURFACE MODEL; IMPLICIT INTEGRATION; LABORATORY EXPERIMENTS; UNCONSOLIDATED-SAND; SOIL; STRESS; FLOW; SIMULATION,"We present a fully coupled poroelastoplastic finite element model to simulate micro-fracture evolution, cornpaction failure and tensile fracture propagation during fluid injection into poorly consolidated geomaterial. The model includes shear dilation, strain hardening and fracture process zone with permeability evolution. We investigated the effects of geomechanics (stress anisotropy) and fluid injection (fluid rheology) on rock deformation and fracture behavior. Results indicate that fluid rheology dominate the rock failure. Pore pressure increase and water wedge effect can cause two kinds of shear dilation which are prior to tensile failure. The effect of compaction is significant to tensile fracture geometries, which differ from those under elastic and poroelastic conditions. The difference between shear band and compaction zone is the transition of fracture regime from the leak-off dominated to the storage dominated governed by fluid injection.",6,6,1
Finite Element,Compaction,"Bruch, A.; Maghous, S.; Ribeiro, F. L. B.; Dormieux, L.",A thermo-poro-mechanical constitutive and numerical model for deformation in sedimentary basins,Sedimentary basin; Mechanical compaction; Chemo-mechanical compaction; Thermo-poroplasticity; Thermo-poroviscoplasticity; Finite element approach,PRESSURE SOLUTION; ELASTIC PROPERTIES; COMPACTION MODEL; HEAT-FLOW; NORTH-SEA; OVERPRESSURE; EVOLUTION; CONSOLIDATION; PERMEABILITY; TEMPERATURE,"Comprehensive modeling of sedimentary basins should integrate the coupled nature of different phenomena such as sediment compaction, pore-fluid flow and heat transport. In this context, the thermal evolution of the basin plays an important role in the mechanical and chemo-mechanical deformation processes as heat modifies fluids viscosity and minerals physicochemical properties, thus affecting pore fluid expulsion and mineral stability. The present paper describes a three-dimensional constitutive and numerical model specifically devised for dealing with thermo-poromechanical deformation processes during diagenesis. The sedimentary basin is modeled as a fully saturated thermo-poro-elastoplastic-viscoplastic medium undergoing large strains. A key feature of the model is related to the evolution of the sediment material properties associated with temperature and large irreversible porosity changes. The computational model, which integrates both poroplastic and poroviscoplastic components of deformation at large strains, relies upon a parallel implementation of the finite element method with a shared memory multiprocessing interface. Numerical simulations of gravitational compaction during the sediment accretion phase as well as along geological period of pore pressure dissipation are performed in the context of oedometric setting. Special emphasis is given to temperature effects on the deformation history of the basin.",6,6,2
Finite Element,Hydraulic Fracture,"Liu, Wenzheng; Zeng, Qingdong; Yao, Jun",Numerical simulation of elasto-plastic hydraulic fracture propagation in deep reservoir coupled with temperature field,Deep reservoir; Hydraulic fracturing; Elasto-plasticity; Heat transfer; Cohesive zone model; Embedded discrete fracture model,FLUID-DRIVEN FRACTURES; MEDIA; ROCK,"With the increasing demand of oil and gas resource, the development of deep reservoir has become an inevitable trend. To investigate the coupled effects of rock elasto-plastic deformation, fluid flow and heat transfer in the process of hydraulic fracturing of deep reservoir, the mathematical model of elasto-plastic hydraulic fracture propagation is established based on cohesive zone model (CZM) and embedded discrete fracture model (EDFM). The constitutive equation incorporating thermal stress is derived by using Drucker-Prager yield condition and the associated flow law. Fluid flow in the fracture is modeled with lubrication theory. The thermal non-equilibrium theory is employed to describe the heat exchange between rock matrix and fluid in the fracture based on EDFM. The CZM is used as fracture propagation criterion. The rock deformation equation is solved by finite element method. The temperature field and fluid flow in the fracture are discretized by finite volume method. Due to the non-linearity of flow equation, the iterative method is used to solve the coupled problem of stress, pressure and temperature fields. A Triangular-PEBI (Perpendicular Bisector) dual mesh system is presented for numerical implementation. The numerical model is validated against with analytical solution and other methods in the literature. The results show the significance of accounting for elasto-plastic deformation and heat transfer when simulating hydraulic fracture propagation in deep reservoir.",5,5,5
Finite Element,Hydraulic Fracture,"Wu, Rui; Deng, Jingen; Liu, Wei; Mao, Shaowen; Sun, Jin; Yan, Min; Li, Ming; Li, Yao",Numerical investigation of fluid injection into poorly consolidated geomaterial considering shear dilation and compaction,Fluid injection; Poorly consolidated geomaterial; Poroelastoplasticity; Cohesive zone model; Shear dilation; Compaction failure,CAM-CLAY PLASTICITY; HYDRAULIC FRACTURE PROBLEM; BOUNDING SURFACE MODEL; IMPLICIT INTEGRATION; LABORATORY EXPERIMENTS; UNCONSOLIDATED-SAND; SOIL; STRESS; FLOW; SIMULATION,"We present a fully coupled poroelastoplastic finite element model to simulate micro-fracture evolution, cornpaction failure and tensile fracture propagation during fluid injection into poorly consolidated geomaterial. The model includes shear dilation, strain hardening and fracture process zone with permeability evolution. We investigated the effects of geomechanics (stress anisotropy) and fluid injection (fluid rheology) on rock deformation and fracture behavior. Results indicate that fluid rheology dominate the rock failure. Pore pressure increase and water wedge effect can cause two kinds of shear dilation which are prior to tensile failure. The effect of compaction is significant to tensile fracture geometries, which differ from those under elastic and poroelastic conditions. The difference between shear band and compaction zone is the transition of fracture regime from the leak-off dominated to the storage dominated governed by fluid injection.",6,6,1
Finite Element,Laterals,"Kan, Changbin; Yang, Jin; Yu, Xiaocong; Dong, Tiejun; Wu, Xudong; Liu, Ming; Li, Chun; Zhang, Changliang; Fu, Jinbao",Load bearing characteristics study on novel deepwater composite drilling conductor by simulation and experimental methods,Composite drilling conductor; Laboratory experiment; Numerical simulation; Vertical bearing capacity; Lateral displacement; Soil pressure variation,SAND; SOIL,"A novel design of composite drilling conductor (CDC) was carried out for improving the vertical and lateral bearing capacity. Bearing characteristics of CDC was investigated when subjected to lateral and longitudinal loads based on the ultimate subgrade reaction method and pile foundation bearing theory. Theoretical models for lateral displacement and vertical load were established. Finite element analysis (FEA) was conducted, and bearing capacity and influencing factors of the composite structure were studied. Through laboratory experiments, the interaction between the structure and the soil as well as the regularity of soil deformation and stress variation in the surrounding soil were studied during installation, vertical and lateral load application. The results showed that the vertical bearing capacity increased with increasing depth of the bucket foundation under the combined effect of the composite structure. Meanwhile, the depth of the embedded point of the composite conductor increased with an increased bending moment when subjected to a combined load with a constant vertical force. When the bending moment on the structure top was constant, the lateral displacement of the structure as well as the depth of the embedded point would increase with increasing vertical force. Furthermore, the bending moment change on the top of the CDC was more significant than the vertical force regarding the lateral displacement. It is also showed that the internal bucket foundation produced an ""elastic plugging"" effect when the CDC was subjected to vertical loading, while soil pressure transmission occurred from the upper soil to the underlying strata soil. When subjected to lateral loads, the earth pressure on the bucket sidewall was redistributed, and the bucket foundation produced a lateral supporting effect on CDC. The composite structure effectively reduced the conductor vertical and lateral displacement and improved the lateral and vertical bearing capacity. These results provide useful theoretical references for further development and optimization of the CDC structure.",4,6,1
Finite Element,Laterals,"Wang, Heng; Guan, Zhi-chuan; Shi, Yu-cai; Chen, Wei-qing; Liu, Yong-wang; Zhang, Bo; Liang, De-yang; Wang, Xiao-hui",Modeling and analyzing the motion state of bottom hole assembly in highly deviated wells,Motion state; BHA; Highly deviated wells; Rotary speed; Weight on bit,STEERABLE DRILLING SYSTEM; LATERAL VIBRATION; FINITE-ELEMENT; ROTARY; DRILLSTRINGS; DYNAMICS,"Motion state of bottom hole assembly (BHA) has a great effect on the performance of downhole drilling tools. In this article, we developed a finite element model for characterizing the lateral motion of BHA in highly deviated wells taking discontinuous interaction between drill strings and wellbore into consideration. Numerical simulations were conducted by solving the motion equation through Newmark method. To verify the established model, an indoor experimental apparatus was built based on the similarity criterion. Numerical and experimental simulation results were compared and analyzed under different rotary speed, weight on bit (WOB) and well inclination condition. Both of the results showed that BHA locates in and swings along the lower right part of borehole in highly deviated wells without forming into backward whirl motion. Rotary speed has an obvious effect on BHA lateral motion state where the vibration amplitude and frequency get improved with the increase of rotary speed. Compared with rotary speed, WOB and well inclination angle has a much smaller effect on the BHA lateral motion in highly deviated wells. Based on the analyses, relevant recommendations were given for the engineering practical use. This study can help understand the dynamic characteristics of BHA in highly deviated wells and select operation parameters for better drilling.",8,10,0
Finite Element,Gas Field,"Voyiadjis, George Z.; Zhou, Yaneng",Time-dependent modeling of subsidence due to drainage in bounding shales: Application to a depleted gas field in Louisiana,Subsidence; Compaction; Viscoplasticity; Hydrocarbon production; Drainage,LAND SUBSIDENCE; CONSTITUTIVE APPROACH; SIMULATION; COMPACTION; OIL,"Hydrocarbon production is an important process contributing to the subsidence in Louisiana. Releveling data from National Geodetic Survey show that subsidence along several major oil and gas fields accelerated after production when reservoirs were nearly depleted. The Valentine gas field in coastal Louisiana is chosen to analyze the subsidence during and after production based on three-dimensional finite element modeling. An elasticviscoplastic constitutive model is adopted to interpret the accelerated postdepletion subsidence by overcoming the limitation of traditional theories within the framework of poroelatsicity and poroplasticity. The elasticviscoplastic model integrates a failure envelope, an elliptical cap yield function, and Perzyna's theory of overstress viscoplasticity. The elastic-viscoplastic model is applied to both the simplified disc-shaped reservoir and the bounding shales. The material properties of the elastic-viscoplastic model are calibrated based on a computational technique along with available laboratory and field data from the literature. The numerical modeling results can approximately reproduce both the observed subsidence during production and the delayed subsidence after production using the calibrated material properties. The time-dependent subsidence is predominantly attributed to the delayed compaction that arises from the slow pore pressure diffusion in the bounding shales after the reservoir is depleted. The calibrated finite element model is capable of predicting the time-dependent compaction and subsidence, along with the three-dimensional temporal and spatial distribution of pore pressure, void ratio, vertical strain, and vertical displacement in the bounding shales. The pore pressure diffusion and the time-dependent subsidence are influenced by the permeability of both the reservoir sand and bounding shale. Even though permeability generally increases with damage, and decreases with increased effective stress and reduced porosity, typical constant values of permeability are used for simplicity. The local maximum subsidence is predicted to be 28 cm during 30 years (1982-2012) after the Valentine field is depleted.",5,5,0
Finite Element,Gas Field,"Liu, Wenzheng; Zeng, Qingdong; Yao, Jun",Numerical simulation of elasto-plastic hydraulic fracture propagation in deep reservoir coupled with temperature field,Deep reservoir; Hydraulic fracturing; Elasto-plasticity; Heat transfer; Cohesive zone model; Embedded discrete fracture model,FLUID-DRIVEN FRACTURES; MEDIA; ROCK,"With the increasing demand of oil and gas resource, the development of deep reservoir has become an inevitable trend. To investigate the coupled effects of rock elasto-plastic deformation, fluid flow and heat transfer in the process of hydraulic fracturing of deep reservoir, the mathematical model of elasto-plastic hydraulic fracture propagation is established based on cohesive zone model (CZM) and embedded discrete fracture model (EDFM). The constitutive equation incorporating thermal stress is derived by using Drucker-Prager yield condition and the associated flow law. Fluid flow in the fracture is modeled with lubrication theory. The thermal non-equilibrium theory is employed to describe the heat exchange between rock matrix and fluid in the fracture based on EDFM. The CZM is used as fracture propagation criterion. The rock deformation equation is solved by finite element method. The temperature field and fluid flow in the fracture are discretized by finite volume method. Due to the non-linearity of flow equation, the iterative method is used to solve the coupled problem of stress, pressure and temperature fields. A Triangular-PEBI (Perpendicular Bisector) dual mesh system is presented for numerical implementation. The numerical model is validated against with analytical solution and other methods in the literature. The results show the significance of accounting for elasto-plastic deformation and heat transfer when simulating hydraulic fracture propagation in deep reservoir.",5,5,5
Finite Element,Structure,"Kan, Changbin; Yang, Jin; Yu, Xiaocong; Dong, Tiejun; Wu, Xudong; Liu, Ming; Li, Chun; Zhang, Changliang; Fu, Jinbao",Load bearing characteristics study on novel deepwater composite drilling conductor by simulation and experimental methods,Composite drilling conductor; Laboratory experiment; Numerical simulation; Vertical bearing capacity; Lateral displacement; Soil pressure variation,SAND; SOIL,"A novel design of composite drilling conductor (CDC) was carried out for improving the vertical and lateral bearing capacity. Bearing characteristics of CDC was investigated when subjected to lateral and longitudinal loads based on the ultimate subgrade reaction method and pile foundation bearing theory. Theoretical models for lateral displacement and vertical load were established. Finite element analysis (FEA) was conducted, and bearing capacity and influencing factors of the composite structure were studied. Through laboratory experiments, the interaction between the structure and the soil as well as the regularity of soil deformation and stress variation in the surrounding soil were studied during installation, vertical and lateral load application. The results showed that the vertical bearing capacity increased with increasing depth of the bucket foundation under the combined effect of the composite structure. Meanwhile, the depth of the embedded point of the composite conductor increased with an increased bending moment when subjected to a combined load with a constant vertical force. When the bending moment on the structure top was constant, the lateral displacement of the structure as well as the depth of the embedded point would increase with increasing vertical force. Furthermore, the bending moment change on the top of the CDC was more significant than the vertical force regarding the lateral displacement. It is also showed that the internal bucket foundation produced an ""elastic plugging"" effect when the CDC was subjected to vertical loading, while soil pressure transmission occurred from the upper soil to the underlying strata soil. When subjected to lateral loads, the earth pressure on the bucket sidewall was redistributed, and the bucket foundation produced a lateral supporting effect on CDC. The composite structure effectively reduced the conductor vertical and lateral displacement and improved the lateral and vertical bearing capacity. These results provide useful theoretical references for further development and optimization of the CDC structure.",4,6,1
Finite Element,Structure,"Li, Yilun; Guo, Shuangxi; Chen, Weimin",Analysis on multi-frequency vortex-induced vibration and mode competition of flexible deep-ocean riser in sheared fluid fields,Vortex-induced vibration; Multi-frequency; Mode competition; Fluid-solid coupling; Long flexible riser,DYNAMIC CHARACTERISTICS; FORCE DISTRIBUTION; CIRCULAR-CYLINDER; VIV,"Multi-frequency vortex-induced vibration of flexible riser in lineally sheared fluid fields with different shearing parameters is explored by using the numerical approach. By combining the finite element method with a hydrodynamic model, the approach can consider mode competition based on modal energy and can carry out nonlinearly simultaneously dynamic response in time domain. Our analysis shows that multi-frequency VIV may occur both in non-uniform and uniform fluid fields. And, the behaviors of multi-frequency VIV are different from single-frequency VIV. Because several modes are involved and compete with each other, and consequently the determination of modal excitation region become more complicated. As the towing speed (or the shearing parameter) increases in sheared flow, the average RMS displacement does not regularly rise (or drop), but slightly fluctuates owing to changes of the participating mode and its excitation region. On the other hand, the average RMS stress gradually rises owing to higher-order modes being included. Moreover, it is found that the dominant frequency distributing along structural span significantly changes with the towing speed, and the length of the first dominant frequency gets smaller due to larger shearing parameter along with more intense competition between the participating modes.",5,6,2
Finite Element,Speed,"Li, Yilun; Guo, Shuangxi; Chen, Weimin",Analysis on multi-frequency vortex-induced vibration and mode competition of flexible deep-ocean riser in sheared fluid fields,Vortex-induced vibration; Multi-frequency; Mode competition; Fluid-solid coupling; Long flexible riser,DYNAMIC CHARACTERISTICS; FORCE DISTRIBUTION; CIRCULAR-CYLINDER; VIV,"Multi-frequency vortex-induced vibration of flexible riser in lineally sheared fluid fields with different shearing parameters is explored by using the numerical approach. By combining the finite element method with a hydrodynamic model, the approach can consider mode competition based on modal energy and can carry out nonlinearly simultaneously dynamic response in time domain. Our analysis shows that multi-frequency VIV may occur both in non-uniform and uniform fluid fields. And, the behaviors of multi-frequency VIV are different from single-frequency VIV. Because several modes are involved and compete with each other, and consequently the determination of modal excitation region become more complicated. As the towing speed (or the shearing parameter) increases in sheared flow, the average RMS displacement does not regularly rise (or drop), but slightly fluctuates owing to changes of the participating mode and its excitation region. On the other hand, the average RMS stress gradually rises owing to higher-order modes being included. Moreover, it is found that the dominant frequency distributing along structural span significantly changes with the towing speed, and the length of the first dominant frequency gets smaller due to larger shearing parameter along with more intense competition between the participating modes.",5,6,2
Finite Element,Speed,"Wang, Heng; Guan, Zhi-chuan; Shi, Yu-cai; Chen, Wei-qing; Liu, Yong-wang; Zhang, Bo; Liang, De-yang; Wang, Xiao-hui",Modeling and analyzing the motion state of bottom hole assembly in highly deviated wells,Motion state; BHA; Highly deviated wells; Rotary speed; Weight on bit,STEERABLE DRILLING SYSTEM; LATERAL VIBRATION; FINITE-ELEMENT; ROTARY; DRILLSTRINGS; DYNAMICS,"Motion state of bottom hole assembly (BHA) has a great effect on the performance of downhole drilling tools. In this article, we developed a finite element model for characterizing the lateral motion of BHA in highly deviated wells taking discontinuous interaction between drill strings and wellbore into consideration. Numerical simulations were conducted by solving the motion equation through Newmark method. To verify the established model, an indoor experimental apparatus was built based on the similarity criterion. Numerical and experimental simulation results were compared and analyzed under different rotary speed, weight on bit (WOB) and well inclination condition. Both of the results showed that BHA locates in and swings along the lower right part of borehole in highly deviated wells without forming into backward whirl motion. Rotary speed has an obvious effect on BHA lateral motion state where the vibration amplitude and frequency get improved with the increase of rotary speed. Compared with rotary speed, WOB and well inclination angle has a much smaller effect on the BHA lateral motion in highly deviated wells. Based on the analyses, relevant recommendations were given for the engineering practical use. This study can help understand the dynamic characteristics of BHA in highly deviated wells and select operation parameters for better drilling.",8,10,0
Finite Element,Shale,"Li, Binglin; Su, Yuliang; Zhan, Shiyuan; Yao, Wei; Hu, Yangming; Wang, Wendong",Temporal scale analysis of two phase flow in fractured well,Fractured well; Two phase flow; Temporal scale analysis; Time lag effect,CAPACITANCE-RESISTANCE MODEL; SHALE RESERVOIRS; PERMEABILITY; PROPAGATION; SIMULATION; BEHAVIOR; VOLUME; FIELD,"Two phase flow between two fractures commonly exists around fractured wells. Due to the fracture network, the flow velocity is extremely variable in different regions and it can be described by the temporal scale analysis. The flow velocity also changes with time during the change in water saturation, but these changes cannot be captured by the conventional temporal scale analysis. The temporal scales are obtained based on a principal equation, so it is difficult to accurately estimate the formation properties and to determine the exploitation scheme. In this study, the two phase flow model between two fractures has been proposed for the temporal scale description. The impact of reservoir heterogeneity on the temporal scales is considered in the model. Due to the tortuous flow channel shape between the fractures, the flow pressure affects the fluid flow afterwards. This is explained by the time lag effect in the model. The temporal scales are obtained by using finite element method and Laplace transformation at all time points with these considerations. Moreover, the well is soaked intermittently. The soaking duration is chosen based on temporal scales, and then discussed in terms of efficiency and recovery factor. The results showed that the water saturation profile position is reflected by the temporal scales, the flow resistance and the flow velocity are represented by their zero status response contributions, while the initial flow pressure is described by their zero input contribution. The highest zero status response contribution is different for different properties. Moreover, the time lag effect promotes the initial pressure fluctuation, and also upscales the fluid flow in tortuous channels. Finally, the soaking duration is an approximation of the time required to reduce the fracture flow pressure.",1,1,0
Finite Element,Shale,"Voyiadjis, George Z.; Zhou, Yaneng",Time-dependent modeling of subsidence due to drainage in bounding shales: Application to a depleted gas field in Louisiana,Subsidence; Compaction; Viscoplasticity; Hydrocarbon production; Drainage,LAND SUBSIDENCE; CONSTITUTIVE APPROACH; SIMULATION; COMPACTION; OIL,"Hydrocarbon production is an important process contributing to the subsidence in Louisiana. Releveling data from National Geodetic Survey show that subsidence along several major oil and gas fields accelerated after production when reservoirs were nearly depleted. The Valentine gas field in coastal Louisiana is chosen to analyze the subsidence during and after production based on three-dimensional finite element modeling. An elasticviscoplastic constitutive model is adopted to interpret the accelerated postdepletion subsidence by overcoming the limitation of traditional theories within the framework of poroelatsicity and poroplasticity. The elasticviscoplastic model integrates a failure envelope, an elliptical cap yield function, and Perzyna's theory of overstress viscoplasticity. The elastic-viscoplastic model is applied to both the simplified disc-shaped reservoir and the bounding shales. The material properties of the elastic-viscoplastic model are calibrated based on a computational technique along with available laboratory and field data from the literature. The numerical modeling results can approximately reproduce both the observed subsidence during production and the delayed subsidence after production using the calibrated material properties. The time-dependent subsidence is predominantly attributed to the delayed compaction that arises from the slow pore pressure diffusion in the bounding shales after the reservoir is depleted. The calibrated finite element model is capable of predicting the time-dependent compaction and subsidence, along with the three-dimensional temporal and spatial distribution of pore pressure, void ratio, vertical strain, and vertical displacement in the bounding shales. The pore pressure diffusion and the time-dependent subsidence are influenced by the permeability of both the reservoir sand and bounding shale. Even though permeability generally increases with damage, and decreases with increased effective stress and reduced porosity, typical constant values of permeability are used for simplicity. The local maximum subsidence is predicted to be 28 cm during 30 years (1982-2012) after the Valentine field is depleted.",5,5,0
Finite Element,Tubing,"Chen, Wei; Di, Qinfeng; Zhang, He; Chen, Feng; Wang, Wenchang",The sealing mechanism of tubing and casing premium threaded connections under complex loads,Premium threaded connections; Three-dimensional finite element analysis; Sealing mechanism; Analytical method; Complex loads,,"With the increase of ultra-deep and extended reach wells, the premium threaded connections (PTCs) of tubing and casing have to withstand extremely high level of combined loads, and often occurs sealing failure under complex loads. In order to solve this problem, the sealing mechanism of PTCs should be analyzed in depth. The existing analytical method can provide the contact stress formula for PTCs, but the extremely nonlinear mechanics of thread interactions under complex load states cannot be captured due to the stringent assumptions. In this article, a nonlinear 3D elastic-plastic finite element model for 7. casing buttress PTCs with the helix angle is established to analyze the stress distribution characteristics on the sealing surface, shoulder and thread. The results show that the preload has important influence on the sealing characteristics of the PTCs, and the sealing performance of the joint depends on the contact stress on the thread, sealing surface and shoulder. The axial tensile load will increase the sealing performance on the thread and weaken the sealing performance on the shoulder and the sealing surface. When a bending moment is applied on the tool joint, the contact stress increases in the compressed side while decreases in the stretched side, and the contact stress and sealing band width of the sealing surface decline, which indicates that the complex loads greatly affect the sealing performance of the sealing surface. Especially, the sealing surface width and the stress obtained with the three-dimensional finite element model are more reasonable than the analytical method due to the consideration of the helix angle of thread and the elastic-plastic characteristics of the material.",5,8,2
Finite Element,Tubing,"Liang, Zheng; Zhu, ZhaoLiang",Critical helical buckling load assessment of coiled tubing under axial force by use of the explicit finite-element method,Helical buckling; Coiled tubing; Axial force; Explicit FEA; Transmission,,"Previous theoretical formulations for helical buckling of drill strings vary significantly and are mostly proposed for the linear questions. But there are a little no-linear questions in the mechanical behaviour of tubulars. Explicit finite element analysis (FEA) method has the ability to consider geometric details and nonlinearities. This paper builds an explicit FEA model to describe the behaviors of comprehensive buckling and transmission of axial force for coiled tubing (CT) with residual bending in a horizontal well. The calculational results show that the CT with residual bending is easier to buckle than a straight CT. For the CT with an initial sinusoidal shape, the parameters of initial amplitude and initial pitch are inversely proportional to the helical buckling force, and the outer diameter (OD) is proportional to the helical buckling force. In the process of axial force transmission, the parameters of initial amplitude and frictional coefficient are inversely proportional to the axial force, the OD and initial pitch are proportional to axial force. Residual curvature in coiled tubing appears to have only a small effect on its downhole performance, based on FEA modeling of CT with sinusoidal curvature.",9,10,0
Cement,Cement Slurry,"Ma, Chengyun; Deng, Jingen; Wu, Rui; Yu, Baohua; Zhou, Yingcao; Lin, Sen",A novel self-healing spacer fluid for sustained casing pressure mitigation,Self-healing; Spacer fluids; Sustained casing pressure (SCP); Micro-annulus; Micro-cracks; Cement sheath,WELL; OIL; INTEGRITY; INTERFACE; BEHAVIOR; MODEL,"Sustained casing pressure (SCP) is one of the most common and costly problems in the oil and gas industry, which results in various unfavorable effects in the economy and catastrophic consequences. The development of micro-annulus and micro-cracks within the cement sheath causes the need to develop a unique self-healing spacer fluid to enhance the integrity of cement sheath. This study aims to investigate a novel self-healing spacer fluid that provides a long-term zonal isolation to mitigate SCP problems during well cementing or production operations. Micro-annulus or micro-crack simulation experiments were conducted on artificial cement sheath samples under various confining pressures to investigate the self-healing capability of the novel self-healing spacer fluid. Post-evaluation methods, such as self-healing test and computed tomography scanner, as well as scanning electron microscopy, were used to investigate the effect of the self-healing spacer fluid on the properties of the original cement slurry and repair effectiveness. The self-healing capability of the novel self-healing spacer fluid was assessed based on the conducted experiments and post-evaluation analyses. The effect of the self-healing spacer fluid on the cement slurry properties and casing corrosion was also analyzed. Experiment results indicated that the novel self-healing spacer fluid could penetrate into the micro-cracks or micro-annulus within the cement sheath to activate the hydration reaction of the non-hydrated cement, thereby producing a hydrated calcium silicate gel ( C-S-H or C-A-H) that could strengthen the main body for the damaged zone. The experiment results also indicated that self-healing spacers had a higher displacement efficiency than common spacers in improving the interface bond strength between the casing and cement sheath. Moreover, the self-healing spacers had a slight influence on the cement slurry properties and the ability to resist casing corrosion. Thus, the self-healing technology is safe and cost-effective for curing the SCP problem.",1,1,2
Cement,Cement Slurry,"da Silva, Italo Batista; Martinelli, Antonio Eduardo; Medeiros de Souza, Wendell Rossine; de Oliveira Freitas, Julio Cezar; Felipe Rodrigues, Marcos Alysson",Dilatometric behavior and crystallographic characterization of Portland-polyurethane composites for oilwell high-temperature cementing applications,Oilwell cementing; Portland cement; Polyurethane and thermal expansion,THERMAL-EXPANSION; WELL CEMENT; HYDRATION,"In order to improve the behavior of Portland-based oilwell sheath to high-temperature applications and the corresponding thermal gradients, polymeric admixtures can be added. Steam injection, for instance, raises the cement sheath-steel casing interface temperature to similar to 300 degrees C which can be deleterious to the mechanical stability and zonal isolation provided by the cement sheath as a result of cracking of the cement. Polyurethane can be added to the cement to improve its plastic behavior and reduce the thermal expansion mismatch between casing and sheath. However, the use polymeric admixtures, especially as aqueous dispersion, can affect the kinetics of the hydration reactions and, as a consequence, the crystallographic composition and coefficient of thermal expansion of the material. Therefore, the present study aimed at evaluating the effects of the addition of different concentrations of polyurethane on the thermomechanical properties of Portland cement pastes cured at 300 degrees C from 14 to 90 days. Formulations containing 1 gpc (0.052 kg), 2 gpc (0.102 kg) and 3 gpc (0.153 kg) of polyurethane, respectively named PU1, PU2 and PU3 were prepared according to the American Petroleum Institute guidelines. A standard PU-free slurry was also prepared. X-ray diffraction and dry dilatometric tests were carried out. The results revealed that the curing time does affect the kinetics of hydration of Portland-polyurethane composites, retarding the formation of high-temperature stable phases, i.e., tobermorite and xonotlite. Moreover, longer curing times were necessary to reveal the improved expansion of the composites with respect to the standard sample. The addition of polyurethane can be pointed as an approach to high-temperature oilwell cement applications, since it reduces the thermal mismatch between cement sheath and steel casing for and retards but do not prevent the formation of xonotlite.",4,4,0
Cement,Cement Slurry,"Choi, Myoungsung; Scherer, George W.; Prudhomme, Robert K.",Novel methodology to evaluate displacement efficiency of drilling mud using fluorescence in primary cementing,Primary cementing; Displacement; Fluorescence; Metallurgy; Surface roughness,CONTACT ANGLES; SURFACES; WETTABILITY; ROUGHNESS; ADHESION; ENERGY,"For primary cementing of a well, successful displacement of drilling mud from the casing and annulus, and properly conditioning those surfaces to bond with the cement slurry, are paramount to achieve zonal isolation. In this study, to evaluate displacement of drilling mud from well casings, a fluorescence methodology incorporating a hydrophobic dye was developed. Fluorescence is attractive because the dye is highly oil soluble and non-polar and can be detected at very low concentrations, so chemical interference between dye and drilling mud is minimized. From the fluorescence measurements, the thickness of residual drilling mud can be quantitatively determined, which makes it possible to quantify the efficiency of drilling mud removal. Residual oil layers under consideration in this study from 32 mu m to 1.5 mu m are observed. The spacer fluids D and E are excellent in their ability to remove the drilling mud, whereas spacer F performs poorly. The effects of metallurgy and surface roughness on wettability were investigated using the measured thickness of residual drilling mud. There is little effect of the composition of the steel tube on wettability, but the surface roughness or presence of corrosion can significantly affect the wettability.",5,5,0
Cement,Cement Slurry,"Srivastava, Aman; Ahmed, Ramadan; Shah, Subhash",Effects of magnesium oxide on carbonic acid resistance of oil well cement,Oil well cement; Magnesium oxide; Carbonation; Degradation; Expansion; Porosity,CO2 GEOLOGICAL STORAGE; DEGRADATION; MGO; INTEGRITY; KINETICS,"This paper presents the results of an experimental study on the effects of magnesium oxide additive on the performance of oil well cement under a high-pressure high-temperature (HPHT) carbonic acid environment. Magnesium oxide (MgO) is a well-known expanding agent that improves sealing performance of cement. However, the performance of MgO-based cement has not been tested in a carbonic acid environment. Therefore, to investigate the impact of MgO on carbonic acid resistance of cement, two cement slurry formulations: Class H cement with 35% silica (baseline or HS) and baseline cement with MgO (HSMG) were compared after exposure to an acidic environment. To evaluate their performance, cylindrical cores and shear bond strengths (SBS) samples were prepared and aged in HPHT autoclave containing brine (2% sodium chloride solution) saturated with mixed gas containing CH4 and CO2. Six aging tests were conducted varying CO2 concentration, temperature, and pressure. After aging for 14 days at constant pressure and temperature, the samples were recovered, and their physical (bond and compressive strength, porosity and permeability) and mineralogical composition were measured and compared with those of unaged samples. The results suggest that addition of 5% MgO reduces the carbonation of cement and could potentially prolong the operational life of cement by protecting its binding components (calcium hydroxide and calcium silicate hydrate).",5,5,0
Cement,Cement Slurry,"Curbelo, F. D. S.; Garnica, A. I. C.; Araujo, E. A.; Paiva, E. M.; Cabral, A. G.; Freitas, J. C. O.",Vegetable oil-based preflush fluid in well cementing,Vegetable oil-based microemulsion; Cleanup fluid; Surfactants; Cement slurry,DRILLING-FLUID; FILTER CAKE; REMOVAL,"Efficient cement bonding in wellbores provides better zonal insulation, containment of gas migration, prevention of excessive water production, besides affecting their economical performances. Carrying out a properly sized and formulated cleanup process (or pre-flush) is one of the most costly tasks in wellbore preparation. Different chemicals are commonly used both to remove filter cakes and enhance surface water-wetting, such as solvents and surfactants. The search for environmentally-friendly cleanup fluids, in particular, with acceptable wetting properties, has been challenging. This paper describes an experimental study to characterize and prepare a vegetable oil-based microemulsion to work as pre-flush fluid in wellbores. Results obtained from cleaning assays (removal test), wettability testings and fluid compatibility analyses have exhibited excellent performances in filter cake removal. Enhanced water-wetting and suitable rheological compatibility of cement/cleanup fluid/mud systems and good compressive strength were also achieved.",6,6,5
Cement,Cement Slurry,"Yang, Yuanguang; Yuan, Bin; Wang, Yongqing",Updated methodology for evaluating lost circulation control of cement slurry for double lost channels,Cementing; Fracture-pore lost channel; Bridging; Sealing coefficient,HIGH-TEMPERATURE; SYSTEMS,"This paper presents an evaluation method for evaluating the sealing capacity of cement slurry with lost circulation control for effective lost channel sealing during cementing operations. The method was developed based on a lost device and an evaluation model that we developed ourselves. This evaluation model includes three critical evaluation indexes: the loss time, loss weight, and maximum sealing pressure. In addition, it can be used to quantitatively evaluate the effective sealing capability of cement slurry with lost circulation control. This method is aimed at evaluating the sealing capacity of cement slurry as a way to investigate its applicability in designing effective treatments for the sealing of multiple lost channels. The results suggest the particle lost circulation materials (LCM) can improve the bridging capacity of fiber cement slurry. The loss capacity of a fracture-pore double lost channel is not equal to that of a fracture and a channel superposition. Moreover, the lost channel method can avoid an excessive or overly low evaluation of the sealing capacity of the cement slurry.",8,8,1
Cement,Cement Sheath,"Ma, Chengyun; Deng, Jingen; Wu, Rui; Yu, Baohua; Zhou, Yingcao; Lin, Sen",A novel self-healing spacer fluid for sustained casing pressure mitigation,Self-healing; Spacer fluids; Sustained casing pressure (SCP); Micro-annulus; Micro-cracks; Cement sheath,WELL; OIL; INTEGRITY; INTERFACE; BEHAVIOR; MODEL,"Sustained casing pressure (SCP) is one of the most common and costly problems in the oil and gas industry, which results in various unfavorable effects in the economy and catastrophic consequences. The development of micro-annulus and micro-cracks within the cement sheath causes the need to develop a unique self-healing spacer fluid to enhance the integrity of cement sheath. This study aims to investigate a novel self-healing spacer fluid that provides a long-term zonal isolation to mitigate SCP problems during well cementing or production operations. Micro-annulus or micro-crack simulation experiments were conducted on artificial cement sheath samples under various confining pressures to investigate the self-healing capability of the novel self-healing spacer fluid. Post-evaluation methods, such as self-healing test and computed tomography scanner, as well as scanning electron microscopy, were used to investigate the effect of the self-healing spacer fluid on the properties of the original cement slurry and repair effectiveness. The self-healing capability of the novel self-healing spacer fluid was assessed based on the conducted experiments and post-evaluation analyses. The effect of the self-healing spacer fluid on the cement slurry properties and casing corrosion was also analyzed. Experiment results indicated that the novel self-healing spacer fluid could penetrate into the micro-cracks or micro-annulus within the cement sheath to activate the hydration reaction of the non-hydrated cement, thereby producing a hydrated calcium silicate gel ( C-S-H or C-A-H) that could strengthen the main body for the damaged zone. The experiment results also indicated that self-healing spacers had a higher displacement efficiency than common spacers in improving the interface bond strength between the casing and cement sheath. Moreover, the self-healing spacers had a slight influence on the cement slurry properties and the ability to resist casing corrosion. Thus, the self-healing technology is safe and cost-effective for curing the SCP problem.",1,1,2
Cement,Cement Sheath,"Deng, Kuanhai; Liu, Wanying; Lin, Yuanhua; Zeng, Dezhi; Zhang, Jichuan; Xiang, Junke",Experimental and numerical investigation on repairing process of cement-casing repaired by rolling reshaper,Rolling reshaper; Repairing process; Experiment; Finite element model; Cement-casing; Repairing force,,"In oil field, the bit weight (repairing force) and torque are always determined by experience when the rolling reshaper is used to repair the deformed casing. However, if the repairing force and torque are unreasonable, it will easily give rise to the secondary damage of deformed casing and surrounding cement sheath as well as pipe sticking. Hence, based on the elastic-plastic theory, the three-dimensional finite element model which can simulate the repairing process of cemented casing repaired by rolling reshaper has been presented in this paper by adopting the finite element method. Based on this model, the whole repairing process of cemented casing with elliptic section has been simulated, by which the deformation law of cemented casing, the repairing force and torque required to repair the cemented casing have been obtained in the repairing process. Meanwhile, based on self-developed testing equipment, the full-scale repairing experiment of cemented casing has been conducted by using rolling reshapser, and the correlations between deformation laws of cemented casing and repairing force and torque have been analyzed. As the test results are consistent with the simulation results, it indicates that the finite element model is accurate and reliable so that the research results can provide important reference for design and optimization of technological parameters.",3,3,2
Cement,Cement Sheath,"da Silva, Italo Batista; Martinelli, Antonio Eduardo; Medeiros de Souza, Wendell Rossine; de Oliveira Freitas, Julio Cezar; Felipe Rodrigues, Marcos Alysson",Dilatometric behavior and crystallographic characterization of Portland-polyurethane composites for oilwell high-temperature cementing applications,Oilwell cementing; Portland cement; Polyurethane and thermal expansion,THERMAL-EXPANSION; WELL CEMENT; HYDRATION,"In order to improve the behavior of Portland-based oilwell sheath to high-temperature applications and the corresponding thermal gradients, polymeric admixtures can be added. Steam injection, for instance, raises the cement sheath-steel casing interface temperature to similar to 300 degrees C which can be deleterious to the mechanical stability and zonal isolation provided by the cement sheath as a result of cracking of the cement. Polyurethane can be added to the cement to improve its plastic behavior and reduce the thermal expansion mismatch between casing and sheath. However, the use polymeric admixtures, especially as aqueous dispersion, can affect the kinetics of the hydration reactions and, as a consequence, the crystallographic composition and coefficient of thermal expansion of the material. Therefore, the present study aimed at evaluating the effects of the addition of different concentrations of polyurethane on the thermomechanical properties of Portland cement pastes cured at 300 degrees C from 14 to 90 days. Formulations containing 1 gpc (0.052 kg), 2 gpc (0.102 kg) and 3 gpc (0.153 kg) of polyurethane, respectively named PU1, PU2 and PU3 were prepared according to the American Petroleum Institute guidelines. A standard PU-free slurry was also prepared. X-ray diffraction and dry dilatometric tests were carried out. The results revealed that the curing time does affect the kinetics of hydration of Portland-polyurethane composites, retarding the formation of high-temperature stable phases, i.e., tobermorite and xonotlite. Moreover, longer curing times were necessary to reveal the improved expansion of the composites with respect to the standard sample. The addition of polyurethane can be pointed as an approach to high-temperature oilwell cement applications, since it reduces the thermal mismatch between cement sheath and steel casing for and retards but do not prevent the formation of xonotlite.",4,4,0
Cement,Cement Sheath,"Zhong, Xun; Liu, Dexin; Shi, Xiaofei; Zhao, Hongtao; Pei, Chun; Zhu, Tongyu; Shao, Minglu; Zhang, Fang",Characteristics and functional mechanisms of clay-cement stabilized three-phase nitrogen foam for heavy oil reservoir,Heavy oil reservoir; Clay-cement three-phase foam; High stability; Water shutoff agent,HYDROPHOBIC NANOPARTICLES; DILATIONAL PROPERTIES; NANO-PARTICLES; AQUEOUS FOAMS; DEMULSIFIERS; RECOVERY; BUBBLES,"The large-scale application of two-phase foam flooding in heavy oil reservoirs was restricted due to the instability of foam itself. However, the developed clay-cement three-phase nitrogen foam can make up for the short broad effectively, which benefits from very good thermal stability, salt resistance, oil sensitivity and excellent plugging performance. In this paper, 8.0 wt% clay, 0.50 wt% cement particles and 1.0 wt% foaming agent were used to generate clay-cement nitrogen foam. The synergistic effects of clay/cement reaction products, particle adsorption layer and steric network contribute to a desirable protective sheath covered compact three-phase foam system with high stability and strength, the half-life of which was 42.0 min at 95 degrees C. Moreover, it became more stable when formation sands exist. Generally, clay-cement three-phase nitrogen foam has three kinds of plugging form owing to different formation permeability. In less permeable formations, most foam would separate into two parts, with particles stacking at the entry end and two-phase foam moving forward. While in formations with higher permeability, all foam would flow out directly without effective plugging. Only when it comes to the formations with proper permeability can this foam achieve impressive plugging strength under the effects of Jamin and particle plugging. In addition, the foaming formula can be modified by adjusting particle-surfactant concentrations to fit various formations. Therefore, it is a promising and widely applicable water shutoff agent for heavy oil reservoirs.",8,9,1
Cement,Cement Sheath,"Moradi, Seyyed Shahab Tabatabaee; Nikolaev, Nikolay Ivanovich",Assessment of the cement failure probability using statistical characterization of the strength data,Oil well cement; Compressive strength; Weibull distribution; Sheath stability; Analytical modelling,WEIBULL,"Cement sheath failure may occur under the influence of induced stresses during service life of the well. For many years, analytical or numerical models have been developed to study the probability of the cement sheath failure under different circumstances. Cement compressive strength is considered as a valuable input parameter during the assessment of the cement failure probability. Usually the compressive strength data are obtained by conducting several direct laboratory experiments on cement samples. The average value of these experiments are reported and used in different cement failure models. However, this approach may results in underestimating the cement failure probability. As cement have heterogeneous structures, therefore their strength variations have a statistical character. In this work, the compressive strength data are represented by the Weibull distribution function, which then will be used in the cement failure probability calculations. Results show that using the statistically distributed compressive strength data in calculations, leads to more accurate outputs of the failure model.",8,8,2
Cement,Rock,"Jadoon, Quaid Khan; Roberts, Eric M.; Henderson, Robert A.; Blenkinsop, Thomas G.; Wust, Raphael A. J.","Mineralogical variability of the Permian Roseneath and Murteree Shales from the Cooper Basin, Australia: Implications for shale properties and hydrocarbon extraction",Shale gas; Roseneath; Murteree; Brittleness; Plasticity; Cooper Basin,SOIL; MODEL; CLAY,"Brittleness and plasticity indices in hydrocarbon reservoirs are calculated to understand how rocks behave under stress, and for assessing the fracturing performance of clay-rich shale reservoirs and assessing borehole stability. Evaluating shale plasticity/brittleness requires careful analysis of clay mineral composition in target shales and the development of fracking strategies for optimal shale stimulation. Here we report on the mineralogical variability of two Permian lacustrine shale units, the Roseneath and Murteree shales in the Cooper Basin, Australia, that are considered to have potential as unconventional hydrocarbon producers. The study involved a combination of X-ray diffraction, scanning electron microscopy and petrophysical modelling of the Roseneath and Murteree shales in order to obtain a better understanding of the compositions and microfabrics of these two units. This is part of a larger investigation of the shale gas potential of these two units in the Cooper Basin, and the results presented here may ultimately lead to improved reservoir stimulation techniques in both units. Core data has been integrated with wireline logging data to better identify brittle and plastic zones within the Roseneath and Murteree shales. Mineralogical analysis shows that both units are composed mainly of detrital quartz and clay/mica minerals with siderite cement. The clay mineral composition is dominated by illite/mica, and kaolinite in both units. However, based on the relative mineralogical differences between the two units, the Murteree Shale has more favourable brittle properties than the Roseneath Shale, and is considered to be more amenable to hydraulic fracturing for gas exploitation. However, the Roseneath Shale also has potential for gas stimulation, especially in intervals where siderite cement is prevalent.",2,3,1
Cement,Rock,"Shahsenov, I. S.; Orujov, G. I.",Modeling of the cementation factor and hydraulic permeability using Mercury Injection Capillary Pressure (MICP) measurements,Cementation factor; Pore size distribution; Mercury Injection Capillary Pressure (MICP); Probabilistic model,POROUS-MEDIA,"Electrical models of the porous medium are widely used for the estimation of the volume fraction of fluids filling in the pore space. One of the input parameters into this type of models is the geometrical factor associated with the complexity of the pore network system also known as ""cementation factor"" used in Archie's saturation model. While this parameter can be measured in the laboratory, the aim of this work is to infer it from the pore size distribution (PSD), which in itself does not bear any information about the geometry of the 3D pore network. The proposed probabilistic model assumes a predefined geometry of the elementary cell, and uses PSD obtained from the Mercury Injection Capillary Pressure (MICP) measurements and porosity to predict the cementation factor. The model achieved a good agreement with an average value of the cementation factor measured on the numerous core samples obtained from the two fields investigated in this study. Geometrical considerations were also investigated through introduction of tortuosity and shape of the capillaries in the model to allow for the potential lithological variations of the reservoir rocks. Similar approach was used to estimate hydraulic permeability using the probabilistic model, and the results were tested against air permeability values measured in the laboratory.",3,3,1
Cement,Rock,"Kang, Zhengming; Ke, Shizhen; Yin, Chengfang; Wang, Weidong; Zheng, Shutong; Sun, Xu; Li, Junjian",Dielectric constant measurements of sweep frequency and its effect from 20 MHz to 1000 MHz,Dielectric constant; Sweep frequency; Saturation; Salinity; Pore structure; Cementation exponent,MICROWAVE-FREQUENCIES; ULTRAHIGH FREQUENCIES; SAMPLES; ROCKS,"The array dielectric tool (ADT) can be used in situations where the formation water resistivity is variable or unknown and allows for obtaining Archie's cementation exponent (m) in combination with other porosity logging methods. However, few laboratory measurements of the dielectric dispersion properties at wide frequencies (20 MHz-1000 MHz) have been shown till now, which hinders our understanding of the petrophysical mechanisms. In this study, we introduce the dielectric constant measurements of a sweep frequency in the range of 20-1000 MHz based on the parallel-disk capacitor method. In order to easier control the variables, such as the m and the porosity, artificial cores with changeable m values were manufactured from glass beads. The relationships between the core dielectric constant and the frequency, saturation, salinity, and pore texture were investigated in the MHz to GHz range. It is shown that the frequency, water saturation, salinity, and pore texture affect the dielectric dispersion of cores. Additionally, a modified formula for predicting m with a high-frequency dielectric constant was developed based on core sample data. This study provides a better understanding of the dielectric dispersion mechanism and the modified formula for calculating m can improve the analysis of well log data.",3,3,1
Cement,Rock,"Wu, Jun; Fan, Tailiang; Gao, Zhiqian; Yin, Xinxin; Fan, Xue; Li, Chenchen; Yu, Wenyi; Li, Chen; Zhang, Chenjia; Zhang, Jinhuang; Sun, Xining","A conceptual model to investigate the impact of diagenesis and residual bitumen on the characteristics of Ordovician carbonate cap rock from Tarim Basin, China",Carbonate cap rock; Diagenesis; Carbonate cements; Stylolites; Residual bitumen,OOLITHE-BLANCHE-FORMATION; TAHE OIL-FIELD; HYDROCARBON ACCUMULATION; RESERVOIR QUALITY; PETROPHYSICAL PROPERTIES; FEIXIANGUAN FORMATION; POROSITY DEVELOPMENT; SMACKOVER FORMATION; MAESTRAT BASIN; CENTRAL UPLIFT,"The Lower-Middle Ordovician Yingshan (O1-2 y) Formation associated with large unconformity weathering crust was the main hydrocarbon reservoir in the Tarim Basin, and the dense limestone/dolomite within this formation was revealed as the local carbonate cap rock. Based on petrophysical properties, thin sections, cathodeluminescence (CL) and scanning electron microscope (SEM) measurements, the effects of cap rock on depositional settings, diagenesis and pyrobitumen were carefully analyzed. Carbonate cap rock dominated by micrite has ultralow porosity and permeability, with an average porosity of 0.568% and permeability of 0.07 x 10(-3) mu m There is a significant bottom-up thickness variation (from several to tens of meters) in different members within the O1-2 y formation. The steady cap rock is more likely to be distributed in low-energy depositional environments, corresponding to intershoal sea, low-lying land of open platform and lagoon of restricted platform. Constructive diagenesis processes mainly comprise extreme filling, compaction and cementation, resulting in a significant decrease in the quantity and size of pores. Conversely, leaching and paleokarst dissolution, together with diagenesis associated with hydrothermal fluids, has a detrimental effect on the effective preservation of cap rock. Three types were summarized to characterize the cementation-compaction relationship between cement distribution and intraclast deformation. The increase in intraclast size indicate that the intergranular pores are likely to be cemented. A good sealing impact on the underlying oil-gas is confirmed in sparry calcarenite when its cement content reaches 15% and higher by volume. Early compaction vs. early cementation processes probably affect the sealing capacity, so high quality cap rock is primarily presented while cementation precedes compaction. Highly abundant stylolites filled with residual bitumen and precipitated cements in the cap rock intervals consistently have low poroperm values, resulting in micropore occlusion and occlusion of the late hydrocarbon migration pathways, which can act as barriers for the upward migration of oil-gas. A conceptual model of the evolution feature of cap rock provides a plausible interpretation for better understanding of the spatial distribution of carbonate cap rock in future exploration and development",5,5,3
Cement,Rock,"Fedrizzi, Raquel Machado; Rodrigues de Ceia, Marco Antonio; Missagia, Roseane Marchezi; Santos, Victor Hugo; Neto, Irineu Lima",Artificial carbonate rocks: Synthesis and petrophysical characterization,Carbonate rocks; Cementation; Synthetic carbonate rocks; Rock physics; Mudstone; Porosity,DIGITAL IMAGE-ANALYSIS; MECHANICAL-BEHAVIOR; PHYSICAL-PROPERTIES; PORE SYSTEM; VELOCITY; SANDSTONES; TEXTURE,"Carbonate rocks are important for rock properties research because they are linked to significant oil and gas reserves around the world. The goal of synthesizing carbonate rocks in laboratory is to simulate the natural carbonate rock matrix regarding the main factors of lithification such as grain size and shape, concentration of cementing material and compaction pressure, and allowing the production of rock specimens that can be used for tests in extreme conditions in replacement of the high cost natural cores. The reproduction of rocks in laboratory also allows to access samples with predetermined characteristics enabling a better understanding of the relationship between their physical properties. In this work, samples of synthetic carbonate rocks were made by mixing a fixed amount of calcite and sand, and varying the amount of cement material (Portland cement and water) aiming to reproduce a primary interparticle por system. The behavior of the main petrophysical characteristics of these samples was investigated, such as porosity, permeability and P-and S-wave velocities versus the amount of cementing material. The results were compared with natural carbonate samples and showed a high similarity to the petrophysical behavior of mudstones rocks. That similarity points out the feasibility of those synthetic rocks to be used as analogous of mudstones, specifically those exhibiting only primary porosity, in experiments regarding rock physics, core flooding or rock mechanics.",8,8,3
Cement,Carbonate,"Zhang, Jian; Peng, Zhigang; Zou, Changjun; Chen, Dajun",Improving the carbonation resistance of cement stone for oil wells by a polymer with acid response characteristic,Oil well cement; Polymer; Carbonation resistance; Porosity; Membrane material,CO2 STORAGE; INTEGRITY; CORROSION; KINETICS; IMPACT; PASTE; MODEL,"The influences of acid responsive polymer (ARP) on the carbonation resistance of oil well cement were studied by low field nuclear magnetic resonance (NMR), scanning electron microscope (SEM) and X-ray diffraction (XRD), and the mechanism of ARP improving the cement's carbonation resistance was also revealed. The results shown that mixing ARP into cement can significantly decrease the increasing phenomenon of carbonation depth and porosity in cement stone carbonized for a long time, at same time, ARP can weaken the damage for hydration products and microstructures of cement stone from carbon dioxide due to the layer of membrane materials formed on the surface of cement stone encountered acid medium. With the aid of scanning electron microscope (SEM), Xray diffraction analysis (XRD) technologies, the carbonation resistance mechanism of cement stone improved by ARP was revealed and as follows: (1) Increasing the thickness of the polymer hydration layer being formed on the surface of the cement particles and reducing the contact opportunity between hydration products and corrosion medium; (2) Forming polymeric membrane substance in carbonized environment and blocking the infiltration channels of corrosion medium.",5,6,0
Cement,Carbonate,"Zhang, C. C.; Wu, C. D.; Zhang, S.; Guo, Z. J.; Wang, J. L.","Sedimentary and diagenetic control on the porosity and permeability in Lower-Middle Jurassic reservoirs, northern margin of Tianshan, China",Tight sandstone; Reservoir quality; Pore-throat structure; Sedimentary facies; Diagenesis; Tianshan,SEQUENCE STRATIGRAPHIC FRAMEWORK; SANDSTONE DIAGENESIS; ZIRCON GEOCHRONOLOGY; QUALITY PREDICTION; QUARTZ CEMENTATION; NORTHWEST CHINA; JUNGGAR BASIN; COMPACTION; EVOLUTION; ORIGIN,"The Lower-Middle Jurassic sandstone reservoirs in the northern margin of Tianshan are considered a significant area of tight sandstone gas. Sedimentary, petrologic and petroleum geologic criteria have been surveyed in six sections along continuous outcrops and cores. Thin sections and scanning electron microscope (SEM) images combined with mercury injection techniques are used to restore the evolution of pore-throat structures. The Lower-Middle Jurassic sandstones are mainly low-porosity and extra-low-permeability reservoirs. The results of constant-rate mercury injection reveal that the distribution pattern of the pore radii is not related to permeability, whereas the throat radii increase with increasing permeability. The microcosmic heterogeneity in reservoirs is dominated by a high proportion of narrow throats. An analysis of the reservoirs' physical properties and diagenesis indicates that the quality of the Lower-Middle Jurassic sandstone reservoirs is controlled by sedimentary environment, eodiagenesis, and diagenesis that developed in different sedimentary microfacies. The pore-throat structures can be divided into six types. In coal-bearing formations that are rich in organic matter, compaction decreases the quality of the reservoirs, and the reaction of early-formed kaolinite with remnant, undissolved K-feldspar may cause diagenetic illite to block the throats. At the bottom of the fluvial channels in braided river delta plains or at the top of mouth bars in braided river delta fronts, eodiagenesis can inhibit compaction via early basal carbonate cementation, and the unfavorable reservoirs are extra-low-porosity and extra-low-permeability sandstones. Infiltration-related clay is widespread. Smectite coats covered grains, and kaolinite filled remnant intergranular pores as aggregations, which increased the heterogeneity of the pore-throat structures. Authigenic chlorite coats protect intergranular pores from compaction and cementation by quartz overgrowths. Reservoirs with medium to low porosity and medium to low permeability come from the middle-upper portions of fluvial channels in braided river delta plains of the Xishanyao Formation or from the upper part of sub-water fluvial channels in the Badaowan Formation and the Sangonghe Formation or mouth bars in braided river delta fronts of the Sangonghe Formation. In near-surface settings, such as the bottom of fluvial channels or the top of mouth bars in braided river deltas, infiltration-related dissolution leads to more intergranular dissolution pores. However, the development of the highest-quality reservoirs, i.e., medium porosity and medium permeability, is limited. Other types exist between these end members in quality. Due to good sorting and low matrix content, the barrier bars of the Toutunhe Formation and the Sangonghe Formation with good lateral connectivity in the lacustrine facies are widespread in the northern margin of Tianshan and are considered to be high-quality reservoirs.",5,7,2
Cement,Carbonate,"Wu, Jun; Fan, Tailiang; Gao, Zhiqian; Yin, Xinxin; Fan, Xue; Li, Chenchen; Yu, Wenyi; Li, Chen; Zhang, Chenjia; Zhang, Jinhuang; Sun, Xining","A conceptual model to investigate the impact of diagenesis and residual bitumen on the characteristics of Ordovician carbonate cap rock from Tarim Basin, China",Carbonate cap rock; Diagenesis; Carbonate cements; Stylolites; Residual bitumen,OOLITHE-BLANCHE-FORMATION; TAHE OIL-FIELD; HYDROCARBON ACCUMULATION; RESERVOIR QUALITY; PETROPHYSICAL PROPERTIES; FEIXIANGUAN FORMATION; POROSITY DEVELOPMENT; SMACKOVER FORMATION; MAESTRAT BASIN; CENTRAL UPLIFT,"The Lower-Middle Ordovician Yingshan (O1-2 y) Formation associated with large unconformity weathering crust was the main hydrocarbon reservoir in the Tarim Basin, and the dense limestone/dolomite within this formation was revealed as the local carbonate cap rock. Based on petrophysical properties, thin sections, cathodeluminescence (CL) and scanning electron microscope (SEM) measurements, the effects of cap rock on depositional settings, diagenesis and pyrobitumen were carefully analyzed. Carbonate cap rock dominated by micrite has ultralow porosity and permeability, with an average porosity of 0.568% and permeability of 0.07 x 10(-3) mu m There is a significant bottom-up thickness variation (from several to tens of meters) in different members within the O1-2 y formation. The steady cap rock is more likely to be distributed in low-energy depositional environments, corresponding to intershoal sea, low-lying land of open platform and lagoon of restricted platform. Constructive diagenesis processes mainly comprise extreme filling, compaction and cementation, resulting in a significant decrease in the quantity and size of pores. Conversely, leaching and paleokarst dissolution, together with diagenesis associated with hydrothermal fluids, has a detrimental effect on the effective preservation of cap rock. Three types were summarized to characterize the cementation-compaction relationship between cement distribution and intraclast deformation. The increase in intraclast size indicate that the intergranular pores are likely to be cemented. A good sealing impact on the underlying oil-gas is confirmed in sparry calcarenite when its cement content reaches 15% and higher by volume. Early compaction vs. early cementation processes probably affect the sealing capacity, so high quality cap rock is primarily presented while cementation precedes compaction. Highly abundant stylolites filled with residual bitumen and precipitated cements in the cap rock intervals consistently have low poroperm values, resulting in micropore occlusion and occlusion of the late hydrocarbon migration pathways, which can act as barriers for the upward migration of oil-gas. A conceptual model of the evolution feature of cap rock provides a plausible interpretation for better understanding of the spatial distribution of carbonate cap rock in future exploration and development",5,5,3
Cement,Carbonate,"Fedrizzi, Raquel Machado; Rodrigues de Ceia, Marco Antonio; Missagia, Roseane Marchezi; Santos, Victor Hugo; Neto, Irineu Lima",Artificial carbonate rocks: Synthesis and petrophysical characterization,Carbonate rocks; Cementation; Synthetic carbonate rocks; Rock physics; Mudstone; Porosity,DIGITAL IMAGE-ANALYSIS; MECHANICAL-BEHAVIOR; PHYSICAL-PROPERTIES; PORE SYSTEM; VELOCITY; SANDSTONES; TEXTURE,"Carbonate rocks are important for rock properties research because they are linked to significant oil and gas reserves around the world. The goal of synthesizing carbonate rocks in laboratory is to simulate the natural carbonate rock matrix regarding the main factors of lithification such as grain size and shape, concentration of cementing material and compaction pressure, and allowing the production of rock specimens that can be used for tests in extreme conditions in replacement of the high cost natural cores. The reproduction of rocks in laboratory also allows to access samples with predetermined characteristics enabling a better understanding of the relationship between their physical properties. In this work, samples of synthetic carbonate rocks were made by mixing a fixed amount of calcite and sand, and varying the amount of cement material (Portland cement and water) aiming to reproduce a primary interparticle por system. The behavior of the main petrophysical characteristics of these samples was investigated, such as porosity, permeability and P-and S-wave velocities versus the amount of cementing material. The results were compared with natural carbonate samples and showed a high similarity to the petrophysical behavior of mudstones rocks. That similarity points out the feasibility of those synthetic rocks to be used as analogous of mudstones, specifically those exhibiting only primary porosity, in experiments regarding rock physics, core flooding or rock mechanics.",8,8,3
Cement,Temperature,"da Silva, Italo Batista; Martinelli, Antonio Eduardo; Medeiros de Souza, Wendell Rossine; de Oliveira Freitas, Julio Cezar; Felipe Rodrigues, Marcos Alysson",Dilatometric behavior and crystallographic characterization of Portland-polyurethane composites for oilwell high-temperature cementing applications,Oilwell cementing; Portland cement; Polyurethane and thermal expansion,THERMAL-EXPANSION; WELL CEMENT; HYDRATION,"In order to improve the behavior of Portland-based oilwell sheath to high-temperature applications and the corresponding thermal gradients, polymeric admixtures can be added. Steam injection, for instance, raises the cement sheath-steel casing interface temperature to similar to 300 degrees C which can be deleterious to the mechanical stability and zonal isolation provided by the cement sheath as a result of cracking of the cement. Polyurethane can be added to the cement to improve its plastic behavior and reduce the thermal expansion mismatch between casing and sheath. However, the use polymeric admixtures, especially as aqueous dispersion, can affect the kinetics of the hydration reactions and, as a consequence, the crystallographic composition and coefficient of thermal expansion of the material. Therefore, the present study aimed at evaluating the effects of the addition of different concentrations of polyurethane on the thermomechanical properties of Portland cement pastes cured at 300 degrees C from 14 to 90 days. Formulations containing 1 gpc (0.052 kg), 2 gpc (0.102 kg) and 3 gpc (0.153 kg) of polyurethane, respectively named PU1, PU2 and PU3 were prepared according to the American Petroleum Institute guidelines. A standard PU-free slurry was also prepared. X-ray diffraction and dry dilatometric tests were carried out. The results revealed that the curing time does affect the kinetics of hydration of Portland-polyurethane composites, retarding the formation of high-temperature stable phases, i.e., tobermorite and xonotlite. Moreover, longer curing times were necessary to reveal the improved expansion of the composites with respect to the standard sample. The addition of polyurethane can be pointed as an approach to high-temperature oilwell cement applications, since it reduces the thermal mismatch between cement sheath and steel casing for and retards but do not prevent the formation of xonotlite.",4,4,0
Cement,Temperature,"Srivastava, Aman; Ahmed, Ramadan; Shah, Subhash",Effects of magnesium oxide on carbonic acid resistance of oil well cement,Oil well cement; Magnesium oxide; Carbonation; Degradation; Expansion; Porosity,CO2 GEOLOGICAL STORAGE; DEGRADATION; MGO; INTEGRITY; KINETICS,"This paper presents the results of an experimental study on the effects of magnesium oxide additive on the performance of oil well cement under a high-pressure high-temperature (HPHT) carbonic acid environment. Magnesium oxide (MgO) is a well-known expanding agent that improves sealing performance of cement. However, the performance of MgO-based cement has not been tested in a carbonic acid environment. Therefore, to investigate the impact of MgO on carbonic acid resistance of cement, two cement slurry formulations: Class H cement with 35% silica (baseline or HS) and baseline cement with MgO (HSMG) were compared after exposure to an acidic environment. To evaluate their performance, cylindrical cores and shear bond strengths (SBS) samples were prepared and aged in HPHT autoclave containing brine (2% sodium chloride solution) saturated with mixed gas containing CH4 and CO2. Six aging tests were conducted varying CO2 concentration, temperature, and pressure. After aging for 14 days at constant pressure and temperature, the samples were recovered, and their physical (bond and compressive strength, porosity and permeability) and mineralogical composition were measured and compared with those of unaged samples. The results suggest that addition of 5% MgO reduces the carbonation of cement and could potentially prolong the operational life of cement by protecting its binding components (calcium hydroxide and calcium silicate hydrate).",5,5,0
Cement,Temperature,"Zhou, Yunjian; Wojtanowicz, Andrew K.; Li, Xiangfang; Miao, Yanan",Analysis of gas migration in Sustained-Casing-Pressure annulus by employing improved numerical model,Slip velocity; Sustained Casing Pressure; Gas migration; Non-Newtonian fluids; Swarm bubble,SINGLE BUBBLES; CO2 LEAKAGE; WELLBORE; TEMPERATURE; VELOCITIES; INTEGRITY,"Currently, the analysis of Sustained-Casing-Pressure (SCP) tests is limited because some researchers' simulations did not take the effect of gas migration in mud into account and their models were based on Newtonian fluids. This is not consistent with the actual field situations that gas migrates in non-Newtonian fluids. In addition, the yield stress effect was also not taken into account. To ensure the operators a realistic and accurate diagnostic testing for the SCP problem, the improvements of mathematical models in SCP problem are of great significance. In this study, by considering the correlation between gas velocity and drag coefficient, a new formula of gas migration velocity in stagnant non-Newtonian fluids was established. Moreover, the yield stress effect was incorporated in the new model. The validations of field data demonstrate that the new model has the credence to the field work. Furthermore, in this study, the effect of gas migration on SCP problem was paid attention seriously based on new model. To demonstrate the importance of gas migration effect, the analysis of variance (ANOVA) were employed to find out the values of mud properties (flow behavior index, yield stress, length of mud, consistency index) that can most significantly influence the wellhead pressure. Then these most influential parameters were utilized in both the new model (with gas migration effect) and the previous model (without gas migration effect) to conduct the comparison. The comparison result indicate that the value of mud compressibility and the value of cement permeability got by the new model are higher than those by the previous model, and the value of initial gas chamber size got by the new model is lower than that by the previous model. These stress explicitly the necessity and significance of considering gas migration effect and considering the non-Newtonian effect on SCP problem, which should not be neglected. The developed models in this research offer significant insights into the SCP problem, which turns out to be powerful in the application of analyzing the SCP problem. This work can lay the theoretical basis to assist operators in diagnostic testing of wells with SCP problem accurately.",5,5,2
Cement,Temperature,"Sui, D.; Horpestad, T.; Wiktorski, E.",Comprehensive modeling for temperature distributions of production and geothermal wells,Temperature model; Production wells; Heat transfer,HEAT-TRANSFER; WELLBORE; SYSTEMS; FLOW; PRESSURE,"When producing hot fluids from a reservoir, production wells experience temperature changes with depth for different tubing, casings, cements and wellbore interfaces. The changes of the fluids' temperature depend on many factors. Production flow rate, specific heat capacity (SHC) of produced fluids, thermal conductivity (TC) and viscosity of annular fluids, Joule-Thomson effect on produced fluids, radius of wellbores, annular clearance, inclinations and production time are some of the parameters playing an important role in the heat transfer across the wellbore between produced fluids and formations. Modern downhole production tools are equipped with a temperature sensor to monitor the temperature variation with production time. It is important, however, to be able to predict how the temperature will be changing during the various production phases depending on the production rate and other operational parameters. This information is also valuable in downhole pressure estimation, as the viscosity of the produced fluid varies with temperature. A robust temperature estimation technique is therefore required to be able to estimate the temperature distribution along the well. A comprehensive wellbore heat transfer model for oil production wells has been developed in this study. The model considers a fairly complex wellbore configuration consisting of five wellbore sections with multiple annulus (annulus A, B and C), with the possibility of natural/free heat convection taking place in three brine filled annulus. Correlations taking temperature and pressure into consideration have been implemented for all thermophysical properties, such as TC of tubing, casings, and cements, SHC, viscosity and TC of annular/produced fluids, and densities of produced and annular fluids to mention some. The program allows for custom well configuration and is able to calculate the temperature at the interfaces between the wellbore, casings and tubing. It also allows to use properties of the fluids, casing/tubing, cement and formation other than those used in the simulations presented in this paper. Extensive knowledge of the effect of the essential parameters on the heat transfer is of great importance for the performance of production wells. Sensitivity analysis has been performed to demonstrate the importance of properties of produced/annulus fluids, wellbore architecture and operational parameters in oil production. Our work is a good tool to analyze the thermal performance of wellbores, fluids and so on with a lot of potentials for different applications, like annulus pressure build up, well plan and casing/fluid design for production/geothermal wells.",7,8,1
Cement,Gas Migration,"Zhou, Yunjian; Wojtanowicz, Andrew K.; Li, Xiangfang; Miao, Yanan",Analysis of gas migration in Sustained-Casing-Pressure annulus by employing improved numerical model,Slip velocity; Sustained Casing Pressure; Gas migration; Non-Newtonian fluids; Swarm bubble,SINGLE BUBBLES; CO2 LEAKAGE; WELLBORE; TEMPERATURE; VELOCITIES; INTEGRITY,"Currently, the analysis of Sustained-Casing-Pressure (SCP) tests is limited because some researchers' simulations did not take the effect of gas migration in mud into account and their models were based on Newtonian fluids. This is not consistent with the actual field situations that gas migrates in non-Newtonian fluids. In addition, the yield stress effect was also not taken into account. To ensure the operators a realistic and accurate diagnostic testing for the SCP problem, the improvements of mathematical models in SCP problem are of great significance. In this study, by considering the correlation between gas velocity and drag coefficient, a new formula of gas migration velocity in stagnant non-Newtonian fluids was established. Moreover, the yield stress effect was incorporated in the new model. The validations of field data demonstrate that the new model has the credence to the field work. Furthermore, in this study, the effect of gas migration on SCP problem was paid attention seriously based on new model. To demonstrate the importance of gas migration effect, the analysis of variance (ANOVA) were employed to find out the values of mud properties (flow behavior index, yield stress, length of mud, consistency index) that can most significantly influence the wellhead pressure. Then these most influential parameters were utilized in both the new model (with gas migration effect) and the previous model (without gas migration effect) to conduct the comparison. The comparison result indicate that the value of mud compressibility and the value of cement permeability got by the new model are higher than those by the previous model, and the value of initial gas chamber size got by the new model is lower than that by the previous model. These stress explicitly the necessity and significance of considering gas migration effect and considering the non-Newtonian effect on SCP problem, which should not be neglected. The developed models in this research offer significant insights into the SCP problem, which turns out to be powerful in the application of analyzing the SCP problem. This work can lay the theoretical basis to assist operators in diagnostic testing of wells with SCP problem accurately.",5,5,2
Cement,Gas Migration,"Curbelo, F. D. S.; Garnica, A. I. C.; Araujo, E. A.; Paiva, E. M.; Cabral, A. G.; Freitas, J. C. O.",Vegetable oil-based preflush fluid in well cementing,Vegetable oil-based microemulsion; Cleanup fluid; Surfactants; Cement slurry,DRILLING-FLUID; FILTER CAKE; REMOVAL,"Efficient cement bonding in wellbores provides better zonal insulation, containment of gas migration, prevention of excessive water production, besides affecting their economical performances. Carrying out a properly sized and formulated cleanup process (or pre-flush) is one of the most costly tasks in wellbore preparation. Different chemicals are commonly used both to remove filter cakes and enhance surface water-wetting, such as solvents and surfactants. The search for environmentally-friendly cleanup fluids, in particular, with acceptable wetting properties, has been challenging. This paper describes an experimental study to characterize and prepare a vegetable oil-based microemulsion to work as pre-flush fluid in wellbores. Results obtained from cleaning assays (removal test), wettability testings and fluid compatibility analyses have exhibited excellent performances in filter cake removal. Enhanced water-wetting and suitable rheological compatibility of cement/cleanup fluid/mud systems and good compressive strength were also achieved.",6,6,5
Cement,Solution,"Srivastava, Aman; Ahmed, Ramadan; Shah, Subhash",Effects of magnesium oxide on carbonic acid resistance of oil well cement,Oil well cement; Magnesium oxide; Carbonation; Degradation; Expansion; Porosity,CO2 GEOLOGICAL STORAGE; DEGRADATION; MGO; INTEGRITY; KINETICS,"This paper presents the results of an experimental study on the effects of magnesium oxide additive on the performance of oil well cement under a high-pressure high-temperature (HPHT) carbonic acid environment. Magnesium oxide (MgO) is a well-known expanding agent that improves sealing performance of cement. However, the performance of MgO-based cement has not been tested in a carbonic acid environment. Therefore, to investigate the impact of MgO on carbonic acid resistance of cement, two cement slurry formulations: Class H cement with 35% silica (baseline or HS) and baseline cement with MgO (HSMG) were compared after exposure to an acidic environment. To evaluate their performance, cylindrical cores and shear bond strengths (SBS) samples were prepared and aged in HPHT autoclave containing brine (2% sodium chloride solution) saturated with mixed gas containing CH4 and CO2. Six aging tests were conducted varying CO2 concentration, temperature, and pressure. After aging for 14 days at constant pressure and temperature, the samples were recovered, and their physical (bond and compressive strength, porosity and permeability) and mineralogical composition were measured and compared with those of unaged samples. The results suggest that addition of 5% MgO reduces the carbonation of cement and could potentially prolong the operational life of cement by protecting its binding components (calcium hydroxide and calcium silicate hydrate).",5,5,0
Cement,Solution,"Peng, Ye; Liu, Li; Wang, Shuliang; Lin, Yuanhua; Sun, Yanrong; Xia, Ruochen",Effect of simulated pore solution on passivation characteristic of P110 steel,Casing steel; Simulated pore solution; Passive film; Electrochemical; XPS; SEM,ALKALINE-SOLUTIONS; CYCLIC VOLTAMMETRY; STAINLESS-STEEL; CARBON-STEEL; MILD-STEEL; CORROSION; CHLORIDE; CEMENT; PERFORMANCE; 316L,"Cement was used in oil industry to fix well. After hydration of cement, a porous material with overbased pore solution will be formed. Passivation analysis will be conducted on the passivation of the outer wall of downhole P110 casing steel under overbased conditions. Due to the difficulty of obtaining cement pore solution, two kinds of simulated concrete pore solutions (SP solution, CF solution) were used to carry out experiments. The different properties of passive film in two different solutions were obtained, which provided reliable data to support for the research of passive film properties of casing steel. Therefore, the electrochemical properties were characterized by electrochemical impedance spectroscopy (EIS), polarization curves method and Mott-Schottky curves method during the formation of the passive film. Moreover, X-ray photoelectron spectroscopy (XPS) was measured to qualitatively analyze the composition of the passive film on the casing surface, and scanning electron microscope (SEM) was used to observe surface morphology of the P110 casing steel. The result showed that the passive film was enhanced with time increasing and the time for complete passivation of P110 steel in two simulated concrete pore solutions was different, requiring longer passivation in CF solution. The passive film in the CF solution had a larger film resistance and the film layer was more stable. The semiconductor characteristics of the passive film were n-type and the donor density of the passive film in CF solution was lower than that of the SP solution. The passive film formed in two simulated concrete pore solutions was all Fe oxides, but not completely the same. Also the steady-state passive film formed in the two solutions had a different microscopic morphology.",7,7,2
Slug,,"Andreolli, Ivanilto; de Azevedo, Gabriel Romualdo; Balino, Jorge Luis",Stability solver for offshore oil production systems,Severe slugging; Pipeline-riser system; Gas-liquid flow; Stability; Petroleum production technology,PIPELINE-RISER SYSTEMS; AIR-WATER SYSTEMS; NATURAL GASES; SIMULATION; VISCOSITY; PIPES; MODEL; FLOW,"Most of the applications dealing with multiphase flow applied to petroleum production systems assume a steady state operation, mainly because this is the condition envisaged in the design stage; nevertheless, steady state may not exist, resulting in an unstable behavior. Flow dynamic studies are far more complex because they involve issues related to modeling, mathematical well-posedness and adherence to transient field data. The stability of multiphase flows is usually studied by using commercial computer codes as a black box; this approach is computationally costly if many operating points have to be investigated, as in the design stage of offshore systems. As a more efficient alternative to time domain simulations, the linear stability analysis is a powerful technique to identify the stable and unstable regions. In this paper a stability solver, suitable for oil-gas-water production fluids in offshore oil production systems, is presented. The solver is based on a linear stability analysis applied to a dynamic model. Black oil approximation is considered for the mass transfer between the oil and gas phases. Numerical results were presented for three offshore oil production systems. Stability maps were obtained and compared to field data, showing an excellent agreement with the operational conditions presented.",1,1,2
Slug,,"Brito, R.; Pereyra, E.; Sarica, C.",Well trajectory effect on slug flow development,Slugging; Well trajectory; Slug length; Slug frequency; Transient flow,LIQUID SLUG; MODEL,"The effect of horizontal well trajectory on slug flow development was experimentally studied using a 2.0 in. ID flow loop to mimic different well trajectories. Inclination angle in the lateral section was varied +/- 1 degrees from the horizontal to simulate three well configurations, namely, toe-down, one-undulation with a sump, and one-undulation with a hump. Slug length and frequency along the well were measured using fourteen conductivity probes located along the test section. Experimental results indicated that slug length in the vertical and lateral sections of a well present values up to four and two times, respectively, larger than typical dimensionless slug length reported in the literature. Furthermore, slug flow development along the vertical section is affected by the lateral section deviation angle and length. At the same time, lateral section slug flow development is affected by liquid fall back from the vertical section and lateral section length. Slug characterization along the well is critical to properly design and operate downhole and surface equipment and properly predict pressure gradient and liquid holdup along the well.",2,2,0
Slug,,"Okereke, N. U.; Omotara, O. O.",Combining self-lift and gas-lift: A new approach to slug mitigation in deepwater pipeline-riser systems,Severe slugging; Self-lift; Gas-lift; Riser column; By-pass internal diameter,,"Recent slugging studies have identified the need to develop new and optimal slug mitigation strategies as the key gap in slugging studies. This paper focused on combining the self-lift and gas-lift slug mitigation strategies for slugging mitigation in deepwater scenarios. The Self-Lift Slug mitigation Strategy is a novel approach that involves tapping off gas via a by-pass pipe along the pipeline upstream of the riser. The gas is then re-introduced into the riser column via an injection point on the riser, to break the liquid slugs within the riser and mitigate severe slugging. This research investigated the performance of the Self-Lift Strategy when adapted to a deepwater oil field case scenario via OLGA simulation. An alternative scenario of combining self-lift and gas lift was also investigated. The approach for this study involved a robust methodology of firstly validating the field data by comparing pressure field data with OLGA simulation of the input data from the field. The field case consists of a 2712 m pipeline section and a 1513 m riser section. In this study, the severe slugging scenario was first run at the following flow conditions: well X1 was set up at 72.2 degrees C temperature and mass flow of 3.25 kg/s, well X2 was set up at 70.5 degrees C and 12.13 kg/s mass flow rate and the outlet section set up at 65.5 degrees C and pressure 20 bara. Self-lift was able to reduce holdup within the riser column, however pressure behaviour at the riser column was observed to be over 20 bara which is the design pressure for the inlets of the separator. Further studies involving a combination of Self-lift and gas lift at 8 kg/s and 2 inches by-pass internal diameter, indicated that the pressure at the riser column was reduced to 20 bara, allowing for stable flow into the separator.",2,2,2
Slug,,"Babadagli, Tayfun; Cao, Nahai",An experimental study to determine suitable injection strategies for water-alternating-solvent process in green and brownfields,Solvent injection optimization; Waterflooding; Water content; Injection sequence and slug size; Wettability,RECOVERY,"Considering more than 50% of oil is left on average after primary and secondary methods in conventional reservoirs, techniques to recover the remaining oil from these proven and mature reserves is critically important to meet the future energy demand. One of the ways to achieve this is to inject miscible solvents (usually gas), which is performed in the form of water-alternating gas rather than continuous injection of this type of expensive material. In this case, the process should be optimally designed for slug sizes and proper sequences of the solvent considering several controlling parameters including past history of waterflooding (water content) and wettability. We performed a set of experiments on vertically situated sand pack models saturated with 14cp oil. Heptane was selected as the solvent phase due to high miscibility conditions. Tests were started with waterflooding or solvent injection. Different slug sizes of solvent and water were tested on fully oil-saturated water, oil-wet samples, and samples with connate water (10 and 30%). The amounts of oil and solvent retrieved were monitored using refractometer. Using the collected data, the recovery rates and ultimate recoveries were comparatively analyzed. In addition to the technical feasibility, an economic analysis was performed considering the amount of solvent injected, oil and solvent recovered, and time for recovery. Starting the process with heptane was technically and economically feasible (pay-out time is shorter) in the short run for both the oil-and water-wet cases. This was especially true if the rock were oil-wet, which yielded faster recovery and higher ultimate recovery. Excessive water injection (up to the plateau level) preceding the solvent injection in the oil-wet case resulted in lower recovery factor whereas this design was very effective in the water-wet case. Therefore, the time to switch to solvent injection was critical in the oil-wet case and a short initial cycle of solvent injection followed by short waterflooding cycle is suggested. In the oil-wet case, initial waterflooding resulted in an inefficient process; while it yielded high ultimate recoveries, the process time was longer than other injection options. In the water-wet case, a greater amount of solvent was needed in the first cycle.",3,3,2
Slug,,"Guo, Jixiang; Yang, Yuqi; Zhang, Shuai; Zhang, Dengshan; Cao, Chang; Ren, Bo; Liu, Lei; Xing, Yu; Xiong, Ruiying",Heavy oil-water flow patterns in a small diameter vertical pipe under high temperature/pressure conditions,Upward oil-water flows; Flow patterns; High pressure; High temperature; Heavy oil,NATURAL CIRCULATION LOOP; LIQUID ANNULAR-FLOW; 2-PHASE FLOW; PRESSURE-DROP; INTERFACIAL-TENSION; HORIZONTAL PIPES; PHASE INVERSION; VOLUME FRACTION; DISPERSED FLOW; OPTICAL PROBE,"Experimental measurements were conducted to investigate the upward oil-water flow patterns in a small diameter vertical pipe (0.01m I.D.) under high temperatures up to 130 degrees C and high pressures up to 20 MPa. The viscosity of the oil sample was 584.24 mPa s and the density was 1.899 g/cm(3) at 30 degrees C. The effects of pressure, temperature, input water fraction (IWF) and mixture velocity on the flow patterns were systematically investigated. The observed flow patterns were plotted on a flow pattern map in which input water fraction was used as the y-axis and the mixture velocity was used as the x-axis. Based on the measurement results, the following flow patterns were observed: water-in-oil dispersed flow (D w/o), water-in-oil bubbly flow (B w/o), water-in-oil slug flow (S w/o), water-in-oil creep flow (CE w/o), churn flow (Churn) and core annual flow (AF). Phase inversion was not observed in this work. With an increase in temperature at a given input water fraction, S w/o, CE w/o and Churn flow with large water drops tended to transform into B w/o and D w/o with smaller water drops, the CE w/o disappears gradually, and the boundaries in the flow pattern maps tend to occur at lower input water fraction values. The effect of pressure on the flow patterns was found to be opposite to that of temperature. The possible causes leading to the changes in the flow patterns subjected to pressure/temperature variations were provided in terms of changes in density ratio, interfacial tension, and viscosity ratio of oil and water.",3,4,3
Slug,,"Zhong, Ziyao; Wu, Xiaodong; Han, Guoqing; Li, Chen; He, Lanping; Xiong, Xiaofei; Wang, Shuolong",Experimental investigation on particle transport of coal fines in unsteady terrain slug flow,Experimental study; Coalbed methane; Terrain slug; Critical velocity; Coal particle; Multiphase flow,VELOCITY; PIPELINE; MIGRATION; OIL,"The coal fine output from coalbed methane (CBM) formation during the production of CBM wells seems to be a common occurrence. At the lower section of wellbore, the aggregation of coal fine particles may occur, that lead to the increase of local coal fine concentration and the negative effect on the work of downhole equipment. To investigate the migration of coal fine particles in gas-liquid flow, the gas-liquid-solid three-phase flow experiments were carried out. The experiments were conducted in a downbent V-shaped pipe with different incline angles (5 degrees, 15 degrees and 25 degrees), and recorded the real-time liquid holdup at certain positions of the lower elbow with the conductivity method. The terrain-induced slugs can be identified on the time series curves of liquid holdup. And the characteristic parameters of each slug, such as slug length and translational velocity, were calculated. By injecting marked coal fine particles into the multiphase flow loop and observing whether they can be discharged from the V-shaped pipe, the lower limits of gas and liquid velocities to void the particle retention at the lower elbow were collected. According to the experimental observation of the coal fine particle movement in one slug unit, we defined dimensionless particle velocity function FD to analyze the particle transport mechanism in the terrain slug flow. The FD value distribution of terrain slugs, calculated by the use of slug parameters, changed with the slug dissipation and coalescence in the experimental incline pipeline. Detail analyses of FD statistical parameters show that the mean values of FD increase with the rise of mixture flow velocity, and the decrease of inclination angle. The mean values of FD at the critical particle discharge conditions are positively correlated to particle concentration. And a linear relationship between the critical means of FD and the particle concentrations is presented.",4,4,0
Slug,,"Babadagli, T.; Cao, N.",Can water-alternating-solvent injection be an option for efficient heavy-oil recovery?: An experimental analysis for different reservoir conditions,Heavy-oil recovery optimization; Solvent injection; WAG design; Injection sequence and slug size; Wettability,VAPOR EXTRACTION,"We performed a set of experiments on vertically situated sandpack models. Different slug sizes of water and solvent (heptane used in the experiments) were tested for 2000 cp heavy-oil. As a benchmark, tests were also performed for 14 cp light oil for comparative analysis. In addition to the technical feasibility, an economic analysis was performed considering the amount of solvent injected and oil and solvent recovered. Experiments were repeated for oil-wet systems. For both light and heavy oils, starting the process with the solvent was feasible in the short run technically and economically. If the process starts with water, excess amount of it occupies the largest pores and hinders solvent-oil interaction for mixing and oil displacement. This was true especially if the rock is oil-wet and oil is heavy, which yielded faster recovery and higher ultimate recovery than the water-wet case. The time for switching to solvent injection is more critical in the heavy-oil case as it is more sensitive to the amount of existing water in the system. As oil becomes heavier and if the rock is water-wet, starting the process with waterflooding is not suggested. In this case, more solvent needs to be injected in the first cycle compared to oil-wet systems. Due to partial miscibility and more gravity stable nature, solvent retrieval and sweep with water can be more effective in case of heavy-oil compared to light oil (fully miscible case) and, as a result, can be even more profitable. This is highly critical in exploitation of heavy-oil reservoirs if thermal options are limited and greenhouse gas emission is a concern.",4,4,3
Slug,,"Gerevini, Giovani G.; Farenzena, Marcelo; Trierweiler, Jorge O.",Slugging attenuation using Nonlinear Model Predictive Control in offshore oil production,Slug flow; Deepwater; Offshore crude production; Nonlinear model predictive control,MITIGATION; OBSERVER; FLOW,"The increase in oil production in offshore systems can be achieved by active control, as state in the literature. However, the approach based on linear controllers has performance limitations in real applications, because of valve rate of change, as shown in this paper. As an evolution control approach, we show up the advantages of using a Nonlinear Model Predictive Controller (NMPC) by the Local Linearization on the Trajectory (LLT) algorithm, with the Fast Offshore Well Model (FOWM) as internal model, together with a first idea for tuning the controller parameters. Through a monovariable pressure control strategy, manipulating the production choke, we observed a potential production increase around 9.0% using NMPC. In addition, the multivariable advantage of NMPC strategy is stressed including the gas lift flow as a second manipulated variable. With this structure, it is possible to decrease the production choke variation in 76% and the oil production variability by 80% compared to monovariable structure, with similar production gain.",5,5,0
Slug,,"Tebowei, Roland; Hossain, Mamdud; Islam, Sheikh Zahidul; Droubi, Mohamad Ghazi; Oluyemi, Gbenga",Investigation of sand transport in an undulated pipe using computational fluid dynamics,Sand deposition; Eulerian model; V-inclined,SLUG FLOW; SOLIDS TRANSPORT; SIMULATION,A CFD model has been implemented to investigate the effects the pipe undulation on sand transport. Of particular interest of the present study is the sand deposition in small angled V-inclined bend relevant to oil and gas subsea flowlines where sand deposition could be a major problem. The model used is the two-fluid Eulerian-Eulerian model with the granular temperature to tackle the solid phase properties. A number of sub-models for tackling solid-fluid and fluid-fluid interaction has been incorporated in the modelling frame work to capture the transition of flow regimes. The simulation results show that the seemingly small angled V-inclined has significant impact on sand disposition compared to the horizontal section. Sand is deposited at the downstream section of the V-inclined pipe at much higher velocities compared to the minimum transport velocity of the horizontal pipe.,5,5,2
Slug,,"Goncalves, G. F. N.; Baungartner, R.; Loureiro, J. B. R.; Silva Freire, A. P.",Slug flow models: Feasible domain and sensitivity to input distributions,Horizontal slug flow; Feasible domain; Sensitivity analysis; Unity cell,LENGTH DISTRIBUTION; PIPE-FLOW; PREDICTION; FREQUENCY; VELOCITY,"The present work discusses the feasible and validity domains of unit-cell slug models. The models of Dukler and Hubbard (Ind. Eng. Chem. Fund. 14 (4): 337-347, 1975) and Orell (Chem. Eng. Sci. 60 (5): 1371-1381, 2005) are particularly considered as reference models, for they are based on distinct formulation hypotheses. A parameter sensitivity analysis is also carried out to assess the uncertainty in predicted slug length distributions. The work further discusses a kinematic methodology for the estimation of slug length distributions, a problem of great interest in the design and determination of the operational conditions of gas-liquid separators. The results are validated through new experiments and the data of Ujang et al. (Int. J. Multiphase Flow 32 (5): 527-552, 2006). The new experiments introduce data (including the pdf distributions) on pressure gradients, bubble lengths, passage frequency and translational velocity of bubbles. Particle image velocimetry measurements furnish the local mean velocity profiles in the continuous phase of the liquid slug and film.",6,6,0
Compressive Strength,,"Ma, Jianjun",Wetting collapse analysis on partially saturated oil chalks by a modified cam clay model based on effective stress,Wetting collapse; Wetting swelling; Partially saturated; Effective stress; Modified cam clay model; Oil chalks,UNSATURATED SOILS; CONSTITUTIVE RELATIONS; MECHANICAL-BEHAVIOR; STRENGTH; ROCK; VARIABLES; POROSITY; WATER; SHALE,"This paper presents an interpretation of wetting collapse in partially saturated oil chalks subjected to water flooding. For this purpose, two competitive mechanisms, namely, compressive plastic strains and elastic swelling, have been analyzed through a modified Cam Clay model based on effective stress. The resulting simulation shows that, mechanical behaviors of oil chalks upon wetting have been captured with good accuracy. The interpretation detects the possibility of wetting compaction/swelling for oil chalks under different stress states, emphasis is also placed on specific conditions for the occurrence of wetting collapse. Inspections on effective stress and preconsolidation stress paths show that, the distance between two streams plays the main role on the magnitude of accumulated compressive plastic strain. Since wetting process generally leads to two competitive deformation, elastic swelling due to the diminution of suction and additional plastic flow due to the diminution of plastic yield stress (contraction of yield surface), the plastic compaction would outweigh elastic swelling if a threshold value of suction can be achieved.",2,3,0
Compressive Strength,,"Ghimire, Bishwas; Daigle, Hugh; Gray, Ken E.",Modeling formation resistivity changes due to invasion and deformation during initial leak-off test build-up,Leak-off test; Invasion; Formation resistivity,SIMULATION; PERMEABILITY; LOG,"Leak-off tests (LOTs) are performed to determine the strength of a newly drilled formation below a cased interval and to characterize the upper bound of mud weight that can be safely used while drilling the next section, without risk of formation breakdown and lost circulation. In an LOT, drilling mud is pumped into the wellbore, causing the wellbore pressure to increase and exceed the formation pore pressure. During the initial LOT build up, excess pressure in the wellbore causes the surrounding rock to deform and mud filtrate to invade into the formation via porous flow. In this paper, change in formation resistivity around a wellbore during initial LOT build-up has been investigated. Invasion is modeled assuming two-phase radial Darcy flow and deformation using a 3D finite element model. Invasion may result in an exchange of conductive ions between water-based drilling mud and formation water both by diffusion in the direction favored by the concentration gradient of the ions and by convective transport. This process is incorporated into the model by solving the radial convection-diffusion equation for the aqueous phase using a finite difference method. Archie's law is used to determine the formation resistivity. Findings show that the direct effect of deformation on porosity, therefore on formation resistivity during an LOT, is negligibly small even when the formation rock is highly compressible with compressibility in the order of 10(-3) psi(-1). While salinity solely controls formation resistivity during an LOT conducted in a fully water-saturated interval, water saturation change and salinity change compete to produce a compound effect on formation resistivity of an oil-bearing zone where water saturation varies dynamically due to displacement of formation fluids. Unlike compressibility, the effect of permeability on formation resistivity response is found to be evident and readily observable. While analyzing the formation resistivity responses at various depths of investigation (DOIs), it is found that the effect of DOI on resistivity response can be useful in studying invasion and assessing formation damage during an LOT. In addition to this, through comparing time-lapse resistivity logs at multiple DOIs during an LOT with numerically synthesized resistivity responses, the model promises a novel approach towards determining the permeability of a freshly drilled and unaltered interval.",2,2,1
Compressive Strength,,"Wuyep, E. O.; Oluyemi, G. F.; Yates, K.; Akisanya, A. R.",Geomechanical effects of oilfield chemicals on sand failure in reservoir rocks,Sand failure; Oilfield chemicals; Geomechanical strength; Dissolution; Mechanical testing; Precipitation,CO2 SEQUESTRATION; LIMESTONE,"Sand failure may result in the production of formation sand at the same time the formation fluids are being produced. This work examines the effects of some commonly used oilfield chemicals, specifically, biocide, corrosion inhibitor and scale inhibitor, on the geomechanical strength of reservoir rocks such as limestone and sandstone. A combination of rock mechanical testing, grain size distribution analysis and analytical techniques are used to establish and define the effects of these chemicals on grain dissolution and unconstrained compressive strength. The results suggest that some interactions such as chemical reaction (dissolution/precipitation) between the oilfield chemicals and the two different types of reservoir formation rocks and transport of grains occurred following the exposure of the rocks to the oilfield chemicals leading to the weakening of the grain fabrics rocks and consequent reduction in unconfined compressive strength. The implications of the results for the strength reduction and sand production are discussed.",4,4,1
Compressive Strength,,"Mousavi, E.; Cheshomi, A.; Ashtari, M.",Estimating elasticity modulus and uniaxial compressive strength of sandstone using indentation test,UCS; Elasticity modulus; Indentation test; Critical transition force (CTF); Indentation modulus (IM),LOAD TEST; ROCK,"Elastic modulus (E) and uniaxial compressive strength (UCS) are very important engineering parameters that is required for many engineering projects. In some projects such as well drilling for oil production, deep underground tunnels in crushed zone, due to the depth of the well and fractures of rocks, there are some problems for obtained standard core samples. In this situations various methods have been developed for determining UCS and E using drilling cutting. Indentation test is one of these methods, in this method, an indenter penetrates into the stabilized samples in the surrounding material and then Critical Transition Force (CTF) and Indentation modulus (IM) determine. In the present study in order to developing the application of indentation testing for sandstone, and investigate the effect of particles size, shape and thickness, 14 sandstone blocks were collected from different formations in Iran and their physical characteristics, UCS and, E were measured using standard methods. After crushing the blocks and preparing 600 particles with dimensions of 3x3x3 mm(3), 5x5x3 mm(3), 5x5x5 mm(3), 5x5x8 mm(3), and 8x8x8 mm(3) and irregular shape particles with a thickness of 5 mm, indentation tests were performed on each particle and CTF and IM were calculated for each particle separately. According to the tests carried out some empirical relationships were proposed between UCS CTF (with R-2 >= 0.86) and E - IM (with R-2 >= 0.73) for different shapes and dimensions. Due to the differences in the dimensions of the produced particles, investigating the effect of surface and thickness of particle on the CTF and the IM revealed that the particle's surface had a considerable effect on the CTF and IM; however, the effect of thickness was negligible. Using the dimensionless surface parameter (S and Si), some empirical relationships between UCS - CTF/S (with R-2 >= 0.80) and E - IM/Si (with R-2 >= 0.77) were proposed for predicting UCS and E of sandstone particles with different shapes and dimensions. The accuracy of these relations was validated by performing standard uniaxial and indentation tests on 4 sandstone blocks and comparing measured UCS and E with those predicted using these relations. This comparison showed there is a good correlation between measured and predicted values. The proposed equations in this study were compared with results of previous studies. The relationship proposed in the present study to predict sandstone UCS has a similar accuracy with those proposed in by other researchers.",4,5,2
Compressive Strength,,"Srivastava, Aman; Ahmed, Ramadan; Shah, Subhash",Effects of magnesium oxide on carbonic acid resistance of oil well cement,Oil well cement; Magnesium oxide; Carbonation; Degradation; Expansion; Porosity,CO2 GEOLOGICAL STORAGE; DEGRADATION; MGO; INTEGRITY; KINETICS,"This paper presents the results of an experimental study on the effects of magnesium oxide additive on the performance of oil well cement under a high-pressure high-temperature (HPHT) carbonic acid environment. Magnesium oxide (MgO) is a well-known expanding agent that improves sealing performance of cement. However, the performance of MgO-based cement has not been tested in a carbonic acid environment. Therefore, to investigate the impact of MgO on carbonic acid resistance of cement, two cement slurry formulations: Class H cement with 35% silica (baseline or HS) and baseline cement with MgO (HSMG) were compared after exposure to an acidic environment. To evaluate their performance, cylindrical cores and shear bond strengths (SBS) samples were prepared and aged in HPHT autoclave containing brine (2% sodium chloride solution) saturated with mixed gas containing CH4 and CO2. Six aging tests were conducted varying CO2 concentration, temperature, and pressure. After aging for 14 days at constant pressure and temperature, the samples were recovered, and their physical (bond and compressive strength, porosity and permeability) and mineralogical composition were measured and compared with those of unaged samples. The results suggest that addition of 5% MgO reduces the carbonation of cement and could potentially prolong the operational life of cement by protecting its binding components (calcium hydroxide and calcium silicate hydrate).",5,5,0
Compressive Strength,,"Curbelo, F. D. S.; Garnica, A. I. C.; Araujo, E. A.; Paiva, E. M.; Cabral, A. G.; Freitas, J. C. O.",Vegetable oil-based preflush fluid in well cementing,Vegetable oil-based microemulsion; Cleanup fluid; Surfactants; Cement slurry,DRILLING-FLUID; FILTER CAKE; REMOVAL,"Efficient cement bonding in wellbores provides better zonal insulation, containment of gas migration, prevention of excessive water production, besides affecting their economical performances. Carrying out a properly sized and formulated cleanup process (or pre-flush) is one of the most costly tasks in wellbore preparation. Different chemicals are commonly used both to remove filter cakes and enhance surface water-wetting, such as solvents and surfactants. The search for environmentally-friendly cleanup fluids, in particular, with acceptable wetting properties, has been challenging. This paper describes an experimental study to characterize and prepare a vegetable oil-based microemulsion to work as pre-flush fluid in wellbores. Results obtained from cleaning assays (removal test), wettability testings and fluid compatibility analyses have exhibited excellent performances in filter cake removal. Enhanced water-wetting and suitable rheological compatibility of cement/cleanup fluid/mud systems and good compressive strength were also achieved.",6,6,5
Compressive Strength,,"Ding, Lu; Ni, Hongjian; Li, Mukun; Li, Wentuo; Song, Weiqiang; Guo, Xing",Wellbore collapse pressure analysis under supercritical carbon dioxide drilling condition,Supercritical carbon dioxide; Drilling; Pore pressure; Collapse pressure; Wellbore stability,,"Compared with the conventional drilling methods, supercritical carbon dioxide used in drilling and completion has considerable potentials and many advantages. However, it is found in the research and practice that there are yet many basic problems to be solved. Wellbore stability is one of them. Firstly, in this paper, on the basis of Span & Wagner equation, combined with unique physical properties of supercritical carbon dioxide, parameters such as temperature and pressure in the wellbore while the supercritical carbon dioxide drilling are calculated. Secondly, the heat and mass transfer effect between the supercritical carbon dioxide and the formation has been studied, and the temperature change near the wellbore formation and stress change near the wellbore have been obtained. Thus, pore pressure change near the wellbore has been obtained. When the depth reaches 1500 m, the downhole temperature will be 12 K lower than the wellbore temperature, and the pore pressure will increase to 20 Mpa as the supercritical carbon dioxide seeps into the formation. Thirdly, mechanical properties change rules when rocks are soaked in the supercritical carbon dioxide are obtained through experiments. The compressive strength decreases by 64%, the elastic modulus increases by 153%, and the poisson ratio decreases by 8%. Based on the above research, the wellbore collapse pressure model has been established. It is revealed that the wellbore collapse pressure rises from 9.17 Mpa to 16.26 MPa with the increase of time, which is still lower than the bottom pressure and cannot lead to instability. Meanwhile, the bottom collapse failure index keeps positive and increases gradually with the increase of time. It means that there is no wellbore enlargement. Therefore, the results have verified the wellbore stability while the supercritical carbon dioxide drilling. It has laid a solid foundation for the future development of supercritical carbon dioxide drilling.",8,12,0
Compressive Strength,,"Moradi, Seyyed Shahab Tabatabaee; Nikolaev, Nikolay Ivanovich",Assessment of the cement failure probability using statistical characterization of the strength data,Oil well cement; Compressive strength; Weibull distribution; Sheath stability; Analytical modelling,WEIBULL,"Cement sheath failure may occur under the influence of induced stresses during service life of the well. For many years, analytical or numerical models have been developed to study the probability of the cement sheath failure under different circumstances. Cement compressive strength is considered as a valuable input parameter during the assessment of the cement failure probability. Usually the compressive strength data are obtained by conducting several direct laboratory experiments on cement samples. The average value of these experiments are reported and used in different cement failure models. However, this approach may results in underestimating the cement failure probability. As cement have heterogeneous structures, therefore their strength variations have a statistical character. In this work, the compressive strength data are represented by the Weibull distribution function, which then will be used in the cement failure probability calculations. Results show that using the statistically distributed compressive strength data in calculations, leads to more accurate outputs of the failure model.",8,8,2
Compressive Strength,,"Wang, Wei; Jiang, Youlu; Swennen, Rudy; Yuan, Jing; Liu, Jingdong; Zhang, Shaomin","Pore-throat characteristics of tight sandstone reservoirs composed of gravity flow sediments: Yingcheng Formation, Longfengshan sag, China",Gravity flow; Tight sandstone; Pore-throat size; Lower cretaceous; Longfengshan sag,SOUTHERN SONGLIAO BASIN; DEPOSITIONAL PROCESSES; QUALITY EVOLUTION; DENSITY FLOWS; GAS; DIAGENESIS; SEQUENCE; POROSITY; OIL; PERMEABILITY,"The Lower Cretaceous Yingcheng Formation in the Longfengshan sag (Songliao Basin, China) represents a typical tight sandstone reservoir that hosts large accumulations of hydrocarbons. The lacustrine sandstones mainly reflect gravity flow deposits making up various lithofacies displaying varying degrees of heterogeneity. This study reports on the links among gravity flow type, diagenetic overprinting and pore-throat characteristics that control reservoir quality. Core observations, especially grain size variations and related sedimentary structures are used to differentiate types of gravity flows. Microscopic observations, cathodoluminescence, scanning electron microscopy, pressure-controlled mercury injection tests and rate-controlled mercury injection tests are used to determine the mineralogy, sedimentary composition and pore-throat characteristics of the tight sandstones. In the study area, the gravity flows are divided into muddy debris flows, sandy debris flows, high-density turbidity flows, low-density turbidity flows and mud density flows. The petrophysical properties of these different gravity flow sediments reflect a range of permeability and porosity characteristics. Because of their mud-dominated textures and related weak compressive strength, mud density flows and muddy debris flows become ineffective as reservoirs during burial. In contrast, for approximately similar burial depths, turbidites and sandy debris flows show better reservoir quality. However, reservoir units with high porosities still possess considerable heterogeneity; this is especially true of some sandy debris flows that possess large amounts of secondary pores but which are not charged with hydrocarbons. In particular, in some poorly sorted sandy debris flows that are characterized by high contents of fine-grained matrix, some of the pore throats are blocked by matrix material. Moreover, the dissolution of feldspars and volcanic debris led to the formation of authigenic clays and quartz, which preferentially developed in pore throats with small radii. This process significantly reduced permeability. Overall, the permeabilities of the sandy debris flows are generally lower than those of the turbidites. Due to their relatively large-radius pore throats, turbidites can be categorized as potential effective hydrocarbon reservoirs in the study area. This research provides significant insights into the characteristics of pore throats within tight reservoirs consisting of gravity flow sediments in lacustrine basinal settings.",9,10,0
Cap Rock,,"Gao, Xiaoqiao; Ma, Yongsheng; Jiang, Qicai; Shi, Kaibo; Li, Yang; Shen, Yingchu",Wave processes in relation to the tectono-sedimentary of the Tarim basin: A new method for basin study,Geological rhythm; Wavelet transform; Wave analysis; Tectonic-sedimentation evolution; Tarim basin,NW CHINA; SEQUENCE STRATIGRAPHY; NORTHWEST CHINA; HIGH-FREQUENCY; WESTERN CHINA; SEDIMENTARY; CYCLES; HYDROCARBON; RESERVOIRS; EVOLUTION,"This study gives insights into the tectonic and sedimentary evolution of the Tarim basin, the largest petroleum-bearing basin in Western China, by analyzing sedimentary wave process using multi-scale decomposition of the wavelet transform method, and the mathematical defects of sliding-window method in the process of sedimentary wave analysis was discussed. The filtering analysis, in the time domain, was carried out on cores collected from 14 wells in the Tarim basin. The results show that the evolution of the Tarim basin was controlled by various wave processes. The periods of 212 +/- Ma, 102 +/- Ma and 33 +/- Ma indicated a strong sedimentary rhythm, which displayed a spatial and temporal evolution of wave characteristics. The 33 +/- Ma period represented a third-order sequence of the stratigraphic division, which identified with the unconformities of the Tarim basin; 102 +/- Ma period corresponded to an important period of sedimentation and the plate collision around the Tarim basin, which marked a second-order period of the basin evolution. The centers of subsidence showed periodic shifts since the Cambrian, and the time for periodic migration (completing a circle) of the depocenters or the centers of subsidence is traced as 212 +/- Ma, which corresponded to the first-order period of the basin evolution. The coupling relationships between the wave processes and the evolution and distribution of source, reservoir and cap rocks in the basin were given by three kinds of patterns, which were important in predicting the space-time distribution of source, reservoir and cap rocks. This study gives a new insight on predicting the formation and distribution of petroleum, which could be used for selecting petroleum exploration targets effectively.",1,1,0
Cap Rock,,"Mosaheb, Mojtaba; Zeidouni, Mehdi",Above zone pressure interpretation for leaky well characterization and its identification from leaky caprock/fault,Leakage characterization; Pressure interpretation; Leaky well; Fault; Caprock,CO2 LEAKAGE; FLUID-FLOW; UNDERGROUND-STORAGE; ABANDONED WELLS; NORMAL-FAULT; WATER; GAS; PERMEABILITY; INJECTION; ROCKS,"Pressure transient analysis has long been used for reservoir characterization. Above-zone (AZ) pressure has been recently investigated for inferring leakage pathway characteristics in leakage events from subsurface injection operations. The recorded pressure in the AZ should be purely related to leakage and therefore it can be safely inverted to deduce leakage characteristics. It is crucial to evaluate fluid leakage through abandoned wells to plan for further measurements of leakage prevention. However, the recorded AZ leakage signal may not be related to leaky well(s). Therefore, identification and spatial investigation of well leakage is required for leakage evaluation. In this paper, we propose a pressure interpretation method for early detection of leaky pathways, applying two observation points in the AZ. We distinguish leaky well, fault and caprock based on their corresponding flow regime identification. We show that the pressure difference of the two observation wells can be applied as a proxy for unknown leakage rate, which is crucial for leakage identification as well as characterization. Results show that the estimated location of the leaky well, leakage coefficient, and the leakage rate are in good agreement with the actual values. The estimated leakage coefficient of the leaky well can be used to evaluate well leakage in multiphase systems such as carbon dioxide leakage in deep saline aquifers.",2,2,1
Cap Rock,,"Cartagena-Perez, D. F.; Arias-Buitrago, J. A.; Alzate-Espinosa, G. A.; Arbelaez-Londono, A.; Morales-Monsalve, C. B.; Araujo-Guerrero, E. F.; Naranjo-Agudelo, A.",A modified model to describe porosity-temperature relationship,Thermoelasticity; Poroelasticity; Porosity change; Permeability change; Temperature effect; Confining stress; Caprock integrity,,"This work presents some of the main contributions in the discussion about porosity changes due temperature and an analytical model to describe them when temperature variations occur. The model is based on two mechanical theories: poroelasticity, which considers three different volumes (bulk, solid frame, and porous) in their answers to stress change, and thermoelasticity that allows calculating the mechanical stresses related to temperature changes using thermal expansion. To achieve a more realistic behavior, a previous model is modified by adding the action of confining pressure as a new variable and multiple modifications of the thermal expansion coefficients from laboratory evidence. Those modifications allow the overcoming of either over or underestimation problems. In the proposed model, three modifications are applied to achieve a better approach of actual phenomena: 1) The thermal expansion coefficient is understood as non-linear, 2) the expansion of bulk and constitutive material are differentiated, and 3) the bulk volume is dominated by a new concept of modulated strain that combines thermal and confining stress, in order to include confining stress into the model. It is found that porosity changes happen as a result of the interaction between the thermal and confining stresses. Therefore, the model describes two phases. In the first phase, porosity decreases as a consequence of the constant bulk volume while the solid volume expands, thus accumulating thermal stress. In the second phase, the thermal stress overcomes the confining stress, triggering a porosity recovery. Some applications, such as permeability calculation using Carman-Kozeny correlations are presented. These calculations may give an idea on how the temperature could change the formation's petrophysical properties. Furthermore, a simple formulation of a safe injection temperature can be derived from the concept of maximum allowed reservoir deformation, which depends on temperature change and overburden pressure. Finally, the sensitivities of the new model are presented in order to analyze the impact of mechanical and thermal properties within the porosity calculations.",4,4,0
Cap Rock,,"Ahmadi, Mohammad Ali; Chen, Zhangxing",Analytical approach for leakage characterization in carbon sequestration in a bounded deep saline aquifer,Analytical model; Leakage rate; Closed reservoir; Storage; Aquifer; Monitoring well,CO2 STORAGE CAPACITY; ENHANCED GAS RECOVERY; DIOXIDE SEQUESTRATION; ABANDONED WELLS; DEPLETED OIL; PRESSURE; FLOW; RESERVOIRS; INJECTION; BOREHOLES,"One of the promising methods in CO2 sequestration is CO2 injection into deep saline aquifers. A challenging question in CO2 storage in deep saline aquifers is how we can determine the leakage in a storage aquifer if its cap rock does not fully seal it. Among those approaches previously employed, leakage detection by monitoring pressure changes in a monitoring well has gained the most attention recently. In this study, we have developed a new analytical modeling method to monitor pressure changes in monitoring aquifers as a tool for leakage detection. Our developed analytical models are capable for bounded saline aquifers. To eliminate the effect of a size in our modeling, all the developed models are in dimensionless form. Pragmatic sensitivity analyses are performed to determine the effect of different parameters on a dimensionless leakage rate and a pressure change in a monitoring well and a pressure change in a storage aquifer due to both injection and leakage. Based on the results gained, the dimensionless pressure in the monitoring well depends on the well location and the thickness of the monitoring aquifer; however, it is independent of a leak location. The dimensionless pressure change in a storage aquifer highly depends on the dimensionless diffusivity coefficient and the thickness of the storage aquifer; however, it is independent of a leak location.",4,4,0
Cap Rock,,"Rahmani, Omeid; Khoshnoodkia, Mehdi; Mohseni, Hassan; Hajian, Mahmoud","Sequence stratigraphy of the Triassic Period: Case from the Dashtak and Khaneh-Kat formations, the Zagros Basin, Iran",Zagros Basin; Dashtak; Khaneh-Kat; Sequence stratigraphy; Triassic,FOLD-THRUST BELT; GEOMETRY,"The Dashtak and Khaneh-Kat formations in the Zagros Basin were deposited during the Triassic Period and are mainly composed of carbonate-evaporate rocks. The depositional environment of these formations ranged from supratidal and tidal flat to lagoonal and shoal ramp. However, the lack of evaporite sediments indicates that the Khaneh-Kat formation was deposited in a relatively deeper setting in which no more evaporites were present. In the study area, the Dashtak formation has acted as an effective seal for giant gas reservoirs entrapped within the Dehram Group, whereas the Khaneh-Kat formation appears to have neither of the characteristics of a cap rock. This study revealed that the Dashtak formation is divided into four sequences (middle to late Triassic) and the Khaneh-Kat formation consists of five sequences (middle to late Triassic). The uppermost sequence of the Dashtak formation was removed by post-depositional erosion in the SE despite its complete preservation in the NW. The lower part of the Khaneh-Kat formation extends throughout the basin with its carbonate facies and is equivalent to the Kangan formation. Sequences two to five of the Khaneh-Kat formation are equivalents of the Dashtak formation that were deposited in Kuh-e-Manghasht and Kuh-e-Dalani (Oshtran Kuh). These sequences showed a distinct lateral facies change from evaporite dominated facies to carbonate facies.",4,4,1
Cap Rock,,"Wu, Jun; Fan, Tailiang; Gao, Zhiqian; Yin, Xinxin; Fan, Xue; Li, Chenchen; Yu, Wenyi; Li, Chen; Zhang, Chenjia; Zhang, Jinhuang; Sun, Xining","A conceptual model to investigate the impact of diagenesis and residual bitumen on the characteristics of Ordovician carbonate cap rock from Tarim Basin, China",Carbonate cap rock; Diagenesis; Carbonate cements; Stylolites; Residual bitumen,OOLITHE-BLANCHE-FORMATION; TAHE OIL-FIELD; HYDROCARBON ACCUMULATION; RESERVOIR QUALITY; PETROPHYSICAL PROPERTIES; FEIXIANGUAN FORMATION; POROSITY DEVELOPMENT; SMACKOVER FORMATION; MAESTRAT BASIN; CENTRAL UPLIFT,"The Lower-Middle Ordovician Yingshan (O1-2 y) Formation associated with large unconformity weathering crust was the main hydrocarbon reservoir in the Tarim Basin, and the dense limestone/dolomite within this formation was revealed as the local carbonate cap rock. Based on petrophysical properties, thin sections, cathodeluminescence (CL) and scanning electron microscope (SEM) measurements, the effects of cap rock on depositional settings, diagenesis and pyrobitumen were carefully analyzed. Carbonate cap rock dominated by micrite has ultralow porosity and permeability, with an average porosity of 0.568% and permeability of 0.07 x 10(-3) mu m There is a significant bottom-up thickness variation (from several to tens of meters) in different members within the O1-2 y formation. The steady cap rock is more likely to be distributed in low-energy depositional environments, corresponding to intershoal sea, low-lying land of open platform and lagoon of restricted platform. Constructive diagenesis processes mainly comprise extreme filling, compaction and cementation, resulting in a significant decrease in the quantity and size of pores. Conversely, leaching and paleokarst dissolution, together with diagenesis associated with hydrothermal fluids, has a detrimental effect on the effective preservation of cap rock. Three types were summarized to characterize the cementation-compaction relationship between cement distribution and intraclast deformation. The increase in intraclast size indicate that the intergranular pores are likely to be cemented. A good sealing impact on the underlying oil-gas is confirmed in sparry calcarenite when its cement content reaches 15% and higher by volume. Early compaction vs. early cementation processes probably affect the sealing capacity, so high quality cap rock is primarily presented while cementation precedes compaction. Highly abundant stylolites filled with residual bitumen and precipitated cements in the cap rock intervals consistently have low poroperm values, resulting in micropore occlusion and occlusion of the late hydrocarbon migration pathways, which can act as barriers for the upward migration of oil-gas. A conceptual model of the evolution feature of cap rock provides a plausible interpretation for better understanding of the spatial distribution of carbonate cap rock in future exploration and development",5,5,3
Cap Rock,,"Han, Weon Shik; Kim, Kue-Young",Evaluation of CO2 plume migration and storage under dip and sinusoidal structures in geologic formation,Geologic CO2 sequestration; CO2 plume migration; Sloping aquifer; Numerical simulations,TOP-SURFACE-MORPHOLOGY; CARBON-DIOXIDE; HETEROGENEITY; TEMPERATURE; EQUATION; IMPACT; GAS; INJECTION; PRESSURE; FLOW,"A series of numerical simulations were conducted to explore the frontal speed of the CO2 plume and residence time in the formation preserving the dipping and sinusoidal caprock. For this purpose, we generated various permutations of 2-D numerical models where the contact boundary between the caprock and targeted formation was simplified with the idealized sinusoidal function. Three parameters such as dip, amplitude, and wavelength were chosen to analyze how the dipping and sinusoidal structure could affect the frontal speed of CO2 plume. Subsequently, the study was expanded to understand the effect of caprock permeability and the heterogeneity preserved in the storage formation. Simulation results under the condition of dipping caprock (2 degrees - 10 degrees) indicated that the relationship between the migration distance of the CO2 plume front and time followed the linear trends. Among the chosen sensitivity parameters of dip, amplitude, and wavelength, the speed of the CO2 plume front was the most sensitive to the caprock dip, but the stored CO2 mass varied the most significantly with the amplitude. In addition, when the caprock permeability increased, certain amounts of CO2 escaped to the caprock, resulting in a retardation of the CO2 plume. Similarly, in the sensitivity studies of dip, wavelength, and amplitudes, more CO2 leaked to the caprock corresponded to smaller frontal speed of CO2 plume. Finally, the increase in permeability heterogeneity of the targeted formation decreased the sharpness of CO2 plume front while the mean arrival time of the plume front was relatively consistent.",8,8,0
Cap Rock,,"Togashi, Yota; Kikumoto, Mamoru; Tani, Kazuo",Determining anisotropic elastic parameters of transversely isotropic rocks through single torsional shear test and theoretical analysis,Anisotropic rock; Transversely isotropic elasticity; Torsional shearing; Hollow cylinder; Sedimentary rock,BEHAVIOR; STRAINS,"Deformation properties of sedimentary rock is quite important for evaluating the industrial production of shale gas and the effective design of tunnel constructions, deep rock foundations for nuclear power plant and deep geological disposal. Anisotropic sedimentary rocks, such as shale, can exhibit significantly different material properties in different directions. Knowledge of the anisotropic features of such rocks is, therefore, essential. When a hollow cylinder of an anisotropic material such as a sedimentary rock is torsionally-sheared, the axisymmetry is violated and the stress varies in the rotational direction. Utilizing such stress distributions, we propose a method to determine the parameters of the transversely isotropic elasticity of such a material, including the dominant orientation, via a single torsional shear test using a single hollow cylindrical specimen. A newly designed instrumented cap is also employed. Unlike existing methods, the specimen can be sampled in any arbitrary direction. An overview of the method is presented and its validity is checked both theoretically and numerically. The strain and stress distributions in a hollow cylindrical specimen of a transversely isotropic material is first investigated theoretically, and the stress and strain fields (to which random measurement errors are added) are back-analyzed using the proposed method. The results demonstrate that five elastic parameters, as well as the orientation of the transverse isotropy plane, can be determined uniquely via the proposed method.",9,9,0
Deep Water,,"Dominato, Karlynne R.; Rostron, Benjamin J.; Hendry, M. Jim; Schmeling, Erin E.; Sandau, Courtney D.; Mundle, Scott O. C.","Developing deep high-resolution concentration and C-13 isotope profiles for methane, ethane, and propane",Methane; Isotopes; Drilling; Profile; Gas migration; Reservoir,DISSOLVED METHANE; SEDIMENTARY BASIN; WATER; SASKATCHEWAN; CARBON; PROJECT; STORAGE; GASES; SHALE; FIELD,"Methods to collect and analyze concentration-depth profiles of dissolved methane (C-1), ethane (C-2), and propane (C-3) and their delta C-13-values from directional drilling operations were evaluated. The delta C-13 values of C-1-C-3 gases from drill cuttings were consistent; however, deeper zones (> 1200m BG) were subject to greater variability. The variability for C-1-C-3 isotope values was attributed to the drilling process, where the samples reflected mixing between different geologic zones. Gases and rock fragments from several formations likely contaminated the samples collected from the underlying intervals. The effects of mixing were observed in deeper zones in the borehole below the 'kick off' point for the directional drilling process. The greatest impact was observed for C-1 and C-2 gases, which was attributed to greater concentrations of these gases in shallow gas-bearing zones. This study demonstrates that mud gas and drill cuttings can generate high-resolution concentration and isotope depth profiles for C-1, C-2, and C-3 gases. However, mixing between zones along the borehole during drilling, an effect that can be exacerbated by directional drilling techniques, can impact the precision and accuracy of the geochemical profiles. The variability in the geochemical data generated from drilling programs can have a significant impact on the effectiveness of these profiles for reservoir characterization, exploration, and in identifying the source(s) of fugitive gases migrating to surface.",1,1,1
Deep Water,,"Orlov, Denis; Koroteev, Dmitry; Sitnikov, Alexander",Self-Colmatation in terrigenic oil reservoirs of Eastern Siberia,Colmatation; Formation damage; Permeability reduction; Water flooding; Fine migration; Rock properties,DEEP BED FILTRATION; POROUS-MEDIA; WATER-SENSITIVITY; FORMATION DAMAGE; FINES; MODEL; MIGRATION; TRANSPORT; SANDSTONE; FLOW,"The main objective of this work is to study formation damage phenomenon associated with in-situ migration of fines in rock samples from terrigenic reservoirs of Eastern Siberia experimentally. Results of oil flooding for the wide range of flow rates and permeabilities show that oil does not lead to fine mobilization and its consequent retention with permeability reduction. The permeability decrease is observed only when water is flowing in the porous space. Water itself is shown to be a strong driver of self-colmatation, which is likely because of its intensive physicochemical reaction with pore surface. Performing multiple core flooding tests and analyzing the data, we define the range of rock properties and flow conditions corresponding to development of the situ formation damage (self-colmatation). We classify self-colmatation over 5 types characterized with different behaviors of permeability decrease. We comprehensively study the dependencies of permeability reduction specifics on rock properties and flooding conditions. The dependencies account for multiple parameters correlated with permeability reduction: absolute permeability, residual oil saturation, three characteristic pore diameters, four characteristic grain diameters and four major minerals within the rock structure. We discovered that the increase of formation damages are associated with high absolute permeability and low residual oil saturations. It was shown that characteristic size of migrating fines is 0.01-0.005 mm and the diameter of pores where these fines can be strained is 12 mu m. We derive a single numerical criterion to estimate the influence of 13 parameters on colmatation process. The absolute permeability and the fraction of pore throats with diameters higher than 30 mu m are shown to be the strongest influencers on colmatation.",2,2,0
Deep Water,,"Mosaheb, Mojtaba; Zeidouni, Mehdi",Above zone pressure interpretation for leaky well characterization and its identification from leaky caprock/fault,Leakage characterization; Pressure interpretation; Leaky well; Fault; Caprock,CO2 LEAKAGE; FLUID-FLOW; UNDERGROUND-STORAGE; ABANDONED WELLS; NORMAL-FAULT; WATER; GAS; PERMEABILITY; INJECTION; ROCKS,"Pressure transient analysis has long been used for reservoir characterization. Above-zone (AZ) pressure has been recently investigated for inferring leakage pathway characteristics in leakage events from subsurface injection operations. The recorded pressure in the AZ should be purely related to leakage and therefore it can be safely inverted to deduce leakage characteristics. It is crucial to evaluate fluid leakage through abandoned wells to plan for further measurements of leakage prevention. However, the recorded AZ leakage signal may not be related to leaky well(s). Therefore, identification and spatial investigation of well leakage is required for leakage evaluation. In this paper, we propose a pressure interpretation method for early detection of leaky pathways, applying two observation points in the AZ. We distinguish leaky well, fault and caprock based on their corresponding flow regime identification. We show that the pressure difference of the two observation wells can be applied as a proxy for unknown leakage rate, which is crucial for leakage identification as well as characterization. Results show that the estimated location of the leaky well, leakage coefficient, and the leakage rate are in good agreement with the actual values. The estimated leakage coefficient of the leaky well can be used to evaluate well leakage in multiphase systems such as carbon dioxide leakage in deep saline aquifers.",2,2,1
Deep Water,,"Xiao, Shihong; Zhang, Fujuan; Liang, Zheng",A mathematical casing cutting model and operation parameters optimization of a large-diameter deepwater hydraulic cutter,Abandonment operations; Casing cutting mechanism; Hydraulic cutter; Mathematical casing cutting model; Parameter optimization,GAS INFRASTRUCTURE; OFFSHORE OIL; FORCE; COMPOSITES,"An important part of subsea abandonment operations on gas and oil wellheads is the use of hydraulic cutters. To save time and guarantee security of an operation, so it is desirable to predict their operating parameters with a mathematical model. To determine the relations between cutting force, structure, and operating parameters of a hydraulic cutter to optimize its design and operation, the casing cutting mechanism of a hydraulic cutter was analyzed. Cutting parameters were analyzed based on the characteristics of real-life cutting by a hydraulic cutter, and a mathematical casing cutting model of a large-diameter hydraulic cutter in deep water was established according to the classic empirical formulas of cutting and grinding forces. The model parameters were defined, and the mathematical model was verified by combining it with site data from abandonment operations. An optimization mathematical model of cutting parameters was also established for cutting efficiency, operation parameters were optimized by particle swarm optimization, and the pump output was also optimized. Results indicate that casing cutting is a combination of cutting and grinding. Cutting forces calculated by the mathematical casing cutting model were within 7% of actual cutting forces. The requirements of engineering applications were met. We found that cutting efficiency is greatly improved by adopting an optimal speed and feed, so the research results are pertinent and important to real-life practice.",2,2,1
Deep Water,,"Liu, Wen; Qiu, Nansheng; Xu, Qiuchen; Liu, Yifeng; Shen, Anjiang; Zhang, Guangwu","The evolution of pore-fluid pressure and its causes in the Sinian-Cambrian deep carbonate gas reservoirs in central Sichuan Basin, southwestern China",Paleo-pressure reconstruction; Overpressure mechanism; Basin modeling; Fluid inclusions; Sichuan basin,PALEO-UPLIFT; CELL; ACCUMULATION; SIMULATION; PETROLEUM; SYSTEM; MODEL; WATER,"Reconstructing the evolution of paleofluid pressure in carbonate reservoirs is a challenging problem, particularly when no oil-bearing fluid inclusions are available to provide barometric constraints on the fluid system. To recover the paleofluid pressure in the Sinian Dengying Formation (Z(2)dn) and the Cambrian Longwangmiao Formation (epsilon(1)l) of the central paleo-uplift of the Sichuan Basin, we conducted a comprehensive analysis combining the inclusion pressure-volume-temperature simulation, inclusions in situ Raman shifts, and basin modeling. The results showed that the evolution of the pore pressure could be divided into four stages. Prior to the end of the late Triassic, the whole central paleo-uplift was in a normal pressure state. During the Jurassic, a moderate overpressure prevailed in the dolomitic reservoirs of the Gaoshiti-Moxi area and decreased in the adjacent units. At the end of the early Cretaceous, the overpressure reached a maximum in the whole region and was strongest in the Longnusi area, decreasing to the west. From the late Cretaceous to the present day, the central area of the basin has uplifted rapidly with the overpressure significantly decreasing. Z(2)dn has been restored to normal pressure during the Neogene, while epsilon(1)l remains moderately overpressurized. Based on an analysis of the structural background and preservation conditions, the types of sedimentary facies, the preservation condition of the traps, and the differential weathering process are the primary reasons for the different pressure states in Z(2)dn and epsilon(1)l during the last stages.",3,4,1
Deep Water,,"Venancio, F.; Rosario, F. F.; Cajaiba, J.",Use of a dynamic system and reflectance measurements to assess the impact of monoethylene glycol on calcium carbonate scale,Scale; Calcium carbonate; Hydrate inhibitor; Dynamic test; Growth rate,IN-LINE TECHNIQUE; KINETICS DETERMINATION; HYDRATE; PRECIPITATION; INHIBITORS; CRYSTALLIZATION; ETHANOL,"The build-up of scale in petroleum production systems is a major hindrance to the efficient production of oil and gas. One of the most common types of scale is calcium carbonate, but the formation of gas hydrate is also a recurring concern, especially in offshore and subsea deep water production. Thermodynamic inhibitors are usually used to avoid hydrate formation, but they contribute to the precipitation of inorganic salts. As monoethylene glycol (MEG) is the most commonly used thermodynamic inhibitor, the purpose of this work was to evaluate the effect of MEG on the formation of calcium carbonate scale using a Dynamic Scale Loop (DSL) to evaluate scale inhibitors. The results show, as expected, that the larger the amount of MEG, the lower the calcium carbonate scale formation time. In addition, to better understand the DSL results and the formation and growth of crystals, focused beam reflectance measurement (FBRM) was performed. The results confirm that the addition of MEG decreases the growth rate by hindering the agglomeration of crystals due to an increase in the viscosity of the solutions.",4,4,1
Deep Water,,"Shen, Jian; Qin, Yong; Li, Yepeng; Yang, Yanhui; Ju, Wei; Yang, Chunli; Wang, Geoff","In situ stress field in the FZ Block of Qinshui Basin, China: Implications for the permeability and coalbed methane production",In situ stress; High-rank coal; Coalbed methane; Permeability; Gas and water production; Qinshui basin,EASTERN ORDOS BASIN; SHANXI PROVINCE; ORIENTATION; EXPLORATION; MAGNITUDE; RESERVOIR; PART; AREA; GEOMECHANICS; FRACTURES,"In situ stress affects reservoir permeability and stimulation, and thus coalbed methane (CBM) recovery. In this study, the in situ stress field measured from 238 CBM wells in the FZ Block of Qinshui Basin, China, was investigated. The vertical stress, horizontal maximum and minimum principal stress are 5.92-20.08 MPa, 8.03-41.75 MPa, and 5.38-21.24 MPa, respectively. The in situ stress magnitudes increase with burial depth of the coal seams. The FZ Block is dominated by reverse and strike-slip faulting stress regimes. Most of reverse fault stress regimes appear within burial depth less than 500 m, whereas normal and strike faulting stress regimes are deeper than 500 m. The relation between the coefficient of lateral stress and burial depth shows that shallow strata are characterized by horizontal stresses, whereas deep strata are generally hydrostatic pressures that approximately equal to the principal stresses. Low gas and high water production are associated with vertical hydraulic fractures, wherein the horizontal minimum principal stress is the minimum stress. High gas and low water production are associated with horizontal hydraulic fractures, wherein the vertical stress is the minimum stress. This results are attributed to the enhanced permeability of the coal seam and the communication with overlying or underlying aquifers because the minimum stress varies between vertical and horizontal minimum stress. The orientation of the horizontal maximum principal stress is -NEE-NE and is locally distorted by faults, which can be used to optimize the drilling, completion, and stimulation of CBM wells in the study area.",8,10,1
Deep Water,,"Wu, Yuandong; Zhang, Zhongning; Sun, Lina; Li, Yuanju; Su, Long; Li, Xingpeng; Xu, Hao; Tu, Yang",The effect of pressure and hydrocarbon expulsion on hydrocarbon generation during pyrolyzing of continental type-III kerogen source rocks,Pressure; Hydrocarbon expulsion; Continental type-III kerogen; Semi-closed condition,INDIVIDUAL N-ALKANES; BOHAI BAY BASIN; PETROLEUM GENERATION; CONFINED PYROLYSIS; THERMAL-CRACKING; GAS GENERATION; DEEP PETROLEUM; WATER-PRESSURE; LIAOHE BASIN; OIL CRACKING,"In order to define the roles of water and lithostatic pressure in petroleum formation of continental type-III kerogen source rocks, semi-closed hydrous pyrolysis experiments were conducted under with 50-1200 bar water pressure and 125-2000 bar lithostatic pressure at 480 degrees C. Our results will be of great benefit to the exploration of shale gas and deep petroleum in China. Increasing water pressure from 50 to 325 bar did not affect the yields of gaseous hydrocarbons, oil and bitumen, but increasing water pressure leads the more oil and less gaseous hydrocarbons from continental type-III kerogen in the 325-1200 bar water pressure range under semi-closed conditions. The decreasing yields of gaseous hydrocarbons, dryness of gaseous hydrocarbons and primary hydrogen together confirm that increasing water pressure promotes the primary reaction but decreases the cracking rate of oil. The decreasing values of S-2, HI and H/C in the pyrolysed samples confirm that high water pressure can increase the efficiency of hydrocarbon generation from continental type-III kerogen, while the maturation of kerogen correspondingly increases as shown by increasing values of VR and Tmax. In the 125-625 bar lithostatic pressure range, oil cracking and primary reaction of type-III kerogen may have contributed to the decreasing effect of hydrocarbon expulsion. The increasing hydrogen and gaseous hydrocarbon yields also confirm that the cracking of oil is enhanced within this pressure range. The decreasing trends of oil and gaseous hydrocarbon yields indicate that hydrocarbon generation rate was reduced by the high lithostatic pressure in the 625-2000 bar pressure range. The increasing values of S-2, HI and H/C, and decreasing values of VR and Tmax of pyrolysed samples confirm the retardation effect of highlithostatic pressure on the efficiency of hydrocarbon generation and maturation. In addition, the results also indicate that expelling hydrocarbons strongly promotes further hydrocarbon generation and retards the cracking of oil from continental type-III kerogen in source rocks.",9,10,0
Reservoir Management,,"Abreu, Ana Carolina A.; Booth, Richard; Prange, Michael; Bailey, William J.; Bertolini, Andre; Teixeira, Guilherme; Romeu, Regis K.; Emerick, Alexandre A.; Pacheco, Marco Aurelio C.; Wilkinson, David",A decision support approach to value flexibility considering uncertainty and future information,Optimization; Smart well; Control; Flexibility; Uncertainty; Information,DYNAMIC OPTIMIZATION,"Flexible strategies have become increasingly important for making strategic decisions under uncertainty conditions, once to consider flexibility in projects to engender the option of making return-maximizing decisions, since uncertainty can be resolved over a project's lifetime. The activities related to reservoir development are inherently associated with decisions making under uncertainty conditions and flexible solutions are very advantageous, allowing the option of making return-maximizing decisions, the uncertainty is resolved over a project's lifetime. One of the technologies that fit in this context are the smart wells, since this technology has the ability to acquire relevant requested information for future decision-making, enabling the generation of a development strategy with future flexibility. However, to value its flexibility if we do not account for uncertainty when performing an optimization, the resulting strategy will have two key shortcomings: it will assign too high value to the smart wells, and it will not take advantage of the ability of the smart wells to adapt and mitigate to uncertainty. We propose a strategy that allows the valuation of flexibility under uncertainty, seeking the flow control strategy that maximizes the expected net present value, dynamically reacting to new information as it is acquired. We demonstrate the proposed approach using a tank drainage problem for which we can evaluate optimization solutions for a broad range of scenarios, including model uncertainty and the flexibility to accommodate future measurements, with a reduced time of evaluation. Then we applied this proposed approach on a reservoir model that highlights its novel aspects: asset optimization under uncertainty, flexible control based on future information, and quantification of the value of flexibility and future measurements. In addition to valuing flexibility and future information, which contributes to the selection of appropriate smart-well technology and measurements, the proposed approach delivers a decision tree that describes a flexible strategy of optimum valve settings that properly accounts for future measurements and their impact on uncertainty reduction. This approach gives a qualitative value, indicating whether the field has the potential of significant improvement using smart wells, and a quantitative valuation of the benefits of smart completions resulting in a realizable strategy to guide the control of these completions in a real field management project.",2,2,0
Reservoir Management,,"Debbabi, Yacine; Stern, David; Hampson, Gary J.; Jackson, Matthew D.",Use of dimensionless scaling groups to interpret reservoir simulation results,Scaling groups; Dimensionless numbers; Reservoir heterogeneity; Flow diagnostics; Reservoir prediction,DOMINATED DELTAIC RESERVOIR; IMMISCIBLE FLOW; FLUID-FLOW; DIAGNOSTICS; GRAVITY; IMPACT,"In conducting studies to make reservoir management decisions, it is important to efficiently interpret results of reservoir simulations. An understanding of how and why predicted reservoir performance changes with model parameters guides evaluation of production strategies as well as exploration of the impact of uncertainty in reservoir description. The aim of this work is to demonstrate the use of dimensionless scaling groups to interpret and qualitatively predict simulation results of multiphase flow in subsurface reservoirs with a large number of wells. Dimensionless scaling groups which quantify the balance between the forces causing fluid flow were computed between well pairs to rationalize simulation results. The data required to partition the model according to injector-producer pairs and estimate the scaling groups were obtained within minutes using simplified, single-phase numerical experiments. We show that scaling groups can be used to classify multiphase flow behaviours observed over the field into a small set of flow regimes characterized by the combination of their dominant forces. Changes in fluid distribution and reservoir performance with the model parameters can be analyzed in terms of changes in the force balance, and qualitatively predicted using the scaling groups. Predictions made using scaling groups may guide, and thereby reduce the use of, time-consuming multiphase flow simulations to optimize field development plans, to improve the calibration of reservoir models to production data and interpreted subsurface heterogeneity, and to assess the impact of reservoir uncertainties on production.",2,2,0
Reservoir Management,,"Stephen, Karl D.",Assisted seismic history matching of the Nelson field: Managing large numbers of unknowns by divide and conquer,Assisted history matching time-lapse seismic; simulation,NEIGHBORHOOD ALGORITHM; GEOPHYSICAL INVERSION; GRADUAL DEFORMATION; PERTURBATION; UNCERTAINTY,"Automatic history matching may be used to condition reservoir simulation models with time-lapse seismic data. Stochastic optimization algorithms are used to perform a good search of the parameter space to ensure effective determination of the best models. These approaches can require many thousands of simulations for large dimensional problems. Divide and conquer is an assisted history matching approach that enables deconvolution of the parameters so that they can be searched more efficiently and also leads to better uncertainty analysis. We present an application of this approach on the Nelson field. Nine years of production history data are used along with baseline and monitor seismic surveys. Localised variations were made to permeability and net-to-gross ratio in the model. The reservoir was divided into separate parameter regions by combining experimental design and proxy model analysis. The former enabled insignificant parameters to be discarded while the latter showed that each region could be treated as a separate history matching sub-problem. Each sub-problem was then solved simultaneously using an adapted stochastic neighbourhood algorithm. The results show that a forty-two dimensional problem could be reduced to a combination of three 9D problems and a 3D problem due to the spatial deconvolution of parameters and misfits. An improved match was obtained for the production and seismic data. Compared to a full stochastic search of the parameter space, the number of required models was several orders of magnitude smaller. Improved uncertainty analysis was made possible resulting in better understanding of the future behaviour of the reservoir. An improved match to reservoir models leads to better confidence in their prediction and thus they can be used more effectively in reservoir management. The method presented here to improve the match retains the benefits of stochastic searching without the penalty of requiring an impractical number of simulations.",2,2,0
Reservoir Management,,"Lei, Lei; Xie, Shuyun; Chen, Zhijun; Carranza, Emmanuel John M.; Bao, Zhengyu; Cheng, Qiuming; Yang, Fan",Distribution patterns of petroleum indices based on multifractal and spatial PCA,Multifractal; PCA analysis; Petroleum indices; Oil resource prediction,SEDIMENT GEOCHEMICAL DATA; OIL; AREA; EXPLORATION; INTERPOLATION; SINGULARITIES; PREDICTION; ANOMALIES; DEPOSITS; TARGETS,"Currently, the challenges of oil/gas target prospecting by surface soil geochemical exploration are the covers of the prospecting regions. And the arid, sandy, undeveloped deserts of Xinjiang, China, are merely the geographic challenges facing today's oil and gas exploration and production industry. While there is too often much complex information to assimilate and understand for quick and accurate decisions leading to improved reservoir management, advanced technology, such as the development of newer algorithms and numerical methods that can be helpful in exploration to process large and/or old geochemical datasets to improve targeting of buried oil/gas geochemical systems. Herein, we investigated the possibility that geochemical concentration distribution in space may be members of a special class of complex processes, termed as multifractal, which require a large number of exponents to characterize their scaling properties. In addition, the results present that the 15 petroleum indices of study could be classified into three groups according to their multifractal spectra. The three groups of the indices are discriminated well by several multifractal parameters. Such discrimination results are in agreement well with the analytical results by statistical cluster analysis results and principal component analysis method (PCA) included in the software package of GeoDAS. Based on the PCA results, C-A (concentration-area) fractal method has been applied in this paper to delineate the geochemical anomaly areas for petroleum resources prediction. The first and second components clearly represent the potential petroleum prospecting areas which correspond well to the discovered oil/petroleum sites. Both the multifractal method and spatial analysis technique in this paper provide new insights into the selection of target indices of petroleum geochemical exploration as well as comprehensive information extraction for oil/gas target prospecting by surface soil geochemical exploration.",3,3,5
Reservoir Management,,"Dutta, Jayanta; Kumar, Ashutosh; Bhardwaj, Nitin; Gunasekaran, Karthikeyan; Mohammed, Sajid","Production induced faulting risk assessment in a depleted reservoir: A case study from deepwater Krishna-Godavari basin, India",Deepwater depleted reservoir; Risk assessment; Production induced faulting; Slip tendency; Dilation tendency; Secondary fractures re-activation,IN-SITU STRESS; FLUID-FLOW; PORE PRESSURE; REACTIVATION; FIELD,"In a producing field, the fluid conduit nature of faults could initiate due to changes in the stress state within the reservoir. It has large impacts on different aspects (seal integrity, casing shear, mud loss during drilling, reservoir permeability, and induced earthquakes) of the field performance. In order to optimize the future drilling campaign and field management strategy, production induced faulting risk assessment was performed to evaluate the fault behavior in a depleted reservoir, where the reservoir pressure has decreased by 40% from its pre-production pressure. The risk assessment was done through (i) identifying the critically stressed fracture/fault in the pre-production stage, (ii) assesses the risk of production induced new fractures/faults generation & reactivation of existing faults, and (iii) risk ranking of faults within the reservoir. The assessment model was based on the relationship between failure mode and fluid flow with change in stresses on the fault planes due to reservoir pressure depletion. The model was built through integrating different data, such as, reservoir fault mapping, core data, drilling data, production data, and geomechanical modelling. The analysis revealed that all the faults at the pre-production stage were not critically stressed and therefore, were closed. Production induced new fractures/faults are neither generated nor existing faults re-activated till the current depleted reservoir condition in the study field. Risk ranking based on the slip and dilation tendency analysis suggests that because of the depletion fault slip tendency has not increased much and risk of fault slip is on the lower side. But, the dilation tendency has increased for all the faults which makes these faults more prone to extensional/tensile failure than shear failure. Furthermore, the analysis suggests that the severe mud loss events encountered in the post-production wells were due to re-activation of existing secondary fractures at the fault intersection depths during drilling.",5,5,3
Reservoir Management,,"Hong, A. J.; Bratvold, R. B.; Thomas, P.; Hanea, R. G.",Value-of-information for model parameter updating through history matching,Decision analysis; Value-of-information analysis; Uncertainty; History matching; Production optimization; Reservoir simulation,MONTE-CARLO METHODS; OPTIMIZATION; UNCERTAINTY,"The oil and gas (O&G) industry spends billions of dollars on data (e.g., production data, seismic data and tracer data) gathering and analysis for the purpose of reducing uncertainty and improving their understanding of the most salient features of the subsurface. Yet, the O&G industry spends minimal effort and investment to assess whether the benefit of this data gathering and analysis exceeds the cost. One form of data gathering and analysis is history matching (HM), which has been an essential reservoir management tool for decades. This paper addresses the value of HM by applying the value-of-information (VOI) framework originally developed in the decision sciences. There are several challenges involved in assessing VOI in HM contexts. Although reservoir management (HM and production optimization) and decision analysis (DA) use many of the same methods, the two domains involve different terminology used in fluid flow modeling and application of state-of-the-art HM and optimization methods. Furthermore, most applications of VOI analysis have focused on static, as opposed to time-dependent, analysis. Finally, some recent publications in the O&G industry that have illustrated and discussed VOI from HM have not been consistent with the original definition of VOI. In this paper, we illustrate and discuss the use of a consistent, DA-based, VOI analysis framework to assess the VOI in HM contexts. In order to make the VOI framework understandable and accessible to both the reservoir management and DA communities, we provide a ""bridge"" between the nomenclature and terminology used in VOI calculations and that used in state-of-the-art HM and optimization methods. The paper includes four VOI analysis examples. The first illustrates the implementation of the general VOI framework for a simple HM problem. The second illustrates and discusses the difference between the calculations presented by other authors and the standard VOI definition used in the DA community. The third illustrates the implementation of VOI calculations in more realistic settings, including a sensitivity analysis of measurement noise. The fourth illustrates the application of VOI assessment in a case where a reservoir simulation model is involved.",6,6,1
Reservoir Management,,"Lamas, Luis Fernando; Botechia, Vinicius Eduardo; Correia, Manuel Gomes; Schiozer, Denis Jose; Delshad, Mojdeh",Influence of polymer properties on selection of production strategy for a heavy oil field,Polymer flooding; Production strategy selection; Reservoir numerical simulation; Reservoir engineering; Chemical enhanced oil recovery; Reservoir management,,"Polymer flooding is an enhanced oil recovery method (EOR) where water-soluble polymer is added to the injection brine. This increases brine viscosity and reduces water mobility, aiming to increase volumetric sweep and thus oil recovery. Selection and development of a production strategy for oil field is a complex task. Polymer properties bring additional complexity to this process and it is important that each of them is properly treated and considered. This paper discusses the selection of production strategy considering different approaches: (1) water flooding, (2) ideal polymer (only viscosifying effect of polymer) and (3) polymer flooding, including separately four of the most influencing polymer properties i.e. retention, viscoelasticity, salinity and degradation. The analysis is extended to a probabilistic point of view, where scenarios were generated combining geological and polymer uncertainties. Selected production strategies are compared to quantify the impact of each property on field indicators. Comparisons were made in terms of net present value (NPV), produced oil, injected and produced water, oil recovery factor and polymer mass. Two different situations were considered: (1) to optimize considering each property since beginning (design thorn control variables, meaning development, and management stages) and (2) considering design variables (development stage) for ideal polymer, optimizing only control variables (management stage) for each property. The methodology is applied to a synthetic field, based on characteristics of an offshore field with high permeability (similar to 1 000 mD) and containing heavy and viscous oil (similar to 100 cP, 14 degrees API). Ranking the properties according to overall impact on the project NPV, it was found the impact of each variable in a descending order: degradation, salinity, viscoelasticity, and retention. Water and ideal polymer strategies limit indicators results, giving an idea of the performance of strategies. Considering the key polymer properties from the beginning of optimization process resulted in similar values in terms of NPV when compared with strategies that considered ideal polymer in the selection of project variables. Risk curves show that conclusions can be extended to a probabilistic point of view. The results allow a comprehensive understanding of the influence of each polymer property on selection of production strategy considering uncertainties. The results also show that it is possible to select a good strategy using Ideal polymer model. Finally, results show that strategies selected for water and for ideal polymer model act as lower and upper limits of performance for the field, giving valuable information to the decision maker, even before accurate data about polymer is available.",6,6,2
Reservoir Management,,"Saghafi, Hamidreza; Arabloo, Milad",Development of genetic programming (GP) models for gas condensate compressibility factor determination below dew point pressure,Compressibility factor; Gas condensate; Genetic programming (GP); Sour gas,NATURAL-GAS; OIL; RESERVOIRS; BEHAVIOR; STATE,"Gas compressibility factor plays a vital role in various engineering applications related to natural gas reservoir management, planning, transportation and processing. Compared to dry gases, gas condensates are thermodynamically complex and require thorough attention. The main challenge is phase segregation and compositional change during temperature variations or pressure depletion. Therefore, this study is focused on proposing novel compositional models based on a Genetic Programming (GP) framework for the accurate calculation of the gas condensate compressibility factor below dew point pressure. The new models are developed based on 1800 gas condensate datasets obtained from open literature. Both qualitative and statistical quantitative assessments were used to compare the precision and accuracy estimation of the new models to existing literature models. Moreover, the proficiency of the proposed models for compressibility factor calculations of gas condensate samples for sweet and sour gas samples was investigated. In addition, a sensitivity analysis based on Spearman and Pearson techniques was performed to carry out the degree of influence of each input parameter on the target value. It is expected that the developed models will pave the way for the accurate calculation of compressibility factors for gas condensates, which can be used by engineers for performance monitoring, optimization and production management in gas condensate systems.",7,7,0
Reservoir Management,,"Zhao, Wei; Liu, Huiqing; Wang, Jing; Zhang, Hongling; Yao, Chuanjin; Wang, Linlin; Qi, Pengpeng",Investigation of restarting pressure gradient for preformed particle gel passing through pore-throat,Preformed particle gel; Deformation behavior; Mathematical modeling; Restarting pressure gradient,CONFORMANCE CONTROL; MICROSPHERES; DISPLACEMENT; SIMULATION,"Excess water production is prevalent in mature reservoirs, which reduces production profits. Water treatment by polymers/gels is one of the most efficient ways to solve this problem. Preformed particle gel with the size from nanometer to micrometer has been applied as an effective and commercial crosslinked polymer for conformance management. However, few quantitative mathematical models were studied, especially the unique deformation-restarting property which reflects the deformation and in-depth propagation performance of PPG. In this paper, a single pore-throat cell based on the rearranged sand spheres was chosen. Then, the restarting pressure gradient model for PPG passing through pore-throat unit was made based on elastic mechanics theory and micro-element analysis. The forces on the deformable PPG, such as driving force, frictional and extruding resistance, were considered in stress analysis. Meanwhile, a variable diameter capillary model similar to the structure of the pore-throat was constructed to validate the PPG propagation process. Sensitivity analyses indicated that elastic modulus had the most significant impact on restarting pressure. Moreover, the restarting pressure gradient was a function of PPG size, pore-throat size, elastic modulus, friction coefficient and Poisson's ratio. The experimental data have a good agreement with the mathematical results. The restarting pressure gradient increases with increasing of the diameter ratio of PPG to pore throats. This study can provide a way to evaluate the process of ""plugging-deformation-restarting"" for PPG passing through the pore-throat and a good start for future advanced models.",8,8,4
Annular Pressure,,"Zhou, T.; Kabir, C. S.; Hoadley, S. F.; Hasan, A. R.",Probing rate estimation methods for multiphase flow through surface chokes,"Models anchored in thermodynamic principles outperformed correlations; Although rate-dependent discharge coefficient may be used, a fixed value does not sacrifice much accuracy; The slip velocity appears unimportant in field settings because of dominance of annular flow; Accurate input of choke size and upstream pressure can ensure solution quality",PREDICTIONS; IMPROVEMENT; PRESSURE; MODEL,"Choke is an essential device that controls flow rates at either subsurface or surface. Many models and correlations have appeared over decades handling multiphase flow through surface chokes. But, direct comparison of their relative performance has been a few, if any. This study evaluates several models and correlations to explore their relative performances. As expected, models anchored in thermodynamic principles outperformed others. Improvements in modeling followed the initial findings. We studied several models to explore their relative merits and ease of use in field settings. Seven different data sets gathered from laboratory and field settings, involving about 1000 independent data points, constituted the essence of this study. The study found the importance of PVT data in any flow through choke calculations. Specifically, we found that changes in density and heat capacity of fluids with pressure and temperature should be part of any rigorous effort for computation of flow rates. To ensure reliability and consistency in solutions, a model based on thermodynamic considerations deserve preference for generalized applications because it can handle pressure and temperature-dependent fluid properties. In this context, the recognition of choke-discharge coefficient's dependence on flow rate and Reynolds number constitutes an important element in ensuring the reliable outcome of results.",2,3,0
Annular Pressure,,"Kesana, Netaji R.; Ibarra, Roberto; Langsholt, Morten; Skartlien, Roar; Skjaeraasen, Olaf; Tutkun, Murat",Measurements of local droplet velocities in horizontal gas-liquid pipe flow with low liquid loading,Low liquid loading; LDA; Isokinetic sampling; Atomization; Velocity profiles,ANNULAR 2-PHASE FLOW; ENTRAINMENT; OIL,"New data on streamwise droplet velocity profiles for low liquid loading pipe flows are reported. The fluids used in the experiments are SF6 (gas-phase) and Exxsol D60 (oil-phase). Experiments are conducted in a 10 cm pipe diameter high-pressure (similar to 780 kPa, absolute) flow loop to reproduce gas-condensate field conditions. Instantaneous streamwise velocity data, obtained using the non-intrusive Laser Doppler Anemometry (LDA) technique, are used to calculate mean and root-mean-squared (RMS) local velocities. Asymmetric droplet velocity profiles with respect to the pipe center-line are observed especially for the stratified low atomization flow conditions. However, as the flow momentum increases, the droplet velocity profiles seem to become more symmetric. Also, these data suggest that, irrespective of the conditions studied, the single-phase gas flow characteristics are preserved closer to the top pipe wall. The data from the LDA imply that the bottom pipe half region is highly influenced by the gas-liquid interfacial characteristics. This results in high streamwise turbulence intensity in the region influenced by the interfacial waves (interfacial turbulence). An isokinetic sampling instrument is also used to measure the local instantaneous dynamic pressure. The dynamic pressure and the locally extracted liquid (droplets) volume rate under isokinetic conditions are used to calculate local fluid velocity. Excellent agreement has been obtained when comparing this calculated local velocity from the isokinetic instrument to the LDA data.",3,3,2
Annular Pressure,,"Movahedi, Hamed; Shad, Saeed; Mokhtari-Hosseini, Zahra B.",Modeling and simulation of barite deposition in an annulus space of a well using CFD,Barite settling; Eulerian-eulerian model; Single particle model; CFD simulation,SPHERICAL-PARTICLES; DEM SIMULATION; FLOW; FLUIDS; FIBER,"In drilling industry, barite particles settling and barite sag as a major problem can potentially impose significant operational issues. Static conditions, in which well undergoes an extended shut-in period, could occur during different drilling and completion operations such fishing operation, tripping, and logging. Despite its importance, such phenomenon is not well understood yet. To avoid issues related to barite settlement and barite sag, a good understanding of the impact of different drilling parameters on barite settlement and sag phenomenon is required. Recently, the mathematical formulation and modeling of settlement and sag processes have gained more attention. In order to better design the drilling fluids and to optimize the operational conditions such as flow rate and drill pipe rotation speed, as well as drilling well trajectory design to avoid barite settlement, the mathematical formulation and modeling of such physical phenomena is required. This study is aimed at mathematically describing and analyzing the settling of barite particles in annular concentric space without axial flow by the means of computational fluid dynamic (CFD) simulation. The modeling approach consists of two main steps: a) simple vertical annular domain and b) complex three dimensional barite settlement process in a deviated well with rotational drill pipe. The current work is based on Eulerian two phase model. The settling of the single particle and the hindering effect of other particles on settling velocity have been investigated. Based on single particle model, the rate of barite settlement and fluid pressure reduction have been modeled. However, the single particle model cannot describe the particle to particle interactions and their impacts on settlement such as particle shearing viscosity, kinetic particle viscosity, and collisional effects. In this study, the accurate and comprehensive modeling of barite settlement has been done by applying the Eulerian-Eulerian approach. The models have been validated against available published experimental data in the literature. In addition, in order to further validate the model presented here, drill pipe rotation, fluid rheology, and inclination angle impacts have been experimental investigation and compared with results of the proposed model. The results indicate that the model based on using Eulerian-Eulerian approach accurately predicts the experimental data results. Afterward, the sensitivity analyses were carried out to show the impact of inclination angle, inner pipe rotation, fluid rheology, and barite content on the rate of settlement. This study showed that drag forces induced resuspension plays a vital role in barite settlement inside a deviated well. The results reveal that the settling rate is decreased with increasing the inner pipe rotation and the vortex effect created by inner pipe rotational, play a major role in the reduction of barite settlement. The results also show that the maximum settlement rate accrues at the deviation angles between of 45-60 degrees.",5,5,0
Annular Pressure,,"Hu, Zhiqiang; Yang, Jin; Li, Wenlong; Li, Shuzhan; Feng, Pengtian; Xin, Yanyu",Research and development of compressible foam for pressure management in casing annulus of deepwater wells,Annular pressure; Compressible foam; Multi-casing annuli; Hydrostatic compression; Mitigation effect; Optimization design,PREDICTION MODEL; GAS-WELLS; BUILDUP; BEHAVIOR; DESIGN; OIL,"Casing annulus pressure build-up owing to fluid thermal expansion in sealed annuli severely threaten the casing safety and wellbore integrity of deepwater wells. To mitigate the annular pressure with stronger effect and lower cost, a new type of syntactic foam with high compression ratio, which consists of hollow glass microspheres and a resin matrix system, was developed in this study. It can provide extra space for the annular fluid to expand when the annular pressure exceeds the specific foam crush pressure, allowing the foam to collapse and consequently, mitigate the annular pressure. The foam compression behavior is divided into three stages according to a hydrostatic compression test, and the annular pressure is mainly influenced by the microspheres volume and temperature. To optimize the parameters of the compressible foam, a novel model considering fluid thermal expansion, casing elastic deformation, and foam compression behavior in multi-annuli is established. The results indicate that the compressible foam can reduce the trapped annular pressure effectively and permanently. In a case study well, the annular pressure no longer exceeds the maximum acceptable annular pressure in each annulus with optimized design of the foam wraps and a suitable number of installed foam casing joints.",5,9,1
Annular Pressure,,"Tang, Ming; Yuan, Lanfeng; He, Shiming; Fu, Tao",Simplified modeling of YPL fluid flow through a concentric elliptical annular pipe,YPL fluids; Elliptical wellbore; Laminar flow; Pressure gradient; Simplified model,TURBULENT-FLOW; LAMINAR; DUCTS,"Accurate prediction of the pressure gradient is the prerequisite for precise control of downhole pressure; such control can effectively avoid the complicated underground situations caused by improper downhole pressure control, such as well leakage, overflow and wall instability. The existing model of the annular pressure gradient in drilling process only considers a perfectly cylindrical wellbore; however, the real drilling hole easily becomes an elliptical wellbore under non-uniform in situ stress, leading to the relatively large error of the conventional model. Based on the theories of fluid mechanics, the analytical and simplified models of steady-state laminar flow in the concentric elliptical annular (elliptical wellbore) pipe are established. The analytical model is validated by the computational fluid dynamics (CFD) simulations of Fluent software. In addition, the simplified model was validated by analytical solutions. The primary conclusions are as follows. (1) When the flow rate is constant, the axial average and maximum velocities increases linearly and exponentially, respectively, with the increase of epsilon. The velocity profile of the analytical model is in good agreement with the velocity profile of the CFD simulations. (2) The CFD simulations are in perfect agreement with the analytical results, and the error of the pressure gradient is within +/- 10% error bands for pressure gradient. (3) The simplified model predictions are in good agreement with the analytical model results, and the error of most of the results is within +/- 5% bars. The model is convenient for use in predicting the pressure gradient accurately for yield power law (YPL) fluid flowing in an elliptical wellhole.",5,5,2
Annular Pressure,,"Kan, Changbin; Yang, Jin; Yu, Xiaocong; Wang, Yanbin",A novel mitigation on deepwater annular pressure buildup: Unidirectional control strategy,Deepwater completion; Trapped pressure; Numerical simulation; Experimental studies; Casing tools,WELLS,"When completing deepwater wells, a significant portion of the completion fluid is often trapped in the casing annuli because of widespread use of multi-layer casing technology. When transferred into testing or production, the temperature field in the immediate vicinity of the wellbore is redistributed by any present thermally conductive fluids. Raising trapped completion fluid to a high temperature can trigger high thermal stress, and this stress has been proven to present a grave threat to the safety of deepwater wells. In this paper, a thermal conductivity model of fluid-filled annuli based on a typical well structure used in the South China Sea is established to determine the effect of different production parameters during the well production or testing process on pressure behavior. A numerical simulation of the effects of fluid trapped in the casing annuli on temperature distribution was conducted. Based on this simulation, a novel method for mitigating the pressure of the trapped fluid by a way of a unidirectional control strategy was studied, and a unidirectional pressure control casing nipple tool was developed. Laboratory simulations were then conducted using a prototype tool to determine the technical feasibility of the unidirectional control strategy. The change in trapped fluid pressure with time was obtained for different release pressures and tool valve orifice diameters, showing the effects of different valve orifice diameters and volumetric injection rates on the pressure release performance. Experimental results demonstrate that the pressure envelope decreases quadratically with the increase in the pressure grade, while the valve working duration decreases linearly with the increase in valve orifice diameter. The increase in the volumetric injection rate was found to have little effect on the cumulative volume displacement. The proposed unidirectional pressure control strategy for controlling the accumulation of pressure in the annuli of deepwater wellbore casings can effectively eliminate the fatal dangers presented by thermal stress. It can also reduce the risk of casing deformation due to thermal stress within trapped annuli and reduce occurrences of wellhead sealing damage.",6,6,1
Annular Pressure,,"Sui, D.; Horpestad, T.; Wiktorski, E.",Comprehensive modeling for temperature distributions of production and geothermal wells,Temperature model; Production wells; Heat transfer,HEAT-TRANSFER; WELLBORE; SYSTEMS; FLOW; PRESSURE,"When producing hot fluids from a reservoir, production wells experience temperature changes with depth for different tubing, casings, cements and wellbore interfaces. The changes of the fluids' temperature depend on many factors. Production flow rate, specific heat capacity (SHC) of produced fluids, thermal conductivity (TC) and viscosity of annular fluids, Joule-Thomson effect on produced fluids, radius of wellbores, annular clearance, inclinations and production time are some of the parameters playing an important role in the heat transfer across the wellbore between produced fluids and formations. Modern downhole production tools are equipped with a temperature sensor to monitor the temperature variation with production time. It is important, however, to be able to predict how the temperature will be changing during the various production phases depending on the production rate and other operational parameters. This information is also valuable in downhole pressure estimation, as the viscosity of the produced fluid varies with temperature. A robust temperature estimation technique is therefore required to be able to estimate the temperature distribution along the well. A comprehensive wellbore heat transfer model for oil production wells has been developed in this study. The model considers a fairly complex wellbore configuration consisting of five wellbore sections with multiple annulus (annulus A, B and C), with the possibility of natural/free heat convection taking place in three brine filled annulus. Correlations taking temperature and pressure into consideration have been implemented for all thermophysical properties, such as TC of tubing, casings, and cements, SHC, viscosity and TC of annular/produced fluids, and densities of produced and annular fluids to mention some. The program allows for custom well configuration and is able to calculate the temperature at the interfaces between the wellbore, casings and tubing. It also allows to use properties of the fluids, casing/tubing, cement and formation other than those used in the simulations presented in this paper. Extensive knowledge of the effect of the essential parameters on the heat transfer is of great importance for the performance of production wells. Sensitivity analysis has been performed to demonstrate the importance of properties of produced/annulus fluids, wellbore architecture and operational parameters in oil production. Our work is a good tool to analyze the thermal performance of wellbores, fluids and so on with a lot of potentials for different applications, like annulus pressure build up, well plan and casing/fluid design for production/geothermal wells.",7,8,1
Real Time,,"Abreu, Ana Carolina A.; Booth, Richard; Prange, Michael; Bailey, William J.; Bertolini, Andre; Teixeira, Guilherme; Romeu, Regis K.; Emerick, Alexandre A.; Pacheco, Marco Aurelio C.; Wilkinson, David",A decision support approach to value flexibility considering uncertainty and future information,Optimization; Smart well; Control; Flexibility; Uncertainty; Information,DYNAMIC OPTIMIZATION,"Flexible strategies have become increasingly important for making strategic decisions under uncertainty conditions, once to consider flexibility in projects to engender the option of making return-maximizing decisions, since uncertainty can be resolved over a project's lifetime. The activities related to reservoir development are inherently associated with decisions making under uncertainty conditions and flexible solutions are very advantageous, allowing the option of making return-maximizing decisions, the uncertainty is resolved over a project's lifetime. One of the technologies that fit in this context are the smart wells, since this technology has the ability to acquire relevant requested information for future decision-making, enabling the generation of a development strategy with future flexibility. However, to value its flexibility if we do not account for uncertainty when performing an optimization, the resulting strategy will have two key shortcomings: it will assign too high value to the smart wells, and it will not take advantage of the ability of the smart wells to adapt and mitigate to uncertainty. We propose a strategy that allows the valuation of flexibility under uncertainty, seeking the flow control strategy that maximizes the expected net present value, dynamically reacting to new information as it is acquired. We demonstrate the proposed approach using a tank drainage problem for which we can evaluate optimization solutions for a broad range of scenarios, including model uncertainty and the flexibility to accommodate future measurements, with a reduced time of evaluation. Then we applied this proposed approach on a reservoir model that highlights its novel aspects: asset optimization under uncertainty, flexible control based on future information, and quantification of the value of flexibility and future measurements. In addition to valuing flexibility and future information, which contributes to the selection of appropriate smart-well technology and measurements, the proposed approach delivers a decision tree that describes a flexible strategy of optimum valve settings that properly accounts for future measurements and their impact on uncertainty reduction. This approach gives a qualitative value, indicating whether the field has the potential of significant improvement using smart wells, and a quantitative valuation of the benefits of smart completions resulting in a realizable strategy to guide the control of these completions in a real field management project.",2,2,0
Real Time,,"Pedersen, Tom",Properly designed temperature history nanoparticles may improve residual oil saturation estimates from SWCT tests,Residual oil saturation; Single well chemical tracer test; Temperature history; Intelligent nanoparticles; Fluorescence,SILICA NANOPARTICLES; TRANSPORT,"Considerable resources are required to develop new nanoparticles for various applications. Before too much effort is put into the development of nanoparticles that might not work properly, it may be wise to spend more resources on studies of how they should de designed to be really useful for solving an identified problem. In particular, we believe that it is a good idea to demonstrate the usefulness of as yet hypothetical nanoparticles by performing computer simulations of the system at hand with them. To exemplify this idea, we use the so-called Single Well Chemical Tracer (SWCT) test, the purpose of which is to estimate the residual oil saturation (S-or) in the vicinity of a wellbore. In the majority of reported SWCT tests, ethyl acetate is pushed into the oil bearing formation from a well and partly converted to ethanol by hydrolysis. The chromatographic separation between the ethyl acetate and ethanol during back production is then used to estimate S-or. The hydrolysis rate of ethyl acetate depends exponentially on temperature, and if a temperature gradient develops across the ethyl acetate bank, this has to be accounted for if a correct S-or estimate shall be obtained. Nanoparticles that are co-injected with the ethyl acetate and that have a 'memory' of the temperature history they have experienced may prove useful in this respect. We suggest several design criteria for such nanoparticles. The envisioned nanoparticles encapsulate a dye that degrades when heated as well as an internal standard that does not degrade. This property facilitates easy calibration of the fluorescence signal. We propose a simple rule for deriving degradation rates suitable for the temperatures and times typical for a SWCT test. The nanoparticles move with the ethyl acetate so that their temperature history is representative for its hydrolysis. It is important that it is easy and uncostly to analyze the temperature history nanoparticles. They have to satisfy modern health, safety and the environment (HSE) requirements, and have acceptable production and deployment costs. An axis-symmetrical numerical model is used to demonstrate the usefulness of such designed nanoparticles based on data from a published SWCT test. First, we calculate the temperature history of the nanoparticles using a suite of injection temperatures. The pre-exponential factor and activation energy of the dye derived from the design criteria are then used to simulate the degradation in nanoparticle fluorescence with time for the various nanoparticle temperature histories. From these data, we calculate the aggregate average and standard deviation of the nanoparticles' fluorescence in the produced fluid, i.e., information that would be available if the nanoparticles had been used in a real SWCT test. We find that such data provide useful constraints on the temperature history and thus helps us pin-point the correct S-or value. The temperature history sensitive nanoparticles may potentially also yield valuable information on the effective thickness and other characteristics of the target formation, the surrounding rock and perhaps even on the wellbore and its thermal interaction with the reservoir rocks.",3,3,0
Real Time,,"Fan, Jingjing; Sappington, Emily N.; Rifai, Hanadi S.; Rodrigues, Debora F.",Confocal microscopy as a new real-time quantification method for oil content in produced water,"Confocal laser fluorescence microscopy; EPA 1664 method; Produced water, oil, and grease",FLUORESCENCE SPECTROSCOPY; WASTE-WATER; CRUDE OILS; HYDROCARBONS; COALESCENCE; EMULSIONS; DROPLETS; GREASE,"This research proposes confocal laser fluorescence microscopy (CLFM) as an enabling technology to quantify oil prior to produced water disposal. This method takes advantage of the self-fluorescing properties of oil to visualize and quantify in 3D oil droplets in water in real-time. This investigation initially involves the identification and optimization of parameters affecting CLFM oil measurements in synthetically prepared produced water, followed by validation of the optimum CLFM parameters for oil quantification in real produced water. This study demonstrated that the optimized excitation wavelength, z-step size, image analysis threshold value, and minimum sampling size parameters for the CLFM method are suitable for different types of oil. The optimum amount of time for analysis, however, changed for oils with different densities due to different oil upward movement velocities. The detection range of the CLFM was determined to be between 1 and 250 ppm. The quantification of oil content in three different produced water samples were also investigated with the CLFM method and results were compared with the standard EPA 1664 method. The results for both methods correlated well, which suggests that the CLFM has potential to be used as an initial real-time screening of the oil quantities of treated produced water prior to environmental releases in water streams. This technique has several advantages over other methods, such as does not require hazardous solvents for oil extraction, is less labor intensive, and can be automated for real-time online applications, such as subsea systems.",3,3,1
Real Time,,"Djuraev, Ulugbek; Jufar, Shiferaw Regassa; Mahardika, Harry; Ooi, Phey Chee",Numerical simulation of seismoelectric effect for monitoring foam propagation through a reservoir,Seismoelectric effect; Foam propagation; Reservoir monitoring,POROUS-MEDIA; FIELD-MEASUREMENTS; JOINT INVERSION; ELASTIC WAVES; CONVERSIONS; EXPLORATION; EQUATIONS,"The seismoelectric phenomenon describes generation of electromagnetic fields when seismic wave passes through fluid saturated porous media. Discovered in the 1930s, the seismoelectric effect have gained attention only in the last few decades as a tool of great potential in geophysical applications. Despite some usage in mineral exploration and ground water flow, routine field applications of this phenomenon are still under development. Nevertheless, recent advancements show great potential of the seismoelectric method in the oil and gas industry. It is now known that several rock and fluid properties affect the seismoelectric response, hence application of this response may be used for reservoir characterization, subsurface imaging and mapping, and monitoring fluid propagation through a reservoir. In this paper, we numerically studied the prospect of monitoring foam propagation through a reservoir using the seismoelectric phenomenon. The reservoir model used in the study was developed using real field data. The virtual pilot area comprised of a cross-well domain between injector well and producer well, where pre-generated foam was continuously injected into the reservoir for the period of 150 days. The seismoelectric data acquisition was modeled in the domain, where the seismic source was deployed in the injection well, and the receiving stations were installed in production well accordingly. The results of the seismoelectric surveys, with interval of 30 days, produced both seismic and seismoelectric signals received by the stations. The processed data, coupled with the average seismic velocity and arrival times of the seismoelectric conversions, were analyzed with regard to determining the locations of the displacing foam front. Subsequent comparison and analysis showed high accuracy match and consistency between the true front positions obtained from the reservoir simulator and the determined locations produced using the seismoelectric method. Additionally, to demonstrate how the seismoelectric signals can be processed in field trials, we applied noise to the same synthetic data used to estimate the foam front positions. We observed that the occurrence of the seismoelectric signal was imperceptible due to the prevailing noise. Subsequently, we applied a filtering method to reduce the effect of the noise that showed great results in uncovering the presence of the seismoelectric conversion in the electrogram while preserving amplitudes and time arrivals of the seismoelectric, seismic and co-seismic signals. According to the obtained findings, we can state that later computations of locating the foam front would yield results with the same accuracy as the noise-free synthetic signals.",4,4,1
Real Time,,"Kullawan, K.; Bratvold, R. B.; Bickel, J. E.",Sequential geosteering decisions for optimization of real-time well placement,Geosteering; Geosteering decision; Sequential decision; Dynamic programming; Well placement decision; Value of information,,"Achieving an optimal placement of a well in thinly layered, faulted, and uncertain reservoir formations is a challenging operational decision making problem requiring optimization in real time (""geosteering""). This paper develops a discretized stochastic dynamic programming (DSDP) approach for sequential decisions in geosteering operations. This method is found to improve the resulting wellbore trajectories and to increase the overall value of the well by up to 31%.",6,6,0
Real Time,,"Vega, Marcia Peixoto; de Moraes Oliveira, Gabrielle Fontella; Fernandes, Lindoval Domiciano; Martins, Andre Leibsohn",Monitoring and control strategies to manage pressure fluctuations during oil well drilling,Kick; Circulation loss; Downhole pressure control; Decision making; Gain scheduling,LOST CIRCULATION; KICK DETECTION; MODEL; FLUID; DEEP; MUD; MITIGATION; PREDICTION; RESERVOIR; SYSTEM,"During drilling the mud flows through the drill string and exits through the choke valve. The mud density range has as constraints: pore pressure (minimum limit) and fracture pressure (maximum limit). In fact, annulus bottomhole (downhole) pressure needs to be higher than pore pressure, in order to prevent kick, and smaller than fracture pressure, for avoiding mud loss and formation damage. Experimental and simulation studies were implemented in order build a monitoring - diagnosing tool working together with a decision making routine based on an adaptive control scheme that employs gain scheduling. An experimental unit was built, presenting the most important characteristics of the drilling process. The transient nature of annulus bottomhole pressure is due to the process inherent disturbances: rheology, rate of penetration (ROP), kick and mud loss, which were all implemented at the experimental unit. The major objective of the present paper is using the experimental plant and a phenomenological model for implementing real time process automation, in order to assure drilling inside operational window, using in line measurements for flow and density disturbances under circulation loss and kick scenarios.",8,8,1
Tarim Basin,,"Gao, Xiaoqiao; Ma, Yongsheng; Jiang, Qicai; Shi, Kaibo; Li, Yang; Shen, Yingchu",Wave processes in relation to the tectono-sedimentary of the Tarim basin: A new method for basin study,Geological rhythm; Wavelet transform; Wave analysis; Tectonic-sedimentation evolution; Tarim basin,NW CHINA; SEQUENCE STRATIGRAPHY; NORTHWEST CHINA; HIGH-FREQUENCY; WESTERN CHINA; SEDIMENTARY; CYCLES; HYDROCARBON; RESERVOIRS; EVOLUTION,"This study gives insights into the tectonic and sedimentary evolution of the Tarim basin, the largest petroleum-bearing basin in Western China, by analyzing sedimentary wave process using multi-scale decomposition of the wavelet transform method, and the mathematical defects of sliding-window method in the process of sedimentary wave analysis was discussed. The filtering analysis, in the time domain, was carried out on cores collected from 14 wells in the Tarim basin. The results show that the evolution of the Tarim basin was controlled by various wave processes. The periods of 212 +/- Ma, 102 +/- Ma and 33 +/- Ma indicated a strong sedimentary rhythm, which displayed a spatial and temporal evolution of wave characteristics. The 33 +/- Ma period represented a third-order sequence of the stratigraphic division, which identified with the unconformities of the Tarim basin; 102 +/- Ma period corresponded to an important period of sedimentation and the plate collision around the Tarim basin, which marked a second-order period of the basin evolution. The centers of subsidence showed periodic shifts since the Cambrian, and the time for periodic migration (completing a circle) of the depocenters or the centers of subsidence is traced as 212 +/- Ma, which corresponded to the first-order period of the basin evolution. The coupling relationships between the wave processes and the evolution and distribution of source, reservoir and cap rocks in the basin were given by three kinds of patterns, which were important in predicting the space-time distribution of source, reservoir and cap rocks. This study gives a new insight on predicting the formation and distribution of petroleum, which could be used for selecting petroleum exploration targets effectively.",1,1,0
Tarim Basin,,"Zhao, Jun; Li, Wei; Xiao, Chengwen; Qi, Xinzhong; Yuan, Songshan",Numerical simulation and correction of electrical resistivity logging for different formation dip angles,Resistivity logging; Formation dip; Formation anisotropy; Resistivity correction method; Finite-element method,,"Resistivity is an important parameter used to identify the properties of reservoir fluids. In an inclined stratum, the relative position of the wellbore trajectory and changes in the formation alter the response mechanism of normal well logging tools, and the response of well logging tools is different from that in an inclined well. In order to determine the true resistivity of the reservoirs, it is necessary to correct for the inclination of the formation. Firstly, the finite-element method was used to simulate the distribution of the electromagnetic field at the induction logging coils in the formation. Secondly, the induction logging resistivity at different inclination angles was determined by combining the total magnetic field strengths at the receiving coils, and a forward model of the resistivity was then established. Finally, the true resistivity of the formation was simulated by particle swarm optimization. The results showed that the resistivity increases as the dip angle increased. In this study, we used fitted forward and inversion models and the particle swarm optimization algorithm to correct the apparent resistivity of wells A and B in the Dabei Block in the Tarim Basin and thereby determine the resistivity of the formation. The effectiveness of the dip correction of the resistivity was confirmed by data from oil testing.",2,2,0
Tarim Basin,,"Wu, Jun; Fan, Tailiang; Gao, Zhiqian; Yin, Xinxin; Fan, Xue; Li, Chenchen; Yu, Wenyi; Li, Chen; Zhang, Chenjia; Zhang, Jinhuang; Sun, Xining","A conceptual model to investigate the impact of diagenesis and residual bitumen on the characteristics of Ordovician carbonate cap rock from Tarim Basin, China",Carbonate cap rock; Diagenesis; Carbonate cements; Stylolites; Residual bitumen,OOLITHE-BLANCHE-FORMATION; TAHE OIL-FIELD; HYDROCARBON ACCUMULATION; RESERVOIR QUALITY; PETROPHYSICAL PROPERTIES; FEIXIANGUAN FORMATION; POROSITY DEVELOPMENT; SMACKOVER FORMATION; MAESTRAT BASIN; CENTRAL UPLIFT,"The Lower-Middle Ordovician Yingshan (O1-2 y) Formation associated with large unconformity weathering crust was the main hydrocarbon reservoir in the Tarim Basin, and the dense limestone/dolomite within this formation was revealed as the local carbonate cap rock. Based on petrophysical properties, thin sections, cathodeluminescence (CL) and scanning electron microscope (SEM) measurements, the effects of cap rock on depositional settings, diagenesis and pyrobitumen were carefully analyzed. Carbonate cap rock dominated by micrite has ultralow porosity and permeability, with an average porosity of 0.568% and permeability of 0.07 x 10(-3) mu m There is a significant bottom-up thickness variation (from several to tens of meters) in different members within the O1-2 y formation. The steady cap rock is more likely to be distributed in low-energy depositional environments, corresponding to intershoal sea, low-lying land of open platform and lagoon of restricted platform. Constructive diagenesis processes mainly comprise extreme filling, compaction and cementation, resulting in a significant decrease in the quantity and size of pores. Conversely, leaching and paleokarst dissolution, together with diagenesis associated with hydrothermal fluids, has a detrimental effect on the effective preservation of cap rock. Three types were summarized to characterize the cementation-compaction relationship between cement distribution and intraclast deformation. The increase in intraclast size indicate that the intergranular pores are likely to be cemented. A good sealing impact on the underlying oil-gas is confirmed in sparry calcarenite when its cement content reaches 15% and higher by volume. Early compaction vs. early cementation processes probably affect the sealing capacity, so high quality cap rock is primarily presented while cementation precedes compaction. Highly abundant stylolites filled with residual bitumen and precipitated cements in the cap rock intervals consistently have low poroperm values, resulting in micropore occlusion and occlusion of the late hydrocarbon migration pathways, which can act as barriers for the upward migration of oil-gas. A conceptual model of the evolution feature of cap rock provides a plausible interpretation for better understanding of the spatial distribution of carbonate cap rock in future exploration and development",5,5,3
Tarim Basin,,"Kong, Ting; Zhang, Min",Effects of depositional environment on rearranged hopanes in lacustrine and coal measure rocks,Rearranged hopanes; Depositional environment; Lacustrine source rocks; Coal measure rocks,HYDROCARBON SOURCE ROCKS; LISHU FAULT DEPRESSION; SOUTH CHINA SEA; SONGLIAO BASIN; CRUDE OILS; NE CHINA; GEOCHEMICAL CHARACTERISTICS; CLAY-MINERALS; PETROLEUM; TRITERPANES,"On the basis of GC-MS analysis, a suite of 97 lacustrine and coal measure rocks from the Songliao Basin, Ordos Basin and Tarim Basin were found to contain abundant rearranged hopanes. Except for peak ratios, the absolute concentrations of rearranged hopanes were determined based on addition of an internal standard (5 alpha-androstane) normalized to bitumen ""A"", which in lacustrine source rocks are far more than those in coal measure rocks. To examine the effects of depositional environment on relative abundance and absolute concentration of rearranged hopanes, the clay content, redox condition and water salinity of sedimentary rocks from two sample sets were analyzed. The results reveal that the acidic clay acted as clay-mediated acidic catalysis in the formation and degradation of rearranged hopanes, but there is no positive correlation between clay content and rearranged hopanes in lacustrine source rocks. In contrast, the absolute concentrations of rearranged hopanes in coal measure rocks, show a general increase with clay content. Some molecular parameters, such as pristane/phytane (Pr/Ph), C-35 homohopane index and gammacerane index, were found to change as a function of depositional environment. With increasing Pr/Ph, C-35 homohopane index and gammacerane index, the ratios of C-30 diahopane/C-30 hopane and C29Ts/C-29 hopane display an initial increase and subsequent decrease trend. The absolute concentrations of C-30 diahopane and C29Ts in lacustrine source rocks also increase at first, followed by a decrease at the largest value. Whereas the absolute concentrations of rearranged hopanes in coal measure rocks show an apparent positive correlation with some depositional environmental parameters. On the whole, abundant rearranged hopanes in lacustrine source rocks appear to be distributed in suboxic-weak reduction and fresh-brackish condition, while abundant rearranged hopanes in coal measure rocks appear to be present in oxic and fresh condition.",5,5,4
Tarim Basin,,"Fang, Huijing; Xu, Huaimin; Wang, Zhenbiao; Jiang, Tongwen; Zhao, Yuyun; Li, Junjian","Formation mechanism of the Donghe Sandstone residual oil zone in the Tarim Basin, NW China",Residual oil zone; Structural adjustment; Microscopic occurrence state; Tarim basin,WATER-WET SANDSTONE; FIELD; SATURATION; RESERVOIRS; MORPHOLOGY; CONTACTS; STORAGE; MATS,"The residual oil zone (ROZ) with near-residual oil saturation is a naturally water-flooded interval adjacent to an oil-bearing reservoir. It has become a promising development target for the technical progress of enhanced oil recovery. The hydrocarbon show, bitumen distribution and grains containing oil inclusions all indicate the presence of ROZs in the Donghe Sandstone Member of the Tazhong4 and Hade Oilfields in the Tarim Basin. Analysis of the two ROZ examples reveals that a stable paleoreservoir and structural adjustment are significant elements of the ROZ-forming process. The ROZ of the Tazhong4 Oilfield is defined as a reactivated fault ROZ (RFROZ) lying between the paleo oil-water contact (OWC) and producing-OWC. Paleo-hydrocarbons leaked through the reactivated faults, and the current oil saturation has a positive proportion to baffle frequency. The ROZ in the paleo trap northwest of the current reservoir in the Hade Oilfield is defined as a migratory trap ROZ (MTROZ). Paleo-hydrocarbons migrated through connected sand bodies. The current oil saturation in the MTROZ has a positive proportion to baffle frequency and negative proportion to petrophysical properties. The microscopic occurrence state of the residual oil in ROZs was analyzed with direct computed tomography (CT) scanning. The displacement experiments coupled with CT scanning aimed to reveal the different occurrence states of the residual oil in the major stage of natural water flooding in the ROZ-forming process. In the microscopic view, the formation of both RFROZ and MTROZ is a process of clustered flow converting to discontinuous flow, and the clustered flow can be scattered to a larger extent in a high permeability zone. The ROZ development feasibility was preliminarily researched. Low-salinity water flooding after the displacement of the formation water in the etching model provided experimental corroboration for remobilizing the residual oil.",8,8,0
Geochemical Data,,"Dominato, Karlynne R.; Rostron, Benjamin J.; Hendry, M. Jim; Schmeling, Erin E.; Sandau, Courtney D.; Mundle, Scott O. C.","Developing deep high-resolution concentration and C-13 isotope profiles for methane, ethane, and propane",Methane; Isotopes; Drilling; Profile; Gas migration; Reservoir,DISSOLVED METHANE; SEDIMENTARY BASIN; WATER; SASKATCHEWAN; CARBON; PROJECT; STORAGE; GASES; SHALE; FIELD,"Methods to collect and analyze concentration-depth profiles of dissolved methane (C-1), ethane (C-2), and propane (C-3) and their delta C-13-values from directional drilling operations were evaluated. The delta C-13 values of C-1-C-3 gases from drill cuttings were consistent; however, deeper zones (> 1200m BG) were subject to greater variability. The variability for C-1-C-3 isotope values was attributed to the drilling process, where the samples reflected mixing between different geologic zones. Gases and rock fragments from several formations likely contaminated the samples collected from the underlying intervals. The effects of mixing were observed in deeper zones in the borehole below the 'kick off' point for the directional drilling process. The greatest impact was observed for C-1 and C-2 gases, which was attributed to greater concentrations of these gases in shallow gas-bearing zones. This study demonstrates that mud gas and drill cuttings can generate high-resolution concentration and isotope depth profiles for C-1, C-2, and C-3 gases. However, mixing between zones along the borehole during drilling, an effect that can be exacerbated by directional drilling techniques, can impact the precision and accuracy of the geochemical profiles. The variability in the geochemical data generated from drilling programs can have a significant impact on the effectiveness of these profiles for reservoir characterization, exploration, and in identifying the source(s) of fugitive gases migrating to surface.",1,1,1
Geochemical Data,,"Lei, Lei; Xie, Shuyun; Chen, Zhijun; Carranza, Emmanuel John M.; Bao, Zhengyu; Cheng, Qiuming; Yang, Fan",Distribution patterns of petroleum indices based on multifractal and spatial PCA,Multifractal; PCA analysis; Petroleum indices; Oil resource prediction,SEDIMENT GEOCHEMICAL DATA; OIL; AREA; EXPLORATION; INTERPOLATION; SINGULARITIES; PREDICTION; ANOMALIES; DEPOSITS; TARGETS,"Currently, the challenges of oil/gas target prospecting by surface soil geochemical exploration are the covers of the prospecting regions. And the arid, sandy, undeveloped deserts of Xinjiang, China, are merely the geographic challenges facing today's oil and gas exploration and production industry. While there is too often much complex information to assimilate and understand for quick and accurate decisions leading to improved reservoir management, advanced technology, such as the development of newer algorithms and numerical methods that can be helpful in exploration to process large and/or old geochemical datasets to improve targeting of buried oil/gas geochemical systems. Herein, we investigated the possibility that geochemical concentration distribution in space may be members of a special class of complex processes, termed as multifractal, which require a large number of exponents to characterize their scaling properties. In addition, the results present that the 15 petroleum indices of study could be classified into three groups according to their multifractal spectra. The three groups of the indices are discriminated well by several multifractal parameters. Such discrimination results are in agreement well with the analytical results by statistical cluster analysis results and principal component analysis method (PCA) included in the software package of GeoDAS. Based on the PCA results, C-A (concentration-area) fractal method has been applied in this paper to delineate the geochemical anomaly areas for petroleum resources prediction. The first and second components clearly represent the potential petroleum prospecting areas which correspond well to the discovered oil/petroleum sites. Both the multifractal method and spatial analysis technique in this paper provide new insights into the selection of target indices of petroleum geochemical exploration as well as comprehensive information extraction for oil/gas target prospecting by surface soil geochemical exploration.",3,3,5
Geochemical Data,,"Ekpo, B. O.; Essien, N.; Neji, P. A.; Etsenake, R. O.",Geochemical fingerprinting of western offshore Niger Delta oils,Oil fingerprinting; Organic geochemistry; Niger Delta; Nigeria,CRUDE OILS; PETROLEUM GEOCHEMISTRY; GAS-CHROMATOGRAPHY; SOURCE ROCKS; PART II; BASIN; FIELD; BIODEGRADATION; DISTRIBUTIONS; ASPHALTENES,"This study reports the findings based on analyses of saturated (normal alkanes and aliphatic isoprenoid) hydrocarbons and biomarkers in twenty four (24) crude oil samples from western offshore Niger Delta of Nigeria using gas chromatography (GC), gas chromatography-mass spectrometry (GC-MS) and carbon isotopy. The major objectives were to apply reservoir geochemistry and oil fingerprinting to characterize the oils in order to determine their origin and to identify the existence of reservoir continuity and/or compartmentalization. Results from this study using the distributions of normal alkanes, tricyclic and tetracyclic terpanes as well as source specific maturity and facies controlled biomarker ratios of the oils including pristane/phytane (Pr/Ph), Pr/n-C-17, Ph/n-C-l8, C-31:22S/(22S + 22R) homohopane, C-29:alpha alpha(20S/(20S + 20R)) steranes, moretane/C-30-Hopane and Ts/(Ts + Tm), showed that the entire crude oil samples from three reservoir units are the same, the differences are small. The oils originated from same source rocks which were deposited under oxidizing condition with mixed marine/terrigeneous organic source inputs and thermal maturity. This genetic classification is supported by stable carbon isotopic compositions (delta C-13) of the hydrocarbon fractions and multivariate statistical (Principal Component and Cluster) analyses. Geochemical, fingerprinting and multivariate statistical data provided corroborative evidence of a single compartment with vertical and lateral reservoir continuity across the fault complex within the studied fields. This information can be utilized by geologists and petroleum engineers in solving production related problems such as optimising hydrocarbon production via drilling horizontal wells to arrest the reservoir communication that occurs with existing vertical wells.",4,5,1
Geochemical Data,,"Twarog, Anna; Stefaniuk, Michal; Sechman, Henryk; Guzy, Piotr","Integrated analysis of geoelectric and surface geochemical data for exploration of subsurface hydrocarbon accumulations (Carpathian Foredeep, SE Poland)",Geoelectric surveys; Soil gas; Methane; Hydrocarbon deposits; Carpathian Foredeep; Poland,PETROLEUM-EXPLORATION; MIOCENE STRATA; SOIL GASES; POLISH; METHANE; PROSPECTS; ORIGIN; FIELDS; INDIA,"The search for hydrocarbon deposits in the Carpathian Foredeep is dominate by seismic methods. However, chances for additional discoveries of oil and gas will be increased by the integration of geochemical methods with non-seismic methods. The authors document mutual relationships between data obtained from surface geochemical survey and surface geoelectric survey. The geoelectric and geochemical surveys were run along 8 linear profiles positioned over the Rudka gas deposit discovered in Miocene sediments. This deposit is located over the margin of the Ryszkowa Wola Horst (Carpathian Foredeep). The Rudka deposit accumulates microbial gas generated under strictly defined conditions (microbial reduction of carbon dioxide). Soil gas samples were collected from a depth of 1.2 m at 177 sites and analyzed for methane, alkanes, alkenes, and non-hydrocarbon components. Maximum concentrations of CH4, total alkanes C-2-C-5 and total alkenes C-2-C-4 are 1200.0 ppm, 16.49 ppm and 0.289 ppm, respectively. The high concentrations of methane correlated with high values of C-1/Sigma(C-2-C-4) ratio indicate the presence of recent (microbial) methane whereas higher alkanes detected in soil gases originated from deep hydrocarbon accumulations. Two methodological variants of magnetotelluric survey were applied: natural field magnetotelluric soundings and controlled-source audiomagnetotelluric profiling. The interpreted resistivity values of Miocene sediments change from 0.6 to 20 Omega m but higher resistivities, locally exceeding 100 Omega m also occur in the near-surface zone. The lateral decreases of resistivity observed in the cross-sections may be linked to tectonic discontinuities. Changes of resistivity values identified in the magnetotelluric profiles and interpreted as the signs of ""gas chimneys"" correlate well with anomalous concentrations of total alkanes C-2-C-5. The multistage analysis of the results of surface geochemical and geoelectric surveys demonstrated that gas-saturated zones may extend beyond the known contour of the Rudka gas deposit. These results demonstrate that geoelectric and geochemical data collected in the near-surface zone are valuable complements of conventional hydrocarbon exploration methods.",5,6,1
Geochemical Data,,"Nezhad, Yousef Asgari; Moradzadeh, Ali; Kamali, Mohammad Reza",A new approach to evaluate Organic Geochemistry Parameters by geostatistical methods: A case study from western Australia,Organic geochemistry; Machine learning techniques; Geostatistics; Petrophysical logs; ANN; SGS,CARBON CONTENT; DELTA-LOGR,"Organic geochemical data are essential for unconventional shale resources evaluation. However, these data are often measured using sets of expensive and time-consuming geochemical experiments on few cuttings or core samples. Indirect methods, such as petrophysical approach, can provide a fast, convenient and cost effective means for their estimation using well log data. Among them, Delta LogR is a popular method for hydrocarbon source rock assessment. As it is based on a simple relation between logs and TOC, it cannot resolve other organic geochemical parameters. In this study, two methods base on machine learning techniques and on geostatistics, were used to estimate one dimensionally the organic geochemical parameters in one well of the Canning basin, Western Australia. For estimation using the artificial neural network (ANN); petrophysical logs were used as inputs and S1, S2, S3, TOC data of geochemical analysis taken as outputs of the models. The well-derived geochemical data were simulated by Sequential Gaussian Simulation (SGS) method. The obtained results demonstrate that the real and estimated data of the MLP-NN model have an acceptable mean squares error. In addition, all standard SGS diagrams show its superiority to the ANN for producing more similar results to the raw data. These results indicate the ability of these methods for estimation of the required geochemical parameters.",5,5,1
Tight Sandstone,,"Dong, Jin; Huang, Zhilong; Chen, Jinlong; Zhang, Weiwei; Wang, Lu; Li, Tianjun; Huang, Qian; Liu, Lichun",A new method to establish NMR T-2 spectrum based on bimodal Gaussian density function: A case study of tight sandstone in East China Sea Basin,Easter China Basin; Tight sandstone; Bimodal Gaussian density function; Pore size distribution,CAPILLARY-PRESSURE CURVES; PORE STRUCTURE; PERMEABILITY,"The identification and evaluation of tight sandstone reservoirs has been very difficult due to their low porosity, low permeability, complex pore structure and strong heterogeneity. In order to evaluate the quality of tight sandstone reservoir, priority should be given to the quantitative evaluation of pore size. Nuclear magnetic resonance (NMR) log is frequently employed in pore size evaluation; however, due to its high technical costs and other limitations, it can only be conducted in very few wells and the wide application can never be found. In this study, 12 core samples from the tight sandstone in East China Sea Basin have been collected to conduct centrifugal NMR experiments. Based on the analysis of data obtained from experiments, it is discovered that the bimodal Gaussian density function is well fitted to the NMR T-2 spectrum and can be applied to the fitting of NMR T-2 spectrum. Furthermore, in the analysis of physical property parameters of reservoir and each individual parameter of bimodal Gaussian density function, it is indicated that the porosity and permeability are best correlated with them. Therefore, the empirical formula between porosity, permeability and the parameters of bimodal Gaussian density function were established to construct pseudo NMR T-2 spectrum by using bimodal Gaussian density function and it has been verified by the comparison between the result and experimental data. In order to achieve the more accurate and wide application of this method, the NMR T-2 spectrum versus proportion frequency curve was transformed into the pore radius R versus porosity component P-phi curve before the fitting. When used in exploration field, the method can construct continuous pore size distribution curve which can be used for the quantitative evaluation of tight sandstone reservoir's quality. Compared with the method of NMR logging, this technique can be applied to the evaluation of pore structure of tight sandstone reservoirs more widely.",3,3,0
Tight Sandstone,,"Zhang, C. C.; Wu, C. D.; Zhang, S.; Guo, Z. J.; Wang, J. L.","Sedimentary and diagenetic control on the porosity and permeability in Lower-Middle Jurassic reservoirs, northern margin of Tianshan, China",Tight sandstone; Reservoir quality; Pore-throat structure; Sedimentary facies; Diagenesis; Tianshan,SEQUENCE STRATIGRAPHIC FRAMEWORK; SANDSTONE DIAGENESIS; ZIRCON GEOCHRONOLOGY; QUALITY PREDICTION; QUARTZ CEMENTATION; NORTHWEST CHINA; JUNGGAR BASIN; COMPACTION; EVOLUTION; ORIGIN,"The Lower-Middle Jurassic sandstone reservoirs in the northern margin of Tianshan are considered a significant area of tight sandstone gas. Sedimentary, petrologic and petroleum geologic criteria have been surveyed in six sections along continuous outcrops and cores. Thin sections and scanning electron microscope (SEM) images combined with mercury injection techniques are used to restore the evolution of pore-throat structures. The Lower-Middle Jurassic sandstones are mainly low-porosity and extra-low-permeability reservoirs. The results of constant-rate mercury injection reveal that the distribution pattern of the pore radii is not related to permeability, whereas the throat radii increase with increasing permeability. The microcosmic heterogeneity in reservoirs is dominated by a high proportion of narrow throats. An analysis of the reservoirs' physical properties and diagenesis indicates that the quality of the Lower-Middle Jurassic sandstone reservoirs is controlled by sedimentary environment, eodiagenesis, and diagenesis that developed in different sedimentary microfacies. The pore-throat structures can be divided into six types. In coal-bearing formations that are rich in organic matter, compaction decreases the quality of the reservoirs, and the reaction of early-formed kaolinite with remnant, undissolved K-feldspar may cause diagenetic illite to block the throats. At the bottom of the fluvial channels in braided river delta plains or at the top of mouth bars in braided river delta fronts, eodiagenesis can inhibit compaction via early basal carbonate cementation, and the unfavorable reservoirs are extra-low-porosity and extra-low-permeability sandstones. Infiltration-related clay is widespread. Smectite coats covered grains, and kaolinite filled remnant intergranular pores as aggregations, which increased the heterogeneity of the pore-throat structures. Authigenic chlorite coats protect intergranular pores from compaction and cementation by quartz overgrowths. Reservoirs with medium to low porosity and medium to low permeability come from the middle-upper portions of fluvial channels in braided river delta plains of the Xishanyao Formation or from the upper part of sub-water fluvial channels in the Badaowan Formation and the Sangonghe Formation or mouth bars in braided river delta fronts of the Sangonghe Formation. In near-surface settings, such as the bottom of fluvial channels or the top of mouth bars in braided river deltas, infiltration-related dissolution leads to more intergranular dissolution pores. However, the development of the highest-quality reservoirs, i.e., medium porosity and medium permeability, is limited. Other types exist between these end members in quality. Due to good sorting and low matrix content, the barrier bars of the Toutunhe Formation and the Sangonghe Formation with good lateral connectivity in the lacustrine facies are widespread in the northern margin of Tianshan and are considered to be high-quality reservoirs.",5,7,2
Tight Sandstone,,"Zeng, Qinglu; Lu, Wenzhong; Zhang, Ronghu; Zhao, Jilong; Ren, Ping; Wang, Bo","LIDAR-based fracture characterization and controlling factors analysis: An outcrop case from Kuqa Depression, NW China",LIDAR; Fracture; Development characterization; Controlling factors; Kuqa Depression,THRUST BELT; EXAMPLE; MODELS; RESERVOIRS; SANDSTONE; GEOLOGY,"Fracture is of primary importance to the natural gas production capacity from many tight sandstone reservoirs in the Kuqa foreland basin, NW China, but the orientation, size and plane porosity of the fractures in the subsurface is difficult to measure directly. Terrestrial light detection and ranging (LIDAR) surveys can offer factual information of outcrop-based research efforts to characterize fracture development laws and controlling factors. In this paper, utilizing a multi-level covering, we obtain the three dimensional (3D) point cloud data from a LIDAR survey launched at a typical outcrop. Matching with high-resolution digital photos and artificial measured information, the 3-D positions of natural fractures are extracted strictly in the data volume section. Furthermore, the fracture and reservoir model can be founded based on the systematic sampling and laboratory analysis, while a variety of accurate facture parameters can be obtained. It is founded that three groups of shear fractures are mainly developed in two periods with large inclination, short trace length and small spacing of normal distribution. Its patterns has provided a literal distribution of penetrating fracture zone and interlayer fracture zone with a single and a double set of advantage orientation respectively. It turned out that the fracture development scale is controlled by lithology, layer thickness, maximum principle paleostress and rock composition with a good exponential relationship. Our work could provide a workflow linking outcrop fracture observations to the 3D model of subsurface fracture prediction and extend modeling capability in other outcrop studies.",7,9,2
Tight Sandstone,,"Wang, Wei; Jiang, Youlu; Swennen, Rudy; Yuan, Jing; Liu, Jingdong; Zhang, Shaomin","Pore-throat characteristics of tight sandstone reservoirs composed of gravity flow sediments: Yingcheng Formation, Longfengshan sag, China",Gravity flow; Tight sandstone; Pore-throat size; Lower cretaceous; Longfengshan sag,SOUTHERN SONGLIAO BASIN; DEPOSITIONAL PROCESSES; QUALITY EVOLUTION; DENSITY FLOWS; GAS; DIAGENESIS; SEQUENCE; POROSITY; OIL; PERMEABILITY,"The Lower Cretaceous Yingcheng Formation in the Longfengshan sag (Songliao Basin, China) represents a typical tight sandstone reservoir that hosts large accumulations of hydrocarbons. The lacustrine sandstones mainly reflect gravity flow deposits making up various lithofacies displaying varying degrees of heterogeneity. This study reports on the links among gravity flow type, diagenetic overprinting and pore-throat characteristics that control reservoir quality. Core observations, especially grain size variations and related sedimentary structures are used to differentiate types of gravity flows. Microscopic observations, cathodoluminescence, scanning electron microscopy, pressure-controlled mercury injection tests and rate-controlled mercury injection tests are used to determine the mineralogy, sedimentary composition and pore-throat characteristics of the tight sandstones. In the study area, the gravity flows are divided into muddy debris flows, sandy debris flows, high-density turbidity flows, low-density turbidity flows and mud density flows. The petrophysical properties of these different gravity flow sediments reflect a range of permeability and porosity characteristics. Because of their mud-dominated textures and related weak compressive strength, mud density flows and muddy debris flows become ineffective as reservoirs during burial. In contrast, for approximately similar burial depths, turbidites and sandy debris flows show better reservoir quality. However, reservoir units with high porosities still possess considerable heterogeneity; this is especially true of some sandy debris flows that possess large amounts of secondary pores but which are not charged with hydrocarbons. In particular, in some poorly sorted sandy debris flows that are characterized by high contents of fine-grained matrix, some of the pore throats are blocked by matrix material. Moreover, the dissolution of feldspars and volcanic debris led to the formation of authigenic clays and quartz, which preferentially developed in pore throats with small radii. This process significantly reduced permeability. Overall, the permeabilities of the sandy debris flows are generally lower than those of the turbidites. Due to their relatively large-radius pore throats, turbidites can be categorized as potential effective hydrocarbon reservoirs in the study area. This research provides significant insights into the characteristics of pore throats within tight reservoirs consisting of gravity flow sediments in lacustrine basinal settings.",9,10,0
Gas Condensate,,"Beti, Dhrupad R.; Thul, David J.; Ring, Terry A.; McLennan, John D.; Levey, Raymond",A new method of source and reservoir rock pyrolysis to determine the boiling point distribution of petroleum in rock samples,Pyrolysis; S1; Incremental S1; Free petroleum; Refractive index; HAWK (TM),EVAL PYROLYSIS,"This paper presents a new method of source and reservoir rock pyrolysis used to understand the boiling point distribution of petroleum in rock samples. Experiments and simulations of the new incremental S1 method were performed on a range of rock types and API gravities (Black oil < 40, Volatile oil 40-45, Gas condensate >= 50 and Wet gas > 50). Comparison of the results from experiments and simulations are presented. The boiling point distribution results from the new incremental method can be used to infer the carbon number distribution of oil present in rock samples. However, the boiling point distribution data from the incremental S1 method is not adequate to determine the API Gravity of oil present in rock samples. Refractive index (RI) and density of oil have a straight line correlation. The boiling point distribution data from the Incremental S1 can be used in conjunction with the refractive index data to predict the composition of oil present in rock samples.",4,4,1
Gas Condensate,,"Johnson, Caroline; Jamiolahmady, Mahmoud",Production data analysis in gas condensate reservoirs using type curves and the equivalent single phase approach,Equivalent single phase; Gas condensate reservoirs; Production decline type curves; Rate transient analysis; Two-phase production data analysis,RELATIVE PERMEABILITY; MODEL; FLOW,"Most modern production data type curve (PDTC) techniques, which are used in the estimation of reservoir and well productivity parameters such as permeability, drainage radius and skin, were originally developed with the assumption of Darcy flow (i.e. laminar flow, with pressure gradient proportional to the fluid superficial velocity, in accordance with Darcy's law) of a single-phase fluid. Two-phase conditions, e.g. in a gas condensate reservoir (GCR) operating below dewpoint pressure, introduce nonlinearities into the diffusivity equation, making the use of single-phase techniques questionable, and potentially producing erroneous parameter estimates. A common approach to linearizing the system is by the use of pseudovariables which account for the two-phase effects in addition to the pressure-dependence of fluid properties. In this study, GCR production data generated using homogeneous fine-grid compositional simulation models, were first analysed using a well-known conventional (single-phase) modern PDTC technique, namely the Blasingame type curves for radial flow around a vertical well in a circular drainage area. The conventional techniques were then modified using an equivalent single phase concept, which was employed in the computation of two-phase pseudovariables for use with the single-phase PDTC. To compute these two-phase pseudovariables, pressure-saturation/k(r) relationships are required. These were determined using a technique, which employs fluid component weight fractions and gas fractional flow of a fluid with constant fixed total composition. Sensitivities were conducted on reservoir fluid richness (maximum liquid dropout from 1% to 42%), relative permeability curves, degree of reservoir undersaturation and well operating pressures, to examine their impact on production decline response and subsequent conventional PDTC analysis, as well as their impact on the effectiveness of the equivalent single-phase based approach used in this study. The paper first highlights the impact of two-phase flow conditions in GCRs on conventional PDTC analysis, in terms of the quality of the type curve match (TCM) and estimates of permeability, drainage radius and skin. Then it is shown that, in GCR analysis where the impact of two-phase effects are important, significant improvements can be obtained, both in the quality of the TCM and subsequent parameter estimates, through the use of pseudovariables computed using equivalent single phase concepts. The results also identify conditions under which, depending on the fluid richness and/or the degree of undersaturation, two-phase effects, although present, may not significantly impact the quality of interpretation of long-term production data from GCRs, using conventional single-phase PDTC techniques.",5,5,0
Gas Condensate,,"Hekmatzadeh, Mahnaz; Gerami, Shahab",A new fast approach for well production prediction in gas-condensate reservoirs,Gas-condensate; Well production prediction; Analytical model; High-velocity effects; Deviated well,RELATIVE PERMEABILITY; COMPRESSIBLE-FLUID; MODEL,"Prediction of gas-condensate well production is significant for sensible decision making for the reservoir development plan, infrastructure investment, and produced gas and condensate sales contract. Typically, time-consuming numerical simulation with fine grids or local grid refinement around the well is implemented in order to capture the effects of condensate blockage and predict gas-condensate well deliverability. In addition, in the commencement of the reservoir lifetime, the numerical simulation predicts erroneous results due to high uncertainty in reservoir data. A simple analytical model can estimate gas-condensate well production reasonable with a limited number of input data. On the other hand, uncertainty studies require repetitious usage of the analytical calculation. Therefore, a faster and more practical method for calculation of gas-condensates well flow rate has a precious value. In this paper, a fast analytical method is introduced for prediction of gas and condensate production profiles based on the two-phase pseudo-pressure integral and material balance equation. Proposed analytical model in contrast to previous ones, predicts the exact plateau time. As the result, it does not need iteration in each reservoir pressure step to compute the relevant flowing bottom-hole pressure during the constant gas production period. The model is expanded to take into account the high-velocity phenomena in near the wellbore region. It is also extended for the first time for different well geometries including vertical, deviated, horizontal, and hydraulic-fractured wells. Additionally, the analytical model is validated using fine grid numerical simulation for a wide range of rock and fluid properties. The developed analytical model can be used as a fast engineering tool for evaluating the uncertainty in well and reservoir data to choose the best strategy for reservoir development.",7,7,0
Gas Condensate,,"Saghafi, Hamidreza; Arabloo, Milad",Development of genetic programming (GP) models for gas condensate compressibility factor determination below dew point pressure,Compressibility factor; Gas condensate; Genetic programming (GP); Sour gas,NATURAL-GAS; OIL; RESERVOIRS; BEHAVIOR; STATE,"Gas compressibility factor plays a vital role in various engineering applications related to natural gas reservoir management, planning, transportation and processing. Compared to dry gases, gas condensates are thermodynamically complex and require thorough attention. The main challenge is phase segregation and compositional change during temperature variations or pressure depletion. Therefore, this study is focused on proposing novel compositional models based on a Genetic Programming (GP) framework for the accurate calculation of the gas condensate compressibility factor below dew point pressure. The new models are developed based on 1800 gas condensate datasets obtained from open literature. Both qualitative and statistical quantitative assessments were used to compare the precision and accuracy estimation of the new models to existing literature models. Moreover, the proficiency of the proposed models for compressibility factor calculations of gas condensate samples for sweet and sour gas samples was investigated. In addition, a sensitivity analysis based on Spearman and Pearson techniques was performed to carry out the degree of influence of each input parameter on the target value. It is expected that the developed models will pave the way for the accurate calculation of compressibility factors for gas condensates, which can be used by engineers for performance monitoring, optimization and production management in gas condensate systems.",7,7,0
Organic Acids,,"Baek, Kwang Hoon; Arguelles-Vivas, Francisco J.; Okuno, Ryosuke; Sheng, Kai; Sharma, Himanshu; Weerasooriya, Upali P.",Emulsification of Athabasca bitumen by organic alkali: Emulsion phase behavior and viscosity for bitumen/brine/triethylenetetramine,Bitumen; Organic alkali; Natural surfactant; Emulsion phase behavior; Emulsion viscosity,HEAVY OIL-RECOVERY; IN-WATER EMULSIONS; CRUDE-OIL; PIPELINE TRANSPORTATION; NATURAL SURFACTANTS; ASPHALTENE RATIO; STEAM CHAMBER; STABILITY; RHEOLOGY; RESINS,"Recovery of bitumen commonly uses steam assisted-gravity drainage, in which water throughput is intrinsically high. A large amount of condensed water near thermal fronts tends to substantially decrease the effective permeability to bitumen in the conventional gravity drainage process. This research investigates a potential way to use the condensed-water phase as an effective carrier for bitumen by making oil-in-water (o/w) emulsion. The expected mechanism depends on emulsification of bitumen into the water phase by natural surfactants that are generated through reactions of acidic oil components with organic alkali. The main objective of this paper is to study the ability of an organic alkali to create o/w emulsions that are much more mobile than the original bitumen. Triethylenetetramine (TETA) was selected as organic alkali for this paper with no other additives. The main contribution of this paper is a new set of experimental data (phase behavior and viscosities) for emulsions for mixtures of Athabasca bitumen, TETA, and NaCl brine at a wide range of alkali concentrations, salinities, and water-to-oil ratios (WORs) M temperatures up to 373 K. Results show that the o/w emulsions created by TETA can be an effective bitumen carrier with a low viscosity and high bitumen content in the emulsion. It is possible to create o/w emulsions by adding a small amount of TETA to Athabasca bitumen and NaC1 brine. Single-phase o/w emulsions, which are desirable as a bitumen carrier, were observed for TETA concentrations below 5.0 wt% M salinities 0 ppm and 1000 ppm at 373 K. The bitumen content in o/w emulsion was the highest for 2.0 wt% TETA samples, and it increased with increasing temperature. In comparison to the original bitumen, o/w emulsions were 4-5 orders of magnitude less viscous at 298 K, 2 to 3 orders of magnitude less viscous at 323 K, and 1 to 2 orders of magnitude less viscous at 353 K.",5,6,2
Organic Acids,,"Al Helal, Ammar; Soames, Adam; Gubner, Rolf; Iglauer, Stefan; Barifcani, Ahmed",Performance of erythorbic acid as an oxygen scavenger in thermally aged lean MEG,Oxygen scavenger; Mono-ethylene glycol; Salts; Corrosion; Erythorbic acid,PROPYLENE-GLYCOL SOLUTIONS; AQUEOUS ETHYLENE-GLYCOL; MONOETHYLENE GLYCOL; ASCORBIC-ACID; OXIDATION; DEGRADATION; PRODUCTS; WATER,"The objective of this work is to further evaluate the performance of the erythorbic acid oxygen scavenger designed by (Kundu and Seiersten, 2017) within 85% wt. Thermally Aged Lean Mono Ethylene Glycol (TAL-MEG). Experiments were performed at two levels of dissolved oxygen concentrations including 1000 ppb and > 7500 ppb at pH values of 6, 9 and 11. Furthermore, the erythorbic acid oxygen scavenger was evaluated under conditions representative of an industrial MEG regeneration system in terms of salt and organic acid concentrations to replicate field usage. Strong performance of erythorbic acid in combination with manganese and diethylethanolamine (DEAE) was observed under field conditions suggesting that erythorbic acid may provide an attractive alternative oxygen scavenger for use in the oil and gas industry in place of traditional sulfite based scavengers. However, the results generated within TAL-MEG showed a reduction in the performance of erythorbic acid oxygen scavenger when compared to fresh MEG solution. Moreover, results confirmed that varying acetic acid concentration did not affect oxygen scavenger performance within TAL-MEG. It was observed that the pH of the solution was the primary factor in determining the performance of the erythorbic oxygen scavenger tested with insufficient oxygen removal achieved at a pH of 6. In contrast, strong performance was achieved at pH 9 and 11 successfully reaching below 20 ppb dissolved oxygen concentration within a reasonable timeframe with little to no impact due to the presence of mineral salt ions and organic acids.",7,7,0
Organic Acids,,"Soames, Adam; Odeigah, Edith; Al Helal, Ammar; Zaboon, Sami; Iglauer, Stefan; Barifcani, Ahmed; Gubner, Rolf",Operation of a MEG pilot regeneration system for organic acid and alkalinity removal during MDEA to FFCI switchover,Mono-ethylene glycol; Distillation; Corrosion; MDEA; Organic acids; Film forming corrosion inhibitors,HEAT-STABLE SALTS; CARBON-DIOXIDE; HYDRATE FORMATION; ETHYLENE-GLYCOL; CO2 CORROSION; METHYLDIETHANOLAMINE; INHIBITION; ABSORPTION; SOLVENTS; ACETATE,"The switch over from pH stabilisation using MDEA to film forming corrosion inhibitors (FFCI) may be beneficial following formation water breakthrough during hydrocarbon transportation and processing to prevent scaling at elevated pH and to extend the operational lifespan of a field. Where formation water is present, organic acids including acetic can be expected within MEG regeneration systems and can impose a corrosion risk together with carbon dioxide. A case study was performed to evaluate the potential of simultaneous removal of organic acids and MDEA/alkalinity during the switch over from pH stabilisation to film forming corrosion inhibitors (FFCI). Experimental testing was conducted using a MEG pilot regeneration plant operated by the Curtin Corrosion Engineering Industry Centre. Sufficient removal of organic acids was achieved to prevent accumulation within the MEG regeneration loop and subsequent corrosion issues through distillation by lowering the pH of the rich glycol feed to six to promote removal of organic acids with the water distillate. Simultaneously, removal of MDEA and reduction of lean glycol alkalinity was achieved through the reclamation system to facilitate FFCI switchover more rapidly than a comparative industrial operational methodology.",8,8,0
Organic Acids,,"Shovkun, Igor; Espinoza, D. Nicolas",Geomechanical implications of dissolution of mineralized natural fractures in shale formations,Stimulated reservoir volume; Shear failure; Mineral dissolution; Hydraulic fracturing; Acidizing,BARNETT SHALE; GAS-PRODUCTION; POROUS-MEDIA; PERMEABILITY; ROCK; BASIN; FLOW; NETWORKS; MODEL; COAL,"Organic shale reservoirs accommodate large amounts of hydrocarbons in extremely tight rock matrix. Slick water hydraulic fracturing and proppant placement is the most spread stimulating technology for this type of reservoirs. Some shale formations contain a fair amount of easily-dissolvable carbonates, which prompts shale acidizing as a potential method to increase reservoir permeability. Carbonates in shale formations can be present as a part of rock matrix or can be localized in natural fractures - so-called mineral veins. Previous studies investigated the effects of chemical dissolution within the matrix, implying that acidizing can etch the rock, open new conduits for flow, and increase fracture permeability after closure. This study rather focuses on the reservoir-scale geomechanical implications of chemical dissolution of mineral filling in natural fractures. We use a combination of elasto-plastic analytical methods, analogous thermo-elastic numerical solutions, and experimental results to elucidate the impact of veins dissolution on in-situ stresses. Analytical, numerical, and experimental results indicate that mineral dissolution of localized carbonate fractures leads to changes of local in-situ stresses. The direction of stress relaxation strongly depends on the orientation of mineralized fractures. Dissolution of near-vertical mineralized fractures contributes the most to decreases of effective horizontal stress and reduce stress shadow effects in multistage hydraulic fracture completions. Mineral dissolution, similar to pore pressure depletion or thermal cooling/heating, can increase stress anisotropy, which can reactivate critically-oriented natural fractures. In-situ stress chemical manipulation can be used advantageously to enlarge the stimulated reservoir volume.",8,9,1
SAGD,,"Rashedi, Mohammad; Xu, Ouguan; Kwak, Seraphina; Sedghi, Shabnam; Liu, Jinfeng; Huang, Biao",An integrated first principle modeling to steam assisted gravity drainage (SAGD),Steam assisted gravity drainage; Oil sands; Dynamic modeling,INJECTION WELLS; HEAT-TRANSFER; TRAP SUBCOOL; WELLBORE; FLOW; GENERATOR; LOSSES,"In this work, we present the development of a mathematical model and simulation algorithm for the three key constituents of the steam assisted gravity drainage (SAGD) process, namely the steam generator, the steam injector, and the steam chamber. The modeling equations are derived by applying the conservation principle and adopting several empirical/algebraic correlations that support state estimation. In order to avoid the excessive design complexity and the computational load involved in existing models in the current literature, we attempt to develop the reduced-complexity models so that they can be compatible with the state estimation schemes and useful for control related applications. The developed models for the steam injector and the steam chamber are validated through either the simulation results of Petroleum Expert as a reservoir simulator or the similar models in the literature.",2,2,0
SAGD,,"Lele, Pushan; Syed, Abdul Haseeb; Riordon, Jason; Mosavat, Nader; Guerrero, Adriana; Fadaei, Hossein; Sinton, David",Deformation of microdroplets in crude oil for rapid screening of enhanced oil recovery additives,EOR; Droplet deformation; Heavy oil; Interfacial tension; Alkaline flooding,INTERFACIAL-TENSION MEASUREMENT; MICROFLUIDICS-BASED MEASUREMENT; ASSISTED GRAVITY DRAINAGE; ON-A-CHIP; HEAVY OIL; IONIC-STRENGTH; SURFACTANT SOLUTIONS; BITUMEN EXTRACTION; SAGD PROCESSES; SYSTEMS,"We present a microfluidic method to rapidly screen enhanced oil recovery additives based on the deformation of aqueous microdroplets in oil. Conventional methods, such as the pendant drop method, are hindered by large fluid volumes that require several hours to thermally equilibrate between measurements. Here we demonstrate a complementary technology to conventional methods, by which additives can be rapidly screened to select the best candidates for further study. Our glass chip establishes thermal equilibrium (demonstrated at 80 degrees C) of undiluted, highly viscous, crude oil within seconds, and enables the rapid quantification of water-in-crude oil droplet deformation within minutes, at a reservoir-relevant scale. The influence of two alkaline additives, a surfactant and a salt in the injected water phase were quantified, demonstrating the applicability of our method to a variety of recovery strategies.",5,5,2
SAGD,,"Banerjee, Sudiptya; Hascakir, Berna",Flow control devices in SAGD completion design: Enhanced heavy oil/bitumen recovery through improved thermal efficiency,SAGD; Flow control devices,LIQUID-LEVEL; OPTIMIZATION; BITUMEN; FIELD,"One method of thermal recovery, steam-assisted gravity drainage (SAGD), has proven a commercial success in heavy oil/bitumen production. However, geological and reservoir heterogeneity often complicate this task resulting in uneven production rates, higher operational costs, and stranded heavy oil/bitumen. This work theorizes that SAGD recovery is improved using flow control devices (FCDs) to force conformance in SAGD laterals. To test this theory, a novel protocol and test flow loop was developed to measure pressure drop across an autonomous hybrid FCD while flowing multiphase mixtures containing steam. This laboratory data was used to qualify existing pressure drop correlations and determine if nitrogen gas, a common test gas to describe FCD pressure drop response, creates suitable data for modeling steam systems. Finally, the flow loop was used to induce a steam ""flash"", a transition of water at saturation temperature to vapor due to a suddenly decreased pressure environment, within the FCD to determine if steam flashing changes expected pressure drops. Using linear regression, a correlation of expected pressure drop across the autonomous hybrid FCD for mixtures of heavy oil/bitumen, water, and steam was generated. Existing correlations proved inadequate for mixtures containing steam, consistently underestimating pressure drop across the FCD. However, the empirical correlation of this research highly matched laboratory data with an R-squared value of 0.94. A secondary linear model captured modifications in FCD behavior due to steam flashing. This second model also exhibited a strong goodness-of-fit with an R-squared value of 0.96. For both empirical correlations, p-values less than 0.05 were easily obtained, inferring the statistical significance of each correlation. Correlations generated in this research were added to the REVEAL (TM) reservoir simulation package to accurately forecast FCD impact on SAGD well pair performance. Simulating four-year periods of production for SAGD well pairs in Albertan reservoirs consistently show that FCD usage simultaneous improved bitumen recovery by 50% or more and decreased cumulative steam/oil ratios (cSOR) by 12 m(3)/m(3), largely through improved steam chamber conformance and by eliminating steam breakthrough events in the producer. Net Present Value (NPV) analysis of improvements with the additional cost of FCD completion tools unfailingly showed a strong economic argument for the use of FCDs to improve thermal efficiency.",6,7,2
SAGD,,"Guo, Yujia; Roostaei, Morteza; Nouri, Alireza; Fattahpour, Vahidoddin; Mahmoudi, Mahdi; Jung, Heeseok",Effect of stress build-up around standalone screens on the screen performance in SAGD wells,SAGD; Sand retention test; Slotted liner; Sand control,OIL,"Steam Assisted Gravity Drainage (SAGD) is the primary thermal recovery technology currently employed to extract heavy oil and high-viscosity bitumen from Alberta oil sands. In the near-wellbore region, the initial stresses are nearly zero, and as the SAGD chamber grows, the stresses tend to build up due to the thermal expansion of the formation. Also, melting of the bitumen and subsequent loss of the bonding between the grains leads to the collapse of the gap between the formation and sand control liner over time. The result will be effective stress buildup and gradual compaction of the oil sands around the liner. Slotted liners have been extensively used as a sand control device in SAGD wells. Slotted liners must allow free flow through the slots with minimal plugging and acceptable amounts of sand production. In our study, large-scale unconsolidated sand was packed over a multi-slot coupon of the slotted liner. The sand-pack was subjected to several stress conditions corresponding to the evolving stress conditions during the life cycle of a SAGD producer well. The testing program employed several multi-slot coupons to examine the flow performance under typical encountered stresses in SAGD wells. Cumulative produced sand was measured at the end of testing as an indicator of the sand control performance. The permeability evolution of the sand in the near-coupon zone was calculated by measurements of pressure differentials and considered as a measure of screen flow performance. Fines/clay concentration along the sand-pack was also quantified after the test to investigate the fines migration, a phenomenon which is considered to be the main reason for reduced wellbore productivity. Experimental results show that the liner performance is significantly affected by the normal stress buildup on the liner. Experimental observations indicate sand-pack compaction due to the increase of effective stress around the liner leads to a lower porosity and permeability. The situation near the liner is further complicated by the fines accumulation that results in pore plugging and further permeability reduction. When it comes to sanding, however, higher stresses help stabilize the sand bridges behind the slots, leading to less sand production. As for the design criteria, the lower and upper bounds of the slot size are governed by plugging and sand production, respectively. Considering the stress effect on plugging and sanding, testing data indicate that both the lower and upper bounds should be revised to larger slot aperture sizes.",8,8,2
Wax Deposition,,"Boghi, Andrea; Brown, Lloyd; Sawko, Robert; Thompson, Christopher P.",A non-inertial two-phase model of wax transport in a pipeline during pigging operations,Bypass pigging; Waxy oil; Pipe flow; Non-inertial frame of reference,DYNAMIC-ANALYSIS; FLOW-CONTROL; PIG; GAS; SIMULATION; REGION; MOTION,"The removal of wax deposit from pipelines is commonly accomplished using pigs. In order to avoid the formation of wax plugs in pipes, bypass pigs, which create a liquid jet to disperse the scraped deposit, are employed. Despite many One-Dimensional (1D) models have been developed to predict the dynamics of bypass pigs, the details of the interaction between the liquid jet and the debris have not been investigated numerically yet. In this work the fluid dynamics of a wax-in-oil slurry in front of a moving bypass pig is studied by means of three-dimensional (3D) numerical simulations. A mathematical model which couples the pig and the wax-in-oil slurry dynamics, solved in the pig frame of reference, has been developed. The results show that the pig quickly reaches an equilibrium velocity, and the pig acceleration is proportional to the square of the mixture relative velocity. Comparing the present with previous sealing-pig results it appears that the bypass flow is more effective in deterring plug formation. Moreover, the 3D fields have the advantage of showing the wax distribution in each pipe section whereas the 1D model cannot distinguish between deposited and suspended wax.",1,1,0
Wax Deposition,,"Quan, Qing; Ran, Wen; Yang, Lu; Gao, Ge; Wang, Shouxi; Gong, Jing",The effect of pressure on wax deposition from wax-solvent mixtures with natural gas,Wax deposition; Pressure; Natural gas; Cold-finger,CRUDE-OIL; SHEAR; WATER,"deposition reduces the effective flow area of the pipelines, leading to a significant pressure drop, which increases the transportation consumption and leads eventually to complete blockage. Most wax deposition studies have neglected the influence of natural gas, but natural gas is present in the actual pipelines and must be accounted for in field operations. A self-developed cold-finger apparatus was used to investigate the effects of pressure on wax deposition with natural gas (with 89.01% methane). The wax solvent mixtures consisted of a wax (C-22-C-37) dissolved in a paraffinic solvent (C-11-C-15). The wax deposition experiments were performed with 5, 7, and 10 mass percent wax solutions, for pressures ranging from 0.1 MPa to 6 MPa. The experimental results indicated that the maximum amount of wax is deposited at ordinary pressure. The amount of wax deposited increased at pressures ranging from 1 MPa to 2 MPa and decreased thereafter (at pressures ranging from 2 MPa to 6 MPa). In addition, the pressure corresponding to the maximum wax deposition varied with the wax content. Furthermore, the wax crystal morphology was observed using a polarizing microscope, and the morphology was quantitatively described via the fractal dimension. The analysis showed that the fractal dimension decreased with increasing pressure. This study confirms that natural gas plays a vital role in wax deposition studies, especially those aimed at predicting the wax deposition in actual pipelines, using a wax deposition model based on the laboratory experiments.",2,2,2
Wax Deposition,,"Duan, Jimiao; Deng, Songsheng; Xu, Shuo; Liu, Huishu; Chen, Ming; Gong, Jing",The effect of gas flow rate on the wax deposition in oil-gas stratified pipe flow,Oil/gas stratified smooth flow; Petroleum; Fluid mechanics; Deposition mechanism; Computational simulation,HEAT-TRANSFER; SOLIDS DEPOSITION; SHEAR-STRESS; LAMINAR-FLOW; PARAFFIN DEPOSITION; MULTIPHASE FLOW; LIQUID FLOW; MIXTURES; PIPELINES; PREDICTION,"Wax deposit becomes more complicated in oil-gas two-phase pipe flow than single phase flow, and therefore remains poorly understood. The increasing trend of deposit with an increasing gas flow rate has been observed in wax deposit experiments under oil-gas stratified pipe flow. In this study, a numerical method is used to clarify this trend by quantitatively analyzing the heat and mass transfer during wax deposit building up. The method was able to predict the experimentally observed trend of deposit without any adjustable parameter. It was found that there are four effects to affect wax deposit when the gas flow rate changed. These four effects focus on the flow, heat and mass transfer characteristic at the oil-deposit interface, which include the effect of oil wetted area, the wax diffusivity, the boundary layer thickness, and the concentration difference between bulk oil and oil-deposit interface on mass transfer. Furthermore, the overall growth behavior of the wax deposit is the consequence of the competition between these four effects as time progresses. These results provided important insight about the effects of the gas flow rate on the wax deposit in oil-gas stratified pipe flow.",3,4,4
Acid Injection,,"Qiu, Xiangdong; Aidagulov, Gallyam; Ghommem, Mehdi; Edelman, Eric; Brady, Dominic; Abbad, Mustapha",Towards a better understanding of wormhole propagation in carbonate rocks: Linear vs. radial acid injection,Matrix acidizing; Linear acid injection; Radial acid injection; Pore volume to breakthrough; Optimum injection rate; CT scan,REACTIVE DISSOLUTION; SIMULATION,"Understanding acid reactive flow and the formation of wormholes in carbonate rocks is important for designing successful acidizing operations. Linear coreflooding experiments have been widely carried out to gain insights about the dissolution process for varying rock types and acid systems. However, carbonate reservoir stimulation is dictated by radial flow configuration. As such, it is critical to bridge the gap between linear acid injection and radial acid injection. In this work, a series of radial acid injection and linear acid flow experiments are conducted at various injection rates while maintaining the same operating conditions. The objective is to develop a better understanding of the acidizing process under radial flow conditions at larger scale while applying high confining stresses as only a limited number of radial flow experimental studies have been reported in the literature. This is expected to provide guidance for the optimization and control of the matrix acidizing process for the field operations. The radial acidizing tests are performed on rectangular block samples with dimensions of 20 x 16 x 16 in. We use a quantitative acidizing model to select few representative acid injection rates due to the complexity of the experiments and limited availability of large block samples. This model shows good predictive capability when compared to the experimental results. Pore volume to breakthrough (PVBT) and optimum injection rate are determined for both radial and linear acidizing experiments. Lower PVBT values are obtained for the radial acidizing case. This is mostly associated with the larger rock pore volume exposed to acid for the radial block in comparison to the linear cylindrical core. High-resolution CT scan images of the acidized radial carbonate blocks and cylindrical cores are generated and analyzed. The CT scan images show different wormhole morphology when varying the acid injection rates. Similar branching features are obtained for the optimal wormholes in linear and radial tests. Injecting the acid at the optimal rate leads to fewer transverse branches but thicker when compared to the experiment at higher injection rate that requires more acid volume to breakthrough. The low injection rate results in the largest diameter wormholes with high tortuosity. The high-resolution nondestructive imaging and analysis has enabled to gain insight on the interaction between the acid and the rock sample under radial flow conditions. This analysis has revealed that the wormhole propagation direction is not only governed by the effective stress differential but also can be aligned with the fabric layers due to the sedimentation conditions of the rock.",7,8,0
Acid Injection,,"Qi, Ning; Chen, Guobin; Fang, Mingjun; Li, Boyang; Liang, Chong; Ren, Xinghua; Zhang, Kai",Damkohler number-based research on dividing dissolution patterns in carbonate acidizing,Acid-dissolved wormhole; Two-scale continuum model; Damkohler number; Dissolution pattern; Matrix acidizing; Carbonate reservoir,WORMHOLE FORMATION; INJECTION RATE; GAS-RESERVOIR; SIMULATION; ACID; PROPAGATION; BEHAVIOR; FLUID; ROCKS,"In general, the main dissolution patterns in carbonate acidizing include face dissolution, wormhole dissolution and uniform dissolution. Wormholes can also be divided into single, dominant wormhole, ramified wormhole and so on. The wormholes can establish advantageous channels for oil and gas in the reservoirs, increase the permeability of formations and achieve the ultimate goal of carbonate matrix acidizing. Considering the factors that affect carbonate acidizing, the flow rate of acid plays the key role in determining dissolution patterns. Many scholars have carried out the researches by means of numerical simulation or physical simulation experiment individually, but the reports which combine the two methods and define the flow rate boundary between different dissolution patterns in carbonate acidizing are rare. In this paper, the flow rate of acid was dimensionless on the basis of Damkohler number (D alpha), and the boundary of acid injection rate was confirmed by combining numerical simulation with physical simulation experiments. Among the various types of dissolution models, the two-scale continuum model comprehensively considers the convection, diffusion and acid-rock interfacial reaction and is capable of dynamically monitoring the acidizing region at different time steps. This paper, using the finite difference method, solved the typical two-scale continuum model. In order to extend the calculation of the range of Damkohler number, Steffensen's acceleration method was applied to the porosity variation equation. The previous conclusion that at higher injection rate the breakthrough pore volume of acid is in direct proportion to the one-third power of the average pore velocity was validated. Furthermore, the typical pressure fall-off curve was analyzed. Results show that the typical pressure drop curve changes from the power-law curve to the straight line, as the injection rate decreases. Based on the analysis of porosity field and concentration field, combined with physical simulation experiment, the change law of dissolution pattern with Da was analyzed, which clarify the injection rates boundary of dissolution pattern. The results show when Da is between 50 and 200, the core appears wormholes, when Da is between 1 and 50, the dissolution pattern is the transition stage from wormhole to uniform dissolution and when Da is between 200 and 500, the core dissolution pattern is the transition stage from wormhole to face dissolution. The Damkohler number and injection rates of different dissolution patterns can be used to guide the design of acidizing construction.",7,8,2
Acid Injection,,"Li, Junjian; Yang, Hanxu; Qiao, Yan; Fan, Zhen; Chen, Wenbin; Jiang, Hanqiao",Laboratory evaluations of fiber-based treatment for in-depth profile control,Profile control; Plugging effect; In-depth mobility; Dynamic plugging mechanism; Fiber,POLYMER MICROSPHERES; PHENOLIC RESIN; OPTIMIZATION; GEL,"Inspired by the successful implementation in acid fracturing, a fiber-loaded suspension system was designed to investigate inlet injectivity, in-depth mobility and overall plugging effect in unconsolidated high permeability sandpacks. In this paper, a series of experiments were conducted to screen suitable fiber suspension, including additives selection and dynamic plugging tests. Results showed that the formulation of 0.02 wt% citric acid +0.1 wt% YC regulator +0.1 wt% sodium tetraborate +0.12 wt% HPG displayed satisfactory dispersity. Sandpacks equipped with three pressure gauges to detect pressure changes were used for physical experiments. Four parameters (fiber length, fiber concentration, injection rate and permeability) that influenced the plugging efficiency were under discussion. The results revealed that relatively slow injection helped stabilize inlet pressure below upper limit. Three pressures increased in sequence during the subsequent water flooding, indicating that fibers moved forward with permeability reduction in sandpacks. The pressure dropped down but maintained at a high level after the operation finished. By comparison, 0.3 wt% 1000 mu m-long fiber injected at the rate of 1 mL/min was found to achieve the best performance under the permeability of 4000-7000mD. And the more serious the heterogeneity was, the more significant the diversion ability of the high permeability layer was. Noticeably, the fluctuations were observed in pressure curves, which was further interpreted by the dynamic plugging mechanism of fiber in four transport processes: ""migration-capture-redirection-recapture"". With unique slender shape, fibers were flexible enough to bridge and create a compact three-dimensional network structure along the flow direction. Due to high plugging strength and strong penetrability, the new fiber suspension system proves its potential to be an environmentally-friendly candidate in the selection of in-depth diverting agents. The evaluation and mechanism analysis may provide guidance for the operation design of profile control.",7,7,3
Drainage Area,,"Liu, Huihu; Sang, Shuxun; Xue, Junhua; Lan, Tianhe; Xu, Hongjie; Ren, Bo; Liu, Shiqi",Evolution and geochemical characteristics of gas phase fluid and its response to inter-well interference during multi-well drainage of coalbed methane,Coalbed methane; Qinshui basin; Multi-well drainage; Inter-well interference; Gas-phase fluid field; Evolution characteristics,SOUTHERN QINSHUI BASIN; FANZHUANG BLOCK; CHINA; ENRICHMENT; FIELD,"The Fanzhuang block from the southern Qinshui basin was used as a monitoring area to determine the components, the methane carbon isotopes (delta C-13(1)) and the methane hydrogen isotopes (delta D) of the recovered coalbed methane (CBM) during the different production times. The spatial evolution characteristics of the CBM components, delta C-13(1) and delta D and their response to inter-well interference during multi-well drainage in CBM production areas were analyzed visually. The results show that CBM components, delta C-13(1) and delta D all fluctuated; the spatial distribution direction of CBM components, delta C-13(1) and delta D also changed twice or more during sampling in the studied area. The fractionation of delta D lags behind the fractionation of delta C-13(1). The spatial distribution of the CBM components is affected by the CBM components obtained from partial CBM wells; the spatial distribution of delta C-13(1) and delta D of coalbed methane is affected by the fractionation of delta C-13(1) and delta D from the produced CBM. The decrease in the CBM components and the delta C-13(1) and delta D ratios reveals the effects of inter-well interference on the multi-well patterns. The variability in the spatial distribution direction of CBM components, delta C-13(1) and delta D shows that inter-well interference may still be in an early stage or the degree of inter-well interference may be relatively weak. The incomplete consistency of the spatial evolution of CBM components, delta C-13(1) and delta D is mainly related to the fractionation of CBM components and methane isotopes during drainage and the change in the CBM supply caused by the unstable fluid field under unbalanced inter-well interference. It was shown that inter-well interference during multi-well drainage increases and then begins to stabilize. The established geochemical response model and evaluation program of inter-well interference provide a method to determine the stage and the degree of inter-well interference in CBM production areas, not only in the southern Qinshui basin but also in other CBM basins with low permeability.",4,5,3
Drainage Area,,"Johnson, Caroline; Jamiolahmady, Mahmoud",Production data analysis in gas condensate reservoirs using type curves and the equivalent single phase approach,Equivalent single phase; Gas condensate reservoirs; Production decline type curves; Rate transient analysis; Two-phase production data analysis,RELATIVE PERMEABILITY; MODEL; FLOW,"Most modern production data type curve (PDTC) techniques, which are used in the estimation of reservoir and well productivity parameters such as permeability, drainage radius and skin, were originally developed with the assumption of Darcy flow (i.e. laminar flow, with pressure gradient proportional to the fluid superficial velocity, in accordance with Darcy's law) of a single-phase fluid. Two-phase conditions, e.g. in a gas condensate reservoir (GCR) operating below dewpoint pressure, introduce nonlinearities into the diffusivity equation, making the use of single-phase techniques questionable, and potentially producing erroneous parameter estimates. A common approach to linearizing the system is by the use of pseudovariables which account for the two-phase effects in addition to the pressure-dependence of fluid properties. In this study, GCR production data generated using homogeneous fine-grid compositional simulation models, were first analysed using a well-known conventional (single-phase) modern PDTC technique, namely the Blasingame type curves for radial flow around a vertical well in a circular drainage area. The conventional techniques were then modified using an equivalent single phase concept, which was employed in the computation of two-phase pseudovariables for use with the single-phase PDTC. To compute these two-phase pseudovariables, pressure-saturation/k(r) relationships are required. These were determined using a technique, which employs fluid component weight fractions and gas fractional flow of a fluid with constant fixed total composition. Sensitivities were conducted on reservoir fluid richness (maximum liquid dropout from 1% to 42%), relative permeability curves, degree of reservoir undersaturation and well operating pressures, to examine their impact on production decline response and subsequent conventional PDTC analysis, as well as their impact on the effectiveness of the equivalent single-phase based approach used in this study. The paper first highlights the impact of two-phase flow conditions in GCRs on conventional PDTC analysis, in terms of the quality of the type curve match (TCM) and estimates of permeability, drainage radius and skin. Then it is shown that, in GCR analysis where the impact of two-phase effects are important, significant improvements can be obtained, both in the quality of the TCM and subsequent parameter estimates, through the use of pseudovariables computed using equivalent single phase concepts. The results also identify conditions under which, depending on the fluid richness and/or the degree of undersaturation, two-phase effects, although present, may not significantly impact the quality of interpretation of long-term production data from GCRs, using conventional single-phase PDTC techniques.",5,5,0
Drainage Area,,"Lyu, Zehao; Song, Xianzhi; Li, Gensheng",A semi-analytical method for the multilateral well design in different reservoirs based on the drainage area,Multilateral well configuration; Drainage area; Fast marching method; Heterogeneity,FAST-MARCHING METHOD,"The determination of the optimal multilateral well configuration for different kinds of reservoirs is extremely challenging due to the wide varieties of possible well type. In this paper, we propose a novel method to determine the number of laterals, lateral length and lateral spacing in the multilateral well. The objective in the design is to fully exploit the entire reservoir within a certain period of development time. A geological map is constructed based on the reservoir properties. The fast marching method is used to calculate the drainage area of each lateral in the development time. The drainage area of the designed multilateral well configuration can cover the entire reservoir. The results have been validated by analytical method and specific steps of the method are presented. The applications in both homogeneous and heterogeneous cases are studied. Longer development time can lead to less number of laterals, shorter lateral length and larger lateral spacing. The drainage area is irregular in the heterogeneous case. The algorithm can automatically determine the number of laterals, lateral length and lateral spacing based on the geological characteristics to exploit the reservoir efficiently. The proposed method is appropriate for the field application due to the short computational time.",6,6,0
Regularization,,"Liu, Wenchao; Liu, Yuewu; Zhu, Weiyao; Sun, Hedong",A stability-improved efficient deconvolution algorithm based on B-splines by appending a nonlinear regularization,Deconvolution; Nonlinear least-squares problem; Duhamel principle; Stability improvement; Second-order B-spline functions,WELL-TEST DATA; PRESSURE-RATE DECONVOLUTION,"Previous deconvolution algorithms based on B-splines are much easier to be understood and programmed for academic researchers and engineers. However, due to the use of a linear regularization, their stability is weaker than that of the commonly used von Schroeter et al.' s deconvolution algorithm in which a nonlinear regularization is used; the linear regularization can make the deconvolution algorithms less tolerant to data errors. Good stability for the deconvolution algorithms is very important in order to make deconvolution as a viable tool for well-test analysis. In the paper, in order to improve the stability of the deconvolution algorithms based on B-splines, a nonlinear regularization by minimizing the curvature of pressure derivative response, as used in von Schroeter et al.' s algorithm, is appended instead of the linear regularization. And the corresponding nonlinear regularization equations are appropriately deduced. In particular, the improved algorithm is based on the Duhamel principle directly, and the complex transformation by the nonlinear z function, as used in von Schroeter et al.' s algorithm, is avoided; it does simplify the whole deconvolution process; moreover, the sensitivity matrix of an involved basic linear system from the measured pressure and rate data can also be solved directly by the piecewise analytical integration method, which can largely improve the deconvolution computation speed. Ultimately, in combination with the nonlinear regularization equations, a nonlinear least-squares problem is formulated for the stability-improved deconvolution algorithm based on B-splines. Besides, a constraint condition for tuning the parameter values of the B-spline base and an involved smooth factor is presented for restricting the nonlinear regularization process. Through a simulated case study, it is found that the nonlinear least-squares problem can be solved stably by the advanced Powell's Dog Leg method due to its great convergence ability and numerical stability; and the solution accuracy is also verified. Then the effects of the two parameters on the type curves of the deconvolution results are analyzed. And the effect of the error in the initial formation pressure on the type curves of the deconvolution results is also analyzed. Then a statement on how to perform the nonlinear regularization is presented specifically. Furthermore, through the study on two simulated cases with added data errors and an actual case, it is demonstrated that when the nonlinear regularization is appended, the stability of the deconvolution algorithm based on B-splines can be largely improved for mitigating the effect of data errors; besides, the stability-improved algorithm based on B-splines even exhibits higher stability than von Schroeter et al.' s algorithm that takes the same nonlinear regularization method, and the reason can be attributed to the superior properties of the representation of the wellbore pressure derivative 9to be deconvolved) by B-spline functions in the numerical stability of computations and the inherent smoothness. Through the test of some simulated cases, it is also concluded that the stability-improved algorithm based on B-splines by appending the nonlinear regularization still has a high-level computation speed, which is nearly twenty times more than that of von Schroeter et al.' s algorithm. It can be attributed to the more undetermined coefficients and the computational complexity resulted from the zfunction transformation in the formulation of von Schroeter et al.' s algorithm.",1,1,0
Regularization,,"Rojas Tueros, Juan Alberto; Horowitz, Bernardo; Willmersdorf, Ramiro Brito; Barbosa de Oliveira, Diego Felipe",Non-distance-based localization techniques for ensemble-based waterflooding optimization,Waterflooding optimization; Ensemble-based methods; Sensitivity refinement; Constrained optimization,ALGORITHMS,"The problem of determining life-cycle rate controls for both producer and injector wells that maximize the net present value subject to well and field-wide capacity constraints is solved using an SQP algorithm. The required gradient is approximately computed by an ensemble-based method. Refinement techniques are employed to mitigate deleterious effects of spurious correlations and to improve the overall optimization efficiency. Control variables are rates of each well completion assumed independently controlled. Field NPV is decomposed as the sum of the NPV's of each well. Sensitivity matrix of well NPV's with respect to controls of all wells is obtained from ensemble-based covariance matrices of controls and of well NPV's to controls. For efficiency reasons ensemble size should be kept small which results in sampling errors. Since covariance matrixes are plagued with spurious correlations, regularization and novel non-distance-based localization techniques are required to improve the quality of the resulting sensitivity matrix. The effective approximate gradient is the sum of the columns of the refined sensitivity matrix. Three realistic reservoirs taken from the literature are used to demonstrate the efficiency of the refinement techniques. Realizations are generated from optimization iterates by adding temporally correlated random perturbations. Realizations go through a scaling procedure that ensures feasibility of all ensemble members. At the start of the optimization process simulation results of ensemble members are used to compute inter-well connectivities using a Producer-based Capacitance Resistance Model (CRMP) and competitiveness coefficients between producers using an Interference Test. Sensitivity of producer NPV's with respect to injector well controls are refined through a novel localization technique based on the connectivity of each injector/producer pair. Sensitivity of producer NPV's with respect to producer well controls is regularized by competitiveness coefficients keeping the coefficients of each well with respect to its own controls and weight averaging the effects of other producer well controls. Sensitivity of injector NPV's with respect to controls of producer and other injection wells are regularized depending on the actual realization of input injection rate controls by the simulator during control steps. NPV gains up to 15% of the average NPV values in twenty runs are obtained with much reduced scatter in comparison with solutions without refinement. The proposed regularization and novel non-distance-based localization techniques for refinement of the sensitivity matrix in ensemble-based waterflooding optimization, which automatically detects sealing faults and regions of low permeability, results in significant gains in NPV values and reduction in their variability. The added numerical cost is insignificant as previous simulation results are reused. The simulator is treated as a black-box in the optimization process and actual production history may be used in the localization criterion.",5,5,0
Regularization,,"Du, Hui; Wang, Gui; Deng, Guicai; Cao, Cheng",Modelling the effect of mudstone cuttings on rheological properties of KCl/Polymer water-based drilling fluid,Drill cuttings; Rheology; Drilling fluids; Tikhonov regularization,COUETTE VISCOMETRY DATA; ILL-POSED PROBLEMS; BENTONITE SUSPENSIONS; REGULARIZATION; PARAMETERS; RATES,"Drill cuttings unavoidably enter the annulus and affect the rheology of the drilling fluid in the process of drilling. The rheological properties of drilling fluids containing varying particle size and cuttings amounts were measured by using a rotational viscometer equipped with a widened gap. An algorithm based on Tikhonov regularization was proposed to transform the viscometry data into flow curves. Validity and availability of the presented algorithm were investigated by applying the algorithm to the base drilling fluid (without cuttings). Results showed that the flow curves of the cuttings-laden KCl/Polymer drilling fluids used in this study can be well depicted by the Herschel-Bulkley (H-B) model. Based on the rheological parameters obtained from curve fitting, the empirical correlations for the flow behavior index and the consistency coefficient were proposed. The consistency coefficient increases with the increase of cuttings amounts and the reduction of cuttings size. While the flow behavior index decreases with the increase of cuttings amounts and the reduction of the cuttings size. The proposed rheology determination approach in this study could give an orientative performance for cuttings-laden drilling fluids.",5,6,0
Oil-based Mud,,"Zhang, Boyang; Daigle, Hugh",Oil-soluble contrast agents for NMR,NMR; Relaxation; Contrast agents; Hydrophobic; Fluid typing,IRON-OXIDE NANOPARTICLES; THERMAL-STABILITY; ADSORPTION; SILICA; SPIONS,"In well logging applications, nuclear magnetic resonance (NMR) is recognized as a powerful tool to differentiate various fluids inside porous media. However, it can be challenging to do so in complex situations, e.g. when fluid peaks overlap with each other. Water-soluble contrast agents, such as MnCl2 or Gd-EDTA, have been proposed for use to accelerate the water relaxation, thus separating the water signal from those of other fluids. Together with these contrast agents, the log-inject-log method is used and the difference between the two logs is attributed to the doped water phase. This application only works with water-based mud. To extend its use to oil-based mud (OBM), it is desirable to find alternatives to water-soluble contrast agents that are compatible with OBM. In this work, we introduce a new group of doping agents: oil-soluble contrast agents. We selected several iron-based complex compounds that are oil-soluble, and tested and evaluated their effects on oil signal relaxation using a laboratory NMR apparatus. We also tested hydrophobic iron oxide nanoparticles as a contrast agent. The results showed that both the complex compounds and nanoparticles were able to reduce the transverse relaxation time of oil from longer than 2 s to less than 20 ms. To demonstrate their applicability in porous media, we injected doped oil into gas-saturated Berea sandstone and limestone core plugs. With conventional 1D NMR measurements or the use of water-soluble contrast agents, it is not straightforward to discern the gas signal from the OBM signal. Our experiments showed that the gas signal could be easily identified in the presence of doped oil via simple T-2 scans. We also performed experiments to demonstrate that the peaks of water and doped oil could be readily differentiated. The use of oil-soluble doping agents can significantly enhance the contrast of the NMR signals originated from different formation fluids, thus facilitating the fluid typing process. It provides a key alternative to the current water-doping technique. It is particularly advantageous when changing the oil relaxation is desired, such as for eliminating signal interferences from OBM invasion and differentiating heavy oil from clay-bound water. It also provides the possibility of speeding up the logging process by dramatically reducing the oil relaxation time. In addition, they can be employed in the laboratory for various purposes such as water saturation determination and fluid displacement monitoring. These contrast agents can also be of useful when oil-soluble contrast agents are desired in other fields, such as medical imaging applications.",1,1,1
Oil-based Mud,,"Gao, Jianshen; Sun, Jianmeng; Jiang, Yanjiao; Cui, Likai; Zhang, Pengyun; Wu, Jie",A novel quantitative imaging method for oil-based mud: The full-range formation resistivity,Oil-based mud; Microresistivity imaging; Coupling; Full-range resistivity; Relative permittivity; Standoff,,"Oil-based mud cake with its high resistivity affects severely the quality of borehole microresistivity imaging and has limited the use of microresistivity imaging logging in oil-based mud environment. We have utilized an equivalent model of a resistor and a capacitor to emulate the electrical responses of the high-resistivity mud cake and the formation, respectively, and then developed the electrical coupling relationship between the mud cake and formation, including vertical coupling and parallel coupling. We used the coupling relationship with a formation model to measure both the apparent resistivity and apparent relative permittivity of the formation simultaneously. Furthermore, we have imaged two formation models, one low-resistivity and the other high-resistivity using the vertical and parallel coupling, compared with the standard images obtained in the water-based mud environment corresponding to the same formation models. We have found that the vertical coupling and parallel coupling conquering the bad effect made by oil-based mud cake, can measure quantitatively the resistivity of low-resistivity and high-resistivity formation, respectively, and describe qualitatively the relative permittivity of low-resistivity and high-resistivity formation, respectively. The joint use of the vertical and parallel coupling can deal with the full-range microresistivity imaging of formation.",2,2,3
Other topics ,,"Li, Cunlei; Chen, Panpan; Fang, Nianqiao; Liu, Jianmei; Zhang, Jinliang","Stratum development characteristics and sedimentary evolution model of the second member of Shuangyang formation in Moliqing area, Yitong Fault Basin",Slope apron; Yitong Basin; Moliqing fault; Mixed sedimentation; Sedimentary model,SLOPE APRON DEPOSITS; TURBIDITY CURRENTS; GRAVITY FLOWS; DEBRIS FLOWS; NE CHINA; MECHANISMS; INVERSION; SANDS,"During the Second Member of Shuangyang Formation of Moliqing fault in the Yitong Basin, northeast of China, the intermittent transportation and rapid accumulation of nearshore gravity flows make the facies belts of fan apron narrow and changefully. Lacking stable contrastive maker layers, while the several tectonic events such as strike slip, transtension and compression occurring in the later period make the stratigraphic distribution of this area more complex. For these reasons, the research on stratigraphic correlation and the distribution of sedimentary facies are extremely difficult. To solve the above problems, this paper proposes the following solutions: (1) This paper assists to achieve the stratigraphic cycle analysis through logging data entropy spectrum analysis, on which basis and combining with the core data, seismic interfaces and geological markers to achieve the division and correlation of small layers of single sand body; (2) By analyzing the coarse clastic sedimentary system, we research the coarse clastic glutenite sediments of Shuangyang Formation in Moliqing fault from the fluid properties and fluid type conversion so as to clearly understand the vertical sequences and horizontal distribution characteristics analysis of core facies as well as deduce the fluid type of supply source and the characteristics of sediments. The results show that: (1) The sequence development is dominated by tectonic movements, and the strata can be divided into 5 middle-term cycles and 25 short-term cycles adopting T-R mode; (2) studies suggest that because the fluid property of supply source occurs cyclical changes under the condition of multiple sources, and the fluid shows alternation and conversion between gravity flow and traction flow under the control of particular ancient landform, therefore, the sediments of researched area form a mixed sedimentary system of gravity flow and traction flow. On the basis of source characteristics and sedimentary characteristics analysis, this paper proposed the sedimentary type of continental facies slope apron, which is divided into three sub-facies: proximal, middle and distal sub-facies. Among them, proximal sub-facies mainly develop the slop channel sedimentation dominated by mud debris flow deposits, central sub-facies develop the superposition channel microfacies dominated by mix depositions of gravity flow and traction flow and the leading edge microfacies of fan dominated by traction flow, while the distal sub-facies is mainly based on the thin sheet sand body and gravity flow slump depositions.",0,0,0
Other topics ,,"Hasan, Wessam F.; Farhat, Hassan",Hybrid thermal lattice Boltzmann model to study the transportation of surfactants contaminated emulsions in parabolic flows,Hybrid lattice Boltzmann method; Gunstensen model; Thermal; Surfactants-covered droplet; Marangoni stress; Rheology; Deformation index; Power number,DROP DEFORMATION; INSOLUBLE SURFACTANTS; RHEOLOGY; BREAKUP; DYNAMICS; STEADY,"Oil produced from secondary and tertiary processes is mostly in the form of oil in water emulsions, which is an inherent characteristic of the extraction process itself. An attempt to optimize the factors contributing to the cost of transporting such mixtures from the fields to the processing facilities, seems to be very useful and cost effective. In this work, a thorough investigation of the factors influencing the rheology and transportation of emulsions in circular ducts such as temperature, volume fraction, flow driving pressure and surfactants concentration, is performed using a special Lattice Boltzmann model. A dimensionless power number ratio is presented and used for the assessment of the best practices leading to a more efficient emulsions transportation system.",0,0,0
Other topics ,,"Thomas, Edward; Lucia, Angelo",Understanding pore-level phenomena of n-alkanes at high pressures,Shale; Gibbs-Helmholtz; Equation of state; Confinement; Langmuir,EQUATION-OF-STATE; METHANE ADSORPTION; FLOW BEHAVIOR; GAS SHALE; SIMULATION; FLUIDS,"Adsorption of shale related n-alkane fluids in graphite nano-channels is studied. Pure component canonical (NVT) ensemble simulations are performed over a range of isotherms and pore widths. Results for n-hexane are used to validate our approach by comparing them with experimental data in the open literature. The impact of pore throat diameter on adsorption and internal energies of departure is also reported and further demonstrate that there is a carbon chain length dependence on adsorption. All pure component results reported in this work are fit to a Langmuir adsorption model, which provides easy re-use in future studies. Numerical adsorption results for pure component methane adsorption are compared to experimental reservoir conditions. Finally, Ideal Adsorbed Solution Theory (IAST) is applied to the resulting Langmuir isotherms in order to provide some insight into the phase equilibria for applicable shale gas mixtures.",0,0,0
Other topics ,,"Grubac, Branko; Sevic, Snezana; Zivkovic, Marija",Effect of gas-lift on liquefied petroleum gas (LPG) product yield: A case study of Chinarevskoe gas treatment unit (Kazakhstan),Gas-lift; Stripping; Natural gas; LPG; Simulation,NATURAL-GAS; OPTIMIZATION; ALLOCATION,"More than expected increase of LPG yield was observed at the gas treatment unit after continuous gas-lift start up on Chinarevskoe oil field in western Kazakhstan. This paper studies the influence of gas-lift gas on fluid composition changes at separator conditions, and further, on LPG yield at the gas treatment unit. Gas-lift well operation and process plants simulations were carried out using Aspen HYSYS software and matched with real data from the field. Process simulation at constant separator pressure, varying temperatures, gas-lift gas flow rates and water cut indicated increase in LPG yield up to 4%. It was proofed that the increase of LPG yield did not come from propane and butanes from the gas-lift gas. It was concluded that increase of LPG yield is the consequence of mass transfer of components dissolved in oil, liquid, to the vapor phase, i.e. stripping of oil components by gas-lift gas as stripping medium took place. The amount of stripped components, and resulting LPG yield increase, at constant separator pressure on oil treatment plant depended on gas lift gas flow rate, temperatures and gas-lift gas composition. Presence of water had low impact on amounts of hydrocarbon components stripped from oil.",0,0,4
Other topics ,,"Mojeddifar, S.; Chegeni, M. Hemmati; Ahangarani, M. Lashkari",Gas-bearing reservoir characterization using an adjusted Parzen probabilistic network,Seismic attributes; Parzen probabilistic network; Reservoir characterization,NEURAL-NETWORKS; SEISMIC DATA; PARAMETERS; DENSITY,"The Parzen probabilistic network which is based on the Bayes theorem was developed using three wells in gas reservoir F3 to estimate porosity distribution. It used seismic attributes of similarity, instantaneous amplitude and energy rather than the conventional post-stack volume. The conditional probabilities involved in the Parzen probabilistic network should be adjusted based on an appropriate smoothing parameter which was calculated by cross validation approach. When the testing dataset was used, total accuracy was obtained as 0.7578 for the developed algorithm. The obtained results indicated that the adjusted Parzen probabilistic network characterized the discontinuities of F3 reservoir as fault structures and gas chimney and also estimated the porosity distribution.",1,1,0
Other topics ,,"Mahajan, Neeraj H.; Khataniar, Santanu; Patil, Shirish L.; Dandekar, Abhijit Y.; Fatnani, Ashish K.",Anti-collision risk management guidelines for Alaska North Slope directional wells,Anti-collision monitoring; Alaska north Slope; Position uncertainty; Survey tools; Directional well planning,PREDICTION; ACCURACY,"The complex process of anti-collision in directional well planning has gained particular attention in the Alaska North Slope (ANS) as the economic and environmental constraints have compelled the operators to drill from already congested pads. The accuracy of anti-collision study is highly dependent on the positional accuracy of the wellbore, which in turn is associated with the ellipse of uncertainty (EoU) generated by appropriate survey tools and their assigned error models. Initially, this study compares the performance of newly developed Operator Wellbore Survey Group (OWSG) error model and the industry-standard Industry Steering Committee for Wellbore Surveying Accuracy (ISCWSA) error model. The main objective of this study was to develop potential anti-collision guidelines that can be followed when any well would be drilled in ANS by integrating the uncertainties associated with survey tool and anti-collision considerations. To achieve this, the error model results were coupled with thorough sensitivity analysis based on four parameters. First, location, to understand the effect of latitude on EoU. Second, type of well to be drilled, to understand if the anti-collision considerations are well-type specific. Third, survey tools, to understand the limits of survey tools to be used, and lastly, different targets in same sand, to understand the difference if any between the first three parameters. The results show that the positional accuracy of the wellbore degrades drastically at higher latitude areas like Alaska which implies that higher magnitude of separation factor (SF) is required for safety of drilling operations in such areas. The results also show that MWD tool with in-field referencing (IFR) and multi station analysis (MSA) provide higher positional accuracy than the generic gyroscopic tools. The results of this study provide an improved anti-collision risk management workflow for effective well planning in the Arctic and high latitude areas.",1,1,0
Other topics ,,"Jamali, Ali; Ettehadtavakkol, Amin",Good wells make better stimulation candidates: An evidence-based analysis,Candidate well selection; Workover; Intervention; Stimulation; Production enhancement; Permian Basin San Andres,SELECTION,"Effective candidate selection is an important consideration in planning successful stimulation campaigns. Identifying ""high potential"" wells-those that would provide the largest incremental production-has been the subject of several studies, some of which have suggested that stimulation of better producers is a good practice to maximize stimulation benefits. An evidence-based investigation of this idea is lacking and is the subject of this study. This paper hypothesizes that a positive correlation exists between a well's oil production performance and its stimulation incremental oil production. We tested this hypothesis by investigating three independent methods: (1) analysis of aggregate results of case studies in the literature, (2) analysis of production and workover data from four mature Permian Basin San Andres leases, and (3) analysis of the simulation results from a tuned reservoir model. The results confirmed the existence and statistical significance of a positive correlation between pre-stimulation oil rate and stimulation incremental oil production. In our field-scale reservoir simulation model, we used pre-stimulation oil rate to rank stimulation candidates, which identified more than 80% of the top candidates. We recommend prioritizing wells that exhibit high oil production for stimulation in order to statistically increase the likelihood of maximized workover benefits.",1,1,0
Other topics ,,"Gu, Yufeng; Bao, Zhidong; Rui, Zhenhua",Prediction of shell content from thin sections using hybrid image process techniques,Carbonate formation evaluation; Thin section; Shell content; Median filtering; Binarization; Edge detection,CENTRAL SICHUAN BASIN; CARBONATE RESERVOIR; MEDIAN FILTER; GAS-FIELD; CHINA; ORIGIN; CLASSIFICATION; SYSTEMS; MODEL; ROCKS,"Shell content is an important indicator to evaluate the accumulation capability of carbonate reservoirs, but still needs to be estimated artificially. As such, some techniques that can automatically predict shell content only from stained thin section image are proposed. The processing procedures of those techniques include four steps: binarizing color thin section image; detecting edges of objects; using a special technique to extract shell areas; finally adjusting appearances of those extracted shells by dilating and eroding. Six thin sections used for validating techniques derive from the Lower Jurassic formations of the Sichuan Basin. For these six validated cases, the error between the expected and calculated shell content is 0.51%, 2.59%, 0.93%, 2.31%, 2.14% and 2.75% respectively. Moreover, within each thin section image, the main lithology predicted in accordance with the calculated shell content is consistent with that deduced from the expected shell content. The small errors and exact judgments of the lithology manifest that the proposed techniques are capable to provide the reliable shell content data, and compared to the conventional observation and analysis methods they are cost-efficient when dealing with a large amount of thin section images. Therefore, the proposed techniques have practical value and can be used as the handy tool for geologists in the work of observing and identifying thin section.",1,1,1
Other topics ,,"Dong, Wenxiu; Wang, Xiaodong; Wang, Jiahang",A new method to calculate the early performance of solution-gas-drive reservoirs,Two-phase flow; Nonlinearity; Boltzmann transformation; Reservoir performance,WELL TEST ANALYSIS; FLOW,"The performance of gas-solution-drive reservoirs is difficult to figure out since the treatment of highly nonlinear partial differential equations. In previous works, studies about gas-solution-drive reservoirs are restricted to production data analysis and the calculation of performance is almost lacking. The objective of this paper is to propose a novel application of Boltzmann transformation along with an adaptive-size fourth-order Runge-Kutta to figure out the performance of gas-solution-drive reservoirs in early time from the perspective of a well test analysis. Mathematical models about two-phase flow of one-dimensional linear flow and planar radial flow are established respectively. Through solving the governing equations of constant pressure production, the distribution of pressure and saturation at any time can be obtained easily, and curves of pressure and saturation versus time at a specific position can be also achieved. In addition, profiles of gas and oil flow rate at wellbore in terms of time can be acquired. The effect of bottom-hole pressure (BHP) on pressure, saturation and flow rate in early time is investigated. The results obtained from the newly proposed method are compared with numerical simulation results, and comparison results illustrate that the performance of solution-gas-drive reservoirs can be obtained fast and accurately through the new method.",1,1,3
Other topics ,,"Shen, Tong; Moghanloo, Rouzbeh Ghanbarnezhad; Tian, Wei",Interpretation of interwell chemical tracer tests in layered reservoirs with limited crossflow,,EQUILIBRIUM,"This paper presents a systematic approach to evaluate limited crossflow between layers of a stratified reservoir using interwell chemical tracer test. Previous analytic studies either entail no cross-flow between layers or assumes an established vertical equilibrium across transverse direction (owing to viscous/capillary/gravity driving mechanisms); however, they fail to detect the presence of limited crossflow between layers through a ""bridge""; 'bridge' in this study is defined as a pathway through which crossflow takes place with an adjacent layer. Obviously, crossflow may take place through several bridges along a layer. A new formulation is developed to study and detect the limited crossflow. The presence of crossflow is confirmed by a zero-sum change of fraction of total fluid flowing through system layers. We employed both numerical simulation and field examples to verify the proposed method. A transition period is identified during which the fraction of fluid flowing through each layer significantly changes because of crossflow. Our results indicate that tracer test data can be used to evaluate number of bridges and possibly their location(s) along the layer. Identification of crossflow between layers and evaluation of transition zone significantly improves the current efforts to understand reservoir heterogeneity and sweep efficiency. It is expected that the outcome of this research can help design much successful EOR processes.",2,2,0
Other topics ,,"Ennaifer, Amine M.; Kuchuk, Fikri J.",Pressure transient measurement statistics and gauge metrology,Accuracy; Resolution; Drift; Random noise; Statistical estimators,,"Downhole pressure transient measurements are usually affected by random noise caused by the intrinsic noise of the measuring device (the pressure gauge), environmental noise, and/or wellbore pressure fluctuations. The interpretation of pressure transients depends on the characterization of the noise signal and the obtaining of an accurate reservoir pressure response. This article presents a new procedure to characterize acquired formation pressure measurements, their statistical properties, and standard deviation by assuming independent and identically distributed random measurement noise. Apparent accuracy and apparent resolution of measurements are introduced. An automated methodology is developed to obtain and characterize the probability density function of the random noise. This new methodology will replace the conventional manual technique of selectively zooming on pressure curves and measuring their variations. Pressure data from a drillstem test (DST) were used to illustrate the automatic calculation of the apparent resolution. The noise affecting the DST data was then fully characterized and its density function computed. The dataset was also used to introduce and illustrate a new methodology for the analysis of pressure gauge drift using the distribution of slopes extracted from the local linearization of the pressure data. This methodology was able to identify gauges suspected of slight pressure drift that was not detectable visually.",2,2,0
Other topics ,,"Moreno, R.; Avansi, G.; Schiozer, D.; Vernon, I.; Goldstein, M.; Caiado, C.",Emulation of reservoir production forecast considering variation in petrophysical properties,Risk; Petrophysical uncertainty; Proxy model; Reservoir; Simulation,,"Implementation of proxy models, such as emulators might reduce the computational time required in a variety of reservoir simulation studies. By definition, an emulator uses reservoir properties as input parameters in a statistical model constructed from simulator outputs. However, incorporation of petrophysical properties distributions in all model grid-blocks implies too many input parameters for direct emulation. Currently, most employments of emulation only consider single-value parameterization of reservoir properties. In this work, we propose a methodology to consider spatially-distributed properties, such as porosity and permeability, in reservoir emulation technique. First, we present the process of finding a procedure to deal with geostatistical realizations in the emulator and then implement it in a risk quantification application. Construction of an emulator in a probabilistic approach involved: selection of a base model, definition of uncertain inputs, selection of outputs to be emulated, sampling inputs to generate scenarios, simulation of scenarios, and building the emulator. As an application, we used emulators to generate risk curves at the final production time of a synthetic reservoir model. By implementing the proposed procedure, we showed that emulators can provide reliable results during risk analysis in oilfield development. Furthermore, with emulators it is possible to generate risk curves that reproduce simulations results at a lower computational cost. It can be expected that parameterization of petrophysical properties will boost the applicability of the reservoir emulation technique. For instance, emulators can significantly reduce both the time and computational resources demanded in various reservoir studies for high heterogeneity and complex reservoir models such as found in the Brazilian pre-salt area.",2,2,0
Other topics ,,"Khaninezhad, M. Reza M.; Jafarpour, Behnam",Field-scale history matching with sparse geologic dictionaries,Model calibration; Inverse modeling; Sparse reconstruction; Compressed-sensing; Geologic dictionaries; K-SVD algorithm; L1-norm minimization,SINGULAR-VALUE DECOMPOSITION; PRIOR INFORMATION; K-SVD; INVERSE; IDENTIFICATION; REPRESENTATIONS; SENSITIVITY; SIMULATION,"Inference of reservoir flow properties from scattered production data poses a poorly-constrained inverse problem with non-unique solutions. Parsimonious description of reservoir properties can alleviate problem ill-posedness and help with preserving the expected geologic continuity of the solution. Low-rank representations can exploit the prevalent correlations in spatially distributed rock properties to compactly describe them. Recent advances in sparse reconstruction, known as compressed sensing, have inspired efficient and flexible model calibration approaches that offer a departure from classical reduced-order parameterization techniques that only use prior knowledge to select the parameterization subspace. Sparse model calibration allows for dynamic subspace identification by adaptively searching through a large combination of possible relevant subspaces (with different geologic features) to identify an appropriate one that best explains the observed data. We recently presented sparse geologic dictionaries as an effective and flexible method for representation of complex geologic connectivity patterns to facilitate the search for plausible solutions. In this paper, we demonstrate the field-scale application of learned sparse geologic dictionaries for history matching. We use a gradient-based implementation of the history matching problem to investigate the feasibility of adopting the developed method for field-scale application. The paper presents practical considerations, important properties, and alternative implementations of the method. The benefits and limitations of applying the method to reservoir history matching are evaluated and discussed. The performance of the sparse history matching approach with geologic dictionaries is also compared with the classical truncated singular value decomposition parameterization in three field-scale case studies. The results show that sparse model calibration with geologic dictionaries has a superior history matching performance for estimating reservoir properties in realistic settings where the trade-offs between problem dimensionality, model resolution, computation speed, geologic uncertainty, and solution plausibility should be reconciled effectively.",2,2,0
Other topics ,,"Om, Il-Lyong; Ryo, Song-Il; Kim, Chun-Yong",Calculation for cross section and area efficiency of progressing cavity pump with hypotrochoidal multilobe using the differential geometric envelope approach,Progressing cavity pump; PCP; DHM; Envelope; Hypotrochoid; Differential geometry,,"Now progressing cavity pumps (PCPs) and downhole mud-motors (DHMs) with cycloidal profiles are widely used in oil and gas industry. This study presents the method to design the cross section of PCP or DHM with hypotrochoidal multilobe. The conditions for conjugate envelope of hypotrochoidal rotor were derived by using the differential geometric approach. On the basis of this, we made the formulae for the envelope and its offset curve and worked to calculate the area efficiency of cross section and curvature of hypotrochoid. The field of trochoid ratio and offset distance were selected to get the rational offset curve. These results enable to design the cross section of PCP or DHM with multilobe of hypotrochoid which has the continuous and limited curvature. These results also can be used for multilobe PCP or DHM with solid stator.",2,2,0
Other topics ,,"Dabirian, Ramin; Padsalgikar, Ashwin; Mohan, Ram S.; Shoham, Ovadia",Four-layer model for prediction of sand bed height in horizontal gas-liquid stratified flow,Sand transport; Stratified flow; Multiphase pipeline; Sand deposition,INCLINED CHANNELS; PIPES; PARTICLES; TRANSPORT; VELOCITY,"Gas-liquid stratified flow is the most vulnerable flow regime for sand deposition, owing to the low phase velocities that occur in this flow regime. A theoretical and experimental study is conducted for particle transport in horizontal gas-liquid-solid stratified flow with high particle concentrations. Experimental data are acquired for air, water and spherical glass beads flow with a solid particle concentration of 20,000 PPM. Two particle sizes are utilized, 45-90 mu m and 425-600 mu m, with superficial liquid velocities of V-SL = 0.05 and 0.1 m/s and superficial gas velocities of V-SG = 3.75, 6.7 and 8.6 m/s. Data are acquired for the total particle bed height, demonstrating that it reduces with increasing superficial gas velocity, while increasing with smaller particle size. A new four layer model for gas, liquid, moving bed and stationary bed is proposed for high particle concentrations greater than 10,000 PPM. The gas, liquid and solid particle continuity equations, along with the momentum equations for the gas, liquid and moving bed layers are solved simultaneously, where the stationary particle bed is treated as a boundary. The model enables prediction of the heights and velocities of all four layers. The model predictions for total particle bed height are compared with the experimental data showing a good agreement.",2,2,0
Other topics ,,"Yang, Il Ho; Lee, Hyun Suk","Desorbed gas volume estimation using conventional well-log data for the Montney Formation, Deep Basin, Canada",Shale gas; Neutron porosity-density cross plot; Montney Formation; Illite volume; Desorbed gas volume,NORTHEASTERN BRITISH-COLUMBIA; MISSISSIPPIAN BARNETT SHALE; ORGANIC-MATTER; METHANE ADSORPTION; WOODFORD SHALE; RESERVOIRS; ALBERTA; PLAY; BITUMEN; TEXAS,"This study focuses on desorbed gas volume estimation of the Montney Formation, Deep Basin, Canada. Because desorbed gas has significantly contributed to shale gas production, and ranges from 10% to 40% of the total production, an accurate desorbed gas volume estimation is important to evaluate and develop shale gas fields. The desorbed gas volume was calculated using two methods - the adsorption capacity (cf. Langmuir test) and canister volume measurements. Both methods were originally adopted from coal-bed-methane production and applied to shale gas reservoirs after the commercial production of shale gas. The Montney Formation contains less than 2% of total organic carbon, with an average of 0.7% primarily derived from the secondary cracking of migrated oil. This suggests the absence of the adsorption capacity and organoporosity of organic matter. Conversely, the Montney Formation contains more than 20% of clay minerals, and the canister volume test shows that the formation has 22 scf/ton of desorbed gas volume. Based on a mineralogical analysis, this desorbed gas is primarily adsorbed to clay minerals, such as illite, mica, smectite, kaolinite, among others. Because illite is the major component among the clay minerals and has a positive correlation to the canister volume, the illite volume was calculated from conventional well logs to estimate exact desorbed gas volume. We assumed that the clay volume primarily consisted simply of illit The and the rest clay minerals and figure out the volume of illite by using neutrondensity cross plot. The calculated illite volume has a positive correlation to the canister volume, which can be used to infer the desorbed gas volume of the Montney Formation. The estimated desorbed gas volume in the Montney Formation ranges from 19 to 30 scf/ ton, which is lower than the free-gas volume.",2,3,0
Other topics ,,"Plutecki, Wojciech; Szulc, Przemyslaw; Plutecki, Janusz",The influence of the vane diffuser head losses curve on the external characteristic of high specific speed pumps,s-type instability; Cooperation vane diffuser-impeller; Vane diffuser hydraulic loss; Partial characteristics,SUBMERSIBLE PUMP; FLOW; IMPELLER,"In the petroleum industry the production process is secured by the proper operation of water pumps. Their correct selection, operation and maintenance reflect in the energy efficiency of the whole process, thus, the stable H-Q curve, correlated with the highest efficiency, is required in the operation range of the unit. The article concerns the problem of the s-type instability creation on the example of a mixed-flow pump. For the analyzed pump, where the instability of the flow curve occurs in a normal operation range, the experimental characteristic curves were measured. Based on those curves the numerical model was created and verified. The essential novelty of the article reflects in the phenomenon of the head losses rise in the vane diffuser while decreasing the pump discharge, approaching its local minimum in the best point of the pump. This phenomenon was caused by the mutual cooperation of the impeller and diffuser, specially by the impact of the non-uniformed flow structure supplied to the diffusor on its hydraulic performance. Obtained results of the impeller-vane diffuser cooperation were compared in the numerical aspect with the diffuser operation supplied by the uniform flow profile. Such analysis allowed to indicate the reason for the instability creation, where quite flat characteristic of the impeller reference to the head losses curve of the diffuser leads to the creation of the deflection point in the H-Q curve. To extend the scope of the conducted numerical research of the head losses curve increase phenomenon in course of the flow reduction in the vane diffuser of the high specific speed pump the analyses were also performed for the axial pump.",2,2,1
Other topics ,,"Zhao, Jing; Ren, Jinchang; Zabalza, Jaime; Gao, Jinghuai; Xu, Xinying; Xie, Gang",Cognitive seismic data modelling based successive differential evolution algorithm for effective exploration of oil-gas reservoirs,Successive differential evolution algorithm; VSP data; High dimensional data; Velocity and Q inversion,WAVE-FORM INVERSION; INSTANTANEOUS FREQUENCY,"A cognitive modelling based new inversion method, the successive differential evolution (DE-S) algorithm, is proposed to estimate the Q factor and velocity from the zero-offset vertical seismic profile (VSP) record for oil-gas reservoir exploration. The DE algorithm seeks optimal solutions by simulating the natural species evolution processes and makes the individuals become optimal. This algorithm is suitable for the high-dimensional nonseparable model space where the inversion leads to recognition and prediction of hydrocarbon reservoirs. The viscoelastic medium is split into layers whose thicknesses equal to the space between two successive VSP geophones, and the estimated parameters of each layer span the related subspace. All estimated parameters span to a high dimensional nonseparable model space. We develop bottom-up workflow, in which the Q factor and the velocity are estimated using the DE algorithm layer by layer. In order to improve the inversion precision, the crossover strategy is discarded and we derive the weighted mutation strategy. Additionally, two kinds of stopping criteria for effective iteration are proposed to speed up the computation. The new method has fast speed, good convergence and is no longer dependent on the initial values of model parameters. Experimental results on both synthetic and real zero-offset VSP data indicate that this method is noise robust and has great potential to derive reliable seismic attenuation and velocity, which is an important diagnostic tool for reservoir characterization.",2,2,1
Other topics ,,"Zanbouri, Hosein; Salahshoor, Karim",Development of robust surrogate model for economic performance prediction of oil reservoir production under waterflooding process,Oil reservoir waterflooding; Uncertain permeability; System identification; Surrogate model; Uncertainty model; Robust performance,OPTIMIZATION,"Geological uncertainty imposes significant challenge in modeling oil reservoirs. In this paper, a new robust modeling methodology is presented to identify a set of robust surrogate models with unstructured uncertainty for economic performance prediction of an uncertain oil reservoir under waterflooding process. The oil reservoir, being treated as a multi-input, multi-output (MIMO) system in terms of injection inputs and production outputs, is identified within a robust surrogate modeling framework using a frequency-based system identification approach. For this purpose, the concept of unstructured uncertainty model is incorporated with the surrogate modeling in the context of a function block having a norm-bounded uncertainty profile. The identified MIMO surrogate model is integrated with a desired nonlinear net present value (NPV) objective function to synthesize a new modified robust surrogate model in a multi-input, single-output (MISO) configuration form. This new modeling strategy enables direct calculation of economic performance prediction for the target oil reservoir. Finally, applicability of the proposed method is evaluated on ""Egg Model"" as a three-dimensional synthetic oil reservoir with 8 water injection wells and 4 oil production wells. The results clearly demonstrate that economic performance prediction of the oil reservoir, having uncertain permeability field, lies in the bounds corresponding to the worst-case scenarios of the uncertainty model set.",2,2,2
Other topics ,,"Liu, Jun; Li, Shide; Liu, Qingyou; Liu, Zhenjia; Li, Liangchuan; Xiao, Guohua",Temperature field analysis on the highly-deviated wellbore in backwashing condition,Highly-deviated well; Backwashing condition; Temperature field model; Spot experiment; Temperature field analysis,NUMERICAL-SIMULATION; WELLS; STEAM; FLOW; OIL,"Based on the measured borehole trajectory, a prediction model of temperature field of highly-deviated wells in backwashing condition is established. To verify the model, a test instrument to measure the temperature variations in the wellbore is developed and used to measure the temperature of two typical highly-deviated wells in backwashing condition. The comparative analysis shows that the wellbore temperature predicted by the model is close to that measured in field with the relative error less than 8%. The model was further used to analyze the influence of liquid-injection speed and injection time on the temperature distributions of oil pipe, annulus space and radial direction under the backwashing operation with original-temperature and hot washing liquid. It is found that for the backwashing operation with original-temperature washing liquid, the temperature at the lower part of the shaft is most affected by the displacement rate and backwashing time, whereas the curve section and the lower part of the shaft are most affected by the displacement rate and backwashing time in hot washing operation. Along the depth of the borehole, there is a constant temperature section which is almost unaffected by displacement rate and backwashing time. The radial heat transfer analysis shows that the heat exchange range is not large and near the wellbore.",2,2,3
Other topics ,,"Joseph, Amieibibama; Hicks, Peter D.",Modelling mist flow for investigating liquid loading in gas wells,Liquid loading; Mist flow; Phase change; Peng-Robinson EOS; Convex hull; Gas well,CONTINUOUS-REMOVAL; PIPE INCLINATIONS; WHOLE RANGE; STATE; PREDICTION; EQUATIONS; BINARY,"This paper presents a dynamic simulation approach to investigating liquid loading in gas wells for a fluid flowing in the mist flow regime. Two-component gas-liquid two-phase flow is considered, using coupled thermodynamic and hydrodynamic models as well as constitutive equations that incorporate the Peng-Robinson equation of state and the convex hull algorithm. The behaviour of the flow properties is investigated as phase change occur during flow. The accumulation of liquids is explored by investigating the distribution of the liquid density in the tubing, which is explicitly determined from the flow variables. The calculated phase densities are validated using data obtained from NIST RefProp and the results show good agreement. This procedure can provide substantial benefits in investigating the phenomena of liquid loading in gas wells compared to critical velocity predicting models that determine the stagnation velocity under isothermal conditions.",3,3,0
Other topics ,,"Azadeh, A.; Ahvazi, M. Pourebrahim; Haghighi, S. Motevali",An intelligent algorithm for determination and optimization of productivity factors in upstream oil projects,Upstream oil projects; Productivity; Artificial neural network (ANN); Adaptive network based fuzzy inference systems (ANFIS); Analysis of variance (ANOVA); Data envelopment analysis (DEA); Stochastic DEA,LABOR PRODUCTIVITY; NEURAL-NETWORK; PERFORMANCE EVALUATION; CONSTRUCTION PROJECTS; SERVICE CONTRACTS; OFFSHORE OIL; WORKERS; CONSUMPTION; EFFICIENCY; MODEL,"This paper presents a unique intelligent algorithm to identify and optimize factors affecting the productivity of upstream oil projects. Oil industry is the most important economic sector in the world and upstream projects play an important role in this industry. The proposed algorithm is composed of analysis of variance (ANOVA), data envelopment analysis (DEA), artificial neural network (ANN), adaptive network based fuzzy inference system (ANFIS), conventional regression (CR), and fuzzy regression (FR). In addition, each stage of the algorithm is equipped with verification and validation mechanism. First, a standard questionnaire containing productivity factors is designed and completed by experts of actual upstream oil projects. Then, DEA is used to identify the weights of all influential factors. The relationships between the influential factors and each of the criteria of productivity are then evaluated by ANN, ANFIS, CR and FR through relative error. Finally, ANFIS is selected as the preferred methods for optimization of the actual case of this study according to mean absolute error (MAE). Health, safety and environment (HSE), economic and management are determined as the most influential factors through sensitivity analysis. This is the first study that presents an intelligent algorithm for determination and optimization of productivity factors in an actual upstream oil projects. It can be used as a continuous improvement solution for upstream oil projects.",3,3,0
Other topics ,,"Kaiser, Mark J.; Narra, Siddhartha","An empirical evaluation of economic limits in the shallow water Gulf of Mexico, 1990-2017",Cost characteristics; Economic limit distribution; Factor models; Empirical modeling; Operational decision-making,,"Net revenue during the last year of an offshore structure's life serves as a proxy for the economic limit of production and encapsulate all the relevant cost information available. By reviewing a large group of structures, economic limits can be quantified and compared using structure attributes to obtain insight into operating cost thresholds and business practices. The purpose of this paper is to evaluate the gross revenue statistics the last year of production for oil and gas structures in the shallow water Gulf of Mexico. Summary statistics are tabulated by primary production, structure type, manned status and water depth for 3054 decommissioned structures in water depth less than 400 ft from 1990 to 2017. The P50 adjusted gross revenue the last year of production was $ 1.2 million for gas structures and $ 627,000 for oil structures. For gas structures, P20 and P80 economic limits are $ 282,000 and $ 3.97 million; for oil structures, $ 135,000 and $ 2.01 million. Factor models are constructed to distinguish the impact of individual variables and show that majors have an average $ 820,000 greater economic limit per structure than independents.",3,3,0
Other topics ,,"Yan, Tingjun; Zhao, Xuhe; Wang, Xiaohe; Yu, Jifei; Shi, Yifan",Study on energy conservation water injection system of offshore platform based on jet pump,Water injection; Jet pump; Numerical simulation; Energy conservation,,"In order to reduce energy consumption of water injection development of offshore platform, one idea of jet pumps with characteristics of suction replace the gate valve of water injection wells was introduced. Taking 14 injection wells at a platform in Bohai as the study object, three types of jet pumps which are called JP1, JP2 and JP3 were designed. The corresponding three-dimensional models were established and the Realizable k-epsilon model of ANSYS was applied to study the influence of jet pump nozzle-throat clearance on water injection rate. Moreover, the injection performance of structure-optimized jet pumps was tested. Three conclusions could be drawn. First, JP1, JP2 and JP3 express the best water injection performance with the optimal nozzle-to-throat clearance which is 4 mm, 5 mm and 6 mm. Second, the water injection rate could satisfy the demand of water injection platform and simulation results are similar to the experimental ones when the water injection rate range of three kinds of jet pump is 183-272 m(3)/d, 263-393 m(3)/d and 634-1149 m(3)/d respectively. Third, compared with the throttle valve water injection system at offshore platform, the jet pump water injection system could save about 1,150,000 kW h per year.",3,3,0
Other topics ,,"Jiang, Hang; Pang, Xiongqi; Chen, Di; Peng, Huijie; Yu, Qiuhua; Zhang, Xue","Characteristics of source rock controlling hydrocarbon distribution in Huizhou Depression of Pearl River Mouth Basin, South China Sea",Source rock; Petroleum accumulation system; Hydrocarbon distribution limit; Oil enrichment zone; Huizhou depression,PETROLEUM SYSTEMS; EXPLORATION; MIGRATION; SAG; GEOCHEMISTRY; EXPULSION; WENCHANG,"In a petroleum accumulation system, the source rock plays a significant geological role in controlling hydrocarbon distribution, because it provides the material basis for hydrocarbon accumulation. Thus, quantitative evaluations of source rock control on hydrocarbon distribution are useful for predicting future hydrocarbon discoveries. Using the Huizhou Depression in the Pearl River Mouth Basin, China, as a case study, geostatistical methods and probability calculation were employed to analyze the controlling effect of source rocks. The Huizhou Depression can be divided into five petroleum accumulation systems of which the Huixi contains the largest known amount of hydrocarbons. A probability model of hydrocarbon accumulations is established for quantitative evaluation of potentially favourable hydrocarbon distribution. In each petroleum accumulation system, the larger the hydrocarbon expulsion intensity, the larger the amount of hydrocarbons that accumulates; the longer the distance from the hydrocarbon expulsion centre, the lower the amount of hydrocarbon accumulates. The hydrocarbon distribution limit controlled by the source rock is 3.5 times the radius of the source kitchen in the Huizhou Depression. In the current state of exploration, oil fields in the Huizhou Depression are mainly observed in the areas 1.5 to 2 times the source kitchen radius. Based on the prediction model, structural highs around hydrocarbon source kitchens are potentially favourable zones for structural hydrocarbon reservoirs, and the interiors of source kitchens are potentially targets for subtle hydrocarbon reservoirs and unconventional resources.",3,5,1
Other topics ,,"Muradov, Khafiz; Eltaher, Eltazy; Davies, David","Reservoir simulator-friendly model of fluid-selective, downhole flow control completion performance",Intelligent well production; Advanced well completions; Autonomous flow control device; Wellbore modelling,,"Wells with long production/injection intervals (e.g. horizontal or multi-lateral wells) can be equipped with flow control completion (FCC), which allows zonal control of in/out-flow and is a proven method to improve sweep efficiency, extend well life, and reduce the production volumes of unwanted fluids. The application of FCC is essential to development of many oil fields with complex geology, uncertain reservoir description, close to contact completions or unfavourable mobility ratio. FCC technology keeps developing, for instance the recently introduced Autonomous Inflow Control Device (AICD) or Valve (AICV) strongly reacts to unwanted phases (gas or water) restricting their flow in-situ, which improves recovery as well as reduces the volume of unwanted fluids and the production uncertainty. This paper presents a novel approach to incorporate into a reservoir simulator the flow performance of a downhole flow control completion equipped with flow control devices discriminating flowing fluids, e.g. reacting to water/gas flow distinctly differently than to oil. AICDs and AICVs are examples of such devices. The novel approach is verified by numerical simulation and is further compared against the traditional modelling approach on a reservoir model. In the case of oil and water/gas flow, the multi-modal response of the device is new in the industry, and the reservoir simulators are not yet up-to-date to model such performance. The segregated flow in the annulus results in the device(s) reacting sequentially to either oil or water/gas, as opposed to the ""homogeneous flow"" modelling approach that is traditionally assumed in reservoir simulators. Capturing the sequential reaction of the device to either oil or water/gas in a reservoir simulator is challenging. The equations derived here solve this problem, and offer a more accurate way of modelling autonomous flow control completion performance in a commercial reservoir simulator. This work is an important contribution to the advanced well completion technology modelling and evaluation. This technology is likely to define the future of advanced wells.",3,4,2
Other topics ,,"Li, Longlong; Voskov, Denis; Yao, Jun; Li, Yang",Multiphase transient analysis for monitoring of CO2 flooding,Well test analysis; CO2 flooding; Miscibility; Corresponding analysis; Tangent line method,CARBON-DIOXIDE; DISPLACEMENT; MISCIBILITY,"The potential of well test technology is discussed in this paper to estimate the miscible condition and displacement fronts position during CO2 flooding. To interpret the multiphase well test curve of CO2 flooding process, an accurate compositional numerical model is developed in this study. The model includes fully EoS-based compositional nonlinear formulation, unstructured gridding and multi-segmented well. A systematic well test analysis of CO2 flooding at different regimes, including immiscible, multi-contact miscible and first-contact miscible gas injection, was performed for hydrocarbon systems with different number of components. Based on the interpretation root cause analysis, proposed in this work, the specific characteristics of the well test curve of CO2 flooding have been identified and described. These characteristics provide the guidance for the distinction among the different regime of CO2 displacement. It was demonstrated that the most important characteristics stay invariant from the number of components involved into numerical study. Finally, a tangent line method has been proposed to detect the key point on the pressure derivative curve corresponding to a CO2 front. This method allows to predict the displacement front position for problems of practical interest.",3,4,3
Other topics ,,"Jahanbakhshi, Saman; Pishvaie, Mahmoud Reza; Boozarjomehry, Ramin Bozorgmehry",Impact of initial ensembles on posterior distribution of ensemble-based assimilation methods,Ensemble-based assimilation; Future performance; Spurious correlation; Bayes' rule; Statistical inconsistency; Hypothesis test,RELATIVE PERMEABILITY CURVES; MONTE-CARLO METHODS; KALMAN FILTER; UNCERTAINTY QUANTIFICATION; JOINT ESTIMATION; MODEL; PERFORMANCE; EVOLUTION,"In this study, impact of initial ensembles on posterior distribution of ensemble-based assimilation methods is statistically analyzed. Along with, sampling performance as well as uncertainty quantification of these methods are compared in terms of their ability to accurately and consistently evaluate unknown reservoir model parameters and reservoir future performance. For this purpose, a synthetic test problem, which is a small but highly nonlinear reservoir model under two-phase flow, is utilized. Subsequently, different initial ensemble sets are considered and are updated through the assimilation process performed on the test problem using ensemble-based assimilation methods. Afterwards, consistency of the updated ensemble sets of permeability field as well as consistency of the predicted ensemble sets of cumulative water production have been assessed to reveal dependence of assimilation methods to the initial ensembles. Results of multi-sample hypothesis tests clearly disclose the inconsistencies between different updated ensemble sets of permeability field, and also between different predicted ensemble sets of cumulative water production. This is probably due to spurious correlations among the updated ensemble members within each set. Furthermore, the effects of ensemble size and type of the observation data on the associated inconsistency are investigated.",3,3,4
Other topics ,,"An, Cheng; Wang, Yuhe; Wang, Ying; Killough, John",A modified local error method for adapting time step-size in coupled flow-geomechanics problems,Coupled flow-geomechanics model; Modified local error method; Adaptive time stepping; Iteratively coupled method,FLUID-FLOW; COMPACTION; SIMULATION; TRANSPORT; STRESS,"Coupled flow-geomechanics model is needed for investigating the stress change, rock-compaction behavior, and stress-dependent properties in many practical reservoir scenarios. However, the coupled model of large-scale simulation problems usually encounters large matrix system and high computational expenses, where the time stepping is a crucial factor for numerical stability and computational efficiency. Here, we report an adaptive time stepping with the modified local error method to reduce iteration time and improve the computational efficiency for the coupled flow-geomechanics modeling. Firstly, the iterative coupling approach with the fixed-stress method is introduced, where the flow and geomechanics equations are sequentially solved at each time step. Secondly, since updating geomechanics module consumes most of the computing time of the coupled system, the modified local error method is mainly used for geomechanics module to adapt the time step size based on the change of displacement. Finally, a synthetic two-dimensional coupled problem is established to apply the proposed adaptive time stepping approach, where the numerical results including the computational efficiency are compared with the results from regular iteratively coupled method and the fully coupled model. The sensitivity about the local error tolerance on the numerical results is also investigated. The geomechanical responses regarding mechanical loading is validated by comparing with the analytical solution of Terzaghi's consolidation problem. The numerical results of the two-dimensional coupled model show the modified local error method not only yields a higher-order solution for better accuracy, but also significantly reduces the iteration number and computational time.",4,4,0
Other topics ,,"Ganat, Tarek A.; Hrairi, Meftah",A new choke correlation to predict flow rate of artificially flowing wells,Prediction correlation; Measured data; Correlation coefficient; Relative error; Artificially flowing; Multiphase flow,OIL,"The prediction of fluid flow rates is of prime importance for the oil and gas business. Several classical flow rate prediction correlations have been generated and generally used for wells flowing naturally. However, for oil wells flowing artificially, these correlations overlooked many significant fluid and well parameters, leading to erroneous results and inaccurate predictions. This paper used the outputs of a new mathematical model to predict the flow rates of 34 electrical submersible pump (ESP) oil wells from 3 oil fields located in North Africa, possessing a broad range of parameters, to determine a new correlation to predict the oil flow rate. Mathematical procedures for finding the best-fitting curve were used. When compared to the experimentally measured results of another two datasets, the predicted oil flow rates by the new correlation were in good agreement. Indeed, the performance of the new correlation shows reliable prediction results with about +/- 10% relative error. Furthermore, the results of this new method were statistically superior to results from previous correlation methods. The correlation that was proposed here exhibits greater accuracy (-5% error) than existing previous correlation methods. The new correlation adapts itself to any ESP oil well and could apply to both onshore and offshore wells.",5,5,0
Other topics ,,"Al-Safran, Eissa",Prediction of asphaltene precipitation risk in oil wells using coupled thermohydraulics model,Asphaltene precipitation; Two-phase flow; Asphaltene instability; Parametric study,,"Asphaltene precipitation and deposition is a major flow assurance challenge, which manifests itself in reservoir, production tubing, and flowline and process facility. Asphaltene may precipitate due to two main factors, namely high asphaltene content, and high difference between reservoir pressure and oil bubble-point pressure, i.e. precipitation driving force, even if asphaltene content is low. The objective of this study is to develop a predictive simulation tool to assess the risk of asphaltene precipitation in oil wells and to estimate the asphaltene risk window. Further objective is to use the developed simulation tool to generate well design and production scenarios to efficiently prevent, mitigate and manage asphaltene precipitation. A comprehensive asphaltene deposition workflow is developed to identify the major steps to enable a solution strategy. To implement the workflow, Ansari et al. (1994) mechanistic two-phase flow hydrodynamic model in vertical wells is coupled with two Asphaltene precipitation thermodynamic models, namely de Boer et al. (1995), and Wang et al. (2006). In this study, de-Boer et al. model is extended from a single point reservoir model to a multi-point wellbore model; while Wang et al. is used to predict and compare the asphaltene instability with live-oil instability along wellbore. The developed simulator was validated to predict the risk and depth window of asphaltene precipitation in Middle East oil wells, resulting in a reasonable agreement with the field data. In addition, the simulation tool is used to carry out a parametric study to investigate the impact of oil gravity, and reservoir pressure on asphaltene precipitation risk.",5,5,0
Other topics ,,"Meshalkin, Yury; Koroteev, Dmitry; Popov, Evgeniy; Chekhonin, Evgeny; Popov, Yury",Robotized petrophysics: Machine learning and thermal profiling for automated mapping of lithotypes in unconventionals,Geostatistics; Machine learning; Lithotype; Thermal properties of core sample; Bazhenov formation,,We present a method for predicting rock types. The method is based on continuous high-resolution thermal logging along full-size core samples and being applied for rocks from a major unconventional formation. The method utilizes spatial spectral decomposition and machine learning approaches allowing automatic classification of the core samples over lithological groups within an isolated stratigraphic depth interval of a wellbore. The core samples are basically classified to the particular lithotypes by means of spectral representation of profiles of thermal properties obtained by a modern contactless method.,5,5,0
Other topics ,,"Amir, Sahar Z.; Sun, Shuyu",Physics-preserving averaging scheme based on Grunwald-Letnikov formula for gas flow in fractured media,Grunwald-Letnikov; Fractured porous media; Fractional derivatives; Physics preserving; Average,FINITE-DIFFERENCE APPROXIMATIONS; FRACTIONAL DIFFUSION; MODEL,"The heterogeneous natures of rock fabrics, due to the existence of multi-scale fractures and geological formations, led to the deviations from unity in the flux-equations fractional-exponent magnitudes. In this paper, the resulting non-Newtonian non-Darcy fractional-derivatives flux equations are solved using physics-preserving averaging schemes that incorporates both, original and shifted, Grunwald-Letnikov (GL) approximation formulas preserving the physics, by reducing the shifting effects, while maintaining the stability of the system, by keeping one shifted expansion. The proposed way of using the GL expansions also generate symmetrical coefficient matrices that significantly reduces the discretization complexities appearing with all shifted cases from literature, and help considerably in 2D and 3D systems. Systems equations derivations and discretization details are discussed. Then, the physics-preserving averaging scheme is explained and illustrated. Finally, results are presented and reviewed. Edge-based original GL expansions are unstable as also illustrated in literature. Shifted GL expansions are stable but add a lot of additional weights to both discretization sides affecting the physical accuracy. In comparison, the physics-preserving averaging scheme balances the physical accuracy and stability requirements leading to a more physically conservative scheme that is more stable than the original GL approximation but might be slightly less stable than the shifted GL approximations. It is a locally conservative Single-Continuum averaging scheme that applies a finite-volume viewpoint.",5,6,0
Other topics ,,"Jahanbakhshi, Saman; Pishvaie, Mahmoud Reza; Boozarjomehry, Ramin Bozorgmehry",Joint estimation of facies boundaries and petrophysical properties in multifacies channelized reservoirs through ensemble-based Kalman filter and level set parametrization,Ensemble-based assimilation; Channelized reservoir; Level set parameterization; Relative permeability; Absolute permeability,RELATIVE-PERMEABILITY; DATA ASSIMILATION; SPEED; PERFORMANCE; COVARIANCE; SIMULATION; ENKF,"Ensemble-based assimilation methods are the most promising tools for dynamic characterization of reservoir models. However, because of inherent assumption of Gaussianity, these methods are not directly applicable to channelized reservoirs wherein the distribution of petrophysical properties is multimodal. Transformation of facies field to level set functions have been proposed to alleviate the problem of multimodality. Level set representation ensures that the estimated fields are facies realizations as well as no modification of the assimilation method is required. Moreover, due to the complexity of the history matching problem in the channelized reservoirs, most researchers conventionally assume that the petrophysical properties within each facies are constant and spatially uniform. In this study, an ensemble-based assimilation technique along with the level set parameterization are applied to estimate absolute and relative permeabilities jointly in the channelized reservoirs. That is, categorical facies variables together with petrophysical properties of the facies are simultaneously updated within the assimilation framework. To the best of our knowledge, the current study is the first one that investigates the simultaneous estimation of absolute permeability fields and relative permeability curves in the channelized reservoirs. The proposed method is justified by two different cases in a synthetic channelized reservoir. The first case is a two-facies reservoir, whereas the second case is more complex and contains four facies. Observation data include production rates of the producers, bottomhole pressure of the injectors, and facies types at the well locations. History matching process results in an accurate estimation of the channel structure together with monotonic reduction of the root-mean-squared error between the estimated and the true permeability field. Furthermore, relative permeability parameters are correctly estimated, history match is improved, and uncertainty of the model parameters is reduced.",5,5,1
Other topics ,,"Xiao, Rong; Gupta, Robin; Glotzbach, Rodney C.; Sinha, Somnath; Teletzke, Gary F.","Evaluation of low-salinity waterflooding in Middle East carbonate reservoirs using a novel, field-representative coreflood method",Coreflooding; Capillary end effect; Low-salinity waterflooding; Wettability,,"Low-salinity waterflooding attempts to improve recovery by reducing the salinity of the injection water, where the wettability alteration towards more water-wet state of the reservoir rock is believed to be the leading mechanism. This technology has received significant interest and a rich body of unsteady-state coreflooding test data has been reported in the past few years. However, capillary end-effect driven artifacts in conventional unsteady-state coreflooding could hinder proper understanding and interpretation of the measured results. We have developed a modified steady-state fractional-flow method to minimize capillary end effects. The fractional-flow analysis and simulation illustration of the new method has been published earlier by Gupta et al. (2015). In this work, we applied this new method to several Middle East carbonate reservoirs where slight changes in relative permeability consistent with a change in wettability can be observed but the overall uplift in recovery was very small. In addition, the results from the new method and the conventional coreflooding method were compared in selected cases to demonstrate the benefit of the new method in minimizing capillary end effect artifacts. Overall, this work demonstrates an improved laboratory screening methodology for low-salinity waterflood and similar EOR methods. The results of this work highlight the potential as well as challenges in low-salinity waterflooding in carbonates as a practical EOR technology.",5,6,1
Other topics ,,"Lee, Kyung Jae; Finsterle, Stefan; Moridis, George J.",Estimating the reaction parameters of oil shale pyrolysis and oil shale grade using temperature transient analysis and inverse modeling,Reaction parameters; Oil shale grade; Pyrolysis; Temperature transient analysis; Thermal skin effect; Inverse modeling,GENERATION; SIMULATION; ROCK,"Grade of oil shale and reaction parameters of in-situ pyrolysis must be identified for the prediction of productivity before actual heating and production. Identification of oil shale grade and reaction parameters depends on laboratory experiments on core samples. However, laboratory-determined parameters can be different from those representing in-situ reservoir conditions. In this study, we use inverse modeling to determine oil shale grade and reaction parameters. The inversions are based on a forward model that simulates heat injection into a well. Temperature at the heating well is affected by a thermal skin effect as a result of a decrease of composite thermal conductivity around the heater due to the decomposition-induced porosity increase. Synthetic observations of heater temperature are generated from a forward simulation. Temperature difference and its derivative are used in synthetic inversions to estimate oil shale grade and parameters of active decomposition reactions with an error below 1%. The proposed methodology of inverse modeling is expected to successfully estimate the oil shale grade and reaction parameters without core sampling and subsequent surface experiments.",5,5,1
Other topics ,,"Redondo, Carlos; Rubio, Gonzalo; Valero, Eusebio",On the efficiency of the IMPES method for two phase flow problems in porous media,IMPES; Near wellbore simulation; Multiphase flow; Porous media,MULTIPHASE FLOW; SIMULATION; TRANSPORT,"In this work, we show a method to efficiently solve the multiphase flow through a porous media in the near wellbore region. The numerical discretisation is based on the IMplicit Pressure Explicit Saturation (IMPES) approach. While most of the works in the literature rely on Fully Implicit Methods (FIM) to simulate the reservoir, this is not suited for the near wellbore region, where smaller computational and physical times are required, therefore parametric models with history matching are used in this zone. However, parametric models present several uncertainties that can affect the estimation of the pressure drop. An accurate and fast simulation of that region is therefore required. Here, we propose a new and robust implementation of the IMPES scheme, aiming to reduce the large computational cost of the (implicit) pressure system of equations and increase the robustness and reliability of the scheme. The method takes advantage of the short physical time steps between iterations, observed in the near wellbore region, to produce a new pressure field at the cost of a numerical explicit scheme. Two and three dimensional numerical experiments are carried out to show the validity of the proposed discretisation. We show that the cost of the method is reduced in a factor of 7-19 when compared to the classical IMPES.",5,5,1
Other topics ,,"Tang, Bao-Jun; Song, Xiao-Tong; Cao, Hong",A study on overseas oil and gas investment to avoid the risk of the changes in tax policies: A case in China,Oil and gas investment; The risk of changes in tax policies; Tax stability index,COUNTRIES; KAZAKSTAN; PROJECTS; IMPACT,"The changes in tax policies have become the important factors of risk in oil and gas investment. To avoid this risk and stabilize the income, this paper taking China's overseas oil and gas investment as an example, constructs the tax policy stability evaluation index system, puts forward the calculation method of tax stability index and uses the index ranking to compare the tax policy of different host countries. The study shows that: (1) The risk of the changes in tax policies of China existing partners is relatively high, and the average value of tax stability index is only 0.48. (2) The OECD countries have less cooperation with China in oil and gas, but their stability index is higher, both in the upper and lower places of 0.76. (3) The changes in tax policies of Ecuador and other high-risk countries are cyclical. (4) OECD and other low-risk countries have limited China's oil and gas investment by setting higher oil and gas investment barriers.",5,5,2
Other topics ,,"Dong, Wenxiu; Wang, Xiaodong; Wang, Jiahang",A new skin factor model for partially penetrated directionally-drilled wells in anisotropic reservoirs,Skin factor; Inclination angle; Anisotropy factor; Relative well length; Stimulation ratio of WPI,,"To study the stimulation effect of partially penetrated directionally-drilled wells, the skin factor model for partially penetrated directionally-drilled wells needs to be figured out. Based on the solution of a continuous point source in a laterally infinite reservoir, the solution of partially penetrated directionally-drilled wells in an infinite slab reservoir is obtained by using integral along the directional well. Then by the approximation treatment of large-time pressure solution, a new simplified skin factor model for partially penetrated directionally-drilled wells is obtained. The good agreements with classical result and numerical simulation result validate the solution in this work. According to the new skin factor model, curves of skin factor in terms of several influencing factors, such as inclination angle, well length, formation thickness and reservoir anisotropy factor are presented. Analysis shows that with the increase of inclination angle and relative well length, the skin factor will decrease, but the increase of anisotropy factor causes the skin factor to increase. Besides, the application of how skin factor is used to analyze the stimulation ratio of WPI (well productivity index) is presented. It can be concluded that for a certain reservoir, partially penetrated directionally-drilled wells with large inclination angle and relative well length will have good stimulation effect. Moreover, large vertical permeability is beneficial to the production of partially penetrated directionally-drilled wells.",5,5,3
Other topics ,,"Liu, Chao; Xie, Qingbin","Depositional, sedimentary, and diagenetic controls on reservoir quality in carbonate successions: A case study from the carbonate gas reservoirs of the Lower Triassic Feixianguan Formation, eastern Sichuan Basin, China",Tieshan area; Bitumen filling; TSR reaction; Diagenesis; Carbonate reservoirs,BURIAL DIAGENESIS; JIANNAN AREA; CREEK FIELD; DOLOMITIZATION; DISSOLUTION; EVOLUTION; ORIGIN; CLASSIFICATION; ACCUMULATION; DESTRUCTION,"The Kaijiang-Liangping trough is an important carbonate gas zone in eastern Sichuan Basin. The western platform of this trough has received less attention than the eastern one due to its lower reservoir potential. The current study mainly investigated depositional, sedimentological, and diagenetic features of the Lower Triassic Feixianguan Formation (T(1)f) from the Tieshan area located at the western platform, aiming to discuss their controls on reservoir quality. The gentle slope in the Tieshan area (approximately 5 degrees) deposited platform marginal oolitic shoals featured by thin vertical accumulation and long-distance lateral migration, thereby forming small-scale and scattered-distribution reservoirs. Despite intensive diagenesis alterations after sedimentation, the T1f reservoir porosity was controlled by sedimentological factors (i.e., grain size and sorting) at varying degrees. High-quality reservoirs occurred in the dolograinstones with good sorting and coarse grain sizes. The T1f carbonates underwent the near-surface and burial diagenesis in the Tieshan area. Dolomitization and associated syn- and post-dolomitizational dissolutions were important factors for secondary porosity development. Dolomite recrystallization increased intercrystal porosity in dolostones characterized by precursor mud-dominated fabric, thereby resulting in gradual shift from Lucia class 3 to class 1 petrophysical relationships with increasing crystalline sizes. By contrast, the intergrain porosity was not influenced by recrystallization in dolograinstones, which pervasively displayed classes 1 and 2 petrophysical relationships regardless of dolomite crystal sizes. The T1f gas reservoirs evolved from a paleo-oil accumulation as evidenced by pore-filling bitumen, which had negative effects on crystalline dolostones by filling intercrystal pores. However, its influence on dolograinstones was negligible as dissolution in relation to thermochemical sulfate reduction (TSR) reaction occurred during paleo-oil cracking into gas, thereby increasing intergrain porosity and effectively offsetting porosity decrease caused by bitumen filling. TSR dissolution occurred at certain intensity in the Tieshan area, which was evidenced by H2S occurrence in gas.",6,6,0
Other topics ,,"Mortazavi, Ali; Atapour, Hadi",An experimental study of stress changes induced by reservoir depletion under true triaxial stress loading conditions,Reservoir depletion test; True triaxial stress loading; In situ stress field; Pore pressure-stress coupling,LACQ GAS-FIELD; INDUCED SEISMICITY; PORE PRESSURE; PATH; MAGNITUDE; PERMEABILITY; COMPACTION; INJECTION; DEPTH; MODEL,"The reduction of pore pressure during reservoir production alters the initial stress state within the reservoir and the surrounding rocks. This stress variation is responsible for many problems encountered during production (e.g. fault reactivation, casing deformation). In this investigation, a newly designed True Triaxial Stress Loading and Pore Pressure Applying Apparatus (TTSL-PPAA) was applied to study the coupling of pore pressure draw-down and reservoir stress changes under actual field conditions. The objective was to overcome the shortcomings of commonly employed depletion testing under conventional triaxial conditions, which assumes that both horizontal stress components are equal. The depletion simulations were performed by decreasing the pore pressure and under applying constant vertical and keeping zero horizontal strains, i.e. uniaxial strain boundary conditions. The results showed that both horizontal stresses decrease with a linear trend with pore pressure depletion. The reduction rates of minimum and maximum horizontal stresses, however, are not uniform. The rate of maximum horizontal stress reduction is higher than the minimum horizontal stress component. Moreover, the pore pressure/stress coupling intensity is dependent on the initial, pre-production, stress state. By increasing the initial vertical stress, and therefore, decreasing the ratios of horizontal to vertical stress, (referred to as K-H = nu(H)/sigma(V) and K-h = sigma(h)/sigma(V)), the effect of pore pressure depletion on in situ stress components was decreased. The obtained test results imply that, in addition to stress magnitude changes, the stress regime might be locally changed by production due to pore pressure/stress coupling. Furthermore, the rock sample failure in some depletion tests indicates that the pore pressure/stress coupling can be used to describe the production induced seismicity reported in hydrocarbon reservoirs worldwide.",6,6,0
Other topics ,,"Shi, Yan; Hao, Liming; Cai, Maolin; Wang, Yixuan; Yao, Jing; Li, Rui; Feng, Qingshan; Li, Yunhua",High-precision diameter detector and three-dimensional reconstruction method for oil and gas pipelines,Oil and gas pipeline; Deformation; Diameter-detector; Three-dimensional reconstruction; Recognition of elbow-pipe,PIG FLAW DETECTORS; IN-PIPE ROBOT; VELOCITY,"This paper considers the shape detection of the oil and gas-transport pipeline. Currently, deformation of long-distance pipelines has become an urgent problem to the security and capacity of oil and gas transmission, imposing new requirements of a diameter detector of high accuracy and three-dimensional reconstruction functionality. In this paper, high-precision diameter detection technology for use in an oil and gas pipeline is first presented to precisely detect deformation of a pipeline. Next, by detecting the shape of the pipe inner wall and analyzing the attitude and position relationship of the diameter-detector and the pipeline, we developed a three-dimensional reconstruction model of the detected pipeline based on coordinate transformation and the least-squares method. Furthermore, based on the proposed diameter detection technology, a prototype ""DN800 diameter-detector"" is developed for detecting pipeline in both radial and circumferential directions. Finally, an experimental study was performed to verify the availability and accuracy of the detector. The experimental results show that the developed contour detection system of the pipeline is an effective instrument to detect the deformation of oil and gas pipelines.",6,6,1
Other topics ,,"Santos, Lizandro de Sousa; Ferreira de Souza, Kaio Magno; Bandeira, Marina Ribeiro; Ruiz Ahon, Victor Rolando; Peixoto, Fernando Cunha; Prata, Diego Martinez",Dynamic optimization of a continuous gas lift process using a mesh refining sequential method,Optimal control; Mesh refinement; Nonlinear programming,SIMULTANEOUS STRATEGIES; GENETIC ALGORITHM; ALLOCATION; MODEL; FLOW,"Dynamic optimization of gas lift process (GLP) aims to compute control optimal trajectories of gas injection flow rate so that the oil production can be maximized. It has been observed that dynamic optimization of GLP is little discussed in the recent literature since most of the papers have focused on steady state optimization and multi-variable predictive control applications. In this work, a multiple-objective dynamic optimization of a GLP is applied with the goal of maximizing the oil production while minimizing the gas lift amount of a particular process. To this end, a mesh refining sequential method, which transforms the dynamic optimization problem into a finite-dimensional nonlinear program (NLP), was implemented. The main advantages of this approach are accelerating the numerical algorithm convergence and improving the quality of the optimal control profiles. The Pareto curve was obtained from the multiobjective optimization, allowing predicting the set of optimal solutions for the given problem. Numerical examples evidenced that the oil production can be considerably increased with minimal gas consumption.",6,6,1
Other topics ,,"Cayeux, Eric; Shor, Roman; Ambrus, Adrian; Pournazari, Parham; Ashok, Pradeepkumar; van Oort, Eric",From shallow horizontal drilling to ERD wells: How scale affects drillability and the management of drilling incidents,Drilling; Scale; Latency; Drilling incidents,STABILITY,"The context of drilling operations is quite variable in geometric scale and complexity. Wells range from Extended Reach Drilling (ERD) wells with measured depths greater than 10 km to exceptionally shallow wells no longer than 2 km but only 200-300 m in true vertical depth. With the objective of achieving greater levels of drilling automation, it is important to understand how the well geometrical scale impacts drillability and the management of drilling incidents. The robust control of the drilling process necessitates the correct management of delays in the system. Some sources of delay are directly linked to physical dimensions, while others are the results of the system infrastructure. Time delays due to the travel of information through a medium belong to the first category while delays due to signal filtering or processing and actuator latency belong to the second category. The transient response of the drilling system greatly influences the controllability of the drilling process and both the detection and reaction times for drilling incidents such as over-pulls or pack-offs. This paper proposes a categorization of the various sources of delay in a drilling system. A brief review of similar sources of delay in other industries is presented first, and then the sources of delay are characterized into four classes: the elasticity, inertia, and friction of the physical system, measurement refresh rate and latency, processing latency, and maximum actuator acceleration. Delays within these four classes are quantified for three different scenarios: a 10 km-long ERD well, a shallow horizontal well, and a three-dimensional shale well. Illustrative examples of the four classes of delay are presented within these scenarios. Any drilling automation system faces a varying set of constraints for each application, which should influence both the automation procedures themselves as well as sensing requirements. The paper illustrates how scale influences the necessary constraints in drilling procedures, by comparing the delay within the full range of drilling scenarios. Human operator and rig system reaction time and variable awareness to drilling dysfunctions are the most limiting factors in improving drilling efficiency. The automation of drilling procedures with robustness considerations for scale and latency issues therefore plays an important role in increasing drilling performance.",6,6,2
Other topics ,,"Kok, Mustafa Versan; Varfolomeev, Mikhail A.; Nurgaliev, Danis K.",Isoconversional methods to determine the kinetics of crude oils - thermogravimetry approach,Crude oil; Kinetics; Thermogravimetry; Iso-conversional method; Activation energy,THERMAL-BEHAVIOR; COMBUSTION; REGIONS; TG; PYROLYSIS; LIMESTONE; CLAY,"In this research, kinetics of four crude oils from different origins are determined by iso-conversional methods using thermogravimetry data (TGA-DTG). The experiments were performed at three different heating rates (5-10-15 K/min) between 300 and 1200 K. Thermal characteristics of the crude oil samples such as, reaction intervals and corresponding peak and burn-out temperatures are also determined. Three different iso-conversional methods, known as Starink, Kissinger and Friedman are used in order to determine the activation energy values of the crude oil samples studied that represents the novelty of the research. Activation energy values of the crude oil samples are varied between 50 and 102 kJ/mol and 69-132 kJ/mol in low temperature oxidation region and high temperature oxidation region, respectively.",7,7,1
Other topics ,,"Abubakar, A.; Al-Wahaibi, Y.; Al-Wahaibi, T.; Al-Hashmi, A. R.; Al-Ajmi, A.; Eshrati, M.",Effect of pipe diameter on horizontal oil-water flow before and after addition of drag-reducing polymer part II: Holdup and slip ratio,Oil-water; Drag-reducing polymer; Holdup; Slip ratio; Pipe diameter,2-PHASE FLOW,"In this experimental work, the effect of the drag-reducing polymer on the holdup and slip ratio of the oil-water flow in three different horizontal acrylic pipes was investigated. The internal diameters (IDs) of the pipes were 30.6-mm, 55.7-mm and 74.7-mm. The flow conditions of the oil-water flow consisted of 0.4-1.6 m/s mixture velocities and 0.1-0.9 input oil volume fractions. The master solution of the polymer (commercially known as AN 105-SH) was prepared at 2000 ppm concentration and injected into the water phase at controlled flow rates to provide 40 ppm concentration in the phase. The measurement of the holdup was carried out with help of quick closing valves after which the slip ratio was determined. The results showed that the water holdup and by extension, the slip ratio before the addition of the DRP increased with increase in the input oil volume fraction at low mixture velocity while the reverse was the case at high mixture velocity. The addition of the DRP increased the water holdup and the slip ratio only in water-dominated flow regions in all the three pipes. Finally, the increase in the pipe diameter also increased the water holdup and the slip ratio before and after the addition of the DRP in most of the flow conditions.",7,7,1
Other topics ,,"Loyseau, X. F.; Verdin, P. G.; Brown, L. D.",Scale-up and turbulence modelling in pipes,CFD model; Pipe; Turbulence; Simulation; Scale-up; Non-dimensional,NEAR-WALL; FLOW; DEPOSITION; SIMULATION; EPSILON,"Large diameter pipes are commonly used for oil and gas transportation. Experimental and numerical results, including turbulence properties, are often obtained for small diameter pipes. Only little information is available for pipes larger or equal to 200 mm. Results obtained with Reynolds Averaged Navier-Stokes (RANS) turbulence models for single phase flow in pipes of different sizes are presented and discussed. The use of non-dimensional data is usually assumed sufficient to present general information and is assumed valid for any size of pipe. The validity of such assumptions has been checked and the flow behaviour in small, medium and large pipes obtained with several of the most common RANS turbulence models, has been established under specific conditions via Computational Fluid Dynamics (CFD) techniques. Although difficulties were sometimes encountered to reproduce correctly the turbulence properties described in the literature with the turbulence models implemented in open source CFD codes, it is shown that a scaling-up approach is valid as the general flow pattern can be predicted by a non-dimensional strategy.",7,7,1
Other topics ,,"Eghorieta, Raymond A.; Afolabi, Tolani A.; Panacharoensawad, Ekarit",Drift flux modeling of transient high-viscosity-liquid and gas two-phase flow in horizontal pipes,,VOID FRACTION CORRELATIONS; SPLITTING SCHEME; INCLINED PIPES; SIMULATION; PATTERNS; MOTION; TUBES,"The drift flux model was develop by using two mass conservation equation, a single mixture momentum equation, an algebraic slip relationship, and the new closure relationship for the drift velocity for the case of air and high-viscosity-oil in horizontal and near horizontal pipe. The Finite Volume Method (FVM) with staggered grid system was employed. The flux-splitting scheme was used for discretizing the flux term. The explicit Euler method with the consideration of Courant number. The model was solved using a hybrid shock capturing scheme often used for gas dynamics. Totally 31 transient cases were simulated and compared with the transient experimental result of air and high-viscosity oil data. It is the first time in this study to show that the drift flux model is capable of predicting the transient hydrodynamics of the air and high-viscosity oil cases. This model performed reasonably well with average relative error of 13.55% (Standard Deviation of 11.62%) with respect to experimental results.",7,7,1
Other topics ,,"Asim, Taimoor; Algadi, Abdualmagid; Mishra, Rakesh",Effect of capsule shape on hydrodynamic characteristics and optimal design of hydraulic capsule pipelines,Hydraulic capsule pipeline (HCP); Least-cost principle; Optimisation; Shape factor; Solid-liquid flow,PRESSURE-GRADIENT; LOSS COEFFICIENT; VELOCITY RATIO; DIAMETER RATIO; FLOW; TRANSPORT; ELBOWS,"Hydraulic capsule pipelines (HCPs) are the third generation pipelines transporting hollow containers, known as capsules. These capsules are filled with material/cargo to be transported. The shape of these capsules has a significant effect on the hydrodynamic flow characteristics within HCPs. As the variations in the pressure distribution within HCPs are directly linked to and the flow characteristics within pipelines, it is essential to critically evaluate the effect of capsule shape on the pressure drop across the pipeline. Published literature is severely limited in terms of establishing the effects of the shape of the capsules on the flow characteristics within pipelines. Hence, the present study focuses on using a well-validated Computational Fluid Dynamics tool to numerically simulate the flow of capsules of various shapes quantified in form of a novel shape factor in hydraulic capsule pipelines. Both on-shore and off-shore applications of such pipelines have been investigated in the present study, along-with pipe fittings, such as bends. Variations in flow related parameters within these pipelines have been discussed in detail for a wide range of geometrical parameters associated with the capsules and the pipelines. Pressure drop values have been used to develop novel semi-empirical prediction models as a function of the shape factor and other flow and geometric variables of the capsules. These prediction models have been embedded into a pipeline optimisation methodology, which has been developed based on Least-Cost Principle. The resulting novel optimisation methodology can be used for hydraulic capsule pipeline design. Performance charts for practical applications have been developed for easy implementation of the design methodology for the designers of hydraulic capsule pipelines transporting capsule of different shapes.",7,8,5
Other topics ,,"Cheng, Guang-Sen; Yin, Xing-Yao; Zong, Zhao-Yun",Third-order AVO inversion for lame parameter based on inverse operator estimation algorithm,AVO inversion; Third-order; Inverse operator estimation,ZOEPPRITZ EQUATIONS; LINEARIZED AVO; GAS,"Various linearized Zoeppritz approximations are often used in the forward modeling of amplitude variation with offset (AVO). However, they are usually limited by the elastic parameters with weak properties contrast. The high contrast situations between layers will cause big errors when linear approximate equations are used. Given this problem, the more precise third-order Zoeppritz approximate equation for velocity and density is derived in this study. Parameter sensitivity analysis illustrates that the third-order approximate equation for velocity and density is not favorable for nonlinear AVO inversion because the equation is extremely insensitive to S-wave velocity. In consideration of the sensitivity of elastic parameters and the poor inversion results, we derived the third-order approximate equation for Lame parameter. A direct inversion method (Named as inverse operator estimation algorithm) is further used for nonlinear AVO inversion. The L1 norm constraint is considered to improve stability and efficiency during the nonlinear inversion process. The suitability and feasibility of the equation and inversion method can be demonstrated by the synthetic examples. Field data examples show that the inversion results have a good agreement with logging curves.",8,8,0
Other topics ,,"Moncayo, Jose Antonio; Dabirian, Ramin; Mohan, Ram S.; Shoham, Ovadia; Kouba, Gene",Foam break-up under swirling flow in inlet cyclone and GLCC(C),Foam Break-up; Inlet Cyclone; Foam Generation; Centrifugal Force,STABILITY,"Experimental data are acquired on foam stability and break-up efficiency in a 0.025 and 0.05m inlet cyclones and a 0.05m GLCC compact separators. Additional data are collected in a 0.025m inlet cyclone on the effect of increasing surfactant concentrations on foam stability and break-up efficiency. The experimental results show that foam stability increases with increasing surfactant concentration, having an exponential decay effect on foam break-up efficiency in the cyclone. For the 0.05m inlet cyclone and GLCC, at low G, only negligible foam break-up occurs. On the other hand, at high G, higher foam break-up efficiency is achieved. Comparison of the foam break-up efficiency demonstrates a slightly better performance of the GLCC, as compared to the inlet cyclone.",8,8,1
Other topics ,,"Al-Kaabi, Nasser; Al-Ghouti, Mohammad A.; Oualha, Meriam; Mohammad, Mohammad Yousaf; Al-Naemi, Aziza; Solling, Theis I.; Al-Shamari, Noora; Zouari, Nabil",A MALDI-TOF study of bio-remediation in highly weathered oil contaminated soils,Bioaugmentation; Bacillus sonorensis; Bacillus cereus; Pseudomonas sturtzeri; Oil weathering; Hydrocarbon degradation,POLYCYCLIC AROMATIC-HYDROCARBONS; IDENTIFICATION; BACTERIA; PAH,"We have shown that Bacillus cereus is dominating the bacterial population at three polluted oil-industry sites where weather and soil conditions are extreme in terms of temperature, UV-radiation and salinity. A minor part of the bacterial population includes a strain of Bacillus sonorensis and Pseudomonas sturtzeri. Six bacterial isolates were characterized by MALDI-TOF mass spectrometry. The identity of Bacillus sonorensis was also confirmed by ribotyping using molecular techniques. The extreme conditions result in the limited bacterial diversity at the present sites. Our results indicate that the bacteria have sustained because of their ability to degrade low, medium and high molecular weight hydrocarbons in diesel which were removed by up to 89%, 61% and 92%, respectively by Bacillus sonorensis. Bacillus cereus isolates were less effective, but all showed high activity on high molecular weight hydrocarbons. The study is based on growth tolerance to high diesel toxicity and removal of the three ranges of hydrocarbons. Each isolate showed higher hydrocarbon removal efficiencies when applied separately in biopiles in fresh soil compared to weathered soil. Almost 88% and 25% of the diesel range organics and 23% and 83% of the polyaromatic hydrocarbons were removed from the weathered soil versus the clean, respectively, by Bacillus sonorensis. Such efficiencies were obtained with growth stimulation by addition of nitrogen and phosphorus sources and with Tween-80 as a surfactant. The results are key in an application context, since it is clear that overcoming the recalcitrance of weathered hydrocarbon contaminations to biodegradation is a central issue in for example the Arabian Gulf. Moreover the results emphasize that bioaugmentation/biostimulation with bacteria originally adapted to the site conditions is the way forward since endogenous or exogenous hydrocarbon-degrading bacteria generally are not appropriate for applications that involve weathered hydrocarbon spills.",8,13,2
Other topics ,,"Zhang, Naiyan; Zhang, Zhi; Rui, Zhenhua; Li, Jing; Zhang, Cheng; Zhang, Qingsheng; Zhao, Wentao; Patil, Shirish",Comprehensive risk assessment of high sulfur-containing gas well,Well integrity; Risk matrix; AHP; Borda number; Production safety,INTEGRITY; OIL; MANAGEMENT; MODEL; SEA; AHP,"Well integrity has been a growing concern of oil and gas industry, especially in the years of cheap oil. The failure of well integrity may cause undesirable events or even devastating consequences such as safety hazards or loss of containment. In this paper, a novel calculation model of wellbore integrity comprehensive risk has been presented. Firstly, the risk hazard associated with well barrier failure modes are identified based on the relevant literature. The risk factors of well integrity in production phase are investigated in detail. The risk matrix based on Borda number analytical method and Analytic Hierarchy Process (AHP) is then presented to assess the risks of well integrity in production safety. Finally, the case of XX high sour gas well is empirically investigated to validate the model. The results indicate that 27 risk factors are identified for XX gas well in production. In addition, it is found that the XX gas well is prone to suffer damage in presence of H2S and CO2, furthermore, the Borda number analytical results also show that the most important factor affecting the well integrity is effect of string corrosion, followed by the corrosion of string sealing accessories and the corrosion environment of material applicability. Therefore, the appropriate measures should be taken to reduce the corrosion of string and sealing accessories, thus prolonging the service life of the equipment. The case of XX high sour gas field verifies the feasibility and applicability of the risk matrix method in wellbore integrity risk assessment. The innovative assessment method provides methodological reference and guidance for the application of the limited resources, in addition, it also has practical information for well integrity engineers to improve the performance of safety management, thus ensuring well safety during production.",8,8,2
Other topics ,,"Xian, Benzhong; Liu, Jianping; Wang, Junhui; Dong, Yanlei; Li, Yuzhi; Yan, Qi; Liu, Yali","Using of stratal slicing in delineating delta-turbidite systems in Eocene Dongying depression, Bohai Bay Basin: Insights for the evolution of multi-source delta-turbidite systems in a fourth order sequence",Stratal slice; Delta-turbidite system; Fourth-order sequence; Seismic sedimentology; Seismic geomorphology; Bohai Bay Basin,LACUSTRINE RIFT BASINS; SEISMIC GEOMORPHOLOGY; SEDIMENTARY CHARACTERISTICS; EUSTATIC CONTROL; CHINA; MODEL; STRATIGRAPHY; ARCHITECTURE; PALEOGENE; DEPOSITION,"Delta-turbidite systems represent one of most significant targets for hydrocarbon exploration and development. Due to complex stratigraphic architecture of deltas and small scale of delta-fed turbidites, the prediction and characterization of them pose a challenge to successful exploration for hydrocarbons. Through seismic sedimentology approach, 3D seismic and borehole data were used to improve reservoir prediction of the delta-turbidite systems in the Eocene Shahejie Formation, eastern Dongying depression, Bohai Bay Basin, China. A highstand systems tract (HST) is recognized in the Eocene Shahejie Formation in eastern Dongying depression. It is composed of six fourth-order sequences (PSS5 PSS10), each of which corresponds to a given period of delta progradation. Using stratal slicing of 90 degrees-phase seismic data, mapping the fourth stage of delta development (PSS8), as an example, highlights the distribution and evolution of multi-source deltas and their associated thin-bedded turbidites within a fourth-order sequence. Interpretations of stratal slices indicate that the formation of delta-fed turbidites is closely related to base-level changes, sediment supply and syndepositional faults. Development of early larger-scale turbidites fed by north fan delta and Yongan delta suggests that enough sediment supply, rather than base-level falling, plays a more fundamental and critical role for turbidite formation. At the end period of a highstand fourth order sequence, the largest-scale turbidites developed in the front of Dongying delta are jointly driven by both rapid sediment supply and base level falling. This research also proves that the constraint of fourth-order sequences is necessary for ensuring the isochronism of stratal slices, which provide effective reservoir prediction of small-scale delta-fed turbidites and further insights into evolution of multi-source delta-turbidite systems.",8,8,3
