Search Results (32)

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

A technology that directly injects CO₂-rich industrial waste gas (CO₂-rich IWG) into underground spaces for unconventional natural gas extraction and waste gas storage has received increasing attention. The pore characteristics of coal and shale in a coal-bearing rock series before and after CO₂-rich IWG treatment are closely related to gas recovery and storage. In this study, three coals ranging from low to high rank and one shale sample were collected. The samples were treated with CO₂-rich IWG using a high-precision geochemical reactor. The changes in the pore volume (PV), specific surface area (SSA), and pore size distribution of micropores, mesopores, and macropores were analyzed. The correlations between the Langmuir volume and the PV and SSA of the micropores and mesopores were analyzed. It was confirmed that for micropores, SSA was the dominant factor influencing adsorption capacity. The effectively interconnected pore volume was calculated using macropores to characterize changes in the sample’s connectivity. It was found that the PV and SSA of the micropores in the coal samples increased with increasing coal rank. The CO₂-rich IWG treatment increased the PV and SSA of the micropores in all of the samples. In addition, for mesopores and macropores, the treatment reduced the SSA in the coal samples but enhanced it in the shale. The results of this study improve the understanding of the mechanisms of the CO₂-rich IWG treatment method and emphasize its potential in waste gas storage and natural gas extraction. Full article

The development of geo-energy resources, including oil, gas, and geothermal reservoirs, is being transformed through the creation of low-energy processes and innovative technologies. This Special Issue compiles cutting-edge research aimed at enhancing efficiency, sustainability, and recovery during geo-energy extraction. The published studies explore a diverse range of methodologies, such as the nanofluidic analysis of shale oil phase transitions, deep electrical resistivity tomography for geothermal exploration, and hybrid AI-driven production prediction models. Their key themes include hydraulic fracturing optimization, CO₂ injection dynamics, geothermal reservoir simulation, and competitive gas–water adsorption in ultra-deep reservoirs, and these studies combine advanced numerical modeling, experimental techniques, and field applications to address challenges in unconventional reservoirs, geothermal energy exploitation, and enhanced oil recovery. By bridging theoretical insights with practical engineering solutions, this Special Issue provides a comprehensive foundation for future innovations in low-energy geo-energy development. Full article

CO₂ injection in shale reservoirs is more suitable than the conventional recovering methods due to its easier injectivity and higher sweep efficiency. In this work, Grand Canonical Monte Carlo (GCMC) simulation is employed to investigate the adsorption/desorption behavior of CH₄-C₄H₁₀ and CH₄-C₄H₁₀-CO₂ mixtures in organic and inorganic nanopores during pressure drawdown and CO₂ huff and puff processes. The huff and puff process involves injecting CO₂ into the micro- and mesopores, where the system pressure is increased during the huffing process and decreased during the puffing process. The fundamental mechanism of shale gas recovery using the CO₂ injection method is thereby revealed from the nanopore-scale perspective. During primary gas production, CH₄ is more likely to be produced as the reservoir pressure drops. On the contrary, C₄H₁₀ tends to be trapped in these organic nanopores and is hard to extract, especially from micropores and inorganic pores. During the CO₂ huffing period, the adsorbed CH₄ and C₄H₁₀ are recovered efficiently from the inorganic mesopores. On the contrary, the adsorbed C₄H₁₀ is slightly extracted from the inorganic micropores during the CO₂ puffing period. During the CO₂ puff process, the adsorbed CH₄ desorbs from the pore surface and is thus heavily recovered, while the adsorbed C₄H₁₀ cannot be readily produced. During CO₂ huff and puff, the recovery efficiency of CH₄ is higher in the organic pores than that in the inorganic pores. More importantly, the recovery efficiency of C₄H₁₀ reaches the highest levels in both the inorganic and organic pores during the CO₂ huff and puff process, suggesting that the CO₂ huff and puff method is more advanced for heavier hydrocarbon recovery compared to the pressure drawdown method. In addition to CO₂ storage, CO₂ sequestration in the adsorbed state is safer than that in the free state. In our work, it was found that the high content of organic matter, high pressure, and small pores are beneficial factors for CO₂ sequestration transforming into adsorbed state storage. Full article

The Sichuan Basin’s Liangshan Formation shale is rich in oil and gas resources, yet the recovery rate of shale oil reservoirs typically falls below 10%. Currently, gas injection huff-n-puff (H-n-P) is considered one of the most promising methods for improving shale oil recovery. This study numerically investigates the application of the CO₂ huff-n-puff process in enhancing oil recovery in shale volatile oil reservoirs. Using an actual geological model and fluid properties of shale oil reservoirs in the Sichuan Basin, the CO₂ huff-n-puff process was simulated. The model takes into account the molecular diffusion of CO₂, adsorption, stress sensitivity effects, and nanopore confinement. After history matching, through sensitivity analysis, the optimal injection rate of 400 tons/day, soaking time of 30 days, and three cycles of huff-n-puff were determined to be the most effective. The simulation results show that, compared with other gases, CO₂ has significant potential in improving the recovery rate and overall efficiency of shale oil reservoirs. This study is of great significance and can provide valuable references for the actual work of CO₂ huff-n-puff processes in shale volatile oil reservoirs of the Sichuan Basin. Full article

Carbon neutrality has become a global common goal. CCUS, as one of the technologies to achieve carbon neutrality, has received widespread attention from academia and industry. After CO₂ enters the formation, under the conditions of formation temperature and pressure, supercritical CO₂, formation water, and rock components interact, which directly affects the oil and gas recovery and carbon sequestration efficiency. In this paper, the recent progress on CO₂ water–rock interaction was reviewed from three aspects, including (i) the investigation methods of CO₂ water–rock interaction; (ii) the variable changes of key minerals, pore structure, and physical properties; and (iii) the nomination of suitable reservoirs for CO₂ geological sequestration. The review obtains the following three understandings: (1) Physical simulation and cross-time scale numerical simulation based on formation temperature and pressure conditions are important research methods for CO₂ water–rock interaction. High-precision mineral-pore in situ comparison and physical property evolution evaluation are important development directions. (2) Sensitive minerals in CO₂ water–rock interaction mainly include dolomite, calcite, anhydrite, feldspar, kaolinite, and chlorite. Due to the differences in simulated formation conditions or geological backgrounds, these minerals generally show the pattern of dissolution or precipitation or dissolution before precipitation. This differential evolution leads to complex changes in pore structure and physical properties. (3) To select the suitable reservoir for sequestration, it is necessary to confirm the sequestration potential of the reservoir and the later sequestration capacity, and then select the appropriate layer and well location to start CO₂ injection. At the same time, these processes can be optimized by CO₂ water–rock interaction research. This review aims to provide scientific guidance and technical support for shale oil recovery and carbon sequestration by introducing the mechanism of CO₂ water–rock interaction, expounding the changes of key minerals, pore structure, and physical properties, and summarizing the sequestration scheme. Full article

Multi-stage fractured horizontal well technology is an effective development method for unconventional reservoirs; however, shale oil reservoirs with ultra-low permeability and micro/nanopore sizes are still not ideal for production and development. Injecting CO₂ into the reservoir, after hydraulic fracturing, gas injection flooding often produces a gas channeling phenomenon, which affects the production of shale oil. In comparison, CO₂ huff-n-puff development has become a superior method in the development of multi-stage fractured horizontal wells in shale reservoirs. CO₂ huff and injection can not only improve shale oil recovery but also store the CO₂ generated in industrial production in shale reservoirs, which can reduce greenhouse gas emissions to a certain extent and achieve carbon capture, utilization, and storage (CCUS). In this paper, the critical temperature and critical parameters of fluid in shale reservoirs are corrected by the critical point correction method in this paper, and the influence of reservoir pore radius on fluid phase behavior and shale oil production is analyzed. According to the shale reservoir applied in isolation to the actual state of the reservoir and under the condition of a complex network structure, we described the seepage characteristics of shale oil and gas and CO₂ in the reservoir by embedding a discrete fracture technology structure and fracture network, and we established the numerical model of the CO₂ huff-n-huff development of multi-stage fractured horizontal wells for shale oil. We used the actual production data of the field for historical fitting to verify the validity of the model. On this basis, CO₂ huff-n-puff development under different gas injection rates, huff-n-puff cycles, soaking times, and other factors was simulated; cumulative oil production and CO₂ storage were compared; and the influence of each factor on development and storage was analyzed, which provided theoretical basis and specific ideas for the optimization of oilfield development modes and the study of CO₂ storage. Full article

The pore mobilization characteristics of CO₂ when in shale reservoirs is an important indicator for evaluating the effectiveness of its application for enhanced recovery in shale reservoirs, and it is important to develop a comprehensive set of physical simulation methods that are consistent with actual field operations. This has underscored the need for efficient development techniques in the energy industry. The huff-n-puff seepage oil recovery method is crucial for developing tight oil reservoirs, including shale oil. However, the small pore size and low permeability of shale render conventional indoor experiments unsuitable for shale oil cores. Consequently, there is a need to establish a fully enclosed experimental method with a high detection accuracy to optimize the huff and puff process parameters. The NMR technique identifies oil and gas transport features in nanogaps, and in this study, we use low-field nuclear magnetic resonance (NMR) online displacement technology to conduct CO₂ huff and puff experiments on shale oil, covering the gas injection, well stewing, and production stages. After conducting four rounds of huff-n-puff experiments, key process parameters were optimized, including the simmering time, huff-n-puff timing, number of huff-n-puff rounds, and the amount of percolant injected. The findings reveal that as the number of huff-n-puff rounds increases, the time required for well stabilization decreases correspondingly. However, the enhancement in recovery from additional huff-n-puff rounds becomes negligible after three rounds, showing only a 1.16% improvement. CO₂ re-injection is required when the pressure falls to 70% of the initiaformation pressure to ensure efficient shale oil well development. This study also indicates that the most economically beneficial results are achieved when the injection volume of the huff-n-puff process is 0.44 pore volumes (PVs). Full article

Shale oil resources, noted for their broad distribution and significant reserves, are increasingly recognized as vital supplements to traditional oil resources. In response to the high fracturing costs and swift decline in productivity associated with shale oil horizontal wells, this research introduces a novel approach utilizing CO₂ for enhanced shale oil recovery in radial boreholes. A compositional numerical simulation method is built accounted for component diffusion, adsorption, and non-Darcy flow, to explore the viability of this technique. The study examines how different factors—such as initial reservoir pressure, permeability, numbers of radial boreholes, and their branching patterns—influence oil production and CO₂ storage. Our principal conclusions indicate that with a constant CO₂ injection rate, lower initial reservoir pressures predominantly lead to immiscible oil displacement, hastening the occurrence of CO₂ gas channeling. Therefore, maintaining higher initial or injection pressures is critical for effective miscible displacement in CO₂-enhanced recovery using radial boreholes. Notably, the adsorption of CO₂ in shale oil results in the displacement of lighter hydrocarbons, an effect amplified by competitive adsorption. While CO₂ diffusion tends to prompt earlier gas channeling, its migration towards areas of lower concentration within the reservoir reduces the extent of channeling CO₂. Nonetheless, when reservoir permeability falls below 0.01 mD, the yield from CO₂-enhanced recovery using radial boreholes is markedly low. Hence, selecting high-permeability “sweet spot” regions within shale oil reservoirs for the deployment of this method is advisable. To boost oil production, utilizing longer and broader radial boreholes, increasing the number of boreholes, or setting the phase angle to 0° are effective strategies. Finally, by comparing the production of shale oil enhanced by CO₂ with that of a dual horizontal well fracturing system enhanced by CO₂, it was found that although the former’s oil production is only 50.6% of the latter, its cost is merely 11.1%, thereby proving its economic viability. These findings present a new perspective for the economically efficient extraction of shale oil, offering potential guidance for industrial practices. Full article

The occurrence state of oil, gas, and water plays a crucial role in exploring shale reservoirs. In this study, molecular dynamics simulations were used to investigate the occurrence states of these fluids in shale nanopores. The results showed that when the alkane is light oil, in narrow pores with a width less than 3 nm, oil molecules exist only in an adsorbed state, whereas both adsorbed and free states exist in larger pores. Due to the stronger interaction of water with the rock surface, the adsorption of oil molecules near the rock is severely prohibited. Oil/water/gas occurrence characteristics in the water-containing pore study indicate that CO₂ gas can drive free oil molecules out of the pore, break water bridges, and change the occurrence state of water. During displacement, the gas type affects the oil/gas occurrence state. CO₂ has strong adsorption capacity, forming a 1.45 g/cm³ adsorption layer on the rock surface, higher than oil’s density peak of 1.29 g/cm³. Octane solubility in injected gases is CO₂ (88.1%) > CH₄ (76.8%) > N₂ (75.4%), with N₂ and CH₄ having weak competitive adsorption on the rock. The investigation of different shale reservoir conditions suggests that at high temperature or low pressure, oil/gas molecules are more easily displaced, while at low temperature or high pressure, they are tightly adsorbed to the reservoir rock. These findings contribute to the understanding of fundamental mechanisms governing fluid behavior in shale reservoirs, which could help to develop proper hydrocarbon recovery methods from different oil reservoirs. Full article

The Chang 7 shale oil reservoir has low natural energy and is both tight and highly heterogeneous, resulting in significant remaining oil after depletion development. CO₂ huff and puff (huff-n-puff) is an effective way to take over from depletion development. Numerous scholars have studied and analyzed the CO₂ huff-n-puff mechanism and parameters based on laboratory core sample huff-n-puff experiments. However, experimental procedures are not comprehensive, leading to more general studies of some mechanisms, and existing CO₂ huff-n-puff experiments struggle to reflect the effect of actual reservoir heterogeneity due to the limited length of the experimental core samples. In this paper, CO₂ huff-n-puff laboratory experiments were performed on short (about 5 cm) and long (about 100 cm) core samples from the Chang 7 shale oil reservoir, and the microscopic pore fluid utilization in the short samples was investigated using a nuclear magnetic resonance (NMR) technique. We then analyzed and discussed the seven controlling factors of CO₂ huff-n-puff and their recovery-enhancing mechanisms. The experimental results show that the cumulative recovery increased with the number of huff-n-puff cycles, but the degree of cycle recovery decreased due to the limitation of the differential pressure of the production. The significant increase in recovery after the CO₂ mixed-phase drive was achieved by increasing the minimum depletion pressure as well as the gas injection amount. The soaking time was adjusted appropriately to ensure that the injected energy was thoroughly utilized; too short or too long a soaking time was detrimental. The pressure depletion rate was the main factor in the CO₂ huff-n-puff effect in shale. If the pressure depletion rate was very high, the effective permeability loss was larger. In the CO₂ huff-n-puff process of the Chang 7 shale oil reservoir, the improvement in oil recovery was mainly contributed to by mesopores and small pores. The huff-n-puff experiments using long cores could better characterize the effect of heterogeneity on the huff-n-puff effect than short cores. Full article

Carbon dioxide injection can help solve two issues in shale reservoir production. Firstly, it can reduce carbon emissions while, secondly, improving unconventional reservoir recovery. There are many controlling factors for CO₂ injection to enhance oil recovery in shale reservoirs, and the effect of field implementation varies greatly. The key to popularizing this extraction technology is determining the main controlling factors of CO₂ displacement efficiency. Using CO₂ shale displacement laboratory results, the grey correlation analysis method was used to determine the main controlling factors affecting core oil displacement efficiency, such as shale reservoir physical parameters (rock compressibility, porosity, median pore size, matrix permeability, TOC, and oil saturation) and engineering parameters (soaking time and injection pressure). The genetic algorithm (GA) was introduced to optimize the backpropagation (BP) neural network to construct the prediction model of the CO₂ indoor displacement experiments in shale cores. The results showed that the injection pressure among the engineering parameters, the CO₂ soaking time among the gas injection parameters, and the porosity among the shale physical parameters were the main controlling factors affecting the oil displacement efficiency. The prediction accuracy of the genetic neural network model improved, and the coefficient of determination (R²) reached 0.983. Compared with the conventional neural network model, the mean absolute error (MAE) was reduced by 30%, the root mean square error (RMSE) was reduced by 46%, and the R² increased by 11%. Optimizing the learning and training of the prediction model significantly reduces the cost of laboratory experiments. The deep-learning model completed by training can intuitively show the degree of influence of input parameters on output parameters, providing a theoretical basis for the study of CO₂ displacement mechanisms in shale reservoirs. 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

Permeability is a crucial parameter for enhancing shale oil recovery through CO₂ injection in oil-bearing shale. After CO₂ is injected into the shale reservoir, CO₂ corrosion and adsorption-induced strain can change the permeability of the oil shale, affecting the recovery of shale oil. This study aimed to explore the influence of CO₂ corrosion and adsorption-induced strain on the permeability of oil shale. The deformation of the internal pore diameter of oil shale induced by CO₂ corrosion under different pressures was measured by low-pressure nitrogen gas adsorption in the laboratory, and the corrosion model was fitted using the experimental data. Following the basic definitions of permeability and porosity, a dynamic mathematical model of porosity and permeability was obtained, and a fluid–solid coupling mathematical model of CO₂-containing oil shale was established according to the basic theory of fluid–solid coupling. Then the effects of adsorption expansion strain and corrosion compression strain on permeability evolution were considered to improve the accuracy of the oil shale permeability model. The numerical simulation results showed that adsorption expansion strain, corrosion compression strain, and confining pressure are the important factors controlling the permeability evolution of oil shale. In addition, adsorption expansion strain and corrosion compression strain have different effects under different fluid pressures. In the low-pressure zone, the adsorption expansion strain decreases the permeability of oil shale with increasing pressure. In the high-pressure zone, the increase in pressure decreases the influence of expansion strain while permeability gradually recovers. The compressive strain increases slowly with increasing pressure in the low-pressure zone, slowly increasing oil shale permeability. However, in the high-pressure area, the increase in pressure gradually weakens the influence of corrosion compressive strain, and the permeability of oil shale gradually recovers. Full article

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 CO_2(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 CO_2(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. Full article