CO2 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.

A Multiple-physics coupled model for nanoconfined CO2-CH4 mixture transport behavior: Implications for CO2 geological storage in ultra-tight formation

Considerable efforts have been made to examine the feasibility of CO2-enhanced gas recovery (CO2-EGR), a promising approach for improving gas recovery by using CO2 to displace in-situ CH4 in ultra-tight gas reservoirs rich in nanopores. However, most research has focused on either single-component gas flow physics or competitive adsorption of multiple gas components in nanopores. The flow behavior of nanoconfined CO2-CH4 mixtures remains an area of knowledge gap. This work establishes a theoretical framework for CO2-CH4 mixture flow capacity by coupling mixture flow in the bulk region with surface diffusion in the adsorption area. Results indicate that: a) Total mixture flow conductance increases rapidly at pressures below ∼10 MPa, with CO2 contributing over 99 % to surface diffusion conductance; b) Increasing CO2 molar ratio from 0.2 to 0.8 can lead to a 167 % enhancement in total mixture conductance; c) Variations in CO2-CH4 competitive adsorption characteristics have little impact on total conductance.

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 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.

Evaluation of CO2-enhanced gas recovery and storage through coupled non-isothermal compositional two-phase flow and geomechanics modelling

CO2 injection into unconventional gas reservoir has been recognized as a promising approach to enhance unconventional gas recovery (CO2-EUGR) and sequester CO2 geologically. The CO2-EUGR is a complex multi-physics coupling process. To accurately assess the effectiveness of different injection strategies, this paper firstly presents a non-isothermal compositional two-phase flow model coupling with geomechanics, in which a multicomponent adsorption kinetics is incorporated to separate free phase and adsorbed phase. A hybrid numerical approach combining EbFVM and GFEM is used for numerical solutions. The performance of different injection strategies for CO2-EUGR is evaluated. The results indicate that CO2 injection is able to improve CH4 recovery significantly, over 90 % of injected CO2 can be adsorbed in reservoirs, The performance of CO2-EUGR is permeability dependent, the displacement effect occurs earlier when reservoir permeability is higher; Increase in temperature of injected gas and mixed CO2/N2 injection can further improve CH4 recovery, especially for low permeability gas reservoirs; Mixed gas injection also enables displacement effect to occur earlier; Cyclic injection can hardly lead to increase in CH4 production, especially when reservoir permeability is higher, while it can cause an increase in amount of adsorbed CO2 during injection period. Based on these findings, a geothermal-assisted CO2-EUGR method is proposed.

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%.

Fully coupled THM modeling of CO2 sequestration in depleted gas reservoirs considering the mutual solubilities in CO2-Hydrocarbon gas-brine systems

In recent years, CO2 geological sequestration has gained significant traction as a viable solution for mitigating global emissions. However, assessing such processes has been challenging due to its inherent complexity. Given the extensive temporal and spatial scales, numerical modeling has emerged as the most efficient and cost-effective means of evaluating them. At present, most existing models are tailored for CO2 sequestration in saline aquifers. There are relatively few models available for depleted gas reservoirs, and only a fraction of them possess the capability to account for geomechanical coupling or complex natural gas compositions.CO2 sequestration in depleted gas reservoirs is considered a promising technique for combating global warming. The use of depleted gas reservoirs has several advantages over saline aquifers, such as the availability of existing facilities and the proven capacity and stability of gas storage. It is believed that CO2 storage in depleted petroleum reservoirs can provide intermediate-scale storage until large-scale storage in saline aquifers becomes mature.Here we propose an Equation of State (EOS) module for CO2 sequestration in depleted gas reservoirs or CO2-enhanced gas recovery. It takes into consideration the mutual solubilities in the CO2-hydrocarbon gas-brine system based on the equality of the chemical potentials of the aqueous and non-aqueous phases. In such a way, it can properly address CO2 dissolution into brine when hydrocarbon gas is present. Hydrocarbon gas includes methane, ethane, and propane. It employs well-recognized approaches to calculate the thermodynamic properties of the gaseous and aqueous phases. This EOS module has been applied to our in-house simulator, TOUGH2-CSM, to enable thermo-hydrological-mechanical modeling. Our research could fill the gap and provide a reference for future studies in this regard.

A two-phase, multi-component model for efficient CO2 storage and enhanced gas recovery in low permeability reservoirs

Introduction: Carbon dioxide (CO2) enhanced gas recovery represents a viable strategy for sequestering CO2 while concurrently augmenting gas production from subsurface reservoirs. Gas reservoirs, as inherent geological formations, are optimal repositories for gaseous compounds, rendering them suitable for CO2 storage. Nevertheless, the economic viability of pure CO2 storage necessitates integration with oil and gas recovery mechanisms to facilitate widespread CO2 utilization.Method: This study addresses the complexities of CO2 enhanced gas recovery through a comprehensive approach that combines theoretical model and numerical simulations. A numerical model is developed to simulate three-component diffusion involving CO2, and methane (CH4) in a two-phase system comprising gas and water.Results: The investigation systematically explores the process of enhanced CH4 extraction and CO2 injection into the reservoir and examines the influencing factors on extraction. Simulation results reveal a power-law decrease in CH4 production rate, stabilizing at a constant extraction rate. Enhanced CH4 extraction benefits from increased porosity, with higher porosity levels leading to greater CH4 extraction. Permeability augmentation positively influences CH4 production, although with diminishing returns beyond a certain threshold. The CO2 injection rate shows a direct proportionality to CH4 production. However, elevated CO2 injection rates may increase reservoir pressure, potentially causing cap rock damage and CO2 gas flushing.Discussion: This study contributes valuable theoretical insights to the field of CO2 enhanced gas recovery engineering, shedding light on the intricate dynamics of multi-component fluid transport processes and their implications for sustainable CO2 utilization.

A hybrid numerical model for coupled hydro-mechanical analysis during CO2 injection into heterogeneous unconventional reservoirs

This paper presents a hybrid numerical model for simulating compressible multiphase multicomponent transport in deformable, heterogeneous unconventional reservoirs. A fully implicit theoretical framework for coupled hydromechanical behaviour is established, in which the flash calculation is avoided. To preserve the local mass conversation, an element based finite volume method is used to spatially discretize mass conversation equations. Linear momentum equilibrium equation is discretized with finite element method. Two numerical approaches are coupled through sharing the same shape functions. An implicit mid-interval backwards difference algorithm is used to handle the temporal derivative. Reliability and efficiency of the developed model have been examined by verification tests against available analytical or numerical solutions. The coupled hydromechanical processes in heterogeneous reservoirs were simulated. The results of numerical experiments show that oscillatory problem for saturation in heterogeneous media can be eliminated, demonstrating better performance of developed model for heterogeneous reservoir simulations. Reservoir performance is significantly shaped by its heterogeneity through controlling fluid flow and time for CO2–CH4 displacement. Simulation results show that the time required for completion of CO2–CH4 displacement increases by about 250 days when considering heterogeneity effect. In conclusion, this study offers a valuable tool for facilitating the development of CO2-enhanced unconventional gas recovery.

Thoughts on the development of CO2-EGR under the background of carbon peak and carbon neutrality

In September 2020, the Chinese government proposed the goals to reach carbon dioxide emissions peak by 2030 and achieve carbon neutrality by 2060 (“two-carbon goals”). This brings opportunities to the development and application of CO2-enhanced gas recovery (CO2-EGR) in China. To obtain an overall understanding of the development of CO2-EGR under the two-carbon goals, this paper analyzes the significance, potential, status quo and challenges of CO2-EGR, and makes suggestions on the development of CO2-EGR in China. The research results are obtained as follows. First, the development of CO2-EGR plays a crucial role in ensuring China's energy security, accelerating the construction of the clean energy system to promote energy transition and realizing the two-carbon goals as early as possible. Second, China should clarify a path for CO2-EGR development, build a spatial layout of CO2-EGR, and promote digital inclusion in CO2-EGR, enhance the emission reduction role of CO2-EGR in the multi-energy complementary system, boost large scale application of renewable energy and deep decarbonization in the traditional coal industry, which is difficult to reduce carbon emissions. Third, China should draw lessons from European and American tax credit and innovation funds policies to accelerate the construction of a CO2-EGR policy support system. Fourth, China should carry out research on key CO2-EGR technologies to accelerate the construction of a CO2-EGR methodology and standard system and promote rapid and standardized development of the CO2-EGR industry. It is suggested to establish a CO2-EGR demonstration area in the Sichuan Basin and popularize it across China, so as to improve comprehensive economic benefits through the establishment of large-scale industrial clusters. It is concluded that the two-carbon goals bring opportunities to the development of CO2-EGR in China, which will promote gas production and demonstration of CO2 sequestration in gas reservoirs and have positive significance in ensuring energy security and realizing carbon peak and carbon neutrality in China.

Comparative numerical study on the co-optimization of CO2 storage and utilization in EOR, EGR, and EWR: Implications for CCUS project development

Carbon capture, utilization, and storage (CCUS) and the geological sequestration of carbon dioxide (CO2) have become effective means of mitigating CO2 emissions and combating global warming. Currently, two main issues influence the implementation and progress of major CCUS technologies (e.g., CO2 geo-storage combined with CO2-enhanced oil recovery (CO2-EOR), CO2-enhanced gas recovery (CO2-EGR), and CO2-enhanced deep saline water/brine recovery (CO2-EWR)): high development costs and negative environmental impacts. Additionally, certain operating and reservoir critical parameters could influence the performance of CCUS technologies, making it difficult to design an optimal development scheme. In this study, a comparative numerical simulation analysis on the co-optimization of CO2 storage and utilization in EOR, EGR, and EWR was performed. A geological model based on the Bakken formation was built, and the influence of critical reservoir parameters (reservoir permeability, porosity, initial reservoir pressure, injection pressure, and production pressure) was observed through sensitivity analysis. The following results were obtained: (1) For CO2-EOR, the CO2 storage capacity increases with operating pressure above the minimum miscibility pressure. (2) Based on the best-case scenario, the CO2 storage capacities of EWR, EOR, and EGR were 189.4 × 106 scf, 252 × 106 scf, and 97 × 106 scf, respectively. (3) According to the best-case analysis, the recovery factor of EWR, EOR, and EGR were 5.2%, 91%, and 12%, respectively. (4) By comparing the best-case storage capacity and recovery factor, the optimal CCUS process was the CO2-EOR technology. The research results will guide future decisions on the development of CCUS projects.

Geothermal development associated with enhanced hydrocarbon recovery and geological CO2 storage in oil and gas fields in Canada

In this study, reservoir simulations with economic analysis are performed to investigate the potential of utilizing oil and gas fields for geothermal development associated with enhanced hydrocarbon recovery and geological CO2 storage. Results show that the revenue from CO2 enhanced oil recovery, CO2 storage and geothermal development accounts for 54%, 40%, and 6% of the total revenue to repurpose oil fields, respectively. Meanwhile, the revenue from CO2 enhanced gas recovery, CO2 storage and geothermal development accounts for 12%, 82%, and 6% of the total revenue to repurpose gas fields, respectively. Additionally, the revenue is 18% higher from converting wells to enhanced hydrocarbon recovery, CO2 storage and geothermal development in the oil fields than those in the gas fields. We then conduct a first-of-its-kind evaluation of 16,990 oil fields and 71,907 gas fields in Canada for geothermal development with enhanced hydrocarbon recovery and geological CO2 storage. Results show that 213 oil fields and 2,639 gas fields with a reservoir temperature above 100 °C and buried depth of 800 m or deeper are suitable for the CO2 storage and heat mining projects. The 213 oil fields have CO2 enhanced oil recovery potential of 643 million barrels, geothermal resources of 4.5 billion GJ and CO2 storage capacity of 552 Mt. The 2,639 gas fields have CO2 enhanced gas recovery potential of 6.3 Tcf, geothermal resources of 16 billion GJ and CO2 storage capacity of 8 Gt.

Statistical Analysis of Controlling Factors on Enhanced Gas Recovery by CO2 Injection in Shale Gas Reservoirs

Development of shale gas reservoirs is the fastest growing area on a large scale globally due to their potential reserves. CO2 has a great affinity to be adsorbed on shale organic surface over CH4. Therefore, CO2 injection into shale reservoirs initiates a potential for enhanced gas recovery and CO2 geological sequestration. The efficiency of CO2 enhanced gas recovery (CO2-EGR) is mainly dominated by several shale properties and engineering design parameters. However, due to the heterogeneity of shale reservoirs and the complexity of modeling the CO2–CH4 displacement process, there are still uncertainties in determining the main factors that control CO2 sequestration and enhanced CH4 recovery in shale reservoirs. Therefore, in view of the previous sensitivity analysis studies, no quantitative framework, accurate CO2-EGR modeling, or design process has been identified. Thus, this work aimed to provide a practical screening tool to manage and predict the efficiency of enhanced gas recovery and CO2 sequestration in shale reservoirs. To meet our objectives, we performed correlation analysis to identify the strength of the relationship between the examined shale properties and engineering design parameters and the efficiency of CO2-EGR. Data for this study was gathered across publications on a wide subset of numerical modeling studies and experimental investigations. The sensitivity of data was further improved by a hybrid approach adopted for handling the missing values to avoid bias in our data set. Our results indicate that CO2 flooding might be the best applicable option for CO2 injection in shale reservoirs, whereas the huff-and-puff scenario does not seem to be a viable option. The efficiency of CO2-EGR increases as the pressure difference between injection pressure and reservoir pressure increases. The results show that shallow shale reservoirs with high fracture permeability, total organic content, and CO2–CH4 preferential adsorption capacity are favorable targets for CO2-EGR. Moreover, our results indicate that a successful hydraulic-fracture network with effective values of fracture permeability and conductivity is essential for a higher CO2-EGR efficiency. Well spacing and fracture half-length are crucial engineering features in CO2-EGR process design that must be carefully optimized due to their negative effect on CH4 production and positive effect on CO2 storage. Our statistical analysis lays a foundation for efficient CO2-EGR design and implementation and presents an important contribution to the field of reaching the target of net-zero CO2 emissions for energy transitions.

CO2 Reaction-Diffusion Experiments in Shales and Carbonates

The evaluation of caprock integrity and reservoir efficiency is critical for safe CO2 geological storage management. It is therefore important to investigate geochemical reactions between CO2-rich fluids and host rocks and their contribution in retaining CO2 at depth. This study deals with diffusive reaction experiments on shales and carbonate samples cored from an offshore structure in the Malaysian basin, a potential target for CO2-enhanced gas recovery. The aim is to evaluate the CO2 reaction front velocity in a typical shaly caprock and the mineral response of the reservoir. Rock samples were characterized in terms of texture, chemistry, and mineralogy by X-ray diffraction, electron microscopy (SEM), microanalysis (EDS), infrared spectroscopy (FT-IR), rock geochemistry (XRF), and mercury injection capillary permeability (MICP). Performed analyses show mineralogical alteration induced by CO2 as it penetrated into the samples. Carbonate dissolution and weathering of pyrite to form secondary carbonates belonging to siderite-ankerite series were observed along two reaction fronts. Estimated diffusion coefficients of CO2 are two orders of magnitude lower than CO2(aq) molecular diffusion in pure water and from half to an order of magnitude lower than diffusivity computed on unaltered sample, highlighting the important effect of gas–water–rock reactions on the CO2(aq) diffusivities in shales and carbonates. Results obtained in this study provide an insight regarding the effect of geochemical reactions on CO2 transport and represent a further discussion point on the diffusion coefficients.

Well-pattern optimization of CH4 transport associated with supercritical CO2 flooding

Injecting supercritical CO2 into depleted gas reservoirs enables additional CH4 to be extracted, a process known as CO2 enhanced gas recovery (CO2-EGR). Optimization of the well pattern is another method used to enhance gas reservoir exploitation. The focus of the present work is to address the arrangement of the well pattern when using CO2-EGR. For this purpose, mathematical models with five-spot and seven-spot well patterns are established in steady and unsteady conditions, and their results are validated against previously published models. For the first time, equipotential and streamline charts of the well pattern in CO2-EGR are derived from these models. As a result, the main flow channel of the well pattern is clarified, and the distributions of formation pressure and seepage velocity are determined. Moreover, the relationships between the gas production rate and well pattern parameters such as the producing pressure drop, permeability, formation pressure, temperature, and well spacing are investigated and the factors that influence the recovery ratio are examined. Finally, an optimization strategy for the well pattern parameters in CO2-EGR is proposed to enhance the gas production rate and recovery factor.

Molecular insights on competitive adsorption and enhanced displacement effects of CO2/CH4 in coal for low-carbon energy technologies

Injection of carbon dioxide (CO2) into coals is one of the key strategies in low-carbon energy technology to enhance energy production and mitigate environmental impacts of fossil fuels from industrial processes in clean energy transitions. Geological factors dominate the displacement performance of methane (CH4) by CO2 injection due to the complexity of physicochemical processes in micro-nanopore networks. The concept of molecular dynamics (MD) is a promising way to reveal the gas transport mechanisms therein at the fundamental level. This work systematically investigates the kinetics of competitive adsorption process and quantitatively evaluate CO2-enhanced CH4 recovery performance by considering the effects of different decisive influencing factors at real subsurface environments using MD simulations. We elucidate that the increasing water and ethane contents reduce CH4 uptake and discourage adsorption process. Additionally, moisture, ethane and the increasing temperature promote the pressure drawdown-induced recovery efficiency of CH4. Further, low moisture contents inhibit CH4 displacement efficiency by CO2, whereas high moisture contents above 3 wt% favor the displacement process, particularly at high pressures. This work provides an in-depth understanding of CO2 utilization in gas development and carbon storage feasibility in unconventional reservoirs, which would shed light on CO2-enhanced gas recovery projects in practical field production.

Experimental study on dispersion characteristics and CH4 recovery efficiency of CO2, N2 and their mixtures for enhancing gas recovery

Dispersion is considered as an important indicator to reflect the contamination of produced gas during CO2 enhanced gas recovery (EGR). Reducing dispersion while obtaining a high CH4 recovery is the primary goal of EGR research. In this work, the effects of core permeability and different types of displacing fluids on dispersion and CH4 recovery efficiency were investigated. The CO2 dispersion and the recovery efficiency were compared in the pressure range from gaseous to supercritical state, it was found that the CO2 dispersion coefficient is anomalously large near the critical point. The results reveal that the implementation of EGR at supercritical conditions is most favorable in terms of less CO2 dispersion and higher CH4 recovery. Higher permeability of porous media has a weakening effect on dispersion and increases the CH4 recovery efficiency. In vertical upward displacement experiments, CO2 has a smaller dispersion coefficient and higher CH4 recovery efficiency compared to N2. However, in the horizontal displacement experiments, the gravity effect on CO2 was more pronounced in the high permeability cores, resulting in greater dispersion and lower recovery efficiency. Moreover, it was found that the CH4 recovery efficiency provided by the displacing fluids with high CO2 concentration becomes larger as the injection flow rate increases, while the displacing fluids with high N2 concentration gradually decreases after reaching the maximum recovery efficiency as the injection flow rate increases.

CO2 enhanced gas recovery and sequestration as CO2 hydrate in shallow gas fields in Alberta, Canada

In this study, we carry out reservoir simulations to investigate the effect of CO2 hydrate formation on CO2 storage capacity in shallow gas fields. Results show that CO2 hydrate formation moderates the reservoir pressure due to volume shrinkage thus allowing more CO2 (122–212% pore volume) to be stored. The CO2 storage capacity in a gas field with CO2 hydrate formation is up to 3.2 times that without CO2 hydrate formation. Due to CO2 hydrate formation, the CO2 storage capacity in a gas field first increases when initial water saturation increases from 0.1 to 0.3 but then decreases when the initial water saturation increases from 0.3 to 0.5. However, the CO2 storage capacity decreases with an increase in initial water saturation if there is no CO2 hydrate forms. Results of screening show that out of 68,327 gas fields in Alberta, 517 gas fields can be used to store CO2 as CO2 hydrate, giving a total CO2 storage capacity of 536 Mt. Of this, depleted gas fields in Alberta have the highest CO2 storage capacity including the Chard and Saleski gas fields with storage capacity of 138 Mt and 94 Mt, respectively.

Study on the influence of various factors on dispersion during enhance natural gas recovery with CO2 sequestration in depleted gas reservoir

In CO2 enhanced gas recovery (EGR), physical dispersion occurs between CO2 and natural gas, which can pollute the produced natural gas. Therefore, accurate assessment of the dispersion process is important for the commercialization of EGR. Under reservoir conditions, the effects of gravity, impurities, and other factors on dispersion in porous media were systematically evaluated. Comparison of the apparent dispersion characteristics of sandstone and unconsolidated cores (sandpacks) revealed that the vertically upward dispersion coefficient was smaller owing to the greater permeability and homogeneity of the sandpacks. With horizontal and vertically downward displacement of CO2–CH4, gravity promotes CO2–CH4 dispersion. However, dispersion was suppressed with vertically upward displacement (opposite to the direction of gravity). Under the same experimental conditions, pure N2 exhibited greater dispersion than CO2 as a displacing fluid. Finally, CO2 was used to displace natural gas containing different impurities. The results show that the more impurities (CO2, C2H6) exist in the displaced phase, the greater the mixing degree in the displacement process and the larger the dispersion coefficient.

Predicting Adsorption of Methane and Carbon Dioxide Mixture in Shale Using Simplified Local-Density Model: Implications for Enhanced Gas Recovery and Carbon Dioxide Sequestration

Carbon dioxide (CO2) capture and storage have attracted global focus because CO2 emissions are responsible for global warming. Recently, injecting CO2 into shale gas reservoirs is regarded as a promising technique to enhance shale gas (i.e., methane (CH4)) production while permanently storing CO2 underground. This study aims to develop a calculation workflow, which is built on the simplified local-density (SLD) model, to predict excess and absolute adsorption isotherms of gas mixture based on single-component adsorption data. Such a calculation workflow was validated by comparing the measured adsorption of CH4, CO2, and binary CH4/CO2 mixture in shale reported previously in the literature with the predicted results using the calculation workflow. The crucial steps of the calculation workflow are applying the multicomponent SLD model to conduct regression analysis on the measured adsorption isotherm of each component in the gas mixture simultaneously and using the determined key regression parameters to predict the adsorption isotherms of gas mixtures with various feed-gas mole fractions. Through the calculation workflow, the density profiles and mole fractions of the adsorbed gases can be determined, from which the absolute adsorption of the gas mixture is estimated. In addition, the CO2/CH4 adsorption selectivity larger than one is observed, illustrating the preferential adsorption of CO2 over CH4 on shale, which implies that CO2 has enormous potential to enhance CH4 production while sequestering itself in shale. Our findings demonstrate that the proposed calculation workflow depending on the multicomponent SLD model enables us to accurately predict the adsorption of gas mixtures in nanopores based on single-component adsorption results. Following the innovative calculation flow path, we could bypass the experimental difficulties of measuring the multicomponent mole fractions in the gas phase at the equilibrium during the adsorption experiments. This study also provides insight into the CO2/CH4 competitive adsorption behavior in nanopores and gives guidance to CO2-enhanced gas recovery (CO2-EGR) and CO2 sequestration in shale formations.