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Collaborating Authors
Fluid modeling, equations of state
Development of a Scalable Parallel Compositional Simulator for Thermo-Hydromechanical Coupling in Fractured Rocks Using an Embedded Discrete Fracture Model
Wang, Tong (School of Petroleum Engineering, China University of Petroleum (East China) / National Key Laboratory of Deep Oil and Gas, China University of Petroleum (East China) / Department of Chemical & Petroleum Engineering, University of Calgary) | Sun, Zhixue (School of Petroleum Engineering, China University of Petroleum (East China) / National Key Laboratory of Deep Oil and Gas, China University of Petroleum (East China)) | Sun, Hai (School of Petroleum Engineering, China University of Petroleum (East China) / National Key Laboratory of Deep Oil and Gas, China University of Petroleum (East China)) | Chen, Zhangxin (Department of Chemical & Petroleum Engineering, University of Calgary) | Yao, Jun (School of Petroleum Engineering, China University of Petroleum (East China) / National Key Laboratory of Deep Oil and Gas, China University of Petroleum (East China) (Corresponding author))
Department of Chemical & Petroleum Engineering, University of Calgary Summary Numerical simulation of thermo-hydromechanical (THM) coupling in practical complex fractured rocks is an essential but challenging issue for the evaluation and optimization of underground energy production. In this study, we present our work on a scalable parallel compositional simulator for THM coupling, which is suitable for massive 3D polygonal fractures. In addition, we also present the improvements, parallel implementation, and optimization of an embedded discrete fracture model (EDFM). A unified cell-centered grid system based on the finite volume method (FVM) is used for all governing equations, and an extended stencil is adopted for mechanical equations to resolve the low-resolution defect of the traditional FVM. The deformation of both matrix rock and fractures is considered. A sequential fully implicit (SFI) method is adopted to solve THM coupling. This simulator is validated against three analytical solution models. We also test the performance and parallel scalability on 1,024 CPU cores with up to 50 million matrix gridblocks and 5.5 million fracture gridblocks. The results show that this simulator can efficiently solve the THM coupling problem in practical massive fractures. Introduction Multiphysics coupled flows in underground fractured rock occur widely in a variety of energy development scenarios (Lei et al. 2017), such as extracting heat from geothermal reservoirs, CO In the subsurface, fracture systems have a significant impact on physical processes, and the fluid flow conductivity in fractures is typically three orders of magnitude higher than that in the matrix rock. The fracture systems can control the distributions of pore pressure and temperature, and the changes in these physical fields will affect the mechanical behavior of the fractures reversely and then affect the conductivity of the fractures.
- North America > United States (0.46)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.24)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Effect of Surface Wettability on the Miscible Behaviors Of Co2-Hydrocarbon in Shale Nanopores
Feng, Dong (China University of Petroleum, Beijing) | Chen, Zhangxin (University of Calgary) | Zhang, Zenghua (CNOOC Research Institute Co. Ltd.) | Li, Peihuan (China National Oil and Gas Exploration and Development Company Ltd.) | Chen, Yu (China Oilfield Services Limited) | Wu, Keliu (China University of Petroleum, Beijing) | Li, Jing (China University of Petroleum, Beijing)
Abstract The minimum miscible pressure (Pm) of CO2-hydrocarbon mixtures in nanopores is a key parameter for CO2-enhanced shale oil recovery. Although the miscible behaviors of CO2-hydrocarbon mixtures in nanopores have been widely investigated through the simulations and calculations, the heterogeneity of shale components with different affinity to hydrocarbons results in the deviation of traditional predictions and motivates us to investigate how the surface properties influence the CO2-hydrocarbon miscible behaviors in nanopores. In this work, we established a model and framework to determine the wettability-dependent physical phenomena and its impact on the Pm of CO2-hydrocarbon in shale nanopores. First, a generalized scaling rule is established to clarify the potential correlation between critical properties shift and wettability based on the analysis of microscopic interactions (fluid-surface interactions and fluid-fluid interactions). Second, a wettability-dependent SKR EOS is structured and a generalized and practical framework for confined phase behavior with different surface wettability is constructed. Subsequently, the Pm of CO2-hydrocarbon mixtures in confined space with various wettability is evaluated with our model. The calculated results demonstrate that the nanoconfined effects on Pm not only relate to the pore dimension but also depend on the contact angle. In an intermediate-wet nanopore, the minimum miscible pressure approaches the bulk value. In an oil-wet nanopore with a width smaller than 100nm, the minimum miscible pressure is suppressed by the confined effects, and the reduction is further strengthened with a reduction in pore dimension and increase of wall-hydrocarbon affinity. Our work uses a macroscopically measurable parameter (contact angle) to characterize the shift of critical properties derived from the microscopic interactions, and further construct a generalized and practical framework for phase behavior and minimum miscible pressure determination in nanopores with different surface properties. The method and framework can make a significant contribution in the area of upscaling a molecular or nanoscale understanding to a reservoir scale simulation in shale gas/oil research.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (5 more...)
Abstract This paper investigates the influencing factors on the liquid recovery from the Duvernay Shale Condensate Reservoirs by using reservoir simulation methods with multi-fracked horizontal wells and gas recycling injection. In the simulation of case studies, three key factors (nano-confinement, adsorption, and diffusion effects) related to the gas condensate phase behavior and liquid recovery are simultaneously considered and quantified. The outcomes of this study create an efficient approach to identify sweet spots with high liquid recovery from the Duvernay shale condensate by evaluating these three factors. As widely known, liquid recovery from shale is very low, which is different from conventional reservoirs. It is believed that phase behaviors of gas condensate are changed significantly by a confinement effect, causing gas production performance in shale different from that in the conventional formations. Hence, multi-mechanistic flow regimes are employed in a dual porosity/dual permeability model, including matrix and fractures, to simulate the gas condensate flow mechanisms in the Duvernay shale. The nano-confinement, adsorption and diffusion effects on the gas condensate phase behavior are simultaneously considered in the simulations. Using the Duvernay shale condensate properties with an equation of state (EOS) model, the nano-confinement effect works better when a pore diameter is less than or equal to 4 nm. Simultaneously considering the nano-confinement, adsorption and diffusion effects, the total liquid recovery is increased by 49% in five years of production. The gas recycling injection operation permits to inject dry gas separated from the condensate fluids. The gas condensate phase behavior is significantly affected by both pressure and concentration gradients because the matrix permeability is extremely low in shale. Through adjusting field operations with favorable production-injection ratios, the optimization of improving liquid recovery is definitely achieved.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Vapor-Liquid Equilibria and Diffusion of CO2/n-Decane Mixture in the Nanopores of Shale Reservoirs
Dong, Xiaohu (China University of Petroleum Beijing) | Chen, Zhongliang (China University of Petroleum Beijing) | Chen, Zhangxin (University of Calgary) | Wang, Jing (China University of Petroleum Beijing) | Wu, Keliu (China University of Petroleum Beijing) | Li, Ran (University of Calgary) | Li, Li (PetroChina Coalbed Methane Company Limited)
Abstract Numerous laboratory tests on the Northern American shale plays have observed a large number of nanopores. Because of the pore-proximity effect, the vapor-liquid phase equilibrium and transport performance of fluids in nanopores differ significantly from that observed in PVT cell. In recent years, CO2 huff-and-puff has been widely applied to unlock the shale reservoirs. But on account of the high adsorption selectivity of CO2, after the injection of CO2, the original vapor-liquid equilibria of hydrocarbons is changed. The purpose of this study is to predict the phase behavior and diffusion of the CO2/n-decane mixtures in the nanopores. The Peng-Robinson (PR) equation of state is combined with Young-Laplace equation to calculate the phase-composition diagram at the presence of capillary pressure. The equilibrium molecular dynamics simulations (MDS) are also conducted to study the phase behavior, and the number density profiles of different molecules are calculated. Then, based on the discussion of phase behavior, a series of equilibrium MDS runs are carried out to calculate the self-diffusion coefficients of CO2, n-decane, and all fluid molecules. For each MDS with a different CO2 mass fraction, the two types of fluid molecules are thoroughly mixed, the conditions of pore size and temperature are consistent with those in the phase behavior studies. Results indicate that considering the capillary pressure, when the mass fraction of CO2 is less than 40%, the bubble point suppression is more clearly shown in the phase envelope. The number density profiles of n-decane molecules show the apparent characteristics of adsorption layers. As the mass fraction of CO2 molecules increases, the self-diffusion coefficients of CO2, n-decane, and their mixtures all increase. The self-diffusion coefficients of CO2 molecules are higher than that of the n-decane molecules, and the diffusion coefficients of the entire fluid system are somewhere in between. Appropriate CO2 injection into shale oil reservoirs can not only reduce the confinement-induced bubble point suppression but also improve the flow behavior of oil in nanopores. This study can shed some critical insights for the vapor-liquid phase equilibria of confined fluids in nanopores and provide sound guidelines for the application of CO2 huff and puff in shale reservoirs.
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Confined Behavior of Hydrocarbon Fluids in Heterogeneous Nanopores by the Potential Theory
Dong, Xiaohu (China University of Petroleum, Beijing) | Luo, Qilan (China University of Petroleum, Beijing) | Wang, Jing (China University of Petroleum, Beijing) | Liu, Huiqing (China University of Petroleum, Beijing) | Chen, Zhangxin (University of Calgary) | Xu, Jinze (University of Calgary) | Zhang, Ge (Sinopec Shengli Oilfield)
Abstract Nanopores in tight and shale reservoirs have been confirmed by numerous studies. The nanopores are not only the primary storage space of oil and gas, but also the main transport channels of confined fluids. Although considerable efforts have been devoted to study the confined behavior of hydrocarbon fluids in nanopores, most of them have a local smooth-surface assumption. The effect of pore heterogeneity is still lacking. In this paper, in order to effectively simulate the nanopore complexity, we propose the assumptions of furrowed surface and sinusoidal surface to represent the heterogeneous nanopores (or rough nanopores) in tight and shale rocks. Then, based on these assumptions, the multicomponent potential theory of adsorption (MPTA) is coupled with the Peng-Robinson equation of state (PR EOS) to investigate the behavior of hydrocarbon fluids in rough nanopores. In this theory, considering the different types of nanopore heterogeneity, the geometrical heterogeneity is modeled by a spatial deformation of the potential field, and the chemical heterogeneity is modeled by an amplitude deformation of this field. The fluid-fluid interactions are modeled by the PR EOS, and the fluid-surface interactions are modeled by a Steel 10-4-3 potential for slit-like nanopres and a modified Lennard-Jones (LJ) 12-6 potential for cylindrical nanopores. Then a prediction process for the behavior of methane, ethane, propane and their mixtures is performed. The results are compared against the experimental data of their adsorption isotherms from publishd literatures to validate the accuracy of the theory and process. Then, the effect of pore heterogeneity on the confined behavior of methane, ethane, propane is quantitatively studied. Results indicate that for the experimental data considered in this work, the theory for heterogeneous nanopores is capable of predicting the confined behavior of hydrocarbons in a wide range of pressure and temperature. The developed mathematical model can well predict the confined behavior of fluids both in slit-like and cylindrical nanopores. Compared with the results of a smooth pore surface, the geometrical heterogeneity can significantly affect the thermodynamic properties of hydrocarbon fluids, but the chemical heterogeneity cannot strongly distort the confined behavior of fluids. The effect of geometrical heterogeneity on the confined behavior of fluids mainly depends on the effective pore size. In hydrocarbon fluids, as the composition of heavy components increase, the effect of heterogeneity on the confined behavior of fluids is reduced. Also, as the nanopore size reduces, the effect of pore heterogeneity on the confined behavior of fluids is enhanced. For fluid mixture, compared with smooth surfaces, it is observed that for heterogeneous surface, the mole fraction of the heavy component in the vicinity of pore wall can increase significantly, and that of the light component is reduced. This investigation makes it possible to completely characterize the confined behavior of a confined fluid in heterogeneous nanopores.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (9 more...)
Confined Behavior of CO2/Hydrocarbon System in Nanopores of Tight and Shale Rocks
Dong, Xiaohu (China University of Petroleum Beijing) | Liu, Huiqing (China University of Petroleum Beijing) | Wu, Keliu (China University of Petroleum Beijing) | Liu, Yishan (China University of Petroleum Beijing) | Qiao, Jiaji (China University of Petroleum Beijing) | Gao, Yanling (China University of Petroleum Beijing) | Chen, Zhangxin (University of Calgary)
Abstract The presence of nanopores in tight and shale rocks has been confirmed by numerous studies. Due to the pore-proximity effect, the confined behavior of fluids in nanopores differs significantly from that observed in PVT cell. Currently CO2 huff-and-puff has been used to unlock the tight and shale reservoirs. Because of the high adsorption selectivity of CO2, after the injection of CO2, the original fluid density and composition of hydrocarbons in nanopores has been changed. In this paper, the PR-SLD model is applied to investigate the confined behavior of pure CO2/hydrocarbon fluids and their mixtures in nanopores. The Leeโs partially integrated 10-4 potential model is used to represent the solid-fluid interaction. For mixtures, a group contribution method is used to estimate the binary interaction parameters of CO2/hydrocarbon mixture. Thereafter, from the results of density distribution across the nanopore, the adsorption amount of fluids can be derived. Based on this model, a prediction process for the behavior of pure CO2 and hydrocarbon fluids (of methane and ethane) and their mixtures is performed. Results indicate that the adsorption selectivity of CO2 is much higher than CH4 and C2H6. And the density of pure CO2 in nanopores is higher than that of CH4 and C2H6. For binary mixture, because of the difference of interaction energy, the mole fraction of CO2 molecular is gradually increased from pore center to pore surface, and that of the hydrocarbon molecular is reduced from pore center to pore surface. The composition difference between bulk fluids and adsorbed fluids of CO2-C2H6 mixture is lower than that of CO2-CH4 mixture. For ternary mixture, the mole fractions of CO2 and C2H6 are always increasing from pore center to pore surface, and the mole fraction of CH4 is decreased from pore center to pore surface. Compared the original pure hydrocarbon mixtures, the addition of CO2 further increases the density of bulk fluids and adsorbed fluids. This study sheds some important insights for the behavior of confined fluids in nanopores and provides sound guidelines for the application of CO2 huff and puff in tight and shale reservoirs.
- North America > Canada > Alberta (0.29)
- North America > United States > North Dakota (0.28)
- Asia > Middle East > UAE (0.28)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (0.87)
Abstract Shale gas is a very important energy resource for humans in the 21st century. However, the mechanism underlying the transoport behavior of shale gas in nanopores (typically 1 nm to 100 nm) remains a huge challenge in industries, as well as in research. In this study, we investigated the free gas transport in nanopores of shale rocks by using the real gas equation of state (EOS) and elastic hard-sphere (HS) model. Excellent results were obtained from the validation of the real gas model on the basis of molecular simulation and experimental data. This paper discusses the following: (1) the model efficiently and reasonably describes the known gas transport behavior in nanopores by establishing the relationship among real gas effect, molecular interactions and collisions, and gas transport behavior; (2) the use of real gas HS EOS considers repulsion, which reduces Knudsen diffusion and laminar slip flow conductance. In addition, packing fraction in EOS provides minimum boundaries for Knudsen number and flow regime; (3) the molecule-wall collision is mainly dominated by pore diameter, and the intermolecular collision is mainly dominated by pressure in nanopores. Under 10 MPa, the molecule-wall collision dominates in nanopores. Otherwise, the intermolecular collision dominates; (4) the laminar slip flow conductance increases with the corresponding increase in strength of intermolecular collision. With increased strength in the molecule-wall collision, Knudsen diffusion conductance increases, thereby improving the transport efficiency, as shown by apparent permeability.
- North America > Canada > Alberta (0.68)
- North America > Canada > British Columbia (0.46)
- North America > United States > Texas (0.46)
Abstract In the petroleum industry, accurately estimating wellbore heat loss in thermal recovery processes remains a critical problem. One difficulty lies in simulating heat transfer and fluid dynamics within wellbore annuli. A literature survey shows that the state-of-the-art thermal wellbore simulators use empirical correlations to calculate the heat loss through wellbore annuli. As more sophisticated wells have been drilled, there is a growing need for a more detailed wellbore annulus heat transfer model. In this study, a 2D transient mathematical model is proposed for the conjugate natural convection and radiation within wellbore annuli. The governing equations consist of a continuity equation, a vorticity transfer equation, an energy transport equation and a radiative transfer equation (RTE). A finite volume approach with a second-order upwinding scheme is implemented for discretization. Newton-Raphson iterations are deployed for linearization. The algorithm is validated by consistence in simulation results compared with benchmark numerical solutions with the Rayleigh number up to 10. Parameters such as an aspect ratio, a radius ratio and a conduction-to-radiation coefficient are examined. A case study on vacuum insulated tubing heat transfer using Marlin Well A-6 data demonstrates the merits of the developed program by the consistence of simulation results compared with field measurements.
- North America > United States (0.68)
- North America > Canada > Saskatchewan (0.28)
- Research Report > New Finding (0.66)
- Overview (0.48)
A Parallel Thermal Reservoir Simulator on Distributed-Memory Supercomputers
Zhong, He (Dept. of Chemical and Petroleum Engineering, University of Calgary, 2500 University Drive NW, Calgary, AB) | Liu, Hui (Dept. of Chemical and Petroleum Engineering, University of Calgary, 2500 University Drive NW, Calgary, AB) | Cui, Tao (State Key Laboratory of Scientific and Engineering Computing, Academy of Mathematics and Systems Science, Chinese Academy of Sciences) | Wang, Kun (Dept. of Chemical and Petroleum Engineering, University of Calgary, 2500 University Drive NW, Calgary, AB) | Yang, Bo (Dept. of Chemical and Petroleum Engineering, University of Calgary, 2500 University Drive NW, Calgary, AB) | Yang, Min (Dept. of Chemical and Petroleum Engineering, University of Calgary, 2500 University Drive NW, Calgary, AB) | Chen, Zhangxin (Dept. of Chemical and Petroleum Engineering, University of Calgary, 2500 University Drive NW, Calgary, AB)
Abstract This paper describes the algorithms and implementation of a parallel thermal reservoir simulator designed for heavy oil simulation using distributed-memory supercomputers that can solve prohibitive problems efficiently. The thermal simulator inherits the features of a sequential thermal simulator. The performance of supercomputers is proportional to the number of CPUs. As a result, thermal problems can be solved thousands of times faster using supercomputers. This parallel simulator is based on our in-house platform, which provides grid management, data management, linear solvers and a visualization module. The exchange of information between CPUs is achieved by using the message passing interface standard, MPI. Results indicate that this simulator exhibits excellent scalability on the IBM Blue Gene/Q system and is thousands of times faster than serial simulators on a workstation. The simulator is also capable of simulating models with billions of grid blocks and fine resolution results can be obtained.
- Asia > Middle East (0.93)
- North America > United States > Texas (0.69)
A Universal Model of Water Flow Through Nanopores in Unconventional Reservoirs: Relationships Between Slip, Wettability and Viscosity
Wu, Keliu (University of Calgary) | Chen, Zhangxin (University of Calgary) | Xu, Jinze (University of Calgary) | Hu, Yuan (University of Calgary) | Li, Jing (China University of Petroleum) | Dong, Xiaohu (China University of Petroleum) | Liu, Yuxuan (Southwest Petroleum University) | Chen, Mingjun (Southwest Petroleum University)
Abstract Understanding and controlling flow of the water confined in nanopores has tremendous implications in theoretical studies and industrial applications. Here we propose a universal model for the confined water flow based on a conception of effective slip, which is linear sum of true slip, only depending on wettability, and apparent slip, caused by the spatial variation of the confined water viscosity as a function of wettability as well as nanopores dimension. Results by the model show that the flow capacity of the confined water is 10~10 times of those calculated by no slip Hagen-Poiseuille equation for nanopores with various wettability, in agreement with 47 different cases from the literature. This work may shed light on the controversy over the increase or decrease in flow capacity from the MD simulations and experiments, and guide to tailor the nanopores structure for modulating the confined water flow in many engineering fields, including nanomedicine, water purification, energy storage as well as the flowback of fracture fluid in petroleum industry.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)