Abstract:The Shahejie Formation in the Jiyang Depression develops multiple sets of thick organic-rich shale sequences with different lithofacies and has strong vertical heterogeneity. To clarify the pore-fracture development characteristics of shale reservoirs with different lithofacies and their impacts on reservoir properties，this study focused on the shale intervals of Es₄^U（The Upper Submember of the 4th Member of the Eocene Shahejie Formation）and Es₃^L（The Lower Submember of the 3rd Member of the Eocene Shahejie Formation）in the Dongying Sag of the Jiyang Depression. Test methods including core observation，thin-section identification，whole-rock X-ray diffraction，argon ion polishing，and field-emission scanning electron microscopy（FE-SEM）were used，and the mineralogical and petrological characteristics of shale oil reservoirs were determined. The“high-magnification large-field quantitative analysis methods”combining argon ion polishing and FE-SEM imaging were employed to comparatively analyze reservoir space types and quantitative pore structure characteristics of different lithofacies. Research reveals that the shale minerals are characterized by“high carbonate content，medium feldspar content，and low clay content”. The Es₄^U and Es₃^L in Jiyang Depression develop matrix-type and interbedded-type shale facies. The matrix-type shales primarily consist of carbonate-rich shale facies and mixed shale facies，and the interbedded-type shales consist of sandstone-interbedded shale facies. The deep subsidence zones of the northern steep slopes in the Dongying Sag feature sandstone-interbedded layered calcareous mixed facies，whereas the depocenters exhibit matrix-type laminated or layered carbonate-rich shale facies. The reservoir spaces feature a“five-pore and five-fracture”system comprising intergranular pores，intragranular pores，calcite intercrystalline pores，clay mineral interlayer pores，pyrite intercrystalline pores，along with grain-edge fractures，calcite intercrystalline fractures，structural fractures，bedding fractures，and overpressure fractures，predominantly dominated by nano- and micro-nano pores. Significant differences exist in pore-fracture development characteristics and reservoir properties among different lithofacies. The development of micro-fractures， such as intercrystalline fractures，grain-edge fractures，and bedding fractures，determines the effectiveness of shale reservoir spaces. According to the differences in the connectivity efficiency and development of various micro-fractures，the matrix-type laminated shale exhibits a complex pore-fracture network connectivity pattern composed of bedding fractures，grain-edge fractures，intercrystalline fractures，intergranular pores，and intercrystalline pores（dissolution pores），demonstrating high-efficiency storage spaces. In contrast，layered shales mainly rely on grain-edge fractures for micro-nano pore connectivity，showing relatively poore effective storage capacity.

Abstract:Abstract: The black shale of the Lower Carboniferous Luzhai Formation in the Northern Liucheng Slope of the Guizhong Depression has strong vertical heterogeneity，which seriously restricts the evaluation and fracturing ability of the shale reservoir in the later stage. The isochronal stratigraphic sequence framework of the study area was established based on data from logging，cores，thin section observation，organic carbon test，X-ray diffraction mineralogy measurement，and XRF element scanning.Within the stratigraphic sequence framework，the heterogeneity of the reservoir was studied，and the main factors controlling the heterogeneity were discussed according to the recovered paleoenvironmental information. The results show that three third-order sequences can be identified in the first Member of the Luzhai Formation，and seven quasi-sequences（i.e.，seven layers）can be identified in the first Submember of the first Member of the Luzhai Formation. The distribution of organic carbon content，mineral composition content，and shale lithofacies has strong vertical heterogeneity，and different layers exhibit obvious differences. The high organic carbon content is mainly concentrated in the middle and upper part of layer ① and the bottom of layer ③. Mud-rich siliceous，mixed，and silica-rich calcareous shale lithofacies are mainly developed in the study area. According to the organic carbon content，the mud-rich siliceous shale lithofacies is considered to be the high-quality lithofacies in the study area，which is mainly concentrated in the bottom of layer ③. The heterogeneity of the shale in the first Submember of the first Member of Luzhai Formation is controlled by paleoproductivity，redox conditions，and terrestrial input. High paleoproductivity and the anoxic sedimentary environment are conducive to the accumulation and preservation of organic matter in the middle stage of layer ① and the early stage of layer ③. An appropriate amount of terrestrial input can carry the appropriate amount of nutrients and increase the abundance of organic matter，ensuring the development of mud-rich siliceous shale with abundant organic carbon.

Abstract:In view of the insufficient applicability of geophysical characterization methods for sweet spots in shale oil in Niuzhuang Subsag，the core and logging data were used to analyze the physical characteristics of different types of lithofacies based on basic research，and the combinatorial lithofacies models were established for AVO forward analysis，so as to determine the elastic parameters of different lithofacies combinations. The intersection analysis was conducted using the elastic parameters obtained from prestack inversion to explore the spatial distribution of dominant lithofacies combinations. The shale oil and gas resources are rich in the terrestrial rifted lake basin in Jiyang Depression，with developed fractures and great potential for exploration and development.The favorable aspects of fractures for shale oil development are that they can effectively increase the production capacity of shale oil reservoirs，while the unfavorable aspects are that they increase the difficulty of drilling and cause frequent well kicks and lost circulation during drilling，which seriously affects the efficiency of drilling. Therefore，the accurate prediction of fractures has been a major problem in the exploration and development of shale oil in this block. In this paper，the anisotropy of the reflection coefficient of P-wave was theoretically analyzed. Based on the development characteristics and distribution pattern of shale oil fractures in the study area，OVT domain data were used to analyze the sub-azimuth stack and seismic attribute difference，and AVAZ inversion of pre-stack OVT domain seismic data was performed based on P-wave amplitude azimuthal anisotropy fracture prediction technique，so as to predict the fracture azimuth and development strength. The fracture results predicted by the pre-stack anisotropy inversion prediction were compared with actual drilling conditions and imaging logging results，and they were highly reliable，providing effective technical support for subsequent shale oil exploration and development. According to the relationship between the in-situ stress of shale oil reservoirs and the curvature attributes and elastic parameters，Young’s modulus，Poisson’s ratio，and other parameters obtained from pre-stack inversion were combined with the curvature attributes to predict the magnitude and direction of horizontal in-situ stress. Through the above research，the petrophysical and geophysical response characteristics of the sweet spots in Niuzhuang Subsag were clarified，and the geophysical characterization methods for sweet spots were established.These methods were used to comprehensively characterize the favorable target areas of shale oil.

Abstract:The characterization of shale oil-bearing properties and shale oil mobility is an important part of shale geological evaluation. The qualitative and quantitative research on pores and fluids on platforms of different scales is mainly carried out by current analytical methods，and cross-scale in-situ accurate evaluation has not yet been realized. Therefore，the mud shale in Dongying Sag of Jiyang Depression was taken as an example，and fluorescence spectroscopy was used to study hydrocarbon inclusions and crude oil in reservoir pores and determine the mathematical relationship between crude oil density and fluorescenc spectrum. Laser confocal technology was also used to accurately identify the properties of point-line-face-volume microscopic crude oil across scales to determine the occurrence state of crude oil in micrometer-nanometer pores. The experimental results show that the fuorescence spectra of aromatic hydrocarbon，non-hydrocarbon，and asphaltene have obvious differences and have good correspondence with crude oil of different densities. The difference in the fluorescence of crude oil is mainly affected by the degree of oil and gas evolution and little affected by the oil and gas differentiation. With the increase in temperature，the alkane and aromatic hydrocarbon increase，and the non-hydrocarbon and asphaltene decrease. The quality of crude oil changes from light to heavy，and the red-green entropy changes from low to high. The fluorescence intensity changes from strong to weak. It can be seen that the red-green entropy and fluorescence intensity of crude oil can be used to characterize crude oil of different densities. In the fourth member of Shahejie Formation（Es₄）of Dongying Sag，The crude oil in calcite veins of mud shale is mainly light oil，and the crude oil in mudstone pores is mostly medium to heavy oil. The crude oil in asphalt and organic matter in mud shale is heavy oil and thickened oil. In addition，the continental mud shale samples in Dongying Sag are highly heterogeneous，and the oil-bearing porosity of the samples varies significantly in the vertical and horizontal sections，indicating that oil and gas are mainly enriched in layers in the interlayers with high porosity. Fluorescence spectroscopy and laser confocal technology can be used to effectively characterize the three-dimensional spatial occurrence characteristics of crude oil in adsorbed and free states in the pores of shale reservoirs. The three-dimensional morphology of crude oil in pores of different lithologies of shale reservoirs was observed in multiple section directions. The crude oil in the clay layer is mainly in an adsorbed state and microscopically appears as intermittent diffuse fog spots，and pore diameter is generally less than 75 nm，with heavy oil dominated. The crude oil in the carbonate layer pore is mainly in a free state and microscopically appears as solid oil columnar. The pore diameters are generally larger than 80 nm，with light-medium oil dominated.

Abstract:The Mesozoic buried-hill clastic rock reservoirs in the Chengdao-Zhuanghai area have great exploration potential，but the reservoirs are highly heterogeneous，with few wells available for coring，making it challenging to predict high-quality reservoirs. A training dataset where logging data corresponded to diagenetic facies labels was established through the statistical analysis of core samples，thin sections，and logging data，as well as the petrologic characteristics and diagenetic facies types of the reservoir in this region. Recognition of diagenetic facies of the reservoirs was carried out using active learning and supervised learning techniques，and the development intervals of high-quality reservoirs were predicted. The results indicate that most Mesozoic buried-hill clastic rock reservoirs in the Chengdao-Zhuanghai area are composed of lithic feldspar sandstones，followed by feldspathic lithic sandstone. The main reservoir space is composed of secondary pores，followed by fractures. They can be classified into four diagenetic facies types：strong compaction with moderate-weak dissolution and weak cementation facies（SCF），strong dissolution with strong-moderate compaction and weak cementation facies（SDF），strong cementation with weak compaction and weak dissolution facies（SCF），and transitional facies（TF）. Among them，the diagenetic facies named SDF exhibit the best overall reservoir properties，followed by TF. The machine learning results indicate that the active learning technique exhibits strong inter-well generalization capabilities，high prediction accuracy，and enhanced human-machine interactive learning abilities compared to random forest supervised classification models. The TF with moderate preferred physical properties is the primary diagenetic facies type in the Mesozoic buried-hill clastic rock reservoirs in the Chengdao-Zhuanghai area，followed by SDF. Differential dissolution is the primary controlling factor for Mesozoic high-quality reservoirs in the Chengdao-Zhuanghai area.

Abstract:Multiple marginal subsags in the northern South China Sea Basin have been confirmed as subsags with rich hydrocarbon，but unclear favorable reservoir controlling factors have hindered their efficient development. By taking the Paleogene deep reservoir（Wenchang Formation and Enping Formation）in the northern area of Huizhou Sag（the northern Huizhou Sag）in the Pearl River Mouth Basin as an example，the reservoir characteristics and controlling factors were analyzed by using the data of drilling，logging，casting thin section，scanning electron microscopy，and physical property analysis. The results show that there are obvious differences in reservoir characteristics between the eastern and western areas of the northern Huizhou Sag. The rock types of the east area are mainly lithic sandstone and feldspar lithic sandstone，and the favorable reservoir space is mainly secondary solution pores. The reservoir rock types in the western area are lithic feldspar sandstone and feldspar quartz sandstone，and the fa‐vorable reservoir space is mainly residual primary pores. The eastern area is dominated by reservoirs with low porosity，medium porosity，and low and ultra-low permeability，while the western area is dominated by reservoirs with low porosity and low and ultra-low permeability. It is affected by the variability of faults and the spatiotemporal evolution of source-sink systems，and the differences in reservoir parent material，reservoir maturity，and diagenesis are significant. In the eastern area，proximal transport occurs. The sediments are rich in feldspar，and the coupling of hydrocarbon generation and acid discharge with the fracture system in the later stage leads to large-scale dissolution and the development of secondary solution pores. The transfer belt in the western area has a strong sand transport capacity and high rigid minerals，which effectively slows down compaction and facilitates the retention of primary pores. Early oil and gas charging and overpressure can also improve the reservoir’s physical properties.Finally，two high-quality reservoir development models，“primary porosity”and“solution porosity”，are established.

Abstract:To explore the influence of differential diagenesis on the oil bearing properties of tight sandstone reservoirs，Chang 8 reser‐voirs with ultra-low porosity and ultra-low permeability in the Qingcheng area were used as an example. Based on the statistical cast thin section data of 337 samples and the scanning electron microscope（SEM）and high-pressure mercury injection data of 10 samples，the porosity evolution characteristics of different types of reservoirs were calculated，and the influence of differential diagen‐esis on the oil bearing properties of the reservoirs was analyzed. The research results show that the Chang 8 tight sandstone reservoirs in the Qingcheng area are mainly composed of lithic feldspar sandstone and feldspathic litharenite，with dissolution pores and residual intergranular pores developed. According to the characteristics of brittle mineral content，soft particle content，porosity，and calcare‐ous cement content，the Chang 8 reservoirs can be divided into three types：high-porosity sandstone（Type Ⅰ），high-porosity cal‐careous sandstone（Type Ⅱ），and rich soft particle sandstone（Type Ⅲ）. Type Ⅰ reservoirs are mostly underwater distributary chan‐nel sand bodies and have the strongest compaction effect in the early diagenesis stage，with an average compaction porosity reduction rate of 60.0%，but they have a strong dissolution effect in the later stage，with an average dissolution porosity increase rate of 11.8%，weak cementation effect，and an average cementation porosity reduction rate of 27%. The average remaining porosity value is 9.5%.Type Ⅱ reservoirs are mostly underwater distributary channel sand bodies，and their estuarine bar sand body is slightly developed compared with Type Ⅰ reservoirs. The early calcium cementation of Type Ⅱ reservoirs is strong，and the compaction is relatively weak. The average compaction porosity reduction rate is 56.8%，and the average cementation porosity reduction rate is 34.1%；the av‐erage dissolution porosity increase rate is 11.5%，and the average remaining porosity is 7.9%. Type III reservoirs are more likely to de‐velop in sand bodies along the side of underwater distributary channels. The early compaction of Type II reservoirs is not strong，with an average compaction porosity reduction rate of 49.3%，but the later dissolution is weak，with an average dissolution porosity in‐crease rate of 10.5%. The late cementation is strong，with an average cementation porosity reduction rate of 43.2%. The final porosity is the lowest，with an average value of 6.9%. The pore throat radius of Type Ⅰ and Type Ⅱ reservoirs is concentrated in 0.1-1 μm，and the pore throat connectivity is good. The pore throat heterogeneity is weak，and the oil bearing property is good. The distribution of pore throat in Type III reservoirs is not concentrated，and the connectivity is poor；the pore throat heterogeneity is strong，and the oil bearing property is poor. In the Late Early Cretaceous，oil and gas migrated and accumulated on a large scale，and the three types of reservoirs were not densified. With the further densification of reservoirs in the middle diagenesis A stage，the differences in physical properties and pore throat structure of the three types of reservoirs are enhanced，affecting the adjustment distribution of oil and gas in the later stage. The oil bearing property of Chang 8₂ is poorer than that of Chang 8₁ because the Type II reservoirs in Chang 8₂ are more developed，and strong carbonate cementation reduces the connectivity of pore throats，which is not conducive to oil and gas charging.

Abstract:Chemical flooding is an essential means to enhance oil recovery，and the scientific application boundaries of flooding systems and the evaluation methods for resource potential play a crucial role in the sustainable development of chemical flooding resources. For a long time，evaluation methods for chemical flooding potential，both in China and abroad，have generally focused on key indicators such as reservoir characteristics and formation fluid properties；however，they have not been associated with the applicable boundaries of flooding systems. With the performance improvement of flooding systems，the application boundaries of chemical flooding technology have expanded，making traditional evaluation methods for resource potential increasingly limited in terms of pertinence，operability，and foresight when facing a wider range of reservoir types. To overcome this key issue，this article systematically reviewed the evaluation methods for chemical flooding resource potential in China and abroad，focusing on the new oil displacement agents and systems developed by Shengli Oilfield through continuous research and development in recent years，as well as the expansion of applicable boundaries in different dimensions. Among them，the temperature boundary has been expanded to 95 ° C；the mineralization boundary has been expanded to 5 × 10⁴ mg/L；the calcium and magnesium ion content has been expanded to 1 500 mg/L；the crude oil viscosity boundary has been expanded to 1 000 mPa·s，and the permeability boundary has been expanded to below 10 × 10^-3 μm². A new evaluation method for resource potential related to the adaptability of chemical flooding systems has been established，dividing Shengli chemical flooding resources into five categories：reservoirs after polymer flooding，offshore reservoirs，low-efficiency ordinary heavy oil reservoirs，high-temperature and high-salinity reservoirs，and medium- and low-permeability reservoirs. At the same time，an intuitive reference chart for the applicability of chemical flooding systems was constructed to guide the development and practice of different types of chemical flooding resources more scientifically and efficiently. As a result，the chemical flooding reserves have increased by more than 10 × 10⁸ t.

Abstract:To enhance the economic and environmental benefits of continental shale oil reservoir exploitation，this study，based on the whole life-cycle theory，built a green exploitation optimization model for economic and environmental benefits based on carbon dioxide capture，utilization，and storage-enhanced oil recovery（CCUS-EOR）technology. This model consists of four parts：the environmental benefit accounting model，economic benefit accounting model，comprehensive benefit accounting and sensitivity analysis，and optimization schemes. The environmental benefit accounting covers the monetization of emissions of CO₂，PM，SO₂，etc. The economic benefit accounting uses the cash flow method to evaluate operational costs. Local sensitivity analysis identifies key factors for targeted optimization schemes. The research combined qualitative and quantitative methods with scenario analysis. It designed various scenarios from recovery rate，carbon price，management，and policy perspectives. By comparing economic and environmental benefits across different schemes，the optimal exploitation strategy was determined. The model results show that CCUS-EOR technology significantly improves environmental benefits over economic ones. In a studied oilfield，the environmental benefit per ton of shale oil is -148.44 yuan，and the economic benefit is 239.56 yuan；the comprehensive benefit is 91.12 yuan. Sensitivity analysis shows that oil production revenue is the most impactful factor，followed by material costs and hazardous waste treatment. Some optimization schemes from the sensitivity analysis show significant effects. The model is highly applicable to oil and gas field development，such as CCUS-EOR+unconventional reservoirs and chemical flooding + low-permeability oil reservoirs.

Abstract:To address the needs of reservoir development with complex geological conditions in Shengli Oilfield，this paper systematically elaborates on the independent R&D process，core technologies，and application achievements of reservoir numerical simulation software. Through years of dedicated research，Shengli Oilfield has developed a series of proprietary software，including a 3D three-phase black oil model，as well as compositional numerical simulation software for chemical flooding and CO₂ flooding. These innovations have effectively resolved key technical challenges such as characterizing flow laws at ultra-high water-cut stages and describing the oil displacement mechanisms of novel chemical flooding systems. The software demonstrates significant technical advantages in simulating differentiated oil-water flow at ultra-high water-cut stages and nonlinear flow in low-permeability reservoirs. Furthermore，by establishing efficient mathematical model discretization and solution algorithms，such as decoupling sequencing，alternating direction，adaptive grids，and algebraic multigrid methods，the software achieves rapid solutions for reservoir models with millions to tens of millions of grid cells，largely meeting the needs of field development planning. However，compared to international commercial reservoir simulation software，Shengli Oilfield’s self-developed numerical reservoir simulation software still exhibits gaps in functional completeness，large-scale parallel computing efficiency，and the integration of emerging technologies. To bridge these gaps，further advancements are required in core reservoir simulation technologies，including new development paradigms for integrating modeling and simulation as well as combining multiple recovery methods；CPU + GPU large-scale parallel computing；the integration and application of emerging technologies based on big data and artificial intelligence.Through continuous technological innovation and functional optimization，Shengli Oilfield’s reservoir numerical simulation software will strengthen its competitiveness，providing robust support for the efficient development of complex reservoirs.

Abstract:Reservoir’s static pressure is an essential basic data in the development and research of oil and gas fields. Its acquisition conditions are strict，and the sample number is extremely small. Static pressures are estimated with empirical methods based on dynamic pressure data during the production process；however，data errors are significant. To address the above issues，a static pressure prediction method for CO₂ flooding oil reservoirs based on the time series partitioning Transformer model was proposed，utilizing deep learning theory. Model parameters were selected based on correlation analysis，and iterative interpolation was used to fill in samples to construct a static pressure prediction sample set. According to the principle of channel independence，the multivariate time series was divided into univariate time series，and a time series partitioning mechanism was introduced to divide the time series into subsequential blocks to capture local features. Based on the Transformer model architecture，a multi-head self-attention mechanism was utilized to extract features，and a self-supervised learning mechanism was employed to enhance the ability to capture complex dynamic characteristics，achieving the prediction of reservoirs’static pressure. The research results indicate that the proposed model can accurately predict the static pressures at the middle of the oil reservoir of each well in the active well group，significantly improving prediction accuracy.

Abstract:In-situ heating and upgrading technology is a key method to improve the recovery efficiency of shale oil and gas with medium-low maturity. It aims to simulate and optimize the heat transfer effects of underground shales during the in-situ heating and upgrading process to explore the feasibility of in-situ upgrading to accelerate shale ripening and improve the recovery efficiency of shale oil and gas. Therefore，the physical and chemical characteristics of shale samples were tested to determine the basic phase composition，thermal response characteristics，porosity，and other key parameters of characteristic shales. A three-dimensional fracture-network heat transfer model was established. Combined with the finite element fluid simulation technology，the heat transfer law of the fracture-network was systematically simulated and analyzed，and the influence law of fracturing，gas injection volume，gas injection temperature，rock layer heating methods，and insulation on the heating effect of in-situ upgrading was explored. The results show that the thermal loss of the heating gas before entering the fractures can be significantly reduced by improving the insulation effect of the wellbore，thereby increasing the heating efficiency. Compared with unfractured wellbores，the presence of fractures significantly increases the heating efficiency by up to 14 times and nearly quadruples the area of the heat-affected zone. The research also reveals that increasing the gas injection volume and temperature could make a gradient decrease in the heating efficiency of the fractures at the front end of the wellbore，which helps the heating gas spread to more distant areas. This strategy is important for expanding the heat-affected zone. Furthermore，the use of intermittent heating and soaking well strategies can save 53% of the heating gas input compared with continuous heating while keeping the temperature distribution within 5% of the heat-affected zone. By optimizing the heating strategy and improving the insulation effect，the recovery efficiency of shale oil and gas can be increased，which is expected to promote the application of in-situ upgrading technology in the recovery of unconventional oil and gas.

Abstract:In the simulation experiments of dry gas injection in shale，the use of degassed crude oil（the dead oil）in saturated cores and the fracture simplification of cores often lead to discrepancies between experimental simulation and actual field results. A new experimental method for dry gas injection in shale was established by improving the sealing system of the conventional core holder.Hydraulic fracturing was carried out under continued pressure after saturating the core with formation crude oil（the live oil）. Based on the formation of fracture networks，huff and puff experiments of dry gas in the cores were conducted. The huff and puff effect of the live oil and dead oil was compared，and the potential of dry gas injection to enhance shale oil recovery was objectively evaluated. The experimental results show that the cumulative recovery rate of the live oil after five rounds of huff and puff is 49.4%，much higher than that of dead oil at 30.1%. The recovery rate of the live oil in each cycle shows a decreasing trend. In the first three rounds of injection，the gas mainly enhances the crude oil production in the matrix near the fractures through dissolution and expansion，and the cumulative recovery rate of the first three rounds accounts for 82.4% of the total recovery rate. In the subsequent cycles，the gas mainly enhances the production of crude oil in the matrix far from the fractures through diffusion，and the recovery rate of each cycle is relatively low. The area affected by the injected gas can be increased by reducing the interfacial tension between oil and gas and increasing the diffusion coefficient. Using dead oil would significantly underestimate the potential for enhanced oil recovery and gas storage in shale reservoirs.

Abstract:In fractured volatile oil reservoirs，the fractures are well developed. The conventional water flooding development shows the production characteristics of ineffective water injection. Consequently，there is an urgent need to explore methods to enhance the oil recovery of volatile oil reservoirs. Given the richness of associated gas resources in volatile oil reservoirs，the associated gas flooding has emerged as an economically viable and effective strategy for enhancing oil recovery. To clarify the microscopic pore-throat mobilizing characteristics and feasibility of associated gas flooding in fractured volatile oil reservoirs，this study employed in-situ nuclear magnetic resonance（NMR）displacement imaging technology to investigate pore-throat mobilization characteristics under varying reservoir types，fracture orientations，and gas injection rates. Finally，the numerical simulation was employed to predict the associated gas flooding development effect of Well Group K-001 in K Oilfield. Results reveal that water flooding primarily mobilizes oil in microscale micropores（1-10 μm）and microscale macropores（>10 μm），achieving maximum recovery of 37.2%，with remaining oil predominantly retained in submicron pores （0.1-1 μm） and microscale micropores.Associated gas flooding enhances oil recovery by improving mobilization efficiency in microscale micropores（4%）and submicron pores（9%）. NMR imaging demonstrates that volatile oil near the outlet in matrix cores is mobilized under the dual effects of dissolved gas and associated gas，while oil near fractures in fractured cores is primarily mobilized via localized pressure differences between fractures and the matrix. Fracture orientation and gas injection rate are critical factors influencing recovery. Increasing the fracture width or injection rate could reduce mobilization efficiency in microscale pores and submicron pores，leading to an approximately 2% decline in recovery. Numerical simulations of Well Group K-001 confirm that associated gas flooding further enhances recovery after waterflooding，with water-alternating-gas injection achieving the highest incremental recovery（10%）. This study validates the feasibility of associated gas flooding for enhancing oil recovery in volatile oil reservoirs from an oil reservoir perspective.

Abstract:The proven reserves of fractured-vuggy reservoirs in Tahe Oilfield are large，and the geological conditions featuring high temperature and high salt are more obvious than the sandstone reservoirs in the eastern area. The reservoir space is mainly developed in the forms of karst caves，fractures，dissolved vugs，and so on. The combination relationship and the distribution pattern of different reservoir space in three-dimensional space are diverse，the flow law is complex，the heterogeneity is strong，the energy of edge and bottom water is high，and the distribution of remaining oil is various. It is difficult to enhance oil recovery. Based on the reservoir geological characteristics，a 3D visual model of a typical structure was designed and developed，and the multi-gel joint water plugging experiment was carried out to reveal the adaptability of gel water plugging in different fractured-vuggy reservoirs.The results show that after the gel joint water plugging in different reservoirs，the effects of controlling water and increasing oil are as follows：enhanced oil recoveries are 12% in fracture network reservoirs，10% in crushed zone reservoirs，8% in fractured-vuggy reservoirs，and 5% in karst cave reservoirs，respectively. In addition，the pilot application in the mine field was carried out based on the results of the laboratory experiment. After water plugging in the small-scale well with multiple karst caves，the water cut was reduced from 100% to 30%，and the cumulative oil production was increased by more than 1 000 tons.

Abstract:In low-permeability oil reservoirs，nitrogen flooding is prone to cause gas channeling，resulting in a low recovery.Nitrogen oil-based foam flooding has enhanced energy and remediation advantages to avoid damage to water-sensitive reservoirs and can effectively improve the development efficiency of such oil reservoirs. Therefore，a new type of nitrogen-oil-based foam system was constructed，and related research was carried out. Firstly，the performance of the foam system was evaluated by assessing the interfacial rheology of the foaming agent and the liquid retention rate of the foam. Subsequently，the foam occurrences in porous media were studied to understand its performance in formation. Finally，the microscopic model displacement experiments were conducted to investigate the displacement effects of three oil recovery methods：conventional nitrogen flooding，nitrogen flooding with a foaming agent dissolved in crude oil，and nitrogen oil-based foam flooding. The results show that the nitrogen oil-based foam system composed of 0.7% Span20 and 0.8% FSA-99 has good stability and a relatively high viscoelastic modulus. After 40 minutes，the liquid retention rate of the foam can still reach 50.1%. After 1.5 h at 80 °C，more than 40% of the bubbles in the porous medium were still smaller than 200 μm，indicating that the oil-based foam of the compound system has good temperature resistance. By comparing three different methods of oil recovery，it is found that when nitrogen gas comes into contact with crude oil containing foaming agents，an oil-based foam is produced. This foam can seal the gas channel after gas channeling occurs，increasing the sweep efficiency and enhancing the recovery. Compared with the first two oil recovery methods，nitrogen oil-based foam flooding has a better effect，which can inhibit the formation of channels for gas migration in the early stage of displacement and use the crude oil in the non-mainline area，with the final recovery reaching 69.95%.

Abstract:The superposition relationships between sand bodies in glutenite reservoirs located in steep slope zones are complex，and the reservoir properties and connectivity vary significantly among different facies zones，making it challenging to determine the rational well spacings for CO₂ miscible flooding. The single connected sand body was identified based on the geological characteristics.A reservoir numerical simulation model considering the random distribution of connected sand bodies was established to reveal the development scale，superposition relationship，and distribution density characteristics of connected sand bodies in different facies zones. The relationship between injection-production correspondence ratio and well spacing density was studied in different facies zones，and a new model of the relationship between recovery and well spacing density was constructed in combination with the Shelkachev formula. Furthermore，the net income future value method was employed to optimize and establish a basic chart for rational well spacings for CO₂ miscible flooding. A composite superposition coefficient of connected sand bodies was introduced to further address the impact of the complex superposition relationships between connected sand bodies in glutenite reservoirs. Based on a randomly selected geological model and the basic chart of rational well spacings，the correction coefficient of well spacing was calculated for different composite superposition coefficients：the ratio of rational well spacing to basic rational well spacing. The study shows that the correction coefficient of rational well spacings is in a quadratic relationship with the composite superposition coefficient. A correction chart of superposition relationships between connected sand bodies is established，and a rationale well spacing optimization method with different permeability and crude oil viscosity is proposed. Two well groups of CO₂ miscible flooding pilots are designed in the study area. The injection-production well spacing ranges from 310 m to 400 m according to the differentiated superposition relationships between connected sand bodies in different facies zones. Two rounds of trial injection have been carried out successively，effectively delaying the decline of glutenite reservoirs in the early stage of development. The annual decline rate of adjacent blocks is over 30% in the initial stage，and the pilot well group achieves continuous stable production for more than 30 months. The well spacing designs in the pilots are rational，and effective displacement is established.