Shale Gas Reservoirs Research Articles

A thermodynamics-based coupled model for multi-phase flowback in deformable dual-porosity shale gas reservoirs

Over the past decades, there has been growing interest in modelling multi-phase flowback in shale gas reservoirs during hydraulic fracturing, primarily due to the significant risk of groundwater pollution. However, the lack of fully coupled simulations and a unified theoretical model has hindered the study of coupled adsorptive hydro-mechanical behaviour and its influence on fluid flowback prediction. In this paper, we have extended the non-equilibrium thermodynamics-based Mixture Coupling Theory to derive the constitutive relationship and governing equation for adsorptive multi-phase fluid flows in deformable dual-porosity media. Helmholtz free energy density has been used to establish the relationship between solids and fluids. The interaction of adsorptive fluids in the pore and fracture space has been fully considered, leading to a new form of constitutive equation, which obtained the molecular adsorptive effect on the rock by introducing adsorption entropy production. The proposed governing equations determine the fully coupled evolution of solid deformation and multi-phase flow, with the consideration of adsorption as well as pore and fracture porosity change. Numerical simulation is then performed to study the flowback of a real shale gas well and the influence of coupled behaviour on model prediction. The simulation shows that the flowback flux is mainly by the fracture (more than 99.9 %) and the overall cumulative volume is 2427.1 m3 within 225 h which accounts for about 5.3 % of the total injected fracturing fluid, and the sensitivity analysis reveals that the manual fracture porosity is the most sensitive factor to the cumulative flowback. This work provides new insights into the flowback process of shale reservoirs in a fully coupled view and the proposed theoretical tool should contribute to the modelling of other adsorptive multi-phase flow problem in deformable dual-porosity media such as carbon storage and coalbed methane production.

The law of fracture propagation and intersection in zipper fracturing of deep shale gas wells

In response to the unclear understanding of fracture propagation and intersection interference in zipper fracturing under the factory development model of deep shale gas wells, a coupled hydro-mechanical model for zipper fracturing considering the influence of natural fracture zones was established based on the finite element – discrete element method. The reliability of the model was verified using experimental data and field monitoring pressure increase data. Taking the deep shale gas reservoir in southern Sichuan as an example, the propagation and interference laws of fracturing fractures under the influence of natural fracture zones with different characteristics were studied. The results show that the large approaching angle fracture zone has a blocking effect on the forward propagation of fracturing fractures and the intersection of inter well fractures. During pump shutdown, hydraulic fractures exhibit continued expansion behavior under net pressure driving. Under high stress difference, as the approaching angle of the fracture zone increases, the response well pressure increase and the total length of the fractured fracture show a trend of first decreasing and then increasing, and first increasing and then decreasing, respectively. Compared to small approach angle fracture zones, natural fracture zones with large approach angles require longer time and have greater difficulty to intersect. The width of fractures and the length of natural fractures are negatively and positively correlated with the response well pressure increase, respectively, and positively and negatively correlated with the time required for intersection, the total length of hydraulic fractures, and fracturing efficiency, respectively. As the displacement distance of the well increases, the probability of fracture intersection decreases, but the regularity between displacement distance and the response well pressure increase and the total length of fractures is not obvious.

Molecular dynamics of CH4 adsorption and diffusion characteristics through different geometric shale kerogen nanopores

In shale, pore structure plays an extremely significant effect on CH4 storage and transportation in a reservoir, especially for the reservoir involving large amounts of extremely tiny nanopore and variance of microstructure. In this study, three molecular dynamics models for different types of kerogen nanopores such as serration type, arc type and great-wall type are established, validated and implemented to assess the impact of pore structure on CH4 adsorption and diffusion behaviors in kerogen matrix and nanopore at temperature 320 ∼ 380 K, pressure 5 ∼ 20 MPa and pore size 3 ∼ 5 nm. The simulation results demonstrate that the CH4 density in the bulk of serration-type, arc-type and great-wall-type pores is 1.6, 1.3 and 1.9 higher than that inside kerogen molecules. Increasing temperature can weaken the adsorption capacity of kerogen, but the serration-type pore is the most sensitive to temperature. Regardless of the pore type, increasing pressure can significantly enhance the adsorption capacity of kerogen which is almost unaffected by pore size, whereas the CH4 diffusion coefficient increases with pore size. Furthermore, the great-wall-type pore can adsorb more CH4 molecules due to its smooth surface, followed by change in the arc-type and serration-type pores in turn. Among these types of pores, the CH4 diffusion coefficient is the most insensitive to the size of arc-type pore. Hence, the influences of kerogen pore structure under different conditions of temperature, pressure and pore size are quantified in this work to improve a comprehensive understanding of CH4 adsorption and diffusion behaviors in shale, thereby contributing to high-efficient and sustainable development of shale gas reservoirs.

Molecular insights into dual competitive modes of CH4/CO2 in shale nanocomposites: Implications for CO2 sequestration and enhanced gas recovery in deep shale reservoirs

CO2 enhanced shale gas recovery has significant potential for improving the recovery rate of adsorbed gas and facilitating the geological sequestration of CO2. Nevertheless, the feasibility and microscopic mechanisms of CO2 enhanced gas recovery in deep shale gas reservoirs remain to be elucidated. In this study, a quartz-kerogen slit model was constructed to represent the shale composite nanopores of deep shale reservoirs. Utilizing the grand canonical Monte Carlo and molecular dynamics methods, the adsorption and diffusion behavior of CH4, CO2 and their mixtures was investigated under high-temperature and high-pressure conditions representative of deep shale reservoirs. The influences of temperature, pressure and aperture size were analyzed. The microscopic mechanisms governing the CH4/CO2 competitive adsorption in deep shale nanopores were uncovered by considering the competitive interactions between different rock constituents and quantifying the various gas storage states. The results show that the adsorption capacity of CO2 is greater than that of CH4 under the deep shale reservoir conditions. The replacement efficiency of CH4 by CO2 is higher in small shale pores. High temperature has a more significant negative impact on the adsorption of CO2 compared to that of CH4. Compared to mid-deep shale reservoirs, the nanopores of deep shale reservoirs have a higher proportion of free CH4/CO2 states. Quartz exhibits greater affinity for CH4/CO2 than kerogen, but kerogen possesses a larger specific surface area, resulting in a higher adsorption capacity per unit volume. The hierarchy of CH4/CO2 diffusion capacity in various storage states is as follows: dissolved gas in the kerogen matrix < adsorbed gas on the quartz surface < adsorbed gas on the kerogen surface < free gas in the pore center. This study improves the understanding of CO2 enhanced gas recovery in deep shale gas reservoirs.

Research on DFN Fracture Modeling and Fracturing Network Expansion Simulation Method for Shale Reservoirs

Abstract The degree of natural fracture formation and their link to hydraulic fracturing fractures are critical factors in production in the current large-scale fracturing development of shale gas reservoirs. Any magnitude of fractured reservoir heterogeneity may be described using the Discrete Fracture Network (DFN) model. This paper builds on earlier research by providing an additional summary of the multiscale DFN fracture modeling method, analyzing the fracture occurrence using statistical analysis techniques, analyzing the fracture scale using fractal theory, and determining the fracture development degree by combining the fracture attributes in imaging logging and three-dimensional seismic data. Different-scale fracture network models were developed. Simulating the growth of hydraulic fractures accurately using Mohr Coulomb and Barton Bandis criteria, this study also takes into account the interaction between natural and hydraulic fractures, as well as the physical properties of the rock (e.g., elastic modulus, Poisson’s ratio), closure pressure, crustal stress field, and other factors. The fracture network information, sitmulated reservoir volume, stress shadow and other attributes obtained from fracturing simulation can further analyze and evaluate the effect of fracturing simulation, and optimize the well location deployment plan and construction plan in combination with geological engineering conditions.

Utilization law of shale gas in hydraulic fracturing with the Changning–Weyuan block in China as an example

The process of extracting shale gas, particularly the study of the utilization law of shale reservoirs modified by hydraulic fracturing technology, is crucial for understanding the effective development of shale gas. This understanding can significantly influence the estimated ultimate recovery of reserves. Our study focused on Longmaxi Formation shale in the Changning–Weiyuan block. To investigate the hydraulic fracturing expansion mechanism and utilization law, we employed shale reservoir physical and mechanical characterization, indoor triaxial hydraulic fracturing experiments, and numerical simulations. The findings are as follows. The rupture pressure of hydraulic fractures increases with the peripheral pressure, and high stress is conducive to the formation of internal microfractures. Additionally, a high rate of water injection enhances fracture extensions along the direction of fluid injection. Under varying injection pressures, the length of crack extensions and number of bond damages in shale are positively correlated with the injection pressure. Conversely, under different differential ground stresses, the length of crack extensions and number of bond damages are negatively correlated with the injection pressure. The six main factors affecting the effective utilization of shale gas are as follows: the stimulated reservoir volume, number of hydraulic fracture clusters, fracture length, fracture height, number of fracture stages, and cluster spacing, accounting for 27.13%, 14.74%, 10.31%, 9.58%, 9.53%, and 9.29%, respectively, with a cumulative contribution rate of 80.58%. This study clarifies the hydraulic fracturing mechanisms of shale reservoirs and the laws governing shale gas production, providing technical support for the development of shale gas reservoirs.

Paleoenvironmental Transition during the Rhuddanian–Aeronian and Its Implications for Lithofacies Evolution and Shale Gas Exploration: Insights from the Changning Area, Southern Sichuan Basin, South-West China

During the Rhuddanian–Aeronian interglacial period, global geological events such as glacial melting, synsedimentary volcanic activity, biological resurgence, and large-scale marine transgressions caused frequent fluctuations in paleoproductivity, climate changes, and sea level variations. These paleoenvironmental transitions directly influenced the development characteristics of shale lithofacies. This study investigates the Longmaxi Formation shale in the Changning area in the Southern Sichuan basin, focusing on 28 core samples from Well N1. Using scanning electron microscopy, QEMSCAN, TOC, XRD, and major and trace element analyses, we reconstructed the paleoenvironmental transitions of this period and explored their control over shale lithofacies types and mineral compositions. Four shale lithofacies were identified: carbonate rich lithofacies (CRF), biogenic quartz-rich lithofacies (BQRF), detrital clay-rich lithofacies (CRDF), and detrital quartz-rich lithofacies (DQRF). During the Rhuddanian period, rising global temperatures caused glacial melting and rapid marine transgressions. The low oxygen levels in bottom waters, combined with upwelling and abundant volcanic material, led to high paleoproductivity. This period primarily developed BQRF and CRF. Rich nutrients and abundant siliceous organisms, along with anoxic to anaerobic conditions, provided the material basis and preservation conditions for high biogenic quartz and organic matter content. High paleoproductivity and anoxic conditions also facilitated the precipitation of synsedimentary calcite and supplied Mg2+ and SO42− for the formation of iron-poor dolomite via sulfate reduction. From the Late Rhuddanian to the Mid-Aeronian, the Guangxi orogeny caused sea levels to fall, increasing water oxidation and reducing upwelling and volcanic activity, which lowered paleoproductivity. Rapid sedimentation rates, stepwise global temperature increases, and the intermittent intensification of weathering affected terrigenous clastic input, resulting in the alternating deposition of CRF, CRDF, and DQRF. Two favorable shale gas reservoirs were identified from the Rhuddanian–Aeronian period: Type I (BQRF) in the L1–L3 Layers, characterized by high TOC and brittleness, and Type II (DQRF) in the L4 Layer, with significant detrital quartz content. The Type I-favorable reservoir supports ongoing gas production, and the Type II-favorable reservoir offers potential as a future exploration target.

High-Order Models for Gas Transport in Multiscale Coal Rock.

The coal reservoirs exhibit great heterogeneity and strong anisotropy in multiscale pore/fracture structures. Developing highly accurate multiscale models for real-time prediction of microgaseous flow in complicated porous media with pronounced contrast in transport coefficients is crucial but not yet available, which is time-consuming, expensive, and even computationally impossible. In this study, a multiscale approximate solution of the gas flow and pressure field is derived in this paper for predicting coalbed methane (CBM) transport in macro-microscopic two-scale porous media of typical coal rocks in Guizhou Province, China, and the detailed finite element algorithm is established. The multiscale approximate solutions are constructed from the first- and second-order auxiliary cell functions and low- or high-order derivatives of the homogenized pressure field, which can accurately approximate the solution of the original problem to a certain extent. The numerical accuracy and validity of the multiscale approximate solutions under various working conditions are analyzed in detail by comparing and verifying the results with the direct numerical simulation results of fine-mesh high-precision finite elements. The results show that the homogenized approximate solution can only roughly capture the characteristics of the macroscopic pressure evolution, the first-order approximate solution can partially reproduce the macro-microscopic pressure oscillation phenomenon, and the second-order approximate solution can accurately predict the pressure profile and its evolution law with time in porous media with macro-micro configuration under various complex conditions. The second- and high-order two-scale approximate solutions constructed in this paper exhibit high numerical accuracy and excellent computational efficiency. We also develop multiscale approximate solutions for predicting microgaseous flow at a low reservoir pressure where the slippage effects are very pronounced. Potential applications of our high-order models to the coal reservoirs with a hierarchical matrix and fractures are discussed. The developed multiscale models exhibit excellent applicability to investigating the crossflow effects and coupling mechanisms between the matrix and cleats or fractures with multiple configurations in the CBM and shale gas reservoirs, which is crucial for the effective implementation of hydraulic fracturing technology. This study provides a fundamental understanding of gas transport in multiscale matrix-fracture networks, which helps to improve the optimization design of hydraulic fracturing in tight reservoirs.

Molecular insights into CO2 enhanced hydrocarbon recovery and its sequestration in multiscale shale reservoirs

CO2 huff-n-puff (HNP) is an attractive enhanced oil recovery (EOR) technique in shale development due to its low cost, high efficiency, and environmentally friendly feature. Molecular dynamics (MD) simulations have been widely used to investigate the mechanisms of CO2 HNP process. However, the process of CO2 HNP is highly complex, involving the CO2 adsorption and transport in multiscale porous media, while considering the effect of different hydrocarbon compositions of shale oil. In this work, we developed a novel multiscale model (nano + bulk) with the modified Eagle Ford shale oil and water as the reservoir fluid. We investigated the adsorption behaviors and transport dynamics of CO2 in the CO2 HNP process. We quantitatively evaluated the CO2 swelling effect and its miscibility with hydrocarbons. Our results show the preferential adsorption to the graphene wall is pentane < CO2 < octane. CO2 can effectively desorb the light and intermediate hydrocarbons from the graphene wall. In addition, CO2 has good swelling effect and miscibility with the light and intermediate components. Due to the large molecular diameter and the strong interactions with the nanopore wall, the heavy components tend to be trapped in the nanopore after the CO2 HNP process. However, CO2 has similar swelling effect on the light and heavy components, indicating that the heavy components in the bulk pore can be effectively swelled and produced. Different from the unstable diffusion edge in the inorganic nanopores, CO2 has a stable diffusion edge in the organic nanopores. From the adsorption perspective, CO2 has favorable sequestration performance in the inorganic nanopores in shale gas reservoirs. This work provides a comprehensive understanding of the CO2 HNP process and practical implications for CO2 sequestration in shale reservoirs.

Estimation of Adsorption Gas in Shale Gas Reservoir by using Machine Learning Methods

Estimation of Adsorption Gas in Shale Gas Reservoir by using Machine Learning Methods

Data-driven multiscale geomechanical modeling of unconventional shale gas reservoirs: a case study of Duvernay Formation, Alberta, West Canadian Basin

The Duvernay Formation in Canada is one of the major oil and gas source formations in the Western Canadian Sedimentary Basin, located at its deepest point. While it demonstrates promising development potential, challenges arise in the urgent need for integration of geology and engineering models, as well as in optimizing sweet spots, particularly as infill wells and pads become central operational objectives for the shale gas field. A lack of the geomechanical understanding of shale gas reservoirs presents a significant obstacle in addressing these challenges. To overcome this, we implemented data acquisition and prepared historical models and profiles, resulting in an extended high-resolution geological and reservoir property model with a fine grid system. Subsequently, a 3D full-field multi-scale geomechanical model was constructed for the main district by integrating seismic data (100 m), geological structures (km), routine logs (m), core data (cm), and borehole imaging (0.25 m), following a well-designed workflow. The predicted fracturability index (brittleness) ranges from 0.6 to 0.78, and a lower horizontal stress difference (STDIFF) is anticipated in the target formation, Upper Duvernay_D, making it a favorable candidate for hydraulic fracturing treatment. Post-analysis of the multi-disciplinary models and various data types provides guidelines for establishing a specific big database, which serves as the foundation for production performance analysis and aggregate sweet spot analysis. Fourteen geological and geomechanical candidate parameters are selected for the subsequent sweet spot analysis. This study highlights the effectiveness of multi-scale geomechanical modeling as a tool for the integration of multi-disciplinary data sources, providing a bridge between geological understanding and future field development decisions. The workflows also offer a data-driven framework for selecting parameters for sweet spot analysis and production dynamic analysis.

SENSITIVITY ANALYSIS OF SHALE GAS RESERVOIR PARAMETERS BASED ON PROXY MODEL

The complexity and vast variability of shale gas reservoirs demand a profound comprehension of the intricate interplay between various parameters and their influence on reservoir performance. This study aims to provide such an understanding by conducting a comprehensive sensitivity analysis of shale gas reservoir parameters. The core of this analysis lies in leveraging proxy models, which serve as efficient surrogates of complex numerical models. These proxy models enable us to assess the sensitivity of different parameters without the need for extensive computational resources. By employing such models, we can identify the key parameters that have a significant impact on reservoir behavior. The methodology involves several crucial steps. Firstly, a shale gas numerical model is established to capture the geological and engineering characteristics of the reservoirs. This model serves as a foundation for subsequent analysis. Secondly, proxy models are constructed based on the numerical model, offering a simplified representation while maintaining the essential dynamics. The application of sensitivity analysis techniques, such as Sobol analysis and Morris analysis, follows. Sobol analysis quantifies the relative importance of each parameter, providing insights into their individual contribution to reservoir performance. On the other hand, Morris analysis examines the non-linear and interactive effects of parameters, revealing their combined influence. The anticipated outcomes of this study are far-reaching. Firstly, it will provide valuable insights into the sensitivity of different parameters, enabling decision-makers to prioritize their attention and resources. Secondly, it will facilitate the optimization of shale gas development strategies, leading to more efficient and cost-effective operations. Finally, this study has the potential to guide future research and developments in the shale gas industry, contributing to its sustainable growth and development.

A Comprehensive Review on the Geological Uniqueness and Enrichment Regularity of Shale Gas Reservoirs in China

This paper reviews the geological uniqueness and enrichment regularity of shale gas reservoirs in China, analyzes the patterns of shale gas formation under different geological backgrounds, discusses the main controlling factors affecting the enrichment of shale gas, and proposes potential directions for future exploration and development of shale gas. The study shows that the patterns of shale gas formation in China are diverse and are jointly controlled by multiple factors such as sedimentary environment, diagenesis, and later tectonic movements.

A Critical Review on the Advancements in Exploration and Production of Shale Gas

The exploration and production of shale gas have seen significant advancements in recent years, driven by the increasing global demand for clean energy sources. These advancements encompass the understanding of a wide range of areas, including the formation theory of shale gas reservoirs, evaluation methods, well drilling, completion, and simulation techniques. Innovative design, modelling, and field practices have been developed for shale gas well drilling and completion, as well as its production techniques. Furthermore, new simulation techniques, software, algorithms, and other tools have been introduced to improve the modelling and simulation of shale gas production. Experimental and simulation research in shale gas exploration, development, and production using hydraulic fracturing has also seen considerable progress. These advancements are contributing significantly to the global demand for clean energy sources with a promise to achieve sustainable development goals. This review work explores the exploration and exploitation of shale gas with a detailed description of multidisciplinary research efforts, providing valuable insights into shale reservoir/rock characterization and geo-mechanics, fluid-surface interactions, gas adsorption behaviours and single- and multi-phase flow mechanics. These advancements are not only increasing the efficiency and productivity of shale gas extraction but also paving the way to meet the future global energy demand while also contributing to the goal of achieving net-zero carbon emissions. The novelty of the review work is that it exhibits a combined qualitative and quantitative study of recent advancements in the sphere of exploration and production of shale gas reserves and its discoveries around the globe.

Development of coupled fluid-flow/geomechanics model considering storage and transport mechanism in shale gas reservoirs with complex fracture morphology

Field observations frequently demonstrate stress fluctuations resulting from the reservoir depletion. The development of reservoirs, particularly the completion of infill wells and refracturing, can be significantly impacted by stress changes in and around drainage areas. Previous studies mainly focus on plane fractures and few studies consider the influence of complex transport and storage mechanism and irregular fracture geometry on stress evolution in shale gas reservoirs. Based on the embedded discrete fracture model (EDFM) and finite-volume method (FVM), a coupled geomechanics/fluid model has been successfully developed considering the adsorption, desorption, diffusion and slippage of shale gas. This model achieves coupling simulation of natural fractures, hydraulic fractures with complex geometry, storage and transport mechanism, reservoir stress, and pore-elastic effect. The open-source software OpenFOAM is used as the main solver for this model. The stress calculation and productivity simulation of the model are verified by the classical poroelasticity problem and the simulation results of published research and commercial simulator with EDFM respectively. The simulation results indicate that σxx, σyy, σxy and Δσ changes with time and space due to the time effect and anisotropy of formation pressure depletion; Due to the influence of different mechanisms on shale gas storage and transport, the reservoir pressure and stress distribution under different mechanisms are different; Among them, the stress with full mechanisms differs the most compared to the stress without any mechanism. The reservoir with stronger stress sensitivity (smaller Biot coefficient) is less sensitive to formation pressure depletion, and the stress variation range is smaller. For reservoirs with weak stress sensitivity, formation pressure depletion is more likely to lead to stress reversal. Under the influence of fracture geometry, the pressure depletion regions caused by the three types of fracture geometry are approximately rectangular, parallelogram and square, respectively. The corresponding σxx, σyy and Δσ also have great differences in spatial distribution and values. Therefore, the time effect, shale gas storage and transport mechanism and the influence of complex fracture geometry should be considered when predicting pressure depletion induced stress under the condition of simultaneous production. This study is of great significance for understanding the evolution law of stress induced by pressure consumption, as well as the design of infill wells and repeated fracturing.

Characterisation of Shale Gas Reservoirs in the Uralik Formation, Western Margin of the Ordos Basin

Characterisation of Shale Gas Reservoirs in the Uralik Formation, Western Margin of the Ordos Basin

Geological Conditions of Shale Gas Accumulation in Coal Measures

The shale of different potential layers is studied by using rock pyrolysis analysis, total organic carbon determination (TOC), kerogen microscopic component identification, mineral X-ray diffraction, scanning electron microscopy, and low-temperature nitrogen adsorption experiments. The results are as follows: (1) Shishui Formation of the Lower Carboniferous and Longtan Formation of the Upper Permian are the two most important shale gas reservoirs in the Chenlei Depression. The sedimentary environment of the target shale is a marine land interaction facies coastal bay lagoon swamp sedimentary system. Two sedimentary facies of tidal flat facies, subtidal zone, and lagoon swamp facies are developed. (2) The organic matter types of shale are Type III and II2, with TOC content greater than 1%. The maturity of shale samples is relatively higher (Ro,max is above 2%), which means they have entered the stage of large-scale gas generation. The overall brittle mineral content of the target shale sample is relatively higher (above 40%), which is conducive to artificial fracturing and fracture formation in the later stage, while an appropriate amount of clay minerals (generally stable at 40%) is conducive to gas adsorption. (3) The overall pore structure of the water measurement group and Longtan group is good, with a higher specific surface area and total pore volume (average specific surface area is 12.21 and 8.36 m2/g, respectively), which is conducive to the occurrence of shale gas and has good adsorption and storage potential. The gas content of the water measurement group and the Longtan Formation varies from 0.42 to 5 cm3/g, with an average of 2.1 cm3/g. It indicates that the water measurement group and the Longtan Formation shale gas in the study area have good resource potential.

Molecular simulation to understand the effect of methane concentration and moisture contents on hydrogen adsorption in kerogens

The adsorption behaviors of methane(CH4), hydrogen(H2), and their mixtures are crucial for estimating the underground hydrogen storage(UHS) capacity in depleted shale gas reservoirs. In this study, we developed four formulated kerogen models, each representing different maturation levels of type II kerogen molecules via utilizing molecular dynamics (MD) methodologies. We investigated the adsorption characteristics of pure H2 and mixed gases(H2 and CH4) on these kerogen models with varying gas components(0.5:0.5 to 0.9:0.1) and moisture content(0–3.0 wt percentage) through grand canonical Monte Carlo(GCMC) simulations. Our findings reveal that pure H2 lacks a pressure point for adsorption equilibrium below 100 MPa at ambient temperature(298K). The competitive adsorption dynamics between H2 and CH4 on kerogen models demonstrate that CH4 exhibits stronger selectivity at lower pressures. Yet, this selectivity diminishes compared to H2 as system pressure increases, indicating turning points in pressure buildup with kerogen maturity. Additionally, the presence of pre-loading H2O molecules reduces the adsorption capacity of mixed gases, particularly affecting CH4 more than H2. This study offers profound insights into the effect of kerogen maturity and moisture content on the interaction between H2/CH4 and kerogen at a microscopic scale.

Microscopic Characterization of Deformation Behavior during Kerogen Evolution: Effects of Maturity and Skeleton Moisture Content.

The CH4 storage and seepage capacity of shale kerogen are the main controlling factors of the natural gas production rate, and the porosity and permeability of kerogen are greatly affected by kerogen deformation. Therefore, the study of the deformation rule and CH4 adsorption characteristics of kerogen at different maturities and skeleton moisture contents has an important impact on the proper understanding of the development potential of shale gas reservoirs. In this paper, kerogen maturity (II-A, II-B, II-C, and II-D) and skeleton moisture content (0.0, 0.6, 1.2, 1.8, and 2.4 wt %) were considered. The deformation of kerogen, the adsorption of CH4 after deformation, and the quadratic deformation induced by CH4 were studied by using Grand Canonical Monte Carlo (GCMC) and molecular dynamics (MD). The results show that the kerogen volume strain increases with increasing skeleton moisture content, following the order II-A < II-B < II-C < II-D for the same moisture content. The density of the kerogen matrix decreases, and porosity increases with rising moisture content. The void fraction of immature kerogen decreases with increasing water content, while the opposite is true for postmature kerogen. The presence of skeleton moisture decreases the CH4 adsorption capacity of immature kerogen and increases the CH4 adsorption capacity of postmature kerogen. The chemical structure of immature kerogen is relatively soft, making its volume more affected by CH4 adsorption compared with postmature kerogen. In the same water environment, postmature kerogen has greater CH4 storage, diffusion, and seepage capacity compared to those of immature kerogen, suggesting that reservoirs with high organic matter maturity should be prioritized for development.

Reservoir Fluid Data Acquisition Using Advanced Mud-Logging Gas in Shale Reservoirs

Reservoir Fluid Data Acquisition Using Advanced Mud-Logging Gas in Shale Reservoirs