Enhanced Gas Recovery Research Articles

Impact of gas adsorption of nitrogen, argon, methane, and CO2 on gas permeability in nanoporous rocks

Gas adsorption on the surface of nanoporous rocks is an important process that occurs in many applied scenarios such as shale gas production or CO2 enhanced gas recovery or storage. While there are few theoretical considerations on the effect of gas adsorption on permeability, a systematic laboratory investigation of the impact of gas adsorption on gas flow and permeability is still lacking. In this paper, permeability of four adsorptive gases, i.e., nitrogen, argon, methane, and carbon dioxide, was measured, along with helium permeability, for two nanoporous rock samples that have high and low total organic carbon (TOC) content, respectively. The measurements were conducted at a range of pore pressures from 150 to 1500 psi (1.03–10.34 MPa). Gas adsorption isotherms were also measured at the same conditions. A mathematical model that considers adsorption with specific boundary conditions for the experimental setup was used for data analysis. The results show that gas adsorption causes larger drop in pressure decay and greater retardation in pressure equilibrium. However, the reduction of permeability relative to helium (25%–46%) is similar for gases with different levels of adsorption, indicating the occurrence of single-layer adsorption for these gases. Comparison between the two samples further supports the concept of single-layer adsorption and signifies the impact of pore size on the permeability reduction due to adsorption. These new findings deepen the fundamental understanding and provide important clarification on the effect of gas adsorption on gas flow and permeability in nanoporous rocks.

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 comprehensive mathematical model considering multiple mechanisms for CO2 displacement of methane in shale nanopores

With the rise in energy demand, shale gas exploitation has gained prominence, particularly through the use of carbon dioxide (CO2) injection for enhanced gas recovery. However, the intricate gas flow mechanisms within this process in shale nano-pores remain poorly understood, which greatly limited the accurate numerical simulation of shale gas production by CO2 injection. This study investigates the flow mechanisms of CH4 and CO2 gases in shale nano-pores, developing an improved apparent relative permeability model for the two-component CH4–CO2 gas, incorporating multiple transport mechanisms. Sensitivity analysis includes factors such as pressure, pore radius, viscosity correction effects, flow mechanisms, and composition fractions. Key findings from this study are as follows: (1) Increasing pore radius or decreasing pressure enhances the apparent permeability of CH4–CO2 gas, with pressure effects becoming negligible above 20 MPa. (2) The impact of viscosity correction on gas permeability diminishes with higher pressure or larger pore radius, becoming negligible for pore radii over 10 nm. (3) Larger pore radii increase slip flow and Knudsen diffusion, while molecular and surface diffusion proportions decrease; surface diffusion and slip flow dominate at high pressures. (4) A higher CH4–CO2 component ratio increases CH4 permeability and decreases CO2 permeability, with minimal influence from pressure and pore radius. These results can improve numerical simulations for shale gas production by using CO2 injection.

Feasibility of CO2 storage and enhanced gas recovery in depleted tight sandstone gas reservoirs within multi-stage fracturing horizontal wells

Injecting CO2 when the gas reservoir of tight sandstone is depleted can achieve the dual purposes of greenhouse gas storage and enhanced gas recovery (CS-EGR). To evaluate the feasibility of CO2 injection to enhance gas recovery and understand the production mechanism, a numerical simulation model of CS-EGR in multi-stage fracturing horizontal wells is established. The behavior of gas production and CO2 sequestration is then analyzed through numerical simulation, and the impact of fracture parameters on production performance is examined. Simulation results show that the production rate increases significantly and a large amount of CO2 is stored in the reservoir, proving the technical potential. However, hydraulic fractures accelerate CO2 breakthrough, resulting in lower gas recovery and lower CO2 storage than in gas reservoirs without fracturing. Increasing the length of hydraulic fractures can significantly increase CH4 production, but CO2 breakthrough will advance. Staggered and spaced perforation of hydraulic fractures in injection wells and production wells changes the fluid flow path, which can delay CO2 breakthrough and benefit production efficiency. The fracture network of massive hydraulic fracturing has a positive effect on the CS-EGR. As a result, CH4 production, gas recovery, and CO2 storage increase with the increase in stimulated reservoir volume.

Numerical Simulation of Non-Darcy Flow in Naturally Fractured Tight Gas Reservoirs for Enhanced Gas Recovery

In this work, we analyze non-Darcy two-component single-phase isothermal flow in naturally fractured tight gas reservoirs. The model is applied in a scenario of enhanced gas recovery (EGR) with the possibility of carbon dioxide storage. The properties of the gases are obtained via the Peng–Robinson equation of state. The finite volume method is used to solve the governing partial differential equations. This process leads to two subsystems of algebraic equations, which, after linearization and use of an operator splitting method, are solved by the conjugate gradient (CG) and biconjugate gradient stabilized (BiCGSTAB) methods for determining the pressure and fraction molar, respectively. We include inertial effects using the Barree and Conway model and gas slippage via a more recent model than Klinkenberg’s, and we use a simplified model for the effects of effective stress. We also utilize a mesh refinement technique to represent the discrete fractures. Finally, several simulations show the influence of inertial, slippage and stress effects on production in fractured tight gas reservoirs.

Experimental and Numerical Simulation Study on Enhancing Gas Recovery with Impure CO2 in Gas Reservoirs

Experimental and Numerical Simulation Study on Enhancing Gas Recovery with Impure CO2 in Gas Reservoirs

Research on Mechanism and Effect of Enhancing Gas Recovery by CO2 Huff-n-Puff in Shale Gas Reservoir.

The technology of CO2-enhanced gas recovery (CO2-EGR) plays a pivotal role in the CCUS (Carbon Capture, Utilization, and Storage) industry, which helps to achieve a win-win situation of economic benefit and environmental benefit for gas fields. Shale gas reservoirs, with their unique geological and surface engineering advantages, are one of the most promising options for CCUS implementation. Focusing on shale formations within the mid-deep blocks of the Sichuan Basin, this study conducted competitive adsorption experiments using multicomponent gases. Through physical simulations and single-well numerical modeling, factors such as injection volume, timing, shut-in time, and huff-n-puff rounds were examined for their impact on recovery. The results show that the higher the CO2 content in the injected medium, the more pronounced advantage in gas adsorption on shale surfaces. Optimal performance was achieved with a CO2 content in the injection medium of 80% to 100%, an injection volume of 0.2-0.3 PV, a shut-in time exceeding 6 h, and a relatively delayed injection timing. The recovery in the first round of huff-n-puff was increased by 24.2% to 47.8%, which gave a full play to the role of huff-n-puff and achieved favorable benefits. Based on the middle-deep geological parameters, a single-well numerical simulation was established, which demonstrates that single-well EUR (estimated ultimate recovery) can be increased by 14.2% to 19.8% compared to gas wells without CO2 injection. This study provides essential guidance for the enhanced recovery in shale gas reservoirs through CO2 huff-n-puff.

Experimental and numerical evaluation of relative permeability modifiers during water control in a tight gas reservoir

Relative permeability modifier (RPMs) is a water control technique that is implemented for enhancing gas recovery rates and prolonging well productive life during fracturing the tight gas reservoir. RPMs filtrate into formation for a certain depth along with the fracturing fluid to control water output by a “drag” effect on water phase only. To optimize RPM treatment, both experimental investigation and numerical simulation are used in this paper. In laboratory, transient core-flooding tests were conducted to investigate the water control performance of newly formulated polymer (RPM). The relative permeability of gas was corrected due to gas volume changes during displacement. The results showed that the selective water control effect of RPM by reducing water relative permeability dramatically with little impact on gas relative permeability. The RPM concentration was optimized as 0.01 %XSJ-14(A)+0.05 %XSJ-14(B) while injection volume as 5PV by comparison of relative permeability curves. A 2D fracture model of a tight gas model was built to compare the production before and after RPM treatment. The results of numerical simulation confirmed the different flow control effect of RPM on water and gas. A sensitivity analysis was conducted for the effect of fracture length, fracture conductivity, RPM filtration and RR value. The results indicate that there are limits of all the factor on RPM’s water control performance.

Influence of Diffusion, Adsorption, Connate Water, and Salinity on Enhanced Gas Recovery and Carbon Storage Reservoir Simulations

Influence of Diffusion, Adsorption, Connate Water, and Salinity on Enhanced Gas Recovery and Carbon Storage Reservoir Simulations

Giant Effect of CO2 Injection on Multiphase Fluid Adsorption and Shale Gas Production: Evidence from Molecular Dynamics.

Carbon dioxide (CO2) injection in unconventional gas-bearing shale reservoirs is a promising method for enhancing methane recovery efficiency and mitigating greenhouse gas emissions. The majority of methane is adsorbed within the micropores and nanopores (≤50 nm) of shale, which possess extensive surface areas and abundant adsorption sites for the sequestration system. To comprehensively discover the underlying mechanism of enhanced gas recovery (EGR) through CO2 injection, molecular dynamics (MD) provides a promising way for establishing the shale models to address the multiphase, multicomponent fluid flow behaviors in shale nanopores. This study proposes an innovative method for building a more practical shale matrix model that approaches natural underground environments. The grand canonical Monte Carlo (GCMC) method elucidates gas adsorption and sequestration processes in shale gas reservoirs under various subsurface conditions. The findings reveal that previously overlooked pore slits have a significant impact on both gas adsorption and recovery efficiency. Based on the simulation comparisons of absolute and excess uptakes inside the kerogen matrix and the shale slits, it demonstrates that nanopores within the kerogen matrix dominate the gas adsorption while slits dominate the gas storage. Regarding multiphase, multicomponent fluid flow in shale nanopores, moisture negatively influences gas adsorption and carbon storage while promoting methane recovery efficiency by CO2 injection. Additionally, saline solution and ethane further impede gas adsorption while facilitating displacement. Overall, this work elucidates the substantial effect of CO2 injection on fluid transport in shale formations and advances the comprehensive understanding of microscopic gas flow and recovery mechanisms with atomic precision for low-carbon energy development.

Enhanced Gas Recovery Coupled with CO2 Sequestration in Tight Sandstone Reservoirs with Different Pore-Throat Structures

Enhanced Gas Recovery Coupled with CO₂ Sequestration in Tight Sandstone Reservoirs with Different Pore-Throat Structures

Numerical simulation of CO2 enhanced condensate gas recovery: A case study in pen 5 gas reservoir

AbstractCO2 flooding is an effective technology for suppling condensate gas reservoir pressure and mitigating global warming. In this study, numerical simulation studies have been conducted to enhance gas recovery in Pen5 condensate gas reservoir using CO2 flooding. Pen5 reservoir has lasted 20 years of primary depletion, which affected by water invasion and retrograde condensation. In numerical simulation study, the GEM module is applied to implement history‐matching of production data, and good agreement has been achieved. Based on comprehensive geological understanding, production dynamics, and numerical simulation techniques, areas with minimal impact from water invasion and retrograde condensation contamination have been delineated. The comparison between continued depletion and the implementation of CO2 injection as a replacement technology in favorable areas has demonstrated the feasibility of CO2 flooding development in these regions. The analysis of the advantages and disadvantages of using miscible flooding and immiscible flooding was conducted, and the optimal development well pattern was evaluated. In the end, the plan of CO2 flooding of Pen5 reservoir has been designed and the gas production rate in the next 10 years has been predicted. The research findings of this study have reference significance for the practical application of CO2 flooding in developing condensate gas reservoirs.

Enhancing shale gas recovery: An interdisciplinary power-law model of hydro-mechanical-fracture dynamics

This study explores the efficiency of using carbon dioxide (CO2) to extract shale gas, highlighting its potential to enhance extraction while mitigating environmental CO2 pollution. Given the intricate microstructure of shale, CO2 injection inevitably induces deformation within the shale reservoir's internal microstructure, thereby impacting gas displacement efficiency. The organic matter (kerogen) network and fracture network in shale, serving as primary spaces for gas adsorption and migration, exhibit complex microstructural characteristics. Thus, we developed a dynamic coupled hydro-mechanics permeability model for binary gas displacement, and three novel, interdisciplinary fractal power-law parameters are proposed to represent the distribution of shale fractures, considering the adsorption–desorption strength of the kerogen network. Numerical simulations analyzed the changes in gas seepage, diffusion, shale stress, permeability, and factors influencing displacement efficiency during the CO2–EGR (enhanced gas recovery) projects. Key findings include (1) CO2 injection leads to a nonlinear increase in the number of shale fracture networks, thereby enhancing the CH4 output efficiency. (2) Compared to traditional fractal theory, the proposed power-law model is applicable to a wider range of reservoir fracture distributions and effectively characterizes the density (by α), size (by r), and complexity (by n) of the fracture network during the CO2–EGR process. (3) Changes in the proposed interdisciplinary power-law parameters significantly alter CO2 and CH4 adsorption capacities and, in turn, significantly affects displacement efficiency and shale deformation. According to calculations, these parameters have the greatest impact on the CO2–EGR process, ranging from 16.3% to 68.1%.

CO2 injection-based enhanced methane recovery from carbonate gas reservoirs via deep learning

CO2 injection is a promising technology for enhancing gas recovery (CO2-EGR) that concomitantly reduces carbon emissions and aids the energy transition, although it has not yet been applied commercially at the field scale. We develop an innovative workflow using raw data to provide an effective approach in evaluating CH4 recovery during CO2-EGR. A well-calibrated three-dimensional geological model is generated and validated using actual field data—achieving a robust alignment between history and simulation. We visualize the spread of the CO2 plume and quantitatively evaluate the dynamic productivity to the single gas well. We use three deep learning algorithms to predict the time histories of CO2 rate and CH4 recovery and provide feedback on production wells across various injection systems. The results indicate that CO2 injection can enhance CH4 recovery in water-bearing gas reservoirs—CH4 recovery increases with injection rate escalating. Specifically, the increased injection rate diminishes CO2 breakthrough time while concurrently expanding the swept area. The increased injection rate reduces CO2 breakthrough time and increases the swept area. Deep learning algorithms exhibit superior predictive performance, with the gated recurrent unit model being the most reliable and fastest among the three algorithms, particularly when accommodating injection and production time series, as evidenced by its smallest values for evaluation metrics. This study provides an efficient method for predicting the dynamic productivity before and after CO2 injection, which exhibits a speedup that is 3–4 orders of magnitudes higher than traditional numerical simulation. Such models show promise in advancing the practical application of CO2-EGR technology in gas reservoir development.

Helium expansion revisited: Effects of accessible volume on excess adsorption in kerogen matrices

Enhancing our understanding of the excess adsorption capacity in shale gas reservoirs is paramount for accurately predicting production capabilities and refining extraction processes. A significant factor in this calculation is the accessible volume, which can only be measured indirectly using helium as a proxy. In this study, hybrid grand canonical Monte Carlo/molecular dynamics (GCMC/MD) simulations were employed to scrutinize the accessible volume and quantify the excess adsorption capacities of various gases in kerogen matrices, characterized by diverse micropore distributions at 363.15 K (90 °C) and pressures up to 50 MPa. We evaluated multiple approaches to determine accessible volume in simulations, emphasizing the importance of selecting a probe size that reflects the actual size of the adsorbate. The simulation outcomes reveal that accessible volumes derived from the helium expansion method, mimicking the traditional experimental techniques, tend to be overestimated by around a factor of two. This finding challenges the reliability of such measurements and suggests a need for their recalibration based on computer simulation models. Furthermore, when our simulations were compared with various theoretical adsorption isotherm models, the more advanced Supercritical Dubinin-Radushkevich and Supercritical Brunauer-Emmett-Teller models demonstrated better accuracy in predicting absolute adsorption values compared to the more conventional Langmuir model. However, neither model accurately predicted the absolute adsorption quantities, indicating room for improvement. Finally, the simulations underscore the significant adsorption capacity of CO2 compared to other gases, highlighting its promising role in facilitating enhanced gas recovery and geological sequestration within shale formations.

Competitive adsorption mechanisms of multicomponent gases in kaolinite under electric fields: A molecular perspective

The investigation of the competitive adsorption mechanisms of gas mixtures within the inorganic nanopores of shale influenced by an electric field holds paramount importance for improving shale gas recovery and enhancing CO2 storage efficiency. This study employs molecular dynamics (MD) simulations to investigate the competitive adsorption mechanisms of gas mixtures on kaolinite surfaces. Subsequently, the engineering parameters governing electric field-enhanced CO2 sequestration and enhanced gas recovery (CS-EGR) are explored and optimized. In the absence of an electric field, the analysis reveals that water molecules exhibit the highest adsorption capacity in a ternary H2O–CO2–CH4 mixture, resulting in the formation of a water film of a specific thickness. CO2 displays a superior adsorption capability over CH4. As the CO2 volume injected into the reservoir increases, CH4 undergoes desorption due to the dominant adsorption effect of CO2. However, the efficiency of CO2 displacing CH4 diminishes significantly. The introduction of an electric field alters the equilibrium state of the gas mixture, leading to a further increase in CO2 adsorption and enhancing its selectivity relative to that of CH4 by 33%. These findings lay the foundation for the practical implementation of electric field-enhanced CS-EGR in shale reservoirs.

Review on Carbon Capture, Utilization, and Storage for Enhancing Gas Recovery

Review on Carbon Capture, Utilization, and Storage for Enhancing Gas Recovery

Numerical simulation of enhanced gas recovery from methane hydrate using the heat of CO2 hydrate formation under specific geological conditions

Methane hydrate (MH) is found under the seabed in Japan's exclusive economic zone and is attracting attention as a domestic natural gas resource. One of the methods for extracting methane gas (MG) from sub-seabed MH reservoir is depressurisation. However, the production decelerates after a certain time partly due to the cooling of the reservoir caused by the heat absorption during MH dissociation. Therefore, several enhanced gas recovery (EGR) methods have been proposed, such as injecting CO2 into a sub-seabed sand layer to form CO2 hydrate (CDH) and, using the heat of CDH formation. This method is two functions: EGR and the reduction of greenhouse gas emission. In this study, a numerical method was developed to investigate the performance of the EGR from MH, using the heat of CDH formation. In our previous study, CDH formation model had been installed into a programme code for two-phase flow of CO2 and water in porous media. Based on this code, we newly implemented the state equation, enthalpy model, viscosity model, and heat conduction model of MG and the dissociation model of MH. Then, simulations were performed to form CDH in specific sand-mud alternate layers and to dissociate MH. As a result, it was suggested that increasing the CO2 injection amount potentially increases MH dissociation and the vertical distance between the mud layer capping the injected liquid CO2 and the bottom-simulating reflector of CDH is important to ensure a large CDH region to generate a large amount of heat. It was also shown that even after stopping CO2 injection, MH dissociation can continue for a certain period.

Dynamic Response of Gas Recovery Enhancement Efficiency in Coalbed Methane Displacement by Hot Flue Gas: From the Perspective of Thermo–Hydro–Mechanical–Chemical Coupling

Dynamic Response of Gas Recovery Enhancement Efficiency in Coalbed Methane Displacement by Hot Flue Gas: From the Perspective of Thermo–Hydro–Mechanical–Chemical Coupling

Current Progress and Development Trend of Gas Injection to Enhance Gas Recovery in Gas Reservoirs

Conventional recovery enhancement techniques are aimed at reducing the abandonment pressure, but there is an upper limit for recovery enhancement due to the energy limitation of reservoirs. Gas injection for energy supplementation has become an effective way to enhance gas recovery by reducing hydrocarbon saturation in gas reservoirs. This review systematically investigates progress in gas injection for enhanced gas recovery in three aspects: experiments, numerical simulations and field examples. It summarizes and analyzes the current research results on gas injection for EGR and explores further prospects for future research. The research results show the following: (1) Based on the differences in the physical properties of CO2, N2 and natural gas, effective cushion gas can be formed in bottom reservoirs after gas injection to achieve the effects of pressurization, energy replenishment and gravity differentiation water resistance. However, further experimental evaluation is needed for the degree of increase in penetration ability. (2) It is more beneficial to inject N2 before CO2 or the mixture of N2 and CO2 in terms of EGR effect and cost. (3) According to numerical simulation studies, water drive and condensate gas reservoirs exhibit significant recovery effects, while CO2-EGR in depleted gas reservoirs is more advantageous for burial and storage; current numerical simulations only focus on mobility mass and saturation changes and lack a mixed-phase percolation model, which leads to insufficient analysis of injection strategies and a lack of distinction among different gas extraction effects. Therefore, a mixed-phase-driven percolation model that can characterize the fluid flow path is worth studying in depth. (4) The De Wijk and Budafa Szinfelleti projects have shown that gas injection into water drive and depleted reservoirs has a large advantage for EGR, as it can enhance recovery by more than 10%. More experiments, simulation studies and demonstration projects are needed to promote the development of gas injection technology for enhanced recovery in the future.