Search Results (23)

Anthropogenic CO₂ emissions are a major driver of climate change, highlighting the urgent need for effective mitigation strategies. Carbon Capture, Utilization, and Storage (CCUS) offers a promising approach, particularly through CO₂-enhanced gas recovery (EGR) in shale reservoirs, which enables simultaneous hydrocarbon production and CO₂ sequestration. This study employs a numerical simulation model to compare two injection strategies: CO₂ flooding and huff-and-puff (H&P). The results indicate that, without accounting for key mechanisms such as adsorption and molecular diffusion, CO₂ H&P provides minimal improvement in methane recovery. When adsorption is included, methane recovery increases by 9%, with 14% of the injected CO₂ stored over 40 years. Incorporating diffusion enhances recovery by 19%, although with limited storage potential. In contrast, CO₂ flooding improves methane production by 26% and retains up to 94% of the injected CO₂. Higher storage efficiency is observed in reservoirs with high porosity and low permeability, particularly in nano-scale pore systems. Overall, CO₂ H&P may be a viable EGR option when adsorption and diffusion are considered, while CO₂ flooding demonstrates greater effectiveness for both enhanced gas recovery and long-term CO₂ storage in shale formations. Full article

CO₂-enhanced gas recovery (EGR) has emerged as a promising method for improving hydrocarbon production and achieving carbon sequestration in offshore gas reservoirs. This study investigates the performance and influencing factors of CO₂-based gas displacement using long core displacement experiments. Consolidated synthetic cores were prepared to replicate reservoir conditions, and experiments were conducted at formation pressure and temperature to evaluate the effects of permeability, injection pressure, CO₂ concentration, and core length on gas recovery efficiency. The results reveal that (1) for a homogeneous porous medium, permeability and injection pressure have minimal correlation with recovery efficiency when sufficient gas is injected; (2) direct gas displacement after reservoir depletion outperforms pressure-boosting displacement methods; (3) higher CO₂ concentrations delay gas breakthrough, enhance piston-like displacement behavior, and improve recovery efficiency; and (4) core length significantly affects recovery, with longer cores resulting in slower breakthroughs and more stable displacement. Cores of at least 1 m in length are essential for accurately simulating field conditions. For a CO₂ injection with a pressure of 7 MPa and a temperature of 81 °C, when 0.87 PV of CO₂ is injected, the current recovery can reach 87%, after which the displacement efficiency decreases sharply. The ultimate EGR can be as high as 50%. These findings provide valuable insights into optimizing CO₂ injection strategies for enhanced gas recovery in offshore reservoirs, offering guidance for both experimental designs and practical applications in the field. Full article

In the middle and late stages of offshore carbon-rich gas reservoir development, insufficient reservoir energy poses significant challenges and difficulty in improving gas recovery. Injecting CO₂ back into the reservoir is a promising development approach that can address both carbon emissions and enhanced gas recovery (EGR). During the CO₂ injection process, the CO₂–CH₄ dispersion significantly impacts the recovery of CH₄. To understand the mass transfer and dispersion laws of CO₂ and high-carbon natural gas under current in situ reservoir conditions, this study conducted 1-m-long core experiments to investigate the effects of different gas compositions and permeabilities on gas recovery and diffusion laws in offshore reservoirs, taking into account the evolution of permeability in the porous medium. The experimental results indicate that the higher carbon concentration helps reduce mixing with formation gas, which consists of 70% methane, 25% nitrogen, and 5% carbon dioxide, resulting in a smaller diffusion coefficient. Under the conditions of an injection rate of 0.4 mL/min, a temperature of 81 °C, and a pressure of 7 MPa, the diffusion coefficient decreases by 27.5% as the carbon dioxide concentration increases from 70% to 90%, resulting in a 1.5% increase in recovery efficiency. As the permeability decreases, the viscous resistance of the fluid increases, leading to longer breakthrough times, and the reservoir fluid becomes more akin to piston displacement, reducing the degree of dispersion. The findings of this study provide guidance for optimizing gas injection strategies by reducing CO₂ dispersion and further enhancing natural gas recovery. Full article

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. Full article

Onshore gas-to-wire is considered for 6.5 MMSm³/d of natural gas, with 44% mol carbon dioxide coming from offshore deep-water oil and gas fields. Base-case GTW-CONV is a conventional natural gas combined cycle, with a single-pressure Rankine cycle and 100% carbon dioxide emissions. The second variant, GTW-CCS, results from GTW-CONV with the addition of post-combustion aqueous monoethanolamine carbon capture, coupled to carbon dioxide dispatch to enhance oil recovery. Despite investment and power penalties, GTW-CCS generates both environmental and economic benefits due to carbon dioxide’s monetization for enhanced oil production. The third variant, GTW-CCS-EGR, adds two intensification layers over GTW-CCS, as follows: exhaust gas recycle and a triple-pressure Rankine cycle. Exhaust gas recycle is a beneficial intensification for carbon capture, bringing a 60% flue gas reduction (reduces column’s diameters) and a more than 100% increase in flue gas carbon dioxide content (increases driving force, reducing column’s height). GTW-CONV, GTW-CCS, and GTW-CCS-EGR were analyzed on techno-economic and environment–thermodynamic grounds. GTW-CCS-EGR’s thermodynamic analysis unveils 807 MW lost work (79.8%) in the combined cycle, followed by the post-combustion capture unit with 113 MW lost work (11.2%). GTW-CCS-EGR achieved a 35.34% thermodynamic efficiency, while GTW-CONV attained a 50.5% thermodynamic efficiency and 56% greater electricity exportation. Although carbon capture and storage imposes a 35.9% energy penalty, GTW-CCS-EGR reached a superior net value of 1816 MMUSD thanks to intensification and carbon dioxide monetization, avoiding 505.8 t/h of carbon emissions (emission factor 0.084 t^CO2/MWh), while GTW-CONV entails 0.642 t^CO2/MWh. Full article

Recently, there has been a growing interest in utilizing depleted gas and oil reservoirs for carbon capture and storage. This interest arises from the fact that numerous reservoirs have either been depleted or necessitate enhanced oil and gas recovery (EOR/EGR). The sequestration of CO₂ in subsurface repositories emerges as a highly effective approach for achieving carbon neutrality. This process serves a dual purpose by facilitating EOR/EGR, thereby aiding in the retrieval of residual oil and gas, and concurrently ensuring the secure and permanent storage of CO₂ without the risk of leakage. Injectivity is defined as the fluid’s ability to be introduced into the reservoir without causing rock fracturing. This research aimed to fill the gap in carbon capture and storage (CCS) literature by examining the limited consideration of injectivity, specifically in depleted underground reservoirs. It reviewed critical factors that impact the injectivity of CO₂ and also some field case data in such reservoirs. Full article

To initially improve the gas production rate and shorten the payback period for tight gas reservoirs, the multiple-fractured horizontal well (MFHW) model is always applied. However, in the late stages of exploitation, it is difficult to adopt reasonable measures for enhanced gas recovery (EGR), particular for continental sedimentary formation with multiple layers, and efficient strategies for EGR in this type of gas field have not yet been presented. Therefore, in this paper, a typical tight gas reservoir in the late stages of exploitation, the Denglouku gas reservoir in Changling gas field, in which MFHWs were utilized and contributed to the communication of the higher Denglouku formation (0.34 mol% CO₂) and lower Yingcheng formation (27 mol% CO₂) during hydraulic fracturing, is studied comprehensively. Firstly, alongside the seismic, logging, drilling and experimental data, 3D geological and numerical simulation models are developed. According to the differences in CO₂ mole fractions for different formations, the gas production rate of MFHWs produced from Denglouku formation is accurately calculated. Then, the well gas production rate (WGPR) and the well bottom-hole pressure (WBHP) history are matched with the calculated values, and thus the types of remaining gas are provided through the fine reservoir description. Finally, in a combination of gas recovery and economics, the optimal infill well type and the adjustment scheme are determined. The results show that there are three main categories of remaining gas, which are areal distribution, abundant points, and marginal dispersion, and the ratios of reaming gas reserve for these three types are 80.3%, 4.2%, and 15.5%, respectively. For the tight gas reservoir developed by MFHWs with parallel and zipper patterns, the best infilling well type is the vertical well. The combination of patching holes, sidetracking, infilling and boosting can obtain the highest gas recovery, while the scheme with patching holes and sidetracking has the best economic benefits. To balance the gas recovery and economics, the measurement of patching holes, sidetracking and infilling with vertical wells is utilized. In the final production period, compared with the basic schemes, the gas recovery can increase by 5.5%. The primary novelty of this paper lies in the determination of the optimal infilling well types and its presentation of a comprehensive adjustment workflow for EGR in tight gas reservoirs. The conclusions in this paper can provide some guidance for other similar tight gas reservoirs developed with MFHWs in the later period. Full article

The microscopic structure of low-permeability tight reservoirs is complicated due to diagenetic processes that impact the pore-fluid distribution and hydraulic properties of tight rocks. As part of an ongoing study of carbon dioxide-enhanced oil and gas recovery (CO₂-EOR/EGR) and CO₂ sequestration, this research article adopts an integrated approach to investigate the contribution of the micropore system in pore-fluid distribution in tight sandstones. A new dimensionless number, termed the microscopic confinement index (MCI), was established to select the right candidate for microscopic CO₂ injection in tight formations. Storativity and containment indices were essential for MCI estimation. A set of experiments, including routine core analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM), mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR), was performed on three tight sandstone rock samples, namely Bandera, Kentucky, and Scioto. Results indicate that the presence of fibrous illite acting as pore bridging in Bandera and Kentucky sandstone samples reduced the micropore-throat proportion (MTMR), leading to a significant drop in the micropore system confinement in Kentucky and Bandera sandstone samples of 1.03 and 0.56, respectively. Pore-filling kaolinite booklets reduced the micropore storativity index (MSI) to 0.48 in Kentucky and 0.38 in Bandera. On the other hand, the absence of fibrous illite and kaolinite booklets in Scioto sandstone led to the highest micropore system capability of 1.44 MTMR and 0.5 MSI to store and confine fluids. Therefore, Scioto sandstone is the best candidate for CO₂ injection and storage among the tested samples of 0.72 MCI. Full article

To mitigate dangerous climate change effects, the 195 countries that signed the 2015 Paris Agreement agreed to “keep the increase in average global surface temperature below 2 °C and limit the increase to 1.5 °C” by reducing carbon emissions. One promising option for reducing carbon emissions is the deployment of carbon capture, utilization, and storage technologies (CCUS) to achieve climate goals. However, for large-scale deployment of underground carbon storage, it is essential to develop technically sound, safe, and cost-effective CO₂ injection and well control strategies. This involves sophisticated balancing of various factors such as subsurface engineering policies, technical constraints, and economic trade-offs. Optimization techniques are the best tools to manage this complexity and ensure that CCUS projects are economically viable while maintaining safety and environmental standards. This work reviews thoroughly and critically carbon storage studies, along with the optimization of CO₂ injection and well control strategies in saline aquifers. The result of this review provides the foundation for carbon storage by outlining the key subsurface policies and the application of these policies in carbon storage development plans. It also focusses on examining applied optimization techniques to develop CO₂ injection and well control strategies in saline aquifers, providing insights for future work and commercial CCUS applications. Full article

Carbon-dioxide-enhanced shale gas recovery technology has significant potential for large-scale emissions reduction and can help achieve carbon neutrality targets. Previous theoretical studies mainly focused on gas adsorption in one-dimensional pores without considering the influence from the pore geometry. This study evaluates the effects of pore shape on shale gas adsorption. The pure and competitive gas adsorption processes of CO₂ and CH₄ in nanopores were investigated using molecular simulations to improve the prediction of shale gas recovery efficiency. Meanwhile, quantitative analysis was conducted on the effects of the pore shape on the CO₂-EGR efficiency. The results indicate that the density of the adsorption layer in pores is equally distributed in the axial direction when the cone angle is zero; however, when the cone angle is greater than zero, the density of the adsorption layer decreases. Smaller cone-angle pores have stronger gas adsorption affinities, making it challenging to recover the adsorbed CH₄ during the pressure drawdown process. Concurrently, this makes the CO₂ injection method, based on competitive adsorption, efficient. For pores with larger cone angles, the volume occupied by the free gas is larger; thus, the pressure drawdown method displays relatively high recovery efficiency. Full article

CO₂ geological sequestration in subsurface shale formations is a promising strategy to store CO₂ and to increase shale gas production. The understanding of gas adsorption and diffusion mechanisms in microporous media is critical for CO₂ storage-enhanced gas recovery (CS-EGR). The type of kerogens is one of the important factors that influence the adsorption and diffusion behaviors of gases. In this work, the Grand Canonical Monte Carlo and Molecular Dynamics simulations were utilized to develop kerogen models and further investigate gas and water adsorption and diffusion behavior on the type IA, IIA, and IIIA kerogen models. The results indicated that the adsorption and diffusion capacities of CO₂ are larger than those of CH₄. The adsorption and diffusion capacity decreased with increasing water content. However, the CO₂/CH₄ adsorption selectivity increased with the increase in water content. Type IIIA demonstrated the best potential for adsorption and diffusion. This study provides insights into the role of the adsorption and diffusion behavior of CO₂ and CH₄ mixtures on kerogens of different types under different water contents at a microscopic scale, and can facilitate further understanding of the processes involved in CO₂ storage coupled with enhanced energy recovery. Full article

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. Full article

CO₂-based enhanced gas recovery (EGR) is an appealing method with the dual benefit of improving recovery from mature gas reservoirs and storing CO₂ in the subsurface, thereby reducing net emissions. However, CO₂ injection for EGR has the drawback of excessive mixing with the methane gas, therefore, reducing the quality of gas produced and leading to an early breakthrough of CO₂. Although this issue has been identified as a major obstacle in CO₂-based EGR, few strategies have been suggested to mitigate this problem. We propose a novel hybrid EGR method that involves the injection of a slug of carbonated water before beginning CO₂ injection. While still ensuring CO₂ storage, carbonated water hinders CO₂-methane mixing and reduces CO₂ mobility, therefore delaying breakthrough. We use reservoir simulation to assess the feasibility and benefit of the proposed method. Through a structured design of experiments (DoE) framework, we perform sensitivity analysis, uncertainty assessment, and optimization to identify the ideal operation and transition conditions. Results show that the proposed method only requires a small amount of carbonated water injected up to 3% pore volumes. This EGR scheme is mainly influenced by the heterogeneity of the reservoir, slug volume injected, and production rates. Through Monte Carlo simulations, we demonstrate that high recovery factors and storage ratios can be achieved while keeping recycled CO₂ ratios low. Full article

There is a potential for synergy effects in utilizing CO₂ for both enhanced gas recovery (EGR) and geothermal energy extraction (CO₂-plume geothermal, CPG) from natural gas reservoirs. In this study, we carried out reservoir simulations using TOUGH2 to evaluate the sensitivity of natural gas recovery, pressure buildup, and geothermal power generation performance of the combined CO₂-EGR–CPG system to key reservoir and operational parameters. The reservoir parameters included horizontal permeability, permeability anisotropy, reservoir temperature, and pore-size-distribution index; while the operational parameters included wellbore diameter and ambient surface temperature. Using an example of a natural gas reservoir model, we also investigated the effects of different strategies of transitioning from the CO₂-EGR stage to the CPG stage on the energy-recovery performance metrics and on the two-phase fluid-flow regime in the production well. The simulation results showed that overlapping the CO₂-EGR and CPG stages, and having a relatively brief period of CO₂ injection, but no production (which we called the CO₂-plume establishment stage) achieved the best overall energy (natural gas and geothermal) recovery performance. Permeability anisotropy and reservoir temperature were the parameters that the natural gas recovery performance of the combined system was most sensitive to. The geothermal power generation performance was most sensitive to the reservoir temperature and the production wellbore diameter. The results of this study pave the way for future CPG-based geothermal power-generation optimization studies. For a CO₂-EGR–CPG project, the results can be a guide in terms of the required accuracy of the reservoir parameters during exploration and data acquisition. Full article

The adsorption of CO₂ and CO₂/CH₄ mixtures on kaolinite was calculated by grand canonical Monte Carlo (GCMC) simulations with different temperatures (283.15, 293.15, and 313.15 K) up to 40 MPa. The simulation results show that the adsorption amount of CO₂ followed the Langmuir model and decreased with an increasing temperature. The excess adsorption of CO₂ increased with an increasing pressure until the pressure reached 3 MPa and then decreased at different temperatures. The $S_{C{O}_2/C{H}_4}$ decreased logarithmically with increasing pressure, and the $S_{C{O}_2/C{H}_4}$ was lower with a higher temperature at the same pressure. The interaction energy between CO₂ and kaolinite was much higher than that between CH₄ and kaolinite at the same pressure. The interaction energy between the adsorbent and adsorbate was dominant, and that between CO₂ and CO₂ and between CH₄ and CH₄ accounted for less than 20% of the total interaction energy. The isothermal adsorption heat of CO₂ was higher than that of CH₄, indicating that the affinity of kaolinite to CO₂ was higher than that of CH₄. The strong adsorption sites of carbon dioxide on kaolinite were hydrogen, oxygen, and silicon atoms, respectively. CO₂ was not only physically adsorbed on kaolinite, but also exhibited chemical adsorption. In gas-bearing reservoirs, a CO₂ injection to displace CH₄ and enhance CO₂ sequestration and enhanced gas recovery (CS-EGR) should be implemented at a low temperature. Full article