Abstract:The high-quality development of the petroleum industry is crucial to ensuring China’s energy security. Against the backdrop of global energy transition and the“carbon peaking and carbon neutrality”goals，traditional petroleum development technologies urgently need to shift towards green，low-carbon，and efficient directions. As a eco-friendly solutions for sustainable oilfield development，biological agents for oil recovery have become a promising technical direction for achieving green and sustainable development in mature oilfields，owing to their advantages such as renewability，biodegradability，environmental friendliness，functional diversity，and strong robustness in reservoir environments. A systematic overview of the theoretical studies and field practices of biological agents for oil recovery in China and abroad was provided，with future development prospects outlined considering existing technical limitations. Biological agents used for oil recovery mainly include biosurfactants，biopolymers，and enzymes，which have demonstrated significant technical advantages in multiple aspects of oilfield development.Biosurfactants exhibit excellent surface and interfacial activity，effectively reducing oil-water interfacial tension and enhancing oil displacement efficiency；biopolymers，with their high viscosity，can be used as environmentally friendly oil flooding system and drilling fluid additives to enhance oil recovery and minimize formation damage；enzymes，with their specific and mild catalytic activity，play an essential role in reservoir protection and environmental remediation. However，the application of biological agents in oilfield development still faces challenges such as varying levels of maturity，high synthesis costs for some agents，and incomplete implementation processes，leaving their application potential to be further explored. In the future，efforts should be grounded in China’s“carbon peaking and carbon neutrality”goals and the actual needs of petroleum development，integrating innovations in bioengineering and oil recovery engineering technologies. Targeted research should focus on developing high-temperature and high-salt resistant，efficient，and low-cost biological agent systems for oil recovery and establishing fermentation and application process technologies for different biological agents. Ultimately，a comprehensive biological agent system for oil recovery that meets the full lifecycle and full-process requirements of oilfield development should be formed，ensuring the green and sustainable development of mature oilfields.

Abstract:In view of the challenge of insufficient understanding of the flow mechanism of Jiyang Shale Oil in continental fault-depression basins，starting from the perspective of the generalized Darcy’s law，this paper demonstrated the dynamic evolution patterns of the“five fields”comprising the porosity field，permeability field，saturation field，pressure field，and in-situ stress field. In the Jiyang Shale Oil Reservoir，the dynamic coupling of these five fields governs the development of pores and fractures，the occurrence of fluids，and the mechanisms of fluid flow. This coupling ultimately determines the effectiveness of reservoir stimulation and the potential for productivity. Clarifying this coupling mechanism is therefore a fundamental prerequisite for achieving efficient development of shale oil resources. Building upon the spatiotemporal evolution mechanisms of the“five fields”，the paper refined the tri-zone flow model（easily flowing zone，slowly flowing zone，and stagnant zone）. For individual wells，the distribution characteristics of the“five fields”within each zone，their dominant flow mechanisms，and their differential contributions to oil production were clarified. Focusing on the spatial configuration of these three zones between wells，the paper proposed three well-group flow patterns：isolated，competitive，and beneficially interfered types. The technical trend is identified as creating beneficially interfered tri-zone flow through the synergistic adaptation of well patterns to artificial fracture networks combined with balanced fracturing stimulation. On this basis，two key research directions were put forward，namely the fine characterization of the properties of the three zones and the accurate representation of the flow laws of the three zones，which provide theoretical and technical support for the large-scale and economic development of Jiyang Shale Oil.

Abstract:The adsorption behavior of methane in kerogen is of great significance for shale gas reserve evaluation and production prediction. However，there is still a lack of clear understanding of the hysteresis phenomenon and its micro-causes in the process of methane desorption. Therefore，based on the real kerogen model，the grand canonical Monte Carlo and molecular dynamics（GCMC-MD） coupling method was used to systematically investigate the adsorption-desorption behavior of methane under different conditions and the pore structure evolution characteristics of kerogen. The results show that the volumetric strain of kerogen shows a continuous growth during the methane adsorption process. This positive feedback mechanism of“adsorption，expansion，and readsorption”effectively expands the available pore space and significantly improves the methane storage capacity of the kerogen. Under the same pressure conditions，the methane’s absolute adsorption amount in the depressurization stage is higher than that in the pressurization stage，thus showing a significant hysteresis loop on the isothermal adsorption-desorption curve.The fundamental mechanism is that the kerogen skeleton undergoes partial irreversible structural deformation，making the thermodynamic path of the adsorption-desorption process do not coincide. The increase of temperature will weaken the interaction between methane molecules and pore wall，reduce the adsorption capacity，and alleviate the hysteresis in the desorption process.Under high temperature conditions，the overall deformation response ability of kerogen decreases. Compared with the type III-A kerogen，the type II-A kerogen has a higher proportion of micropores，which leads to a higher energy barrier to methane in the desorption process，thus aggravating the difficulty of desorption.

Abstract:With the development of oil and gas exploitation for unconventional reservoirs，shale oil plays a vital role in national en‐ergy security as an essential replacement resource. Laminated shale is the main lithofacies of shale oil development in Jiyang Depres‐sion，which has good storage and flow performance，and it is of great significance to clarify its microscopic pore structure distribu‐tion characteristics and flow law of shale oil to realize the large-scale benefit development of shale oil. Firstly，for the laminated shale in Jiyang Depression，high-precision core images of organic matter and inorganic matter were obtained based on focused ion beam scanning electron microscopy（FIB-SEM）. The images were preprocessed by filtering and threshold segmentation，and the pore network model of organic matter and inorganic matter was constructed by the maximum sphere algorithm，which could quanti‐tatively characterize the nanopore distribution and topology of the matrix. Secondly，by setting the pore structure parameters of the matrix and the laminated pore，the stochastic modeling method was used to construct a mechanism model of the digital core of the laminated shale and the influence of the proportion of laminated shale and the flow direction on the flow capacity of shale oil was studied. The results show that the non-local mean filtering method can effectively remove the noise points and depict the clear pore edges，which effectively retains the integrity of initial pore and throat morphology. The inorganic pores are mainly 10–40 nm con‐nected pores，and the number of connected pores is 12.2 times that of organic pores；the average coordination number is 3 times that of organic pores，which shows that the network connectivity of inorganic pores is superior to that of organic pores，and its pores have a dominant role in the flow capacity of shale oil. The permeability of laminated shale has obvious anisotropic characteris‐tics，and the permeability of the parallel lamina direction is much higher than that of the vertical laminae direction. The laminae are the main flow channels of shale oil. A higher proportion of the thicknesses of the laminae indicates a greater matrix permeability，and the density of the laminas has an essential impact on the permeability of the shale matrix.

Abstract:At present，the CO₂ huff and puff method is mainly used in international oilfields to improve the recovery of shale reservoirs. However，challenges arise during the development stage of high-cycle huff and puff，including poor boundary physical properties，limited regional conventional huff and puff effectiveness，and usability difficulties. Supercritical carbon dioxide （SC-CO₂）has the characteristics of low viscosity，high density，and strong solubility. In order to reveal the huff and puff effect of SC-CO₂，the CO₂ huff and puff test was carried out on the core after SC-CO₂ immersion treatment. The influence of the huff and puff period，the shut-in time，and the injection pressure on the enhanced oil recovery（EOR）of SC-CO₂ was analyzed. The shale before and after the huff and puff process was scanned using low-field nuclear magnetic resonance technology to analyze the distribution and extraction of oil from the shale matrix pores. The results show that the cumulative recovery of the shale samples after SC-CO₂ immersion treatment increases with the increase in huff and puff cycles，while the single-cycle recovery decreases with the increase in huff and puff cycles. The core permeability after immersion increases by 1-2 orders of magnitude，and the porosity increases by 3-4 times；the shale surface becomes more CO₂-absorbent. The extraction capacity of SC-CO₂ can be increased by extending the shut-in from 6 hours to 24 hours，resulting in an approximately 10% increase in the recovery. The cumulative recovery and the single-cycle recovery of shale increase with the rise in injection pressure. The recovery can increase by 8%-17% When the pressure increases from 6 MPa to 15 MPa. The saturated oil in shale primarily exists in micropores and mesopores in the shale matrix，and the maximum amount of oil is produced within the first cycle of huff and puff.

Abstract:To address the challenges of non-uniform fracture propagation，low fracture prediction accuracy，and low cumulative oil production in shale oil well factory-mode fracturing，dimensionality reduction，entropy，and grey relational analysis methods were applied to establish a quantitative evaluation methodology for geo-engineering dual sweet spots. A competitive propagation mechanism for multiple fractures in well factory mode was proposed. The Monte Carlo method was applied to stochastically sample parameters such as staging/clustering，fracturing sequence，perforation design，and pumping schedule. Coupled with dual sweet-spot characterization and four-dimensional in-situ stress，a multi-parameter coupling approach was used to compute fracture parameters. The finite volume method was applied to simulate and predict various development indicators，and the optimal combination of fracturing parameters was selected. The results indicate that the geo-engineering dual sweet-spot value for high-quality reservoirs is greater than 0.79；the four-dimensional in-situ stress field reveals stress shadowing effects among fractures，clusters，stages，and wells；microseismic monitoring confirms that the numerical model based on the competitive multi-fracture propagation mechanism predicts fracture parameters with an average relative error of 9.3%，which is 10.2 percentage points lower than that of commercial software on average；the staged cumulative oil production from the multi-parameter coupled unconventional fracturing is on average 13.0 percentage points higher than that from conventional fracturing，demonstrating favorable application performance.

Abstract:In-fracture temporary plugging fracturing technology is one of the essential stimulation measures to realize the efficient development of shale gas reservoirs. The selection of temporary plugging construction parameters is very important to achieve efficient plugging. This paper conducted an in-depth analysis of the research status of in-fracture temporary plugging fracturing technology to clarify its future development requirements and provide new ideas and methods for the efficient development of shale gas. This paper reviewed the development history of in-fracture temporary plugging fracturing technology and summarized its technical mechanism and the monitoring technology of the temporary plugging effect through literature research and analysis. The paper compared the method characteristics and evaluation indexes of in-fracture migration-plugging experiments for temporary plugging agents，numerical simulation，and temporary plugging fracture propagation simulation in optimizing temporary plugging construction parameters. The results show that optimizing the temporary plugging construction parameters can achieve efficient plugging and promote fracture propagation，thereby reducing costs and increasing efficiency. However，current optimization technologies find it difficult to achieve high-precision simulations under high-pressure and high-temperature conditions. For laboratory experimental methods，test conditions are often oversimplified into idealized states，neglecting the complex and variable factors under actual formation conditions. Additionally，experimental setups commonly suffer from limitations such as low pressure-bearing capacity and restricted displacement ranges，which collectively constrain the accuracy of experiments. In terms of numerical simulation approaches，most models are predominantly based on simplified frameworks that lack adaptive algorithms for calculating plugging locations and evaluating sealing capacity. Furthermore，critical factors such as the roughness of fracture walls and fluid loss effects are often neglected，making the simulation results inadequate in accurately reflecting the actual plugging processes. To obtain the optimal temporary plugging construction parameters，it is recommended to improve the experimental device，deepen the understanding of microscopic mechanisms，and enhance the development of a precise multi-factor model to replicate the temporary plugging fracturing effect under the real fracture environment.

Abstract:Shengli Oilfield is an important oil production and supply base in China，and its main oil reservoirs have generally entered the stage of ultra-high watercut and high recovery，making high-temperature and high-salinity reservoirs the replacement development battlefield. However，due to the constraints of high formation temperature，high salinity of formation water，heavy oil， and scattered distribution of remaining oil， traditional chemical flooding technology has insufficient adaptability in high-temperature and high-salinity reservoirs，facing the bottlenecks of improving economic benefits and recovery. In response to this challenge，researchers from Shengli Oilfield，after over 30 years of theoretical innovation and technological breakthroughs，have developed a theoretical system that includes polymer flooding，additive synergy of polymer，and additive synergy of oil displacement agents，and a technical series of polymer flooding，alkali-free binary composite flooding，and heterogeneous composite flooding. These innovations have successfully overcome the challenge of significantly enhancing oil recovery in reservoirs characterized by formation temperatures of 85 °C，formation water salinity of 30 000 mg/L，and subsurface crude oil viscosity of 2 000 mPa·s. As of June 2025，chemical flooding in high-temperature and high-salinity reservoirs of Shengli Oilfield has reached a produced geological reserve of 6.7 × 10⁸ t and a cumulative oil production of 8 235 × 10⁴ t，with a recovery increase of 9.9 percent points，up to 52.7%. Chemical flooding technology for high-temperature and high-salinity reservoirs is a key guarantee for the sustained，stable production and high-quality development of Shengli Oilfield. The practice of Shengli Oilfield has shown that original innovation is the driving force for technological breakthroughs；integrated innovation is an important means of technological upgrading；iterative innovation is the catalyst for sustainable technological development，and technological synergy is the inevitable trend for mature oilfields to significantly improve recovery rates. With the increasingly stringent conditions of high-temperature and high-salinity reservoirs，it is necessary to develop a theory of multi-dimensional synergistic enhanced oil recovery in the future，tackle new technologies for multi-dimensional synergistic enhanced oil recovery，and provide support for the sustained and stable production of chemical flooding in high-temperature and high-salinity reservoirs.

Abstract:The heavy oil resources is relatively rich in China，and the development mode is mainly thermal recovery with high energy consumption and high emissions，which emits more than 1 600 × 10⁴ tons of CO₂ annually. With the proposal of carbon peaking and carbon neutrality goals，the quality improvement and efficiency enhancement of heavy oil resources development，as well as energy saving and emission reduction，have become one of the research hotspots in the energy field in China. In this paper，the application status of four conventional thermal recovery technologies was reviewed，in which the dominant steam huff and puff has been in the late stage of development and needs to be converted in terms of the development mode；the steam drive，SAGD，and fire drive technologies still have a lot of problems，which affects the promotion and application of these technologies. Under the background of carbon peaking and carbon neutrality，non-condensate gas-assisted steam thermal recovery and efficiency enhancement technologies，chemical-assisted steam thermal recovery and efficiency enhancement technologies，drive-drain composite enhancement thermal recovery technologies，in-situ catalytic reforming hydrothermal cracking technology for heavy oil reservoirs，CO₂ fracturing and huff and puff mining for low-permeability heavy oil reservoirs，and gas-chemistry composite cold recovery technologies for ordinary heavy oil reservoirs were analyzed. The recovery enhancement mechanism and research application were described，and by synthesizing Chinese and international experience and development status，the study proposed the future direction and development trend of the research and development. The study concludes that under the carbon peaking and carbon neutrality，it is necessary to improve the efficiency of the whole process，optimize the energy consumption structure of oilfields，vigorously develop low-carbon thermal recovery technology，promote the transition from thermal to cold recovery process，and vigorously develop high-efficiency cold recovery technology and other technologies and means，so as to realize the quality improvement and efficiency enhancement of difficult-to-recover heavy oil reservoirs，as well as energy saving and emission reduction.

Abstract:There are short plateau periods of water-cut valley，low production and low efficiency in some wells，and limited enhanced oil recovery when chemical flooding is used to enhance oil recovery in mature oilfields developed by water injection. To address this issue，the high-permeability oil reservoirs of the five sand groups of the Third Member of the Dongying Formation （Ed₃）were taken as the research objects in the Second Block of Shengtuo Oilfield，and physical simulation experiments on the binary composite flooding and the binary composite flooding（agent）and well pattern infilling（pattern）were carried out. Research indicates that the synergistic effect of polymer and surfactant improves the mobility ratio and reduces oil-water interfacial tension during binary composite flooding，leading to a 40.0% decrease in water cut and an estimated ultimate recovery of 51.0%. By infilling well pattern during binary composite flooding，the water cut is further reduced by 4.0%，and the estimated ultimate recovery increases by an additional 8.2%. The binary composite flooding system and well pattern infilling exhibit strong synergy （agent-pattern synergy）. The binary flooding system cultivates，develops，and expands enriched residual oil zones（oil walls），achieving secondary enrichment of residual oil. Well pattern infilling enhances reserve control，mobilizes oil in relatively lowpermeability zones and inter-well residual oil，and further expands the sweep area by 17.1%.

Abstract:Conventional water flooding is a fundamental technology in oilfield development. However，in the late high water-cut stage，reservoir heterogeneity tends to induce the formation of preferential flow paths，leading to ineffective circulation of injected water and thereby constraining further improvement in oil recovery. To overcome this technical bottleneck，research on flow control based on the dynamic plugging mechanism of nanobubbles was conducted. Core flooding experiments demonstrate that nanobubble water exhibits a significant plugging capability in reservoirs with permeability ranging from 10.12 × 10^-3 to 100.30 × 10^-3 μm²，with a resistance factor of 1.33-1.51 and a residual resistance factor of 1.18-1.38. Furthermore，large-scale micromodel displacement experiments visually reveal the enhanced oil recovery （EOR） mechanism：Nanobubbles selectively plug high-permeability channels，effectively diverting flow to unswept zones，which increases the swept volume by 28.6% and enhances the recovery by 20 percentage points. Based on these findings，this study innovatively puts forward the“three-zone pore-throat adaptability concept，”identifying the optimal plugging efficiency within a bubble-to-pore-throat diameter ratio of 0.1-0.3. The engineering effectiveness of this technology was validated in a field trial in the W39 well group in Shengli Oilfield. Following the continuous injection of 10 800 m³ of nanobubble water（average diameter：550 nm；concentration：>4.0 ×10⁸ bubbles/mL；preparation cost：0.5 RMB/m³），the injection pressure increases by 2.4 MPa，while the daily oil production of the mainline well rises by 17.6%，and its water cut decreases by 4.1 percentage points.

Abstract:With the growing demand for petroleum resources and the increasing difficulty of reservoir development，the need for enhanced oil recovery（EOR）has become more urgent. Thanks to their unique advantages，such as small size，large specific surface area，and strong environmental compatibility，nanoparticles （NPs） have attracted extensive attention in tertiary oil displacement，yet their deep-seated microscopic mechanisms of oil displacement still require further investigation. Molecular dynamics（MD），an advanced microscopic simulation technique，has become an important tool in reservoir-development research. This paper systematically reviewed key concepts in MD simulations，including equilibrium and non-equilibrium molecular dynamics，force fields，ensemble theory，and boundary conditions，and it discussed the application of commonly used NPs such as TiO₂，SiO₂，and carbon nanotubes（CNTs）in improving oil recovery. Microscopic mechanisms of NPs-assisted oil displacement were analyzed，including reduction of oil and water interfacial tension（IFT），decrease of crude oil viscosity，improvement of the oil and water mobility ratio，and wettability alteration，as well as auxiliary mechanisms such as enhanced foam stability and improved polymer solution rheology. Future directions for MD-based NPs-assisted oil displacement research were outlined：designing simpler and greener NP synthesis/modification schemes via MD，combining MD simulations with laboratory experiments to study the effect of NPs on displacement efficiency，and integrating quantum mechanics（QM）to increase simulation accuracy.

Abstract:Under the global carbon neutrality mandate，the integrated innovation of unconventional oil and gas reservoir development with carbon capture，utilization，and storage（CCUS）technology has emerged as a critical pathway to address the dual challenges of energy security and environmental sustainability. This paper aims to systematically review and evaluate the mechanisms，current applications，and technical bottlenecks of CO₂-enhanced oil recovery （CO₂-EOR） technologies in the development of unconventional oil and gas reservoirs. From the perspective of the full CCUS industrial chain，it proposed breakthrough directions for the future large-scale integration of these technologies and further explored their dual value in enhancing oil and gas recovery and achieving carbon neutrality goals. Unconventional oil and gas reservoirs，characterized by low permeability，complex pore structures，and discontinuous accumulation，present significant economic and technical challenges for conventional extraction methods. Research indicates that，by virtue of its unique supercritical physicochemical properties，CO₂ can significantly improve reservoir development performance through a variety of EOR technologies，such as cyclic huff-and-puff，displacement，fracturing，heat exchange，and CO₂-assisted imbibition. The interfacial interactions among CO₂，crude oil，formation water，and reservoir rocks are the core controlling factors affecting displacement efficiency，which therefore necessitate precise regulation in conjunction with reservoir heterogeneity as well as temperature and pressure conditions. Current implementation of CO₂-EOR remains constrained by several factors，including uneven distribution of CO₂ sources，high transportation costs，strong reservoir heterogeneity，and underdeveloped CCUS industrial infrastructure. Looking forward from a full industrial chain perspective，advancements are urgently needed in high-efficiency and low-energy CO₂ capture technologies，optimization of flooding and storage parameters，and the establishment of carbon market mechanisms complemented by supportive policy frameworks. These steps are essential to realize a closed-loop“capture，flooding，and storage”industrial chain. CO₂-EOR technology offers a dual advantage by enabling the efficient development of unconventional oil and gas resources while simultaneously reducing carbon emissions. This integrated approach provides substantial value for the ongoing energy transition and supports the global commitment to achieving carbon neutrality. EOR technology offers a dual advantage by enabling the efficient development of unconventional.

Abstract:In the CO₂ flooding process，the optimization of the uniformity degree of the front is crucial for improving the effectiveness of CO₂ flooding. To address the issue of uneven CO₂ flooding front in the reservoirs caused by planar heterogeneity of the reservoir and the influence of injection-production well patterns，a well group model was established to simulate the non-uniform front during the injection-production process. Through an automatic optimization algorithm，a CO₂ flooding injection-production parameter optimization method was developed to achieve control over front uniformity. Using reservoir engineering methods，the reasonable range of injection-production parameters during the optimization process was defined.Parameter optimization applications were studied for three injection schemes in the F142 well group in Shengli Oilfield：continuous gas injection，injection-production coupling，and water-alternating-gas（WAG）injection. The effects of front optimization were evaluated using metrics such as the storage ratio，produced gas-oil ratio（GOR），and oil exchange ratio. The results show that optimizing the uniformity degree of the CO₂ front simultaneously increases the CO₂ storage ratio，reduces the overall produced GOR，and enhances the oil exchange ratio in CO₂ flooding injection-production parameter optimization. For the F142 well group，earlier simultaneous gas breakthrough in production wells is more favorable for oil displacement，while later gas breakthrough is more favorable for CO₂ storage.

Abstract:Tight glutenite reservoirs are generally characterized by low porosity，low permeability，high flow resistance，and poor natural productivity，making effective stimulation methods essential to enhance oil recovery. CO₂ pre-pad fracturing，as an effective stimulation method for enhanced production and gas storage，has attracted increasing attention in recent years，yet standardized modeling and system parameter optimization remain insufficient. To address this issue，based on the characteristics of tight glutenite reservoirs，a flow and fracturing model for CO₂ pre-pad fracturing was developed. By using a combined approach of theoretical analysis and numerical simulation，a systematic study was conducted on fracture propagation patterns，hydrocarbon displacement characteristics，and stimulation performance under different injection conditions. This study employed the embedded discrete fracture model（EDFM）and CO₂-driven hydrocarbon experiments to analyze the influence of key parameters on stimulation performance，such as injection volume，rate，and shut-in time. The results indicate that CO₂ pre-pad fracturing significantly improves reservoir permeability and fracturing fluid recovery，thereby enhancing oil and gas displacement efficiency. The recommended parameters are an injection volume of 200-300 m³ per stage，an injection rate of approximately 8 m³/min，a cluster spacing of 15-20 m，and a shut-in time not exceeding 40 days.

Abstract:To achieve the“carbon peaking and carbon neutrality”goals，carbon capture，utilization，and storage （CCUS）technology plays a key role，among which CO₂ geological storage is an effective means of carbon reduction，mainly utilizing the deep saline aquifer as an important storage site. The injection capacity and storage safety become the two core indicators for evaluating CO₂ storage efficiency during this process. The Jiyang Depression was taken as the target storage area，and the changes in formation pressures and temperatures，CO₂ migration and distribution characteristics，and CO₂ storage capacity after CO₂ injection were evaluated. A CO₂ geological storage model for the deep saline aquifer was established，and nine sets of CO₂ injection schemes were designed to investigate the effects of different injection rates，injection pressures，and injection temperatures on CO₂ migration and distribution characteristics，as well as storage capacity. The results indicate that the injection rate and injection pressure have a significant impact on the injection amount and CO₂ migration and distribution characteristics during CO₂ geological storage，and the impact of the injection pressure is greater，while the impact of the injection temperature is not significant.Increasing the injection rate and injection pressure will increase the total CO₂ injection amount，which is beneficial for improving the storage capacity and increasing the migration distance of the free-phase CO₂ and dissolved-phase CO₂. When 1.4 times the initial formation pressure is applied for CO₂ injection，the maximum CO₂ storage capacity can be achieved. The injection temperature has a significant impact on the formation temperature. Increasing the injection temperature will raise the formation temperature near the injection well. The total CO₂ storage capacity first increases and then decreases with the increase in injection temperature，reaching the maximum when the injection temperature is 52 °C.

Abstract:To address the challenges of mobilizing residual oil and ensuring the stability of CO₂ sequestration in high-water-cut reservoirs，based on CT scans of real sandstone，etching patterns were constructed and used to fabricate glass-etched micromodels.A high-temperature and high-pressure（50 °C，6.0 MPa）visual microfluidic experimental system was then set up. Displacement experiments were conducted sequentially for CO₂-oil and water-oil two-phase systems，as well as for CO₂-water-oil three-phase systems，enabling real-time visualization of multiphase flow processes and quantitative calculation of saturation. The results show that the CO₂-oil two-phase displacement is strongly governed by capillary forces under the same injection rate. Due to the adverse effects of the capillary force threshold difference and viscosity ratio，the displacement front advances in an unstable manner，making it prone to gas channeling. The residual oil saturation is 0.70，and the CO₂ sequestration saturation is 0.30. The water-oil two-phase displacement advances in a piston-like manner. Under the combined effects of water blockage and capillary forces，the residual oil primarily distributes as“H”-shaped columnar slugs，with the saturation decreasing to 0.21. When CO₂ is injected after water flooding，a dual-displacement mechanism of“CO₂ displacing water and water re-displacing oil”is formed. The synergistic action of the wetting barrier from the water film and the spreading of the oil film along the interface effectively suppresses front instability and enhances the mobilization of residual oil，further reducing the residual oil saturation to 0.15 and increasing the CO₂ sequestration saturation to 0.45. The study indicates that the strategy of“water flooding followed by CO₂ injection” simultaneously achieves enhanced oil recovery and increased CO₂ retention，providing valuable insights for optimizing CO₂ injection strategies and improving sequestration safety in high-water-cut reservoirs.

Abstract:Under the“carbon peaking and carbon neutrality”strategy，CO₂ flooding is regarded as a preferred approach to simultaneously enhance oil recovery and achieve geological storage in low-permeability reservoirs，yet its field performance often falls short of expectations. To clarify the spatiotemporal evolution mechanism of the oil-gas miscible zone during CO₂ flooding，physical simulation experiments of long-core CO₂ flooding were conducted and complemented with multi-scale numerical simulations. The study systematically characterized the differential propagation of miscible pressure fronts，phase fronts，and compositional fronts，as well as the dynamic evolution of the miscible zone during CO₂ flooding. Results show that，influenced by hydrocarbon component migration characteristics and multi-contact interactions，the miscible pressure front advances fastest，while the phase front lags behind the compositional front，leading to pronounced temporal and spatial variability in miscible zone distribution. Enhancing miscibility helps suppress the advance of the compositional front and delays the development of CO₂ breakthrough channels. Moreover，injection rate and volume exert significant regulatory effects on front propagation：when the injected CO₂ volume increases from 0.2 PV to 0.6 PV，the phase front extension reaches 68%，effectively broadening the miscible zone. However，excessive injection rates accelerate compositional front migration and aggravate gas channeling risks. Reservoir heterogeneity further complicates miscible zone distribution；when matrix permeability rises from 1.0 × 10^-3 μm² to 15.0 × 10^-3 μm²，the CO₂ phase sweep coefficient increases by 57.9%，whereas higher fracture permeability facilitates preferential compositional front migration through high-permeability pathways，resulting in uneven miscible zone distribution.