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Multiscale and multiphysics influences on fluids in unconventional reservoirs: Modeling and simulation
Get PDFUnconventional reservoir resources are important to supplement energy consumption and maintain the balance of supply and demand in the oil and gas market. However, due to the complex geological conditions, it is a significant challenge to develop unconventional reservoirs efficiently and economically. At present, unconventional reservoirs are exten-sively studied, covering a wide range of areas, with special attention to the multiscale characterization of pore structures and fracture networks, description of complex fluid transport mechanisms, mathematical modeling of flow properties, and coupled analysis with multiphysics fields. This work briefly describes the multiscale and multiphysics influences on fluids in unconventional reservoirs, and the modeling and simulation work conducted to analyze them, with the aim to provide some theoretical basis for enhanced recovery from these geo-energy resources. The present article also aims to enhance the community’s knowledge of other potential utilizations associated with some unconventional reservoirs, specially related to environmentally-driven projects, including permanent greenhouse gas storage and cyclic underground energy storage.Cited as: Cai, J., Wood, D. A., Hajibeygi, H., Iglauer, S. Multiscale and multiphysics influences on fluids in unconventional reservoirs: Modeling and simulation. Advances in Geo-Energy Research, 2022, 6(2): 91-94. https://doi.org/10.46690/ager.2022.02.0
A phenomenological description of the transient single-phase pore velocity period using the resistance force-velocity relationship
Get PDFA new approach to determine the transient period towards steady state pore flow velocity for fluids propagating through porous media under constant pressure condition is presented. The transient expression relates to the mean pore velocity rather than the fluid pressure conventional considered when characterizing transient behavior in porous media. It is based on the general, resistance force-velocity relationship, and is therefore analogous to the approach used when calculating transient periods for objects falling through resisting air and for the increase in electric currents towards respective steady state values. The transient is caused by inertia forces and characterized by a relaxation time comprising fluid density and viscosity together with porous medium properties as porosity and absolute permeability. Results show that the transient period increases with decreasing medium porosity and fluid viscosity and with increasing fluid density and absolute permeability of the medium. The transient period is negligibly small for typical fluid/medium property values characterizing typical subterrain sandstone reservoirs. Significant transient periods, occasionally observed during laboratory fluid injection tests, are therefore caused by other time-dependent processes not captured by the transient expression presented herein, e.g., fines migration or electrokinetic phenomena.Cited as: Standnes, D. C. A phenomenological description of the transient single-phase pore velocity period using the resistance force-velocity relationship. Advances in Geo-Energy Research, 2022, 6(2): 104-110. https://doi.org/10.46690/ager.2022.02.0
A new mechanism of viscoelastic fluid for enhanced oil recovery: Viscoelastic oscillation
Get PDFThis report summarizes our recent experimental findings [Xie et al., Phys. Rev. Lett., 2022] and pore-scale simulation results [Xie et al., Phys. Rev. Fluids., 2020] on viscoelastic oscillation, which is a new observation of viscoelastic instability in the multiphase flow state. The viscoelastic oscillation causes trapping of droplets in contraction-expansion micro-channels regardless of the injection rate. Based on the force balance analysis on the viscous, capillary and elastic forces, the oscillation amplitude is found to linearly increase with viscoelasticity, and the trapped droplet size is determined by the elasto-capillary number. The oscillation also helps to extract droplets from their originally trapped positions such as dead-ends once a critical Deborah number is reached. These results successfully explain the phenomenon that the alternative injection of viscoelastic and inelastic fluids continually produces additional oil, indicating that the viscoelastic oscillation is a new important mechanism of viscoelastic fluid for enhanced oil recovery.Cited as: Xie, C., Xu, K., Qi, P., Xu, J., Balhoff, M. T. A new mechanism of viscoelastic fluid for enhanced oil recovery: Viscoelastic oscillation. Advances in Geo-Energy Research, 2022, 6(3): 267-268. https://doi.org/10.46690/ager.2022.03.1
Simulation-optimization with machine learning for geothermal reservoir recovery: Current status and future prospects
Get PDFIn geothermal reservoir management, combined simulation-optimization is a practical approach to achieve the optimal well placement and operation that maximizes energy recovery and reservoir longevity. The use of machine learning models is often essential to make simulation-optimization computational feasible. Tools from machine learning can be used to construct data-driven and often physics-free approximations of the numerical model response, with computational times often several orders of magnitude smaller than those required by reservoir numerical models. In this short perspective, we explain the background and current status of machine learning based combined simulation-optimization in geothermal reservoir management, and discuss several key issues that will likely form future directions.Cited as: Rajabi, M. M., Chen, M. Simulation-optimization with machine learning for geothermal reservoir recovery: Current status and future prospects. Advances in Geo-Energy Research, 2022, 6(6): 451-453. https://doi.org/10.46690/ager.2022.06.0
Nanoscale pore and crack evolution in shear thin layers of shales and the shale gas reservoir effect
Get PDFStudies on matrix-related pores from the nanometer to the micrometer scale in shales have made considerable progress in recent decades. However, nanoscale pores and cracks developed in the shear thin layers have not been systematically discussed. In this work, interlayer shear slip occurring in shales are observed through practical examples. The results show that the shear thin layer constructed by nanograin coating is widely distributed on superimposed shear slip planes. Usually, the development of the shear thin layer undergoes viscoelastic-rheological-embrittling deformation stages, and the nanograin texture assembled in the shear thin layer can demonstrate three pore and crack structure types. Based on the mechanical analysis concerning nanoscale cohesion force, it is identified that, as long as force remains a state, the shear thin layer must bear a nanoscale pore and crack character. Furthermore, the shale gas reservoir effect of the nanoscale pore and crack is simply discussed. Obviously, the adsorbed gas effect of the nanograin itself has a larger nanoscale size and surface functionality than those of kerogen and clay particles in the shales; three structure types of the nanoscale pore and crack can act as given controlling factors of storage and permeability for the free gas. Both the matrix-related pores and the three pore and crack structures have an intimate connection with respect to each other in the genetic mechanism and temporal-spatial evolution. This work has important theoretical implications for supplementing the pore and crack classification of shale. Moreover, it makes a significant contribution to shale gas exploration and development.Cited as: Sun, Y., Ju, Y., Zhou, W., Qiao, P., Tao, L., Xiao, L. Nanoscale pore and crack evolution in shear thin layers of shales and the shale gas reservoir effect. Advances in Geo-Energy Research, 2022, 6(3): 221-229. https://doi.org/10.46690/ager.2022.03.0
Modeling of two-phase flow in heterogeneous wet porous media
Get PDFThe characterization of two-phase flow has been commonly based on homogeneous wet capillary models, which are limited to heterogeneous wet porous media. In this work, capillary pressure and relative permeability models for three heterogeneous wet systems are derived, which enable the analysis of the effect of oil-wet ratio on the two-phase flow mechanism. The capillary pressures, relative permeabilities and water cut curves of three systems are simulated at the primary drainage stage. The results show that water-wet and oil-wet systems exhibit drainage and imbibition characteristics, respectively, while heterogeneous wet systems show both of these characteristics, and a large oil- wet ratio is favourable to oil imbibition. Mixed-wet large and mixed-wet small systems have water-wet and oil-wet characteristics, respectively, at the end and the beginning of oil displacement. At the drainage stage, the oil-wet ratio can significantly decrease oil conductivity, while water conductivity is enhanced. The conductivity difference between oil and water firstly decreases and then increases with rising water saturation, and the difference diminishes with the increase in oil-wet ratio. The oil-wet ratio can reduce water displacement efficiency, and its effects on the water cut curves vary between the three systems due to wettability distribution and pore-size mutation. The mixed-wet small system has the strongest oil imbibition ability caused by the largest capillary pressure in oil-wet pores and the smallest drainage pressure in water-wet pores, and high water conductivity causes the greatest water cut. The trend of variations in the mixed-wet large system is opposite to that in the mixed-wet small system, and the fractional-wet system is located between the other two systems.Cited as: Xiao, Y., He, Y., Zheng, J., Zhao, J. Modeling of two-phase flow in heterogeneous wet porous media. Capillarity, 2022, 5(3): 41-50. https://doi.org/10.46690/capi.2022.03.0
A real-time autonomous adjusting process for fluid-fluid displacement in CO2 geological sequestration
Get PDFTo achieve net-zero carbon emission, securely and permanently sequestrating CO2 into deep underground is internationally assured as a robust solution, although a few technical challenges on complex in-situ storage process are yet to be overcome. Despite researchers are increasingly familiar with laboratory-scale CO2-brine displacement and how to characterize and improve the process, field implementation is not that simple and of great challenge. In this article, an opportunity on an approach that utilizes fluid-fluid displacement fundamentals is discussed to predict CO2 sequestration using artificial intelligence. A concept of machine learning is introduced, where computer programs can learn and improve automatically via previous experiences. With machine learning model, fluid displacement behaviors that are spontaneously monitored are emphasized to predict the displacement result, which is readily adjusted if needed while training the model from real-time CO2 injection response. Such an approach is a real-time autonomous adjusting process, consisting of three main stages: Selection of first appraisal fluid for trial injection, real-time machine learning from in-situ injection response, and fluid adjustment if needed or continuation on the same injection until achieving a maximum CO2 storage. This approach could play a vital role in the carbon capture and storage industry to develop CO2 storage effectively with adequate resources, and yet has a potential to substitute a conventional design or fluid screening approach for subsurface fluid injection, including underground hydrogen storage and hydrocarbon recovery.Document Type: PerspectiveCited as: Tangparitkul, S. M., Chantapakul, W., Promsuk, N. A real-time autonomous adjusting process for fluid-fluid displacement in CO2 geological sequestration. Advances in Geo-Energy Research, 2023, 7(2): 71-74. https://doi.org/10.46690/ager.2023.02.0
Exploring the mysteries of deep oil and gas formation in the South China Sea to guide Palaeocene exploration in the Pearl River Mouth Basin
Get PDFDeep oil and gas resources in the South China Sea have drawn increasing attention in recent years, involving several essential challenges such as favorable zone prediction, deep burial, poor data quality, non-homogeneous reservoir properties, low drilling rate, and the low research degree of Paleozoic strata. These issues vastly affect the exploration and development of deep oil and gas resources in this area. Specifically, the Lufeng and Huizhou Depressions exhibit rich hydrocarbon accumulation and distribution areas in the Pearl River Mouth Basin, thereby possess great resource potential. The seven papers discussed here propose a set of practical techniques that can be applied to the exploration of deep Paleogene in the shallow layers of the Pearl River Mouth Basin. All of these works make important contributions deepening the theory of Paleogene reservoir formation and promoting further exploration of Paleogene in the Pearl River Mouth Basin, to increase the hydrocarbon storage and production prospects.Cited as: Pang, X., Li, H., Pang, H. Exploring the mysteries of deep oil and gas formation in the South China Sea to guide Palaeocene exploration in the Pearl River Mouth Basin. Advances in Geo-Energy Research, 2022, 6(5): 361-362. https://doi.org/10.46690/ager.2022.05.0
Hydrocarbon accumulation model based on threshold combination control and favorable zone prediction for the lower Enping Formation, Southern Lufeng sag
Get PDFDeep complex oil and gas reservoirs are the future directions of oil and gas exploration. The exploration potential of Paleocene deposits in the Lufeng sag is enormous. However, due to the greater burial depth and complex oil and gas accumulation conditions of the Paleocene, few large-scale reservoirs have been discovered and the next exploration strategy is unclear. In this study, based on the Paleocene geological data of the Southern Lufeng sag, a model of hydrocarbon accumulation based on functional element control is constructed using geostatistical and numerical simulation techniques. The hydrocarbon accumulation elements, thresholds, boundaries and scopes are clarified, and the favorable zones of hydrocarbon accumulation of the lower Enping Formation are predicted using the model of hydrocarbon accumulation based on threshold combination control. The results indicate that the source rock, reservoir, caprock, and low-potential area are the four functional elements controlling hydrocarbon accumulation. Since there are three types of low-potential zones, a total of six accumulation elements are considered to control hydrocarbon accumulation, and the corresponding hydrocarbon accumulation control thresholds are determined by the model of hydrocarbon accumulation according to the controlling effects of these accumulation elements. The predicted Type I favorable zones are located in the eastern part of Lufeng 13 east sub-sag and the northern and southern parts of Lufeng 7 sub-sag; Type II favorable zones are located in the western part and around the Lufeng 13 east sub-sag; Type III favorable zones are adjacent to Type II favorable zones. The hydrocarbon shows are all located in the overlapping zone of five or more accumulation elements.Cited as: Zhang, L., Pang, X., Pang, H., Huo, X., Ma, K., Huang, S. Hydrocarbon accumulation model based on threshold combination control and favorable zone prediction for the lower Enping Formation, Southern Lufeng sag. Advances in Geo-Energy Research, 2022, 6(5): 438-450. https://doi.org/10.46690/ager.2022.05.0
Capillary and viscous forces during CO2 flooding in tight reservoirs
Get PDFIn this study, the multiphase multicomponent Shan-Chen lattice Boltzmann method is employed to analyze the impact of capillary force on oil-CO2-water fluid flow and enhanced oil recovery. Various sizes of the single throat are designed to simulate the interaction between displacing and displaced phases as well as their mechanical equilibrium. Several sensitivities are taken into account, such as wettability, miscibility, interfacial tension, and pore aperture. Based on the objective reservoir conditions, supercritical CO2 as an injection fluid is adopted to study the influence of different displacement patterns on the mechanical equilibrium in both homogenous and heterogeneous porous media, in which enhanced oil recovery is also quantitatively estimated. The results show that the water-alternating-gas injection pattern reduces the moving speed of the leading edge by increasing the swept area of the residual oil, and inhibits the breakthrough effect of the gas, making it the optimal displacement method in terms of the degree of oil production. Compared with the results of different displacement patterns, the enhanced oil recovery of water-alternatinggas injection is the highest, followed by supercritical CO2 flooding after water flooding, and lastly, continuous supercritical CO2 flooding.Cited as: Zhang, C., Zhang, Q., Wang, W., Xie, Q., Su, Y., Zafar, A. Capillary and viscous forces during CO2 flooding in tight reservoirs. Capillarity, 2022, 5(6): 105-114. https://doi.org/10.46690/capi.2022.06.0