The global transition toward renewable energy systems has established hydrogen as a promising energy carrier, with Underground Hydrogen Storage (UHS) in geological formations emerging as a solution for large-scale storage. While understanding hydrogen behavior in geological formations is crucial, modeling mutual solubility in hydrogen-brine systems, particularly in complex brines under UHS conditions, remains challenging. This study presents an enhanced thermodynamic model for predicting mutual solubility in hydrogen-brine systems under deep geological formation conditions. Our approach combines the Peng-Robinson equation of state for non-aqueous phase fugacity calculations with the Pitzer model for aqueous phase activity determination, incorporating comprehensive interaction parameters and multi-phase equilibria under elevated pressure and temperature conditions. Model validation against experimental data demonstrates superior accuracy compared to existing approaches, especially in complex brine systems with multiple ionic species. Furthermore, the model extends predictions to temperature and pressure conditions beyond available experimental data. This work establishes a robust framework for understanding hydrogen behavior in geological formations, enabling accurate prediction of phase equilibria critical for assessing and mitigating risks like salt precipitation. These capabilities enhance evaluation of long-term hydrogen injectivity and storability, advancing the development of safe and efficient UHS systems.

The vertical transfer of overpressure significantly influences the subsurface fluid dynamics, fault zone stability, and geomechanical drilling safety. However, the mechanisms governing vertical overpressure transfer through faults remain poorly understood, and few quantitative assessments have clarified how key geological parameters control the magnitude and evolution of vertically transferred overpressure. In this study, a conceptual model for overpressure vertical transfer was developed, and a sensitivity analysis of geological factors controlling this process was conducted using the DMflow simulator. The results indicate that fault-zone permeability, fault activity duration, sand body permeability, the number of sand bodies connected by a fault, and the initial overpressure difference exert a strong control on both the transfer process and the magnitude of the vertically transferred overpressure. In contrast, the fault dip and sand body spacing have a relatively minor influence on the vertical transfer overpressure. In permeable formations, vertically transferred overpressure dissipates rapidly; therefore, overpressure generated by multiple fault activation events cannot be effectively accumulated. The overpressure is uniform within permeable formations connected by a fault; however, the pressure coefficient is highest in the shallow formation. Overpressure transfer alters local fluid migration pathways. During overpressure re-equilibration, the development of a strong fluid potential gradient promotes the rapid upward migration of deep fluids into shallower layers along the fault. This understanding not only provides new insights into the mechanisms of overpressure generation in sedimentary basins but also has significant implications for predicting pre-drilling formation pressure and improving the understanding of fluid flow behavior within fault zones.

Reservoir geological modeling plays a crucial role in characterizing the spatial distribution and heterogeneity of subsurface reservoirs. The exploration of deep oil and gas resources is not only a global trend in the oil industry but also an inevitable choice for China to ensure energy security and achieve sustainable development in the oil and gas industry. Oil and gas exploration and development technologies have also made continuous breakthroughs, providing strong support for the sustained increase in China’s deep and ultra-deep oil and gas production. Deep and ultra-deep oil and gas reservoirs exhibit high levels of heterogeneity, which are governed by the original sedimentation processes and have a significant impact on oil and gas migration and accumulation. However, traditional pixel-based stochastic reservoir modeling encounters challenges when attempting to effectively simulate multiple facies simultaneously or objects with intricate internal hierarchical architectures. To address the characterization of highly heterogeneous deep and ultra-deep oil and gas reservoirs, this study defines unit architecture bodies, such as point bars, braided rivers, and mouth bars, incorporating internal nested hierarchies. Furthermore, a novel object-based stochastic modeling method is proposed, which leverages seismic and well logging interpretation data to construct and simulate reservoir bodies. The methodology is rooted in the unit element theory. In this approach, sedimentary facies models are stochastically constructed by selecting appropriate unit elements from a database of different sedimentary environments using Sequential Indicator Simulation. The modeling process is constrained by time sequence, event, and sedimentary microfacies distributions. Additionally, the porosity and permeability of each microfacies in the reservoir model are quantitatively characterized based on statistics derived from porosity and permeability data of different strata, sedimentary microfacies, and rock facies in the study area. To demonstrate the superiority and reliability of this novel modeling method, a modeling case is presented. The case utilizes braided river unit elements as objects for the stochastic simulation of the target reservoir. The results of the case study highlight the advantages and robustness of the proposed modeling approach.

Increasing oil recovery technology is crucial for the sustainable growth of the petroleum industry and the assurance of energy security. Dimethyl ether (DME) has emerged as a potential candidate to further enhance the efficiency of water/CO2 flooding processes. However, developing a reliable and accurate multiphase equilibrium calculation package that meets the high efficiency and robustness standards required for reservoir simulation in DME-enhanced water/CO2 flooding remains a significant challenge. This study presents a comprehensive multiphase equilibrium calculation framework specifically designed for H2O/brine-CO2-DME-hydrocarbon systems. The Peng-Robinson (PR) equation of state (EOS) combined with the Huron-Vidal (HV) mixing rule is used to predict phase behavior accurately. The framework incorporates several key components: (1) an improved model for saline systems to enhance computational efficiency; (2) innovative stability analysis strategies to ensure robustness; (3) a salt precipitation module to address water vaporization scenarios; and (4) a numerical solver that integrates successive substitution iteration (SSI) with the trust region (TR) method to secure computational efficiency. Extensive testing involving millions of data points has demonstrated the accuracy, robustness, and efficiency of our algorithm. This framework serves as a powerful tool for phase equilibrium calculations in complex reservoir systems, facilitating more effective simulation and optimization of DME-enhanced water/CO2 flooding operations.

The intensifying global climate change has prompted the imperative implementation of CO2 capture and storage (CCS) projects as a mitigation strategy. Ensuring the safety and reliability of these projects requires meticulous validation, including the establishment of geological models and conducting numerical simulations. In CO2 geological storage initiatives, the limitation of well data during the initial stages leads to data deficiency. This scarcity compromises the precision of geological and numerical models, hindering their ability to accurately depict actual subsurface conditions. Meanwhile, parameters related to heterogeneity significantly also impact storage effectiveness and safety. This study addresses these challenges by utilizing the Shenhua CCS demonstration project as a case study. Various heterogeneous parameters are selected, and local and global sensitivity analysis methods are subsequently introduced to determine the ranges and sequences of these parameters in numerical simulations. The simulation results can aid in assessing the influence of various heterogeneous parameters on the CO2 plume and bottom hole pressure. The study establishes the importance ranking of various heterogeneous parameters under different temporal and spatial conditions through sensitivity analysis. The findings reveal the following key points:1. During the small-scale injection period, the CO2 plume is particularly sensitive to variations in net-to-gross and vertical permeable properties.2. During and after larger-scale injections, the net-to-gross significantly impacts plume evolution, while bottom hole pressure is predominantly influenced by variations in vertical permeable properties.3. Both the CO2 plume and well bottom pressure are primarily affected by changes in sand body morphologies, especially at low net-to-gross scenarios.These conclusions assist in prioritizing the collection of critical parameter data in CCS projects, facilitating the establishment of more precise and reliable geological and numerical simulation models. The heightened accuracy and reliability of these models contribute to improving their predictive capabilities, ultimately guiding engineering practices.

A three-dimensional invasion percolation simulation model is introduced and integrated into a novel three-dimensional geological modeling framework based on the “unit element” theory to study secondary hydrocarbon migration. Leveraging the computational efficiency inherent in the invasion percolation theory, the simulation method is effectively applied to basin-scale hydrocarbon migration using finely discretized grids. Sensitivity analysis demonstrates the substantial influence of geological parameters including structural configuration, sedimentary facies, and pressure, on simulation results. Noteworthy observations from this study encompass: (1) The intricate influence of sedimentary facies and petrophysical properties characteristics on hydrocarbon migration and accumulation patterns within structural and lithological traps. Favorable petrophysical attributes in the carrier beds enhance the likelihood of accumulation in the structural traps, while lithological traps are prevalent in less conducive carrier beds. (2) The significant impact of sand bodies exhibiting favorable petrophysical attributes, such as channels, on migration and accumulation profiles. This underscores the necessity of incorporating sedimentary facies and rock attributes into oil and gas resource exploration. (3) The pronounced effects of overpressure magnitude and direction on hydrocarbon migration and accumulation dynamics. (4) Optimal strategies for oil and gas resource exploration necessitate a comprehensive assessment of rock attributes, overpressure considerations, and sedimentary facies. The practical implementation of this methodology is demonstrated in an actual exploration project within China's Junggar Basin. The simulation results closely align with established oil recovery data and facilitate predictive identification of promising exploration areas. This indicates the methodology is applicable to all petroleum systems similar to Junggar Basin. Through practical applications, the development of a scientifically rigorous three-dimensional geological model for the study area, coupled with numerical simulations of oil and gas migration, facilitates the elucidation of accumulation patterns. This approach aids in identifying pivotal factors such as sand body distribution, internal structural composition, permeability attributes, and fracture behavior, which collectively influence oil and gas migration. Furthermore, by correlating insights obtained from oil and gas discoveries in wells, a deeper understanding of carrier bed properties and their geological evolution is attained.

The heterogeneity of siliciclastic carrier beds is characterized by the compartmentalization of low permeability interbeds. A geo-logic and fluid dynamic model of siliciclastic carrier beds with architectural heterogeneity was constructed to numerically sim-ulate and analyze the characteristics of oil and gas migration and accumulation. The formation and distribution of hydrocarbon migration pathways and eventual accumulations are strongly heterogeneous, forming a pattern that is significantly different from those in macroscopically homogeneous models. In carrier beds with architectural heterogeneity, hydrocarbons generally migrate upward and in the updip direction. However, the verti-cal migration pathways are commonly blocked and deviated by low-permeability barriers, so that lateral migration pathways and local accumulations can occur in any part of the carrier beds. The updip structural traps are still the favorable target of migration, but hydrocarbons can accumulate anywhere as small pools along the pathways from the source to trap. Although the volume of individual pools is small, the pools are numerous and widely distributed. Thus, the total amount of accumulation can be much greater than that in the structural trap. The simulation results of hydrocarbon migration pathways and accumulation in architecturally heterogeneous carrier beds improve our under-standing of the hydrocarbon migration and accumulation pro-cesses and shed new light on the relationship between reservoir, seal, and trap. The spectrum of exploration targets should be expanded to include those along migration pathways.

To understand hydrocarbon migration in terms of the mechanisms, accumulations and exploration targets, it is essential to correctly identify and characterize the carrier systems that control fluid-migration history and oil/gas reservoir formation. The Yinggehai Basin in China is an important area for natural gas exploration and production. However, due to the argillaceous sand sedimentary environment and the absence of faults from the Neogene thermal subsidence period, traditional migration pathways are absent in the Yinggehai Basin, posing significant challenges to target evaluation in this area. Exploration shows that most of the existing gas reservoirs are associated with vertical migration. In this work, coherence cube and curvature seismic techniques are used in the central diapir zone of the Yinggehai Basin to identify diapir-associated fractures and regional stress. Together with geological analysis, two categories of carrier system are discussed in detail to explain the complex migration and accumulation patterns that have puzzled the area. Diapirs have five evolutionary phases, i.e., pressurization, piercing, equilibrium, release and collapse, which have different fracture development patterns, leading to different mechanisms of hydrocarbon migration and accumulation. The carbon isotopes of gaseous hydrocarbons in DF shallow layers and mid-deep layers have an inverted order distribution, indicating mixed accumulation with different maturity, whereas in the mid-deep layers of the diapir-affected areas, there is a single accumulation with low maturity. Early diapiric activity allowed the natural gas produced from deep source rocks to migrate upward along the diapiric carrier system and accumulate in suitable traps to form gas reservoirs. For regional-stress related fractures, the gradual loss of overpressure and fluids from deep to shallow in high-pressure fractures results in the gas accumulation time of deep traps in the regional stress-related carrier system being relatively late and the gas accumulation time of shallow traps being relatively early.

Research on the characteristics and distribution of natural fractures is of great importance for the exploration and development of low-permeability sandstone gas reservoirs. In this study, fracture identification and characterization were carried out using cores and imaging logging. Then, comprehensive fracture development indicators were constructed to predict the distribution of fractures in wells by conventional logging. The main factors that affect the development of natural fractures and the implications of fractures on hydrocarbon exploration and development were discussed. The results showed that the natural fractures were mainly low-angle tectonic fractures in sandstone reservoirs. Most of fractures are unfilled, but the distribution of the fractures in the thin sections has a discrete fracture structure, indicating that the connectivity of the fracture system is poor. The development of natural fractures is mainly influenced by rock strength, petrographic composition, and petrology, and the fractures are more developed in sandstones with a higher content of brittle minerals. The fracture densities are mainly distributed below 0.05 m/m and up to 0.1 m/m. In the present in situ stress state, all of the natural fractures in the LD-A gas field are invalid fractures. The critical pressure of the natural fracture is approximately 16.5–25.4 MP/km; when the pore pressure exceeds this value, the fractures become effective fractures. These results provide new geological knowledge and guidance for the exploration and development of LD-A gas fields and other low-permeability tight sandstone reservoirs.

Accurate and quantitative numerical modeling of phase behavior and speciation of gas-water-rock systems is crucial for fluid and rock evolution analysis, and important in scientific research and engineering applications. In our previous work, mutual solubility models of series gases and brine have been developed for wide temperature, pressure and composition ranges. The gas components included CO2, CH4, H2S, N2 and O2. The existing experimental data can be reproduced accurately. In this paper, the models are extended to include water-rock interactions by means of a full coupling with the open-source software package PHREEQC. With the new coupled model, the solubility of gases and various minerals can be correctly and reliably reproduced. The proposed numerical framework is properly implemented and it can be applied in different scenarios of gas-water-rock interactions. Three practical applications have been investigated: calculation of uranium in situ leaching, CO2 geological storage and natural gas souring are provided in the paper. The application cases have additionally proven the stability and reliability of the proposed model.

Chemical compaction dominated by clay mineral transformations, commonly develops in deeply buried mud stones, and prominently affects the petrophysical properties of mudstones and fluid flow. This paper takes the Neogene mudstones in the Ledong Slope of the Yinggehai Basin as research object, analyzes the relationship between chemical compaction and overpressure, establishes a new multisegment normal compaction trends (NCTs) and reevaluates the overpressure mechanisms. The results show obvious clay mineral transformation with increasing depth, and the top of the clay mineral transformations is approximately equal to the depth of the overpressure. The logging responses of overpressured mudstones are affected by clay mineral diagenesis, showing a 45% increase in the sonic transit time at 3500-5000 m and a 10% decrease in the density at the same interval, and the density response exhibits a relative lag. A method comprising an inversion algorithm calibrated by measured pressure data is proposed to establish multisegment NCTs. Furthermore, new loading-unloading curves comprising a mechanical loading curve and chemical loading curve are established to reevaluate the overpressure mechanisms. The loading-unloading curves show that the pressure gradient generated by mudstone compaction maybe less than 1.8. While the pressure data with pressure gradient larger than 1.8 fall on the unloading curve, indicating elevated sandstone pressures rather than in situ mudstone pressures. The multi segment NCTs were proven to provide a satisfactory overpressure estimate in the Ledong Slope as well as the relative contribution of different overpressure mechanisms. This paper provides new insight into mudstone compaction and overpressure responses, as well as a meaningful reference for the identification of multiple overpressure generation mechanisms and the prediction of pore pressure in deeply buried formations.

The Yinggehai Basin is a typical high temperature and high pressure (HTHP) gas-bearing basin. The pressure coefficient exceeds 2.2 in deeply-buried Miocene reservoirs in the Ledong Slope, a nondiapir zone in the Yinggehai Basin. Determining the overpressure mechanisms and predicting the pore pressure are key issues for natural gas exploration and development in the Ledong Slope. In this paper, overpressure mechanisms were investigated according to the analysis of vertical effective stress-logging responses and geological evaluations, and the pore pressure was predicted using the Bowers method. The loading-unloading crossplots indicated that the overpressure that existed in reservoirs mainly consists of two types: neighbor-source and allo-source overpressure. The neighbor-source overpressure is mainly caused by the pressure transmission from the adjacent mudstone to the reservoir, with a pressure coefficient less than 1.5 ~ 1.6. The high-magnitude overpressure points with pressure coefficients greater than 1.6 show a typical unloading response, indicating elevated sandstone pressures rather than in situ mudstone pressures, which are most likely to be generated by overpressure vertical transfer. The high-magnitude overpressure fluid generated by the high mature ultradeep buried N1s source rock migrated to the shallower reservoirs via hidden faults/microfractures, which led to the vertical transfer of overpressure. Vertically transferred overpressure was generated at 1.5 ~0.2 Ma, which is beneficial for the preservation of overpressure in lenticular sandbodies. The estimated pore pressure by the Bowers method is in good agreement with the measured pressure and provides a meaningful reference for predrilling pressure prediction in nondiapir or diapir zones in the Yinggehai Basin.

This paper describes a system-level risk assessment for the Shenhua CO2 storage site, China, using the National Risk Assessment Partnership Integrated Assessment Model for Carbon Storage (NRAP-IAM-CS). We begin by determining the optimal number of Monte Carlo (MC) simulations to achieve CO2 and brine leakage result convergence. Then, we calculate mass CO2 and brine leakage to the atmosphere and a hypothetical shallow aquifer. Finally, we assess the geochemical impacts in the event of leakage as if there were a shallow freshwater aquifer at the Shenhua site. Simulation results show that leakage results tend to stabilize after 300 Monte Carlo simulations. When the three wells on site are assigned a permeability of 10(-11) m(2) (representing significantly leaking wells), moderate CO2 and brine leakages occur, and the percentage of CO2 leakage exceeds the threshold value we set based on the Intergovernmental Panel on Climate Change (IPCC). This is, however, unlikely to be the case for the Shenhua site. For all the other scenarios, the CO2 leakage is trivial although there is still the possibility of CO2 leakage into the groundwater aquifer exceeding the 1% threshold over 1000 years, assuming constant legacy wellbore permeability. For the significantly leaking scenario, there is a 10% probability to have a moderate (2.7 x 10(7) m(3)) leakage-affected volume in the shallow aquifer with the pH below 6.5, and a large (1.4 x 10(8) m(3)) volume with the total dissolved solids (TDS) above 500 ppm, hence pH and TDS may be considered for site monitoring plans. Based on the simulation results, there is a very low probability of significant CO2/brine leakage through the existing wells at the Shenhua CO2 storage site.

In this work, we present a numerical framework for non-isothermal compositional compressible gas-water phase flow simulations in non-fractured and fractured porous media on structured and unstructured meshes. The framework is implemented as the simulator “DMflow”. The discretization of the mass conservation equations is based on the fully-implicit scheme and cell-centered finite-volume control-volume distributed multipoint flux approximation (CVD-MPFA) coupled with a lower dimensional fractured model. Similarly, the discretization of the energy equation is also based on the same method. The recent newly developed enthalpy model of CO2−CH4-H2S-N2-O2-brine system (Guo et al., 2019), which is validated within a wide temperature and pressure range, is used in the energy equation. Here, we present a sequential implicit method for the non-isothermal flow and avoid the simultaneous solution of the fluid flow primary variables and the temperature. We present the validation cases where the 1D and 2D results for non-isothermal carbon dioxide (CO2) injection into water obtained by the new implemented numerical framework are in agreement with the CMG-GEM. The simulation results of the injection of the CO2 into an aquifer shows the robustness of the method to produce gas phase behavior and temperature distribution in agreement with the literature. We also present a simulation case to demonstrate the capability of our simulator to model non-isothermal CO2 injection process into a fractured water saturated reservoir using an unstructured grid. The method is also then applied to simulate and compare the isothermal and the non-isothermal cases of injection of pure CO2 and impure CO2 into water reservoir with heterogeneity in porosity and permeability.

Reservoir petrofacies is an important tool for the better understanding of the key petrographic parameters (primary texture and detrital component, types and processes of diagenetic alteration) that control reservoir properties of tight sandstones. This study aims to investigate sandstone texture and composition, and diagenetic features of the sixth member of Upper Triassic Yanchang Formation (YC6 member), Ordos Basin, China, and to examine controls of diagenesis and petrofacies on reservoir quality and pore structures of tight sandstone reservoirs. This study has been carried out using petrography, XRD, SEM, routine core analysis and mercury intrusion capillary pressure (MICP) test. The YC6 member sandstones are moderately well sorted, very fine- to fine-grained arkoses. The reservoir quality and pore throat distributions are highly heterogeneous in the sandstones. Four reservoir petrofacies are defined based on the combination of sandstone detrital components, diagenetic processes, pore types and reservoir properties. Contrasting diagenetic characteristics between these petrofacies are mainly determined by detrital grain size through ductile grain compaction. Ductile grain compaction has a significant control on porosity and permeability of the sandstones. Especially, the poor quality has been encountered in the petrofacies where ductile grain content is >12%. Calcite cement has helped destroy quality of the petrofacies where the cement is present in amounts >15%. Reservoir quality is best for the petrofacies that is poor in both ductile grain and calcite cement and commensurately is rich in secondary dissolution. Four pore-facies types are defined based on the dominant pore throat dimension of the sandstones. The large pore-throat regime determines permeability and fluid flow of reservoir rocks. A good correlation between pore-facies and petrofacies indicates diagenetic effect on pore structures of the sandstones. The study provides insights into how reservoir quality and pore structures of tight sandstone reservoirs are correlated with reservoir petrofacies.

In this study, reaction experiments between CO2-saturated brine and wellbore cement samples cured under different pressures were conducted to study microstructural and mineral composition changes using micro-computed tomography (micro-CT), scanning electron microscopy (SEM) and Raman spectroscopy. The CT images of post-CO2 exposure cement samples showed a dissolution-precipitation-dissolution pattern at the exterior of the samples. The dissolution in the inner hole of the samples, however, was not significant. Instead, only CaCO3 precipitation was observed in the inner hole. CaCO3 precipitation in the inner hole contributes to self-sealing of the cement, which reduces the risk of CO2 leakage through wellbore cement. According to CT and SEM observations, a higher curing pressure caused more precipitation of CaCO3, which favored cement self-sealing when exposed to CO2. The appearance of a CO peak and the disappearance of a –OH peak after reaction with CO2 were observed by Raman spectroscopy, which was attributed to cement carbonation that converted Ca(OH)2 into CaCO3. This study provides solid evidence of cement self-sealing due to cement carbonation under geologic CO2 storage circumstances.

莺歌海盆地乐东斜坡区乐东A构造深层超压天然气资源丰富,查明超压形成机制对于认识乐东斜坡区天然气运移成藏过程和地层压力准确预测至关重要.根据超压测井响应、数值模拟及天然气成藏条件解剖讨论了乐东A构造储层超压成因机制,分析了储层强超压形成与天然气成藏的关系.结果表明:乐东A构造中新统储层普遍发育超压,压力系数最大可达2.27,接近地层破裂压力梯度,纵向上压力系数发生突变.富泥地层快速埋藏导致的机械压实不均衡作用可使压力系数达到1.5～1.6左右.强超压(压力系数>1.6)表现出明显的卸载响应特征,表明储层压力远高于原位泥岩压力.储层中卸载型超压主要是由三亚组超压沿断层垂向传递作用引起的.储层强超压的形成与天然气运移成藏过程密切相关,深层成熟—高成熟的三亚组烃源岩提供了强超压传递的流体来源,烃源岩与储层之间发育的隐伏断层/微裂隙系统为天然气垂向运移及超压垂向传递提供了有利通道,天然气晚期充注有利于透镜状砂体中传递超压的保存.研究认识将为钻前压力预测和安全钻井设计提供有效参考,并为莺歌海盆地非底辟区高温高压天然气成藏过程提供新的见解.

In situ leaching (ISL) is the main mining method for sandstone-type uranium deposits. The thermodynamic model can provide important information to real project decision making. However, systematic thermodynamic modeling work is still lacking for uranium-containing systems. In this paper, a thermodynamic model for the uranium minerals-solution-gas system is established with reliable and internal consistent parameters. The B-dot model and Peng-Robinson model are used to calculate the activity coefficients and fugacity coefficients. The determination for the equilibrium constant is carried out based on the comparisons between the calculated results by this model and the experimental solubility data. The solubility of uranium minerals under different experimental conditions can be reproduced by this model. 12 Tetravalent uranium minerals are less soluble than hexavalent uranium minerals in the absence of oxidants, especially under alkaline conditions. The dissolution of uranium mineral assemblages, including pitchblende, uraninite, coffinite, and brannerite, will be promoted by reducing the temperature or increasing the concentration of the leaching or oxidizing agents. For uranium leaching, the efficiency of the acid method is higher than that of the alkaline method, which probably results from the transformation of soluble uranium minerals into insoluble uranium minerals with less solubility in alkaline solutions. Under the CO2 + O-2 leaching condition, the dissolution of uranium minerals will be promoted by increasing the partial pressure of O-2 or CO2, and dissolution is more sensitive to O-2 at high pressure. In addition, two real ISL projects from China have been calculated using the model. The suitable ratio of water and solids and the concentrations of both the oxidant and the leaching agent are suggested for these two projects.

A novel numerical framework is presented for simulation of compositional compressible gas-water phase flow in fractured porous media based on a fully-implicit cell-centred finite-volume method on unstructured grids. We employ a discrete-fracture model where fractures are modelled lower-dimensionally, within a rock matrix. A mass balance equation is solved over the rock-matrix while a lower-dimensional flow equation is solved over the lower-dimensional fractures, with coupling terms to account for the flux transfer from the surrounding rock-matrix. The discretisation of the Darcy-fluxes is based on the control-volume distributed multi-point flux approximation (CVD-MPFA) coupled with a lower-dimensional fracture model. We solve a non-linear system for the primary variables that are the phase pressure and the component molar densities while the secondary variables are updated depending on the updated values of the primary variables at each iteration of the non-linear solver. We use the cubic type equation-of-state (EOS) to model the physical properties of gas components, e.g. CO2. The water phase is multi-component as we allow solubility of gas components in the water phase. Solubility of H2O in the gaseous phase is also included in the developed method. We compare compositional simulation results, using unstructured grids, obtained via the lower-dimensional fracture model and the results obtained by the equidimensional fracture model for a case of CO2 injection into a water saturated reservoir with intersecting fractures. The results show good agreement between the two models while the lower-dimensional fracture model is also computationally cost effective. Results are also presented for the evolution of injected CO2 under gravity through a water saturated reservoir with and without fractures that demonstrate the profound effects of discrete-fractures that can lead to CO2 leakage. The presented method is also applied to a 3D simulation of injection of a multicomponent gas with CO2 and CH4 into a saline water saturated reservoir with a surface 2D fracture network.