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.

CO₂ injection in unconventional oil and gas reservoirs is a key technology for enhancing oil and gas recovery while enabling CO₂ storage. Its application is becoming increasingly prevalent in the development of such reservoirs within the context of “dual carbon” goals. Accurate monitoring and evaluation of CO₂ uptake across different layers are essential for guiding the optimization and adjustment of oil and gas reservoir development schemes. Pulsed neutron oxygen activation logging is employed as a dynamic monitoring technology for oxygen-containing fluid injection in a complex string structure, reflecting the dynamic behavior of injected CO₂ by recording variations in activated oxygen spectrum peaks. However, activation spectrum peaks in CO₂ injection often exhibit single-peak tailing and double-peak overlapping, influenced by statistical fluctuations in activated gamma-ray count rates, fluid properties, multi-layer string structure, and other factors. As a result, accurately determining the transit time of activation spectra and evaluating the amount of CO₂ uptake in each small layer becomes challenging.

To minimize errors in transit time calculation caused by overlapping peak separation and activation peak boundary selection, the morphological characteristics of activation peaks under varying influences were analyzed meticulously. The primary factors affecting oxygen activation logging data were string structure and flow rate differences. From a morphological perspective, peak types were classified into four categories: symmetric single peaks, asymmetric single peaks, partially overlapping double peaks, and severely overlapping double peaks. Asymmetric single peaks, characterized by tailing phenomena, occurred under conditions of significant fluid flow velocity differences and dispersed arrival times at the probe. Conversely, overlapping double peaks appeared when multiple flows from the tubing and the annulus produced superimposed signals, with similar flow rates and identical directions. Usually, the water flow was faster than that in the tubing-casing annulus, resulting in narrower and taller peaks for tubing flow.

Due to the randomness and uncertainty of neutron emission from neutron source, oxygen activation reactions, and the detector technology, the counting rate in the time spectrum under ideal conditions conformed to the normal distribution (also termed Gaussian distribution). Compared with the measured oxygen activation spectrum peak, the Gaussian function exhibited a high degree of morphological similarity. The Gaussian function was used to fit the oxygen activation spectrum peak, and the peak position, peak width, and peak height information were derived from its parameters, subsequently enabling the determination of the transit time. Furthermore, overlapping peaks generated by the tubing flow signal and the tubing-casing annulus flow signal could also be effectively separated using multiple Gaussian functions, enabling precise analysis of multiple downhole flow characteristics.

The spectral signal, characterized by multiple Gaussian peak functions, represented a typical nonlinear model. While the peak width and peak position of each characteristic peak exhibited nonlinear behavior, the peak height remained a linear parameter within this framework. Therefore, the Nelder-Mead (NM) algorithm was used to optimize the nonlinear parameters, with linear parameters being directly calculated by linear regression in each iteration. This approach reduced the dimension of the solution vector and enhanced operational efficiency. Despite the NM algorithm’s advantages of requiring no prior guidance and exhibiting rapid convergence, as a direct optimization algorithm, its results were greatly affected by the initial solution. To address this, the Ant Colony Optimization (ACO) algorithm was introduced. In ACO optimization, ants migrated towards spectral bands containing local maxima based on predefined movement rules, with iteration terminated once all ants halted. All ants were distributed within spectral bands containing local maxima. Through the preliminary optimization of the spectral lines, a reasonable initial solution was provided for the NM algorithm, thereby improving the stability of the transit time calculation results and enabling high-precision quantitative computation of the transit time in the oxygen activation injection profile logging. Compared with the traditional methods involving manual peak boundary determination combined with weighted average or Gaussian function fitting methods, this approach offered higher fitting efficiency, reduced human intervention, and lower calculation error.

Through a comparative analysis of pulse neutron oxygen activation data processing and interpretation in well X (CO₂ injection well) of the M oilfield, the established ACO-NM optimization model could effectively realize the bimodal separation of overlapping peaks in tubing and casing spaces. Transit times were obtained via automatic peak fitting, enabling the quantitative calculation of CO₂ flow in different spaces of the complex string structure. To validate the algorithm’s accuracy, comparative analysis was conducted between the ACO-NM hybrid optimization and the traditional least squares method. Taking surface metered injection volumes as the evaluation standard, relative errors were quantified. The least squares method exhibited errors of 9.59% (tubing) and 9.29% (annulus), while the ACO-NM hybrid optimization algorithm yielded relative errors of 1.87% and 3.31% in the tubing and annulus, respectively. Compared with the traditional least squares method, the calculation results of the optimization algorithm were closer to the surface metered injection volumes. A relative error below 5% was observed between the injected fluid flow calculated by the ACO-NM hybrid optimization algorithm and the actual injection volume at the wellhead. This indicated an improvement in calculation accuracy over the traditional least squares method, which met the needs of dynamic monitoring and evaluation of CO₂ injection in the field. The proposed ACO-NM hybrid optimization calculation method in the dynamic monitoring of CO₂ injection provides crucial technical support for oilfield development and carbon dioxide storage. The application of this method enables enhanced operational efficiency and economic viability of CO₂ injection, improved oil and gas recovery, and more precise and efficient resource development.

The relative permeability hysteresis effect in porous media has been studied extensively over many years, leading to relatively consistent conclusions. Due to the influence of this hysteresis effect, parameters such as the shapes of relative permeability curves across different cycles and the saturation levels of each trapped phase are affected by the saturation path and saturation history during gas-water alternating injection processes. In petroleum engineering applications involving multi-phase flow under alternating conditions, the relative permeability hysteresis phenomenon cannot be neglected. Current numerical simulation studies on CO₂-water alternating processes often fail to adequately consider the relative permeability hysteresis effect, leading to discrepancies between simulated and actual results for key parameters such as CO₂ storage capacity and oil recovery rates. Therefore, based on the Larsen & Skauge three-phase relative permeability hysteresis model, multi-cycle CO₂-water alternating injection experiments were designed and conducted under high-temperature and high-pressure conditions using oil-bearing cores. The variations in relative permeability curves during gas-water alternating injection with different initial injection phases under both miscible and immiscible conditions were systematically analyzed. The Larsen & Skauge three-phase relative permeability hysteresis model was used to fit the core experimental data numerically, and the fitting results using experimentally measured hysteresis parameters were compared with those obtained after parameter calibration. The results showed that hysteresis phenomena were more pronounced in immiscible experiments compared to miscible ones. Additionally, the core’s initial saturation state influenced the gas-water alternating displacement effect. The experimentally determined hysteresis parameters were only valid as initial fitting values, and separate experimental fittings are required for different operating conditions. These findings provide a reference for evaluating the relative permeability hysteresis effect in CO₂-water alternating processes, reveal the variation patterns of relative permeability curves during multi-cycle gas-water alternating displacement, and improve the accuracy of numerical simulation studies on hysteresis effects related to oil recovery and CO₂ storage.

With the exploration and development of oil and gas resources in China, heavy oil reservoirs account for more than 20% of domestic reservoir development. The efficient exploitation of heavy oil resources is crucial for China’s energy security. CO₂ injection technology has been proven to be an effective method to enhance heavy oil recovery. The mid-deep heavy oil reservoirs in the study area face critical challenges including strong formation water sensitivity and difficulties in large-scale waterflooding development, necessitating a shift from current water injection strategies. To address the unclear mechanism of CO₂ injection, unoptimized huff-n-puff development parameters, and lack of experimental research support in the study area, the mid-deep heavy oil reservoir in the Bei 10 well block of Xinjiang oilfield was selected as the research object. Experiments were conducted to investigate CO₂ diffusion in crude oil, supercritical CO₂ extraction of heavy oil, and the high-temperature and high-pressure long-core huff-n-puff tests, aiming to elucidate the mechanisms of CO₂ injection in heavy oil reservoirs and the efficient CO₂ huff-n-puff development mechanisms. The experimental results indicated that: (1) the diffusion coefficient of CO₂ in heavy oil exhibited a positive correlation with both injection temperature and pressure, with pressure demonstrating a greater influence on the diffusion coefficient than temperature. (2) With increasing extraction cycles, the mass fraction of medium-light components (C₆ to C₁₂) decreased significantly, while the mass fraction of medium-heavy components (C₁₄₊) gradually increased, particularly evident within the first three extraction cycles. (3) For heavy oil reservoirs, the recovery rate under depletion development was only 7.01%, while CO₂ huff-n-puff development proved effective in enhancing recovery, achieving a cumulative recovery rate of 36.94% and an oil replacement ratio of 0.59 t/t (oil production per ton of CO₂ injected). (4) Through huff-n-puff experiments, the optimal soaking time was determined to be 1-2 hours, and the optimal pressure depletion rate was 50 kPa/min. The research findings contribute to clarifying the mechanism of enhanced oil recovery by CO₂ injection in mid-deep heavy oil reservoirs, while guiding the design of CO₂ injection parameters in the Bei 10 well block. Moreover, this study provides critical references for the large-scale application of CO₂ huff-n-puff process in the future and offers valuable insights for CO₂ injection development in similar reservoirs.

As a critical component of Carbon Capture, Utilization and Storage (CCUS) technology, CO₂ geological storage plays a decisive role in the development potential and direction of CCUS technology, and serves as an effective means to achieve “dual carbon” goals. Clarifying the series of formation responses caused by CO₂ injection is essential for safe and efficient injection. Pressure buildup is a primary factor constraining the storage capacity and safety. Fluid dissolution, migration, and precipitation are the fundamental features affecting formation stability and storage efficiency. In addition, reservoir injectivity and caprock integrity are key determinants for the success of geological storage projects. The formation response characteristics caused by CO₂ injection were systematically discussed, including pressure buildup, pressure propagation, CO₂-water-rock interactions, mineral dissolution and precipitation, and rock pore structure characteristics. The influences of wettability, porosity, permeability, fluid properties, rock strength, caprock integrity, surface deformation, and fault activation on reservoir injectivity and caprock safety were summarized. Major current issues in research were identified, including the unpredictability of pressure change patterns, unclear reaction mechanisms, low injection efficiency, and incomplete monitoring and evaluation frameworks. Future work should deepen the understanding of storage mechanisms, improve monitoring and assessment methods of formation response, strengthen environmental risk evaluation, and further promote the safe and efficient application of CO₂ geological storage technology, thereby providing strong support for addressing global climate change.

To address the safety concerns associated with the CO₂ geological storage process in fault-block traps of the Subei Basin, safety thresholds were systematically determined by integrating fault sealing capacity, caprock integrity, and wellbore stability through theoretical calculations and laboratory experiments. In terms of fault sealing, a fault connectivity probability model was established. For caprock integrity, the critical breakthrough pressure was determined through experimental testing. Regarding wellbore safety, standards for CO₂ injection into old wells were formulated. Based on the identified safety thresholds of faults, caprocks, and wellbores, numerical simulation techniques were used to simulate CO₂ geological storage and calculate the storage capacity. During the simulation, the model ceased computation when pressure conditions of faults, caprocks, or wellbores reached their safety thresholds. A calculation method for the CO₂ geological storage capacity in fault-block traps in the Subei Basin was established by calculating the CO₂ storage volume in the simulation model and analyzing key parameters such as the pore volume occupancy of storage locations. Two injection strategies, continuous gas injection and water-alternating-gas injection, were employed to calculate the CO₂ geological storage capacity in a specific fault-block trap in the Subei Basin. The results indicated that the opening pressures of the main controlling faults in this trap were 42.9 MPa and 44.8 MPa, respectively. The maximum breakthrough pressure of the caprock reached 40.5 MPa, and the casing failure pressure was 45 MPa. The storage coefficients were 0.04 t/m³ for continuous gas injection and 0.03 t/m³ for water-alternating-gas injection. During water-alternating-gas injection, the pressure increased more slowly than in continuous gas injection due to partial extraction of formation water by production wells, resulting in a higher final CO₂ storage capacity. However, due to a significant increase in the pore volume occupied by CO₂ under the water-alternating-gas injection strategy, the CO₂ storage coefficient was lower than that of continuous gas injection.

In the context of the global carbon neutrality strategy, greenhouse gas emissions —mainly CO_₂— are continuously rising, exerting adverse effects on the global climate, ecosystems, and human life. Geological storage of CO₂ is an important technological approach to achieving carbon neutrality targets. As sealing barriers within potential storage formations, the sealing property of caprocks is crucial for the long-term or even permanent CO₂ storage. Salt-gypsum caprocks exhibit favorable properties such as low porosity, low permeability, high structural stability, and high breakthrough pressure, making them promising candidates for long-term and secure CO₂ storage. However, their physicochemical characteristics differ significantly from those of other lithological caprocks, posing challenges to evaluating their sealing performance for CO₂ storage. Therefore, there is an urgent need to establish an evaluation method tailored to salt-gypsum caprocks. Firstly, based on the Analytic Hierarchy Process (AHP), a comprehensive evaluation index system was developed by considering key influencing factors, such as macro indicators, micro indicators, and breakthrough pressure, affecting the sealing performance of caprocks. Four grading levels were defined for each index, and the influence weight of each index on the sealing performance of salt-gypsum caprocks was determined. Secondly, by integrating the Fuzzy Comprehensive Evaluation Method, the total weight for evaluating the sealing performance of salt-gypsum caprocks for CO₂ storage was calculated. This resulted in the development of a comprehensive evaluation method of CO₂ storage sealing tailored to these types of caprocks. Finally, the method was applied to the Gaoshiti-Moxi block in the Sichuan Basin as a case study, where the CO₂ storage sealing performance of its potential salt-gypsum caprock in a depleted gas reservoir was systematically evaluated. The results revealed that the total weight of the sealing performance evaluation of Gaoshiti-Moxi structural gas reservoir caprocks ranged from [2.5,3.0), corresponding to a grade of “relatively good”, indicating a relatively strong capacity for CO₂ storage. This suggested the site was suitable for the future application of Carbon Capture and Storage (CCS) technology. The research results can provide technical guidance for site selection and storage safety evaluation of CO₂ storage in depleted gas reservoirs with salt-gypsum caprocks.

Under the background of synergistic pollution and carbon reduction, gas field produced water reinjection coupled with CO₂ geological storage provides an important pathway to promote synergistic efficiency and expand the benefits of CO₂ geological storage. The evolution of CO₂ occurrence states in formations with gas field produced water reinjection directly affects the CO₂ storage efficiency and long-term security. Based on the interaction mechanism of CO₂, gas field produced water, and reservoir rocks, the PHREEQC software was employed to systematically investigate the influence patterns and underlying mechanisms of CO₂ pressure, produced water salinity, reservoir rock type, and formation temperature on the two CO₂ occurrence states: dissolved-mineralized phase and free phase. Combined with changes in mineral composition and dissolution-mineralization ratios during reactions, the dominant factors affecting CO₂ occurrence states in formations with gas field produced water reinjection were analyzed. The results showed that: (1) Feldspar and chlorite served as the primary minerals promoting CO₂ mineralization reactions, while illite and calcite functioned as the main carbon fixation minerals. (2) The amount of CO₂ in the dissolved-mineralized phase (hereinafter referred to as CO₂ dissolution-mineralization quantity) increased with higher CO₂ pressure but decreased with increasing salinity of gas field produced water. In sandstone systems, the CO₂ dissolution-mineralization quantity decreased with increasing temperature, while in limestone systems, it first decreased and then increased with increasing temperature. (3) Under simulation conditions, changes in CO₂ pressure led to variations in CO₂ dissolution-mineralization proportions ranging from 47% to 72% in sandstone and limestone systems. Differences in rock type led to variations in CO₂ dissolution-mineralization proportions ranging from 10% to 45%. Changes in produced water salinity and formation temperature led to variations in CO₂ dissolution-mineralization proportions ranging from 2%-31% and 3%-15%, respectively, in sandstone and limestone systems. These findings are significant for deepening the understanding of CO₂ occurrence state evolution and influencing factors, and for advancing the practical demonstration of gas field produced water reinjection coupled with CO₂ geological storage from theoretical research to field applications.

CO₂ flooding can effectively enhance oil recovery of low permeability reservoirs. However, due to the common presence of strong heterogeneity in such reservoirs, accurately predicting the development dynamics of CO₂ flooding is difficult. To address this issue, a time-node-based dynamic prediction model for the entire CO₂ flooding process in low permeability reservoirs was developed, based on the comprehensive consideration of factors such as throat size and distribution, viscosity reduction due to CO₂ dissolution, and changes in interfacial tension, combined with CO₂ flooding seepage mechanics theory. This model achieved innovative whole-process dynamic prediction by accounting for reservoir micro-heterogeneity. The results showed that the throat radius significantly influences flow resistance during the early stage of CO₂ displacement. Meanwhile, the continuous iterative coupling of diffusion, dissolution, viscosity reduction, and drag reduction during the CO₂ displacement process led to differences in the displacement front positions in throats of different radii at the same time. The difference was reflected in development dynamics: larger pore-throat radius and better reservoir properties led to earlier gas breakthrough and higher gas-oil ratio at the same time. According to the CO₂ volume fraction distribution between injection and production wells, the displacement process could be divided into three zones: pure CO₂ zone, mass transfer diffusion zone, and pure oil zone. When the front of the mass transfer diffusion zone in large throats reached the production well, gas breakthrough occurred, and oil production gradually increased; thereafter, the oil recovery increased rapidly. When the front of the pure CO₂ zone reached the production well, the gas-oil ratio increased rapidly, oil production decreased sharply, and the growth rate of the recovery curve slowed down and eventually stabilized. Compared with the experimental results, the predicted recovery errors of the model were 5.7% and 4.5%, respectively, with good agreement in gas-oil ratio and oil recovery curves. This method was used to predict the development dynamics of the H3 experimental area, providing critical guidance for analyzing CO₂ flooding performance and timely adjustment of the development strategy for gas channeling wells.

CO₂ sweep efficiency and gas channeling are key factors restricting the effectiveness of CO₂ flooding in low-permeability tight reservoirs. To address the technical issues of low sweep efficiency and gas susceptibility to channeling in CO₂ flooding, a viscoelastic fluid system (CMS) was proposed to improve CO₂ flooding in low-permeability tight reservoirs. A systematic study was conducted on the viscoelasticity, interfacial activity, injectivity, plugging performance, and oil displacement performance of CMS under oil reservoir conditions. The synergistic flooding performance of CO₂-CMS was explored, and field trials were carried out. Experimental results demonstrated that at reservoir temperatures ranging from 30-80 ℃, CMS with a mass fraction of 0.5% showed certain viscoelasticity, with elasticity as the dominant characteristic, and both viscosity and elasticity decreased as temperature increased. At an oil reservoir temperature of 45 ℃, the viscosity of CMS was 3.27 mPa·s, and it exhibited strong elasticity. Furthermore, CMS could effectively reduce the oil-water interfacial tension to 2.68×10^-2 mN/m. After core samples were immersed in the CO₂-CMS system, the water-phase contact angle decreased to 8.75°, indicating enhanced hydrophilicity. The CO₂-CMS system demonstrated good injectability in low-permeability tight cores, with smaller slug sizes yielding better injection performance. In long-core displacement experiments, using a 0.3 PV slug of CMS followed by CO₂ flooding increased the recovery rate by up to 27.79%. In double-tube parallel core displacement experiments, alternating CMS and CO₂ proved most effective, as it successfully sealed the high-permeability cores and mobilized low-permeability cores, resulting in a 26.28% increase in recovery. Field trial data from well groups indicated that after applying CMS, the overall liquid and oil production increased, and the CO₂ volume fraction in gas-channeling wells significantly decreased. This research provides new technical insights and practical solutions for improving the efficiency of CO₂ flooding in low-permeability tight reservoirs.

The complex small fault block oilfields in Jiangsu are mainly developed through waterflooding with stratified injection. Currently, intelligent stratified injection is applied to improve injection-production coordination and enhance recovery efficiency. Due to the low level of stratified control in production wells and the unclear understanding of the relationship and degree of effectiveness of stratified water injection, issues such as interlayer interference in production wells, single-layer water breakthrough, and rapid water cut increases are prominent. To achieve injection-production coordination, alleviate interlayer and areal contradictions during the high water cut period, reduce ineffective water cycling, and control the rise in water cut of production wells, a cabled intelligent stratified oil production technology was developed. Flow rate, water cut, pressure, and temperature sensors suitable for the high-temperature, high-pressure, corrosive, and scaling-prone downhole environment were selected. Reliable stratified flow control devices and control technologies were adopted, and the spatial layout of components and overall mechanical structure of the stratified production allocator were optimally designed. Different bidirectional transmission cables and connection technologies were selected, the control circuits of the production allocator and a ground-integrated control system were developed, and the supporting downhole stratified oil production strings were optimized. Tool and implementation costs were reduced, enabling real-time continuous monitoring of downhole stratified production parameters and wireless remote control of the stratified production allocator. Field tests, including alternating single-layer production, stratified production allocation, and coupled adjustment, were conducted. The tests confirmed the conclusions of pre-test reservoir dynamic analysis and verified the performance of the intelligent stratified oil production tools and strings. Injection-production coupling, enhanced oil production, water cut control, and stratified measurement and adjustment were achieved, with the water cut of the test well reduced by 38.8%. The application of this technology can provide a basis for fine geological analysis and potential exploration of oil reservoirs, significantly enhancing the intelligent level of oilfield production.

Production capacity evaluation is a critical task during the early development stages of gas reservoirs. Clarifying the impact of reservoir petrophysical properties, water saturation, and CO₂ volume fraction in fluid composition on gas well production capacity is of great significance for accurately evaluating the production capacity of low-permeability gas reservoirs. This study focused on typical ultra-high temperature, high pressure, and low-permeability gas reservoirs in the Yinggehai Basin. Using the gas-water steady-state flow experiments, the influence of water saturation and CO₂ volume fraction on gas-phase permeability of cores with varying petrophysical characteristics was clarified. Based on the principle of flow velocity approximation, a quantitative multi-factor production capacity chart was established. The results showed that: (1) As water saturation in the rock increased, gas-phase permeability decreased. When water saturation in the target reservoir cores was below the irreducible water saturation (40%), every 10% increase in water saturation corresponded to an average production capacity loss of approximately 12%. When movable water existed, two-phase gas-water flow led to a sharp decline in gas-phase permeability. Specifically, as water saturation rose from 40% to 50%, gas production capacity decreased by about 70%. (2) In ultra-high temperature and high-pressure formations, the presence of CO₂ in the gas composition significantly reduced the gas well production capacity. When the CO₂ content was 28%, the production capacity loss rate was about 12%. As the CO₂ volume fraction increased, its impact on production capacity gradually intensified. When the CO2 volume fraction reached 70%, the production capacity loss rate was around 60%. A multi-factor production capacity evaluation chart was established, incorporating the reservoir petrophysical properties, water saturation, CO₂ volume fraction, and production pressure differentials. This chart provides essential theoretical support and practical guidance for the development of similar gas reservoirs.

With the development of fractured horizontal well technology, shale oil exhibits great exploration and development potential. Compared with conventional oil and gas reservoirs, shale reservoirs are characterized by extremely low porosity and permeability, abundant organic matter, strong stress sensitivity, well-developed laminated structure, and diverse fluid occurrence states. Previous studies on shale oil flow patterns have typically focused on individual characteristics, inevitably leading to an incomplete understanding. This study aims to further explore the coupling mechanism of different factors on the shale oil flow patterns, thereby providing theoretical support for the efficient exploitation of terrestrial shale oil.

A novel model was established to accurately characterize the oil flow patterns in shale reservoirs, integrating vertical heterogeneity and stress sensitivity of shale formation, as well as considering the adsorption-desorption effects of shale oil. The boundary conditions were simplified based on the shale oil reservoir properties to ensure both the calculation efficiency and accuracy. Taking laminated shale reservoirs—a primary target for exploitation—as a case study, the physical process of shale oil flowing from the matrix to the hydraulic fracture was investigated systematically using the proposed model. The seepage mechanism of shale oil during primary depletion was clarified, and the combined influence of vertical crossflow and formation stress sensitivity on the production of free oil and adsorbed oil was discussed. Subsequently, the proposed model was applied to the Paleogene Kong-2 member shale in the Cangdong Sag, revealing significant differences in oil production among different lithofacies and further predicting their respective production trends. Practical development strategies for shale oil were formulated based on lithofacies-dominated production characteristics.

Neglecting the vertical heterogeneity in shale formations and adsorption-desorption effects of shale oil may significantly distort simulation results, leading to inaccurate shale oil production predictions. Comprehensive analyses through numerical simulations and field case studies demonstrated that: (1) During the primary depletion, well-developed laminated structures enhanced shale oil recovery. Free oil primarily migrated through laminated channels, while adsorbed oil benefited from accelerated desorption within these structures. (2) In laminated shale reservoirs, free oil mainly migrated from the shale matrix to hydraulic fractures in shale layers, and it mainly exited through sand layers. This established shale layers as oil sources and sand layers primarily as flow channels. (3) The strong stress sensitivity of shale layers enhanced oil recovery, while that of sand layers exerted adverse effects, with shale layers dominating during mid-to-late production stages and sand layers influencing early stages most significantly. The proposed model accurately simulated the physical process of oil flowing from the shale matrix to hydraulic fractures. The simulation results showed strong consistency with field observations, validating the model’s applicability for shale formation development planning and optimization.

Numerical simulations investigated the shale oil flow patterns in laminated shale reservoirs by incorporating rock and fluid properties. The proposed model was utilized to characterize vertical crossflow and the desorption process of adsorbed oil in shale formations, while quantitatively evaluating the significant effects of laminated structure and stress sensitivity on shale oil production. These findings provide crucial insights for enhancing recovery in continental shale formations.

The storage space of fracture-cavity carbonate reservoirs is primarily composed of fractures, cavities, and matrix pores. Among them, fractures and cavities exhibit highly random distribution, serving as the main storage spaces and seepage pathways for oil and gas. The strong heterogeneity of these reservoirs leads to highly complex fluid flow behavior, characterized by the coexistence of free flow occurring in cavities and seepage flow in fractures. Indoor physical simulation experiments are usually required to reveal the fluid distribution patterns and unique flow phenomena within the reservoir. However, current physical models for fracture-cavity systems struggle to meet both high-pressure resistance and visualization requirements, thus limiting the investigation of fluid flow mechanisms under reservoir conditions. To accurately characterize fluid flow in fracture-cavity reservoirs while reducing experimental research costs, the feasibility of fluid flow experiment simulations in fracture-cavity reservoirs was explored based on fluid dynamics and computer simulation technology. By simulating and analyzing the flow characteristics in the free flow and seepage regions of the fractured-vuggy physical model, it was found that under reservoir temperature and pressure conditions, fluid flow in the physical model primarily followed low Reynolds number Stokes flow. Based on this, the traditional free flow equation was simplified, and a unified momentum equation was established to describe both free flow and seepage in the model. Parameters such as the viscous resistance coefficient were introduced into the Euler equations to characterize multiphase flow characteristics in the seepage region, achieving an integrated simulation of different flow regimes in the fracture-cavity model. A 3D fracture-cavity digital model was selected for flow simulation, and the comparison of simulation results verified the reliability of the unified flow model. The simulation results indicated that for typical fracture-cavity physical model flow experiments, the laminar flow model based on Stokes equation could achieve the simulation accuracy of the traditional Darcy-Navier-Stokes (Darcy-NS) coupled model, with strong reliability, while significantly improving computational efficiency. This provides a new research method for the study of flow mechanisms in fracture-cavity reservoirs.