CO2 Enhanced Shale Gas Recovery Research Articles

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.

A generalized adsorption model of CO2-CH4 in shale based on the improved Langmuir model

CO2 enhanced shale gas recovery (CO2-ESGR), as one of the most promising carbon capture, utilization and storage (CCUS) technologies, can both improve the shale gas production for clean energy supply and mitigate greenhouse gas emissions for the goal of carbon neutrality. The adsorption characteristics of CO2 and CH4 in shale play a key role in the reserve assessment of shale gas and the implementation of CO2-ESGR. The problem of accurate prediction of the adsorption and competitive adsorption characteristics of CO2 and CH4 in shale is still one of the main challenges for CO2-ESGR. To bridge the gap, this work developed a generalized prediction model for the adsorption properties of CH4, CO2, and their mixed gas in shale by improving the Langmuir model, covering a large range of temperature, pressure, and total organic carbon content (TOC). The mathematical models for the key parameters of the Langmuir model, the saturated adsorption capacity Q0 and Langmuir pressure PL, were built for the single-component gas based on their functional relationship with temperature and TOC, and for the mixed gas based on their relationship with Q0 and PL of the single-component gas and CO2 content. Then an improved Langmuir model for the adsorption properties of CO2-CH4 in shale was established. The accuracy of the improved model was verified with a relative deviation below 5 % in a large range of temperature (303–363 K), pressure (0–15 MPa) and TOC (1.06 %-3.83 %) by comparing the calculated adsorption with the experimental data. This generalized adsorption model not only ensures the prediction accuracy of CO2-CH4 adsorption characteristics in shale but also expands its application convenience in a large range of temperatures, pressures and TOC, providing a certain theoretical basis for CO2-ESGR technology.

A Combined Neural Network Forecasting Approach for CO2-Enhanced Shale Gas Recovery

Summary Intensive growth of geological carbon sequestration has motivated the energy sector to diversify its storage portfolios, given the background of climate change mitigation. As an abundant unconventional reserve, shale gas reservoirs play a critical role in providing sufficient energy supply and geological carbon storage potentials. However, the low recovery factors of the primary recovery stage are a major concern during reservoir operations. Although injecting CO2 can resolve the dual challenges of improving the recovery factors and storing CO2 permanently, forecasting the reservoir performance heavily relies on reservoir simulation, which is a time-consuming process. In recent years, pioneered studies demonstrated that using machine learning (ML) algorithms can make predictions in an accurate and timely manner but fails to capture the time-series and spatial features of operational realities. In this work, we carried out a novel combinational framework including the artificial neural network (ANN, i.e., multilayer perceptron or MLP) and long short-term memory (LSTM) or bi-directional LSTM (Bi-LSTM) algorithms, tackling the challenges mentioned before. In addition, the deployment of ML algorithms in the petroleum industry is insufficient because of the field data shortage. Here, we also demonstrated an approach for synthesizing field-specific data sets using a numerical method. The findings of this work can be articulated from three perspectives. First, the cumulative gas recovery factor can be improved by 6% according to the base reservoir model with input features of the Barnett shale, whereas the CO2 retention factor sharply declined to 40% after the CO2 breakthrough. Second, using combined ANN and LSTM (ANN-LSTM)/Bi-LSTM is a feasible alternative to reservoir simulation that can be around 120 times faster than the numerical approach. By comparing an evaluation matrix of algorithms, we observed that trade-offs exist between computational time and accuracy in selecting different algorithms. This work provides fundamental support to the shale gas industry in developing comparable ML-based tools to replace traditional numerical simulation in a timely manner.

Adsorption kinetics of CH4 and CO2 on shale: Implication for CO2 sequestration

The adsorption kinetic behavior of CH4 and CO2 in shale is critical for design and practice the CO2 sequestration with enhanced shale gas recovery. In this study, adsorption isotherms and kinetics curves of CH4 and CO2 in two shale samples were measured by the volumetric method at the temperature of 308.15 K, 323.15 K, 338.15 K and 353.15 K with the pressures up to 12 MPa. The pseudo-first-order (PFO) model, pseudo-second-order (PSO) model and Bangham model were used to describe the adsorption kinetics data. Furthermore, the influence of pressure and temperature on the adsorption kinetic behavior of CH4 and CO2 was clarified. The results show that the adsorption kinetic curves can be classified into three stages: rapid adsorption, slow adsorption and adsorption equilibrium stage. The fitting accuracy of the three kinetic models is in the order of Bangham > PSO > PFO. Moreover, the adsorption kinetics of CH4 and CO2 are highly dependent on pressure and temperature. The adsorption rate constant (kb) of CH4 and CO2 increases first and then decreases with increasing pressure. At the pressure below the supercritical pressure of CO2, the kb of CO2 shows a decreasing trend with the increase of temperature, which is the same as that of CH4. However, after exceeding the supercritical pressure of CO2, the variations in kb of CO2 with temperature presents an opposite trend as it increased with increasing temperature. Therefore, the pressure and temperature dependent adsorption kinetic behaviors requires consideration for optimizing engineering parameters in application of CO2 enhanced shale gas recovery and sequestration.

Nanoscale Insights into CO2 Enhanced Shale Gas Recovery in Gas-Water Coexisting Kerogen Nanopores.

The presence of water clusters in kerogen nanopores reduces the occurrence and migration of methane (CH4) and thus affects shale gas extraction. CO2 injection, as an effective approach to enhance shale gas recovery, still presents challenges in its ability to mitigate the impact of immobile water clusters within the kerogen. In this work, molecular dynamics simulations were employed to investigate the microscopic transport process of water clusters and CH4 following CO2 injection in the gas-water coexisting kerogen nanopores. The results demonstrate that CO2 can desorb irreducible water clusters to dredge the pores while extracting CH4, enhancing gas-water mobility, and shale gas recovery by transitioning the wettability of the kerogen nanopore surface from weakly water-wet to CO2-wet. The impact of CO2 on the wettability of kerogen surfaces is primarily manifested in two aspects: CO2 can intrude the interface between water clusters and kerogen to reduce the number of hydrogen bonds between them, resulting in the detachment of water clusters; and the surface of kerogen nanopores can form a layer of CO2 gas film, which prevents desorbed water clusters and CH4 from readsorbing onto the wall surface. This study provides important insights in enhancing the understanding of the microscopic mechanisms in nanoscale flow, as well as for the development of an unconventional gas reservoir.

Log-exponential transformation function for interpreting NMR relaxation measurements of hydrocarbon in organic porous media for enhancing absolute adsorption estimation

Assessing unconventional petroleum resources, particularly shale gas reserve estimation, is challenging due to the adsorption phenomenon. This study presents a new method combining experimental and mathematical procedures to determine the absolute adsorption amount in shale samples. In the experimental section of this study, a new behavior was observed in the NMR decay time series of hydrocarbons in organic porous media. The fast section has a linear relationship with time rather than an exponential one. As a result, a Log-Exponential fit to these decay curves was proposed. Then the logarithmic portion was then used to estimate the absolute adsorbed amount. The method was validated against literature data and conventional methods.Based on this newly developed method, absolute adsorption isotherms were obtained for a Duvernay shale sample and activated carbon packs at pressures ranging from 0.77 MPa to 7 MPa. The model proved to be applicable and consistent with pressure variations. Methane in Duvernay shale exhibited adsorbed isotherm type V, with a methane adsorption capacity of 0.08 g per gram of Total Organic Content (TOC) at 6.24 MPa.In addition to absolute adsorption, the competitive adsorption of methane and CO2 was explored, which is critical for evaluating CO2-enhanced shale gas recovery and storage techniques. The injected CO2 resulted in the displacement of methane from smaller shale pores to larger ones.Adsorption and desorption experiments were conducted to investigate hysteresis. The new method was able to better describe the physical behavior of gaseous hydrocarbons in organic porous media. It was able to capture phase transition and critical pressure specific to organic porous media, which differ from non-organic porous media. This innovative approach enables the accurate characterization of shale reservoirs.

Restricted CO2/CH4 diffusion in nanopores: A quantitative framework to characterize nanoconfinement effect of shale organic pore

The utilization of carbon dioxide (CO2) to enhance depleted unconventional resources can reduce green-house gas emission and increase the recovery ratio. Self-diffusion coefficient of nanoconfined CO2/CH4 is a crucial factor in CO2-enhanced shale gas recovery and CO2 geological sequestration. A workflow was proposed which included the reconstruction of amorphous shale organic nanopores, detection of effective pore size, and integration of grand canonical Monte Carlo (GCMC) method with molecular dynamics (MD) simulations to calculate self-diffusion coefficient. Challenges such as complex pore surface and extreme reservoir condition were considered, and the self-diffusion coefficients of nanoconfined fluid were obtained. It was found that the self-diffusion coefficient of nanoconfined CO2/CH4 is much smaller than that of bulk CO2/CH4, as a concequence of nanoconfinement effect. The effects of temperature, pressure and pore size were considered, and a nondimensional self-diffusion coefficient was proposed to derive a concise relation with Knudsen number. Additionally, a two-segment correlation formula was proposed to describe the concise relation. Owing to the strong CO2-pore surface interaction, CO2 was adsorbed on the pore surface and CH4 was restricted in a smaller pore space. Therefore, this fluid-pore surface interaction reduced the self-diffusion coefficient of binary mixture CO2/CH4. The workflow, nondimensional self-diffusion coefficient, and correlation formula derived in this study can be used for extensive applications, such as catalyst, fuel cell and sewage treatment.

Kerogen Differential Swelling during CO2-CH4 Adsorption: Mechanism and Significance

There exists differential swelling during the pure and competitive adsorption of CO2-CH4, whose mechanism was of broad interest to CO2-ESGR (CO2 enhanced shale gas recovery) and CCUS (carbon capture, utilization, and storage) engineering. However, the kerogen differential swelling during CO2-CH4 adsorption has been rarely reported, and so is its mechanism and significance. Here, the differential swelling mechanism of kerogen atomic representation was investigated using molecular simulation and the poromechanical model. Results indicated that swelling ratios for the systems of pure CO2, pure CH4, and a binary mixture of CO2 + CH4 (mole ratio = 1:1) gradually increase with the increasing temperature, pressure, and bulk mole of CO2. The activation energy of swelling deformation can be calculated via the Arrhenius formula, where they were 1.58 and 1.33 kJ/mol for CO2 and CH4, respectively, at 0.1 MPa, indicating that the swelling deformation of CO2 adsorption requires more energy to trigger than CH4. CO2 plays a dominant role in triggering the swelling deformation of competitive adsorption system. The swelling activation energy of pressure dependence firstly increases and then decreases with the increasing pressure. The outcomes of this paper have a higher fidelity than many previous efforts and were expected to be of broad interest to CCUS and CO2-ESGR.

Displacement Characteristics of CO2 to CH4 in Heterogeneous Surface Slit Pores

Studying the CO2–CH4 displacement process is of great importance to understand the CO2-enhanced shale gas recovery technology. However, most studies have focused on the gas behavior in the reservoir during the dominant stage of competitive adsorption after CO2 injection, as well as the shale gas recovery, displacement efficiency, and gas separation after displacement, while less attention has been paid to the gas behavior during the initial period of displacement. A CO2–CH4 displacement model that can provide a continuous pressure gradient in the displacement direction and a stable back-pressure at the pore outlet was developed based on a heterogeneous surface pore. The model was divided into three areas: CO2 injection area, pore area, and back-pressure area. Molecular dynamics simulations were used to study the effects of depressurization exploitation and injection pressure on the displacement behavior at the initial period of the displacement process under different reservoir conditions. It was found that the displacement process always starts from the CH4 reverse flow stage and then experiences the injection pressure action stage and positive displacement stage in sequence. Moreover, the extent of CH4 reverse flow directly affects the system development process and the final displacement efficiency. A small system presorption pressure and a large injection pressure are beneficial to the displacement. It is believed that the reservoir pressure should be dropped to the lowest possible level during depressurization exploitation, and the CO2 injection pressure needs to be selected by considering displacement efficiency, reservoir safety, and economic cost. The CO2 occupies the adsorption sites near graphene faster than that near montmorillonite (MMT) in the direction of displacement, while the CH4 desorption is faster near MMT. Therefore, it cannot be concluded that the displacement process near graphene is ahead of MMT. It is considered that the gas desorption/adsorption behavior near the graphene dominates the displacement process in terms of gas amount, while the fluctuation near MMT with time and injection pressure directly affects the gas adsorption variation in the pore space from the trend.

Thermodynamic characteristics of high-pressure CH4 adsorption on longmaxi shale subjected to supercritical CO2-water saturation

The shale-CH4 interaction after supercritical CO2 (ScCO2) injection can be well interpreted by adsorption thermodynamics study. Using a gravimetric method, the methane adsorption experiments over wide range of pressure (up to 35 MPa) and temperature (30–90 °C) were conducted on Longmaxi shale before and after ScCO2-water saturation (60days/20Mpa/70°C). In addition, low-temperature CO2 and N2 adsorption experiments were performed to analyze the variations of pore structure of shale. Results indicates that the high-pressure CH4 adsorption curves of shale exhibit obvious excess adsorption characteristics, and the excess adsorption capacity of shale to CH4 decreased after ScCO2-water saturation, which is mainly caused by the decrease of the specific surface area of shale. Comparing to Brunauer-Emmett-Teller, Dubinin-Radushkevich and Ono-Kondo models, the excess adsorption data can be well-fitted by Langmuir model through combining Henry equation. Additionally, the thermodynamic parameters of shale-CH4 adsorption pair, including the isosteric heat of adsorption, enthalpy change, Gibbs free energy change and entropy change, displayed strong dependence on adsorption capacity and temperature, and altered in varying degrees after ScCO2-water saturation, demonstrating that the shale gas recovery can be enhanced by ScCO2-water-shale interaction from the perspective of thermodynamics. This study provides a reference for CO2 enhanced shale gas recovery.

Experimental study on the methane desorption-diffusion behavior of Longmaxi shale exposure to supercritical CO2

Desorption-diffusion behaviors of CH4 in shale after supercritical CO2 (ScCO2) injection are closely related to CO2 enhanced shale gas recovery (CO2-ESGR). A self-developed gas desorption test system was used to measure the desorption kinetics of CH4 in shale collected from Sichuan Basin at different ScCO2 exposure pressures (8, 12, 16 MPa) and temperatures (40, 60, 80 °C), and the low-pressure N2 adsorption was performed to evaluate the variations of pore structure of shale. Results indicate that the desorption kinetics curves of CH4 in shale exhibit typical Langmuir characteristics under different desorption pressures, and the kinetics data were fitted by unipore and bidisperse diffusion models, manifesting that the diffusion of CH4 in the shale samples are dominated by macroporous channel (>95%). With increasing desorption pressure, the desorption capacity of CH4 in shale (nde) increased, while the diffusion coefficient of CH4 in shale (D) decreased. Additionally, the nde and D increased after ScCO2 exposure, and exhibited a slight exposure pressure and temperature dependence, which is mainly caused by the decrease of specific surface area and the widening of microstructure in shale, implying that the ScCO2-shale interaction can promote the desorption-diffusion of CH4 in shale. This study provides a theoretical reference for CO2-ESGR.

Desorption of CH4/CO2 from kerogen during explosive fracturing

Herein, the desorption behaviors of CO2/CH4 onto kerogen atomistic representation at higher temperatures and pressures and its inspirations of dividing stages on deflagration fracturing was clarified quantitatively via molecular simulation and mathematical model, as well as the effects of temperature and pressure. Molecular probe detection results suggested that accessible free volume of kerogen macromolecule was generated among different aliphatic chains or between the aliphatic chains and aromatic clusters, where the former type provides the primary free volume within the kerogen macromolecule. The quantitative division of desorption stages suggested four desorption stages via the established three critical pressures, start pressure (Pst), transition pressure (Ptr), and sensitive pressure (Pse), dividing the desorption properties into four stages: low efficiency desorption stage (P > Pst), slow desorption stage (Ptr < P < Pst), rapid desorption stage (Pse < P < Ptr), and sensitive desorption stage (P < Pse) respectively. All these three critical pressures firstly increase slowly and then significantly with the increasing temperature, indicating that high temperature was favorable for the early arrival of the rapid desorption stage and sensitive desorption stage. Both the pressure reductions for the former two stages keep stable for the temperature < 458 K. However, for the temperature > 458 K, the required pressure reduction for rapid desorption stage increases, suggesting that high temperature was also favorable for enhancement of shale gas production. Thus, the reservoir pressure was rather high after the deflagration fracturing process, resulting in the long duration of slow desorption stage and low efficiency desorption stage. The pressure reduction rate should be extended as long as possible to ensure the complete desorption of CH4, which could make an extension of the rapid desorption stage. The outcome of this paper was of broad interest for CO2 enhanced shale gas recovery and deflagration fracturing, as well as carbon capture and utilization engineering.

Competitive adsorption in CO2 enhancing shale gas: Low-field NMR measurement combined with molecular simulation for selectivity and displacement efficiency model

CO2 enhanced shale gas recovery is considered to be a potential method of shale gas development and CO2 reduction. However, core experiments cannot independently analysis competitive adsorption when the partial pressure of CH4 in the core sample keeps changing during displacement. In this study, an experimental method based on low-field nuclear magnetic resonance (NMR) and in situ gas chromatography is developed to quantitatively analyze the competitive adsorption of shale particles. As was demonstrated in our previous study, the adsorption capacity of the nanopores at various pressures can be obtained from the transverse relaxation spectrum of NMR and the change in pressure in a reference cavity. By NMR experiment combined with gas chromatography, the competitive adsorption selectivity of CH4 and CO2 in nanopores is investigated. In addition, molecular simulations are used to simulate the competitive adsorption and selectivity of CO2 and CH4 in shale nanopores with different pore structures, sizes, and shapes. The results reveal that as the pressure, carbon dioxide mole fraction, temperature, and pore size increases, the competitive adsorption selectivity S decreases. However, it remains greater than one, which demonstrates that CO2 has a stronger adsorption ability than CH4. For shale gas development, as the total pressure decreases, the contribution of the competitive adsorption effect becomes significant. A competitive adsorption model for CO2 and CH4 is established, and it is shown to fit the experimental data and simulation data well at different pressures. Finally, based on single-component adsorption results, we can separate the different effects and predict the displacement efficiency, which may provide a criterion in field scale simulations.

Chemical-mechanical coupling effects on the permeability of shale subjected to supercritical CO2-water exposure

The permeability of shale reservoir rock and caprock is the key parameters influencing the shale gas production and the storage security of CO2. During the CO2 enhanced shale gas recovery, the issue of how the coupled chemical-mechanical process control the evolution of porosity and permeability in shale remains undetermined. In this study, multiple tests were conducted to obtained the shale properties alteration induced by ScCO2-water exposure, including the mineral compositions measured by XRD, XRF and ICP-OES, the mechanical properties measured by uniaxial compression test, the pore structure and permeability of shale measured using nuclear magnetic resonance (NMR) at different confining stresses over a range of injection pressures. After ScCO2-water exposure, the contents of carbonate and clay minerals decreased, while the contents of quartz and feldspar increased. The geochemical reaction altered the pore structure and mechanical properties of shale, resulting in the enlargement of pore, the decrease in uniaxial compressive strength and elastic modulus of shale, which in turn impact the porosity and permeability evolution in shale. At the unstressed state, the pore in shale was enlarged by the pure chemical reaction, leading to the increase in porosity and the initial permeability of shale. At the stressed condition, the porosity and permeability of shale is controlled by the chemical-mechanical coupling effects, the permeability of CO2-water treated shale sample is lower than that of the untreated shale sample, which can be explained by the increase in stress sensitivity of shale permeability induced by the mechanical weakening, as the compressibility Cf and permeability change rate Δkc were increased after ScCO2-water exposure. In addition, the stress sensitivity of permeability in shale is stress-dependent, for both untreated and ScCO2-water treated shale samples, the Cf and Δkc of shale shown a negative relation with effective stress. At a higher effective stress condition, the change in the permeability of ScCO2-water treated shale is more significantly enhanced. The results demonstrated that the ScCO2-water-shale interaction induced chemical-mechanical effect may decrease the permeability of shale at in-situ stress condition, and hence adversely affecting the efficiency of gas recovery and CO2 sequestration in shale formation.

Application of atom force microscope and nanoindentation to characterize nanoscale mechanical properties of shale before and after supercritical CO2 immersion

Understanding the microscopic effects of supercritical CO2 (SC–CO2) on shale plays an essential role in carbon capture utilization and storage (CCUS). The variation of shale microstructures and micromechanical properties induced by SC-CO2 immersion is obscure, which is crucial in CO2-enhanced shale gas recovery. In this study, the organic matter (OM) and minerals of shale are identified in the microscale by scanning electron microscope (SEM), energy dispersive spectrometer (EDS), atom force microscope (AFM) and nanoindentation. The microstructures and micromechanical properties are measured before and after SC-CO2 exposure. The micromechanical properties variation of shale minerals and OM of shale are analyzed. The results show that the mechanical properties of OM have changed significantly after SC-CO2 exposure. Due to the interaction of CO2, the elastic modulus of OM increased by 124%. With the dissolution of CO2, the porosity of calcite increases from 7.1% to 8.1%, while decreasing by 6% in elastic modulus. By comparing the surface roughness calculated by AFM, the clay and OM swell. Although the mechanical properties are more discrete after CO2 immersion, the correlation between Young's modulus and hardness is better. These findings help understand the SC-CO2 exposure effects on shale and provide insights into the applications of SC-CO2 in unconventional resource development from a microscale perspective.

Carbon dioxide adsorption to 40 MPa on extracted shale from Sichuan Basin, southwestern China

CO2-enhanced shale gas recovery is a promising technology for promoting shale gas production and ideally for CO2 geological sequestration through sorption. Despite this, research studies to date have solely been performed at pressures and temperatures substantially lower than those that actually occur in shale formations. The thrust of this work is to measure and model the carbon dioxide adsorption behavior for the full spectrum of in situ pressure range up to 40 MPa with an intention to provide the baseline values of carbon sequestration planning for the Longmaxi shale formation, Sichuan China. In this study, CO2 adsorption isotherms were measured up to 40 MPa for one sample for five different temperatures (40, 60, 80, 100, and 120 °C) by using the gravimetric method. In the experimental program, we uniquely treated the shale with supercritical CO2 to extract the extractable components to eliminate the high-pressure CO2 extraction effect on adsorption. This pre-extraction was found to significantly reduce the specific surface area of the shale. All excess adsorption trends increased rapidly to maxima followed by the decline to a plateau. The negative excess (Gibbs) adsorptions were observed for two samples at 60 °C and at 40 and 60 °C. At 60 °C, maxima were observed near the critical pressure of CO2 (7.38 MPa) for all samples, which is attributed to the rapid increase of CO2 density near the critical pressure. Adsorption data were fit using several models and the Dubinin-Radushkevich model modified with k times the gas density (MDR + k model) was found to most closely describe the experimental results above 30 MPa. The model-fitted carbon-dioxide maximum absolute adsorption capacities (n0) were 0.150–0.272 mmol/g at 60 °C. Further, n0 decreased with increasing temperature. Thermodynamic data such as heats of adsorption were calculated and used to evaluate CO2 adsorption properties under various conditions. The data also showed that the total organic carbon content of the shale was the primary factor determining CO2 adsorption. The results of this work provide useful knowledge regarding the adsorption characteristics of actual shale formations and are expected to assist in future gas extraction and sequestration projects.

CO2 mineralization and CH4 effective recovery in orthoclase slit by molecular simulation

Knowledge of the competitive adsorption behaviors of shale gas and CO2 in shale is crucial for understanding the fluid storage, exploration and segmentation. In this work, Grand Canonical Monte Carlo (GCMC) and molecular dynamics (MD) simulations as well as DFT calculation were carried out to study the adsorption mechanisms of CH4 and its mixtures with CO2 in orthoclase slit. The dependence of gas adsorption behavior on geological depth, water content and CO2 mole fraction, yCO2, were explicitly examined. Quantum chemistry calculation characterizes the chemical adsorption of CO2 on orthoclase surface by forming a carbonate-like structure, showing the feasibility of CO2 enhanced shale gas recovery and geological sequestration of CO2 in orthoclase. The enrichment region of pure CH4 in orthoclase slit is inferred to be at the geological depth of approximately 2600 m, which accords with the high methane yield in 2000–3200 m by CO2 injection. The adsorbed methane molecules are favorably loaded at slits with low water content (0–2 wt%). The adsorption capacity of CH4 in the binary mixture decreases with the increasing yCO2. The favorable mining conditions are predicted to at 2000–3200 m with an economical yCO2 of 0.3. Shallow geological depth (200–400 m) is helpful for the sequestration of CO2. This study has gained deep insights into the adsorption and recovery mechanisms of shale gas in orthoclase slit and has shed light on the efficiencies of CO2 enhanced recovery of shale gas and the mineralization of CO2 in shale.

Fracture-Matrix Modeling Technique Unlocks CO2 Enhanced Shale Gas Recovery

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202222, “Fracture-Matrix Modeling of CO2 Enhanced Shale Gas Recovery in Compressible Shale,” by Dhruvit Satishchandra Berawala, SPE, Equinor, and Pål Østebø Andersen, University of Stavanger. The paper has not been peer reviewed. With technology available at the time of writing, only 3–10% of gas from tight shale is recovered economically through natural depletion, demonstrating a significant potential for enhanced shale gas recovery (ESGR). Experimental studies have demonstrated that shale kerogen/organic matter has a higher adsorption affinity for carbon dioxide (CO2) than methane (CH4). CO2 is preferentially adsorbed over CH4 with a ratio of as much as 5:1. The complete paper examines CO2 ESGR in compressible shale during huff ’n’ puff injection to understand better the parameters controlling its feasibility and effectiveness. The authors present a mathematical model in the complete paper in which the CO2/CH4 substitution mechanism is implemented in an injection/production setting representative of field implementation. Introduction Modeling of CO2 injection and the interplay between CO2 and CH4 sorption has been extremely challenging for scientists and engineers. The presence of CO2 with methane during the CO2 ESGR process makes gas-desorption behavior and measurement more difficult. Few researchers have evaluated the efficiency of CO2 ESGR in compressible shale. To improve the understanding of this technique, the authors present a numerical modeling approach using a 1D+1D fracture-matrix model in order to study the feasibility of CO2 injection in shale formations. The model consists of a high-permeability fracture extending from a well perforation, symmetrically surrounded by a shale matrix as shown in Fig. 1 of the complete paper. The fracture is assumed to have fixed width for simplicity. The system is assumed to consist of free gas in the pores as well as adsorbed gas in the matrix. When pressure in the well is reduced, free and adsorbed gas from the matrix flows toward the fracture and then to the well. The pressure-based advective forces, along with concentration-based diffusive forces, are considered the main transport mechanisms in this work. After the CH4 production cycle, CO2 is injected from the same well into the fracture and to the matrix. Injection of CO2 leads to an increase in total gas pressure in the system. CH4/CO2 adsorption kinetics are modeled using a multicomponent adsorption isotherm presented in earlier works by the authors. Apparent permeability is used to account for gas slippage effect, effective stress, adsorption, and other flow regimes relevant to the nanopore structure of the shale formation. The effect that compressible rock has on the porosity and apparent permeability changes with CH4 production. CO2 injection also is considered. The resulting model is composed of nonlinear partial differential equations that are solved numerically using an operator splitting approach. The geometry, mole conservation, pressure-dependent parameters, and initial and boundary conditions of the mathematical model are detailed in the complete paper, including mathematical definitions and solution procedures in its appendix.

Influence of supercritical CO2 exposure on water wettability of shale: Implications for CO2 sequestration and shale gas recovery

The wettability of reservoir rocks is considered to be closely related to fluid distribution and CO2 geo-storage (CGS) security after injecting CO2 into reservoir. To investigate the influence of supercritical CO2 (ScCO2) injection on water wettability of shale, a sessile drop method was used to measure water contact angles of shale samples collected from Sichuan Basin (marine) and Ordos Basin (continental) at different ScCO2 exposure time and pressure. In addition, X-ray diffraction (XRD) and low-pressure N2 adsorption (LP-NA) were performed to evaluate the variations of mineral compositions and pore structure of shale. Results indicate that shale-water contact angles generally increased (from 22.74% to 43.94%) after ScCO2 exposure, which is primarily caused by the decrease of clay minerals and carbonates in shale. The water wettability of shale weakened after ScCO2 exposure, indicating that the interaction force between shale and water molecules changed, which may have reduced the resistance of water to flow in pores and fractures of shale, inferring that the alterations of shale water wettability after ScCO2 injection is beneficial to gas seepage in pore channels, but may exert a negative influence on CGS stability. This study provides a theoretical reference for CO2 sequestration and CO2-enhanced shale gas recovery (CS-ESGR).

Gas adsorption characteristics changes in shale after supercritical CO2-water exposure at different pressures and temperatures

The supercritical CO2 (ScCO2)-water-shale interaction and its influence on adsorption characteristics of shale have significant impact on the estimation of the CO2 storage capacity. In this study, the influence of ScCO2-water exposure pressures and temperatures (P = 0, 10, 15, 20 MPa, T = 308, 323, 338, 353 K) on shale CH4 and CO2 adsorption characteristics were investigated. CH4 and CO2 adsorption tests, X-ray diffraction analysis, low-pressure N2 adsorption measurement were carried out on the shale samples before and after exposure. The results shown that after ScCO2-water exposure, the CH4 and CO2 adsorption capacity were decreased gradually with the increase of exposure pressure and the decrease of exposure temperature, due to the alterations of mineral composition and pore structure in shale. After ScCO2-water exposure, the contents of shale clay minerals, organic matter and carbonate were decreased, resulting in the decrease of specific surface area and micropore volume. With the increase of exposure pressure and the decrease of exposure temperature, the solubility and extraction ability of ScCO2-water were increased, then more significant mineral composition and pore structure alterations, as well as more significant changes on the gas adsorption capacities of shale were expected. The selectivity factor of CO2 to CH4 of shale shown a gradually decreased trend with the increase of exposure pressure and the decrease of exposure temperature, respectively, and were all greater than 1 for both the untreated and ScCO2-water treated shale samples at different exposure conditions, indicating that CO2 enhanced shale gas recovery and sequestration is feasible even after ScCO2-water exposure. To predict the CO2 storage capacity in shale gas reservoirs, the combined effects of exposure pressure and temperature on the adsorption characteristics of shale should be considered at the reservoir conditions.