To address the challenges of rapid production decline and low recovery of shale oil wells, it is imperative to supplement formation energy and explore innovative development methods. Compared with conventional waterflooding, CO₂ exhibits superior injectivity and miscibility with crude oil, making it an effective oil displacement medium. Simultaneously, CO₂ is a major greenhouse gas and a key target for emission reduction. Therefore, exploring CO₂ huff-n-puff in shale oil reservoirs for enhanced oil recovery while simultaneously achieving carbon sequestration has significant practical value. However, Carbon Capture, Utilization and Storage (CCUS) technology in shale oil is still in its exploratory stage, facing challenges such as immature numerical simulation techniques and the lack of large-scale injection-production operations. To investigate the mechanisms and key controlling factors of enhanced oil recovery through CO₂ injection in shale oil, this study employed numerical simulation techniques, integrating logging data, geological parameters, and fracturing operation data to model the formation and distribution of hydraulic fractures. A composite discrete fracture network numerical model combining both artificial and natural fractures was established to analyze the oil recovery enhancement mechanisms of CO₂ huff-n-puff. The study clarified the influence patterns of reservoir engineering parameters in CO₂ huff-n-puff on both cumulative oil increment and CO₂ storage capacity, and determined the primary controlling factors among these parameters. The results showed that CO₂ huff-n-puff restored production capacity in shale oil wells by replenishing formation energy, extracting light and intermediate components from shale oil, and leveraging CO₂ diffusion, oil viscosity reduction, and expansion effects. Considering both oil recovery and storage, the optimal injection strategy for a single well included: initiating when daily oil production declined to just above 8 m³, injecting 15 000-24 000 tons of CO₂ at a rate of 500-900 t/d, shut-in duration of 30-50 days, and conducting 2-3 huff-n-puff cycles. Among the shale oil reservoir engineering parameters, injection volume was identified as the primary factor, with a weight of 0.48. These findings provide technical guidance and evaluation support for the implementation of CCUS technology in shale oil reservoirs.

Most oilfields currently using CO₂ flooding in China have transitioned from water flooding to CO₂ injection for development. Over prolonged periods, CO₂-water-rock reactions can alter reservoir physical properties, becoming a key issue that must be addressed. To address limitations in existing studies—such as short reaction durations and unclear effects of environmental variables—this research used a high-temperature, high-pressure reactor to simulate reservoir conditions. Advanced equipment, including high-performance field-emission scanning electron microscope and X-ray diffraction, was utilized to study the effects and mechanisms of CO₂-water-rock reactions on reservoir physical properties and mineral compositions under different environmental variables. The experimental results indicated that feldspar dissolution and clay mineral formation were the primary factors affecting reservoir physical properties after CO₂-water-rock reactions. With increasing temperature, the water-rock reaction intensified, accelerating the dissolution of potassium feldspar, calcium feldspar, and sodium feldspar while increasing the proportion of kaolinite, thereby improving reservoir physical properties. When pressure increased, the dissolution of large amounts of CO₂ lowered the solution pH and inhibited the transformation of minerals such as potassium feldspar and sodium feldspar into clay minerals like kaolinite, causing deterioration in overall reservoir physical properties. As the reaction time increased, the dissolution of feldspar and carbonate minerals intensified, leading to increased mass concentrations of major ions such as Na⁺, K⁺, Ca²⁺, an improvement in reservoir physical properties, and the precipitation of gypsum. Within the experimental range, the degree of mineral dissolution caused by CO₂-water-rock reactions exhibited a positive correlation with temperature and time but a negative correlation with injection pressure. Finally, the experimental results were calculated using the Kozeny-Carman equation, indicating that within the experimental range, reservoir porosity and permeability are positively correlated with temperature and time, and negatively correlated with CO₂ injection pressure. By studying the impact of CO₂-water-rock reactions on reservoirs under different environmental variables, this study offers insights for the application of CO₂ flooding to enhance oil recovery (EOR) in shale oil reservoirs.

Tight oil reservoirs, as a key focus in China’s current oil and gas development, present significant exploration challenges due to their poor physical properties, limited connectivity, and strong heterogeneity. During the exploration of tight oil reservoirs, the influence of different injection media and production methods on recovery mechanisms and performance remains unclear, severely restricting their efficient exploration of these reservoirs. Taking the Fuyu reservoir in the Daqing oilfield of PetroChina as a case study, laboratory experiments involving dynamic core injection were conducted using various injection media (CO₂ and surfactants) and methods (displacement, huff-n-puff, and gas-water alternating injection) to investigate their effects on oil recovery mechanisms and efficiency in tight reservoirs. The results indicated that gas-water alternating displacement improved underground oil recovery by 4.14% compared to CO₂ displacement and by 15.38% compared to surfactant displacement. Similarly, gas-water alternating huff-n-puff increased oil recovery by 0.54% over CO₂ huff-and-puff and by 5.09% compared to surfactant huff-n-puff. Displacement methods, after forming preferential oil flow channels, exhibited larger sweep volumes and higher oil displacement efficiency than huff-and-puff methods. Moreover, gas-water alternating injection effectively reduced fluid channeling compared to single-media injection and enhanced the sweep of fine pore spaces. Due to CO₂’s superior viscosity reduction and dissolved gas drive effects on reservoir crude oil, CO₂ injection achieved higher recovery than surfactant injection. Under identical injection-production conditions, low-viscosity crude oil exhibited a higher recovery compared to high-viscosity crude oil, as increased viscosity significantly raised flow resistance. The study reveals the differences in recovery performance associated with various injection media and methods, providing experimental evidence and theoretical support for the efficient development of tight oil reservoirs.

Currently, the international geopolitical landscape is complex and volatile, with energy supply chains facing significant uncertainties. Gas storage, as a crucial component of the national energy reserve system, can effectively mitigate risks from fluctuations in international natural gas market prices and supply disruptions, ensuring stable gas supply for residential and industrial use, thereby serving as a robust safeguard for national energy security. For the safe and efficient operation of gas storage under multi-component, multi-cycle injection, and production conditions, accurately understanding the diffusion and flow patterns of mixed gases—working gas and cushion gas—in gas storage is essential. However, experimental studies on gas diffusion mainly focus on shale, coal, and tight formations, leaving the diffusion patterns of multi-component gases in carbonate reservoirs poorly understood. In this study, carbonate rock samples from the Upper Carboniferous Huanglong Formation (upper member) of the Wolonghe gasfield were examined, and the distribution of pore-throat radius were characterized using nuclear magnetic resonance and high-pressure mercury intrusion experiments. Diffusion experiments were conducted on gas mixtures containing CH₄ with CO₂, N₂, and O₂. Through comparative analysis of fitting results, the optimal mathematical model for gas diffusion coefficients applicable to multiscale carbonate reservoirs was selected. The results showed that the carbonate rock samples exhibited pronounced distribution characteristics of multi-scale pore structure. Under identical temperature and pressure conditions, higher porosity and permeability led to larger diffusion coefficients for all gas components. Moreover, the binary diffusion coefficient of the CH₄-CO₂ pair exceeded that of the N₂-CO₂ pair. In a multi-component system, O₂ exhibited the largest diffusion coefficient, followed by CH₄, while N₂ and CO₂ had the smallest diffusion coefficients. The presence of O₂ affected how the diffusion coefficients of CH₄ and N₂ responded to changes in the volumetric fractions of CO₂ and N₂. The mathematical model optimized using experimental data can be extended to predict diffusion coefficients under different temperature and pressure conditions. These findings provide experimental and computational methods for accurately predicting the patterns of gas storage operations and designing rational operational strategies.

As China advances toward its dual-carbon goals, CO₂ sequestration in saline aquifers is a key pathway. Saline aquifers in southwestern China are rich in resources and hold great potential for CO₂ sequestration. However, current studies on reservoir changes caused by CO₂ sequestration in saline aquifers are mainly limited to the macroscopic scale, with a lack of characterization of changes in the pore structure of rocks before and after CO₂-water-rock reactions at the microscopic scale. Taking the carbonate rock saline aquifer of the second member of the Jialingjiang Formation in the Moxi area, central Sichuan Basin, as an example, 20 sets of CO₂-water-rock interaction experiments were conducted through laboratory simulation of formation pressure (69 MPa) and temperature (97 ℃). Analytical techniques such as X-ray diffraction, nuclear magnetic resonance, scanning electron microscopy, and computed tomography were used to investigate in depth the evolution of physical properties and pore-throat structures of the carbonate rocks under the influence of CO₂. The results showed that: as the reaction progressed, the proportions of clay minerals and quartz in the rock gradually increased, the mass fraction of feldspar minerals decreased significantly, the mass fraction of calcite first decreased and then increased, while the mass fraction of dolomite showed a trend of first increasing and then decreasing. The dissolution of minerals altered the pore-throat structure of the carbonate rock, enhancing pore connectivity, enlarging the pore-throat radius, and increasing porosity and permeability, thereby expanding the pore space within the reservoir. Moreover, the higher the volume fraction of CO₂, the more significant the changes in the physical properties and pore-throat structures of the carbonate rock. Under the influence of pure CO₂, after 50 days of reaction, the porosity and permeability of the carbonate rock increased by 18.64% and 522.03%, respectively. By revealing the significant effects of CO₂-water-rock reactions on the porosity, permeability, and mineral composition of carbonate rocks, these findings provide valuable data support for CO₂ sequestration in saline aquifers.

In shale gas reservoirs, CH₄ often coexists with heavy alkanes such as C₂H₆ and C₃H₈. To investigate the mechanism by which heavy alkanes affect the competitive adsorption of CH₄ and CO₂ in organic nanopores of shale, this study combines density functional theory and Grand Canonical Monte Carlo simulations. The interaction types and strengths between gas molecules and kerogen were systematically analyzed in terms of adsorption energy, structural characteristics, weak interaction analysis, and isothermal adsorption. The adsorption performance of pure-component gases was examined, followed by an evaluation of the influence of varying C₂H₆ and C₃H₈ concentrations on CH₄ adsorption performance. Furthermore, the influence of C₂H₆ and C₃H₈ on CO₂ and CH₄ competitive adsorption was analyzed. The results showed that: (1) With the elongation of alkane carbon chains, the interaction strength between gas molecules and kerogen progressively intensified. The adsorption energies of the four gas molecules on the kerogen surface followed the order: C₃H₈>C₂H₆>CO₂>CH₄. (2) For single-component gas adsorption, the total adsorption capacity decreased from CH₄ to C₃H₈ due to the increased adsorption sites occupied by individual alkanes. Meanwhile, CO₂ exhibited a higher adsorption capacity, which was attributed to its unique geometric structure. (3) With rising system temperature, the adsorption capacity of various gas molecules declined. As system pressure increased, the incremental rise in gas adsorption capacity gradually diminished. (4) In binary mixture adsorption, the existence of C₂H₆ and C3H8 significantly reduced the CH₄ adsorption capacity, with C₃H₈ exhibiting a more significant effect. Meanwhile, the addition of CO₂ greatly decreased CH₄ adsorption capacity. (5) In ternary mixture adsorption, the coexistence of C₂H₆, C₃H₈, and CO₂ demonstrated a synergistic effect on promoting CH₄ desorption. Specifically, the most effective promotion of CH4 production was achieved when C₂H₆ and C₃H₈ accounted for 4% and 8% of the total gas mixture by mass. In addition, compared with C₃H₈, C₂H₆ was more favorable to the storage of CO₂. These findings provide theoretical support for multicomponent competitive adsorption in shale gas and for CO₂-enhanced shale gas extraction.

The L low permeability reservoir in Bohai Sea is characterized by medium porosity and low permeability, with reservoir fluids exhibiting low density and low viscosity. Water flooding has been implemented in the early stage to supplement energy. It is therefore urgent to explore the feasibility of different development methods to provide a basis for subsequent rational development. However, the microscopic operation characteristics, mechanisms, and influencing factors of different displacement methods in this reservoir remain unclear. Taking the L low permeability reservoir in Bohai Sea as the research object, two representative sandstone cores from the reservoir were selected. Using online nuclear magnetic resonance displacement technology, indoor experiments were conducted on core samples using CO₂ miscible flooding and water flooding to CO₂ miscible flooding. Real-time scanning of the cores was carried out during the displacement process to identify the differences in microscopic operation characteristics and influencing factors among the different displacement methods. The results showed that under the same displacement conditions with 2.0 PV of injected fluid, CO₂ miscible flooding achieved higher final displacement efficiencies in both the high-permeability core a (33.80×10^-3 μm², 69.31%) and low-permeability core b (2.95×10^-3 μm², 66.18%), compared with those of water flooding to CO₂ miscible flooding (58.07% and 56.97%, respectively). Compared to the low-permeability cores, the high-permeability core had a higher proportion of large pores and better pore connectivity. The displacement efficiency increased by 3.13% and 1.10% for CO₂ miscible flooding and water flooding to CO₂ miscible flooding, respectively, indicating that physical properties had a limited effect on displacement efficiency. During water flooding, the lower pore-throat operation limits were 0.019 7 μm and 0.009 8 μm for the high-permeability and low-permeability cores, respectively. Lower permeability led to higher pressure differentials, resulting in lower pore-throat operation limits. When water flooding was switched to CO₂ miscible flooding, three-phase flow of oil, gas, and water occurred, further increasing the experimental pressure differential and reducing the lower limits of pore throat operation to 0.008 μm and 0.004 9 μm, respectively, which were close to the lower pore-throat operation limits (0.006 9 μm and 0.005 2 μm) of the two cores that had been using CO₂ miscible flooding. CO₂ miscible flooding is recommended as an optimal development method for the later stage of the L reservoir.

The high cost of industrial flue gas treatment makes injecting CO₂-rich exhaust gas into depleted oil and gas reservoirs a potential technology for enhanced recovery and carbon sequestration. This study aims to guide the injection process, and the effect of N₂ on the physical properties of CO₂-rich injection gas remains insufficiently understood. This study conducted experimental measurements of the physical parameters and phase equilibrium studies using a JEFRI phase analyzer and CPA (cubic plus association) equation of state. The results showed that at higher temperatures, the “opalescence phenomenon” in high CO₂-rich injection gas was weaker and occurred at higher pressures. When temperature approached critical point, the opalescence was stronger but occurred at lower pressures, which were far from the critical pressure. When CO₂-rich injection gas exhibited “opalescence phenomenon”, the fluid had critical point. However, the presence of a critical point did not necessarily imply observable opalescence, and no opalescence was observed when the fluid had no critical point. When the pressure was below 10 MPa, the fluid exhibited gas-like densities with volume decreasing rapidly as pressure increased. Above 20 MPa, the fluid showed liquid-like densities. The 10-20 MPa range represented a transition zone. At 2-55 MPa, the viscosities of five CO₂-rich gas mixtures remained low, exhibiting gaseous characteristics. Under identical temperature and pressure conditions, as the N₂ molar fraction increased from 10% to 90%, the deviation factor of CO₂-rich injection gas increased while fluid density decreased. Thus, N₂ content should be minimized during injection, and higher CO₂ molar fractions improved injection performance. With 12 MPa as the threshold, viscosity increased with rising N₂ content below 12 MPa but decreased with higher N₂ molar fraction above this pressure. A 5% O₂ impurity had a negligible effect on the physical properties of CO₂-rich injection gas and can be neglected. At the same composition, both deviation factor and viscosity of the injection gas first increased and then decreased with rising temperature, and the pressure intersection point varied with temperature and composition. By integrating experimental data with theoretical modeling, this study elucidates the effect of N₂ on the physical properties of CO₂-rich injection gas, providing guidance for enhanced recovery rate using flue gas or exhaust gas injection in oil and gas reservoirs.