Abstract:The lower assemblages（the Carboniferous to the Triassic）in the central Junggar Basin have a large burial depth and a low degree of exploration，and the exploration fields and breakthrough directions of oil and gas are not clear. Based on the analysis of the discovered oil and gas reservoirs，the deep geology structure of the basin was clarified，as well as the sedimentary and the eservoir formation conditions，and the types of oil and gas reservoirs and hydrocarbon accumulation conditions in key areas were systematically dissected. Moreover，the favorable exploration fields of the lower assemblages in the central Junggar Basin were predicted，and the deep and ultra-deep oil and gas exploration in the basin was guided. The research results show that many types of reservoir rocks，such as volcanic rocks，conglomerates，and fine sandstones，are developed in the lower assemblages of the central Junggar Basin，and the reservoir’s physical properties are quite different. Under the overall compact background，there are still high-quality reservoirs with relatively good physical properties，and sweet spots are developed in different layers. Still，the development mechanisms of effective reservoirs are different. Based on the source and storage allocation relationships，four types of oil and gas reservoir combinations are formed in the lower assemblages of the central Junggar Basin，which are adjacent-source volcanic buried-hill reservoirs，intra-source and near-source stratigraphic overlap reservoirs in the Fengcheng Formation-Upper Wuerhe Formation，above-source stratigraphic-lithologic reservoirs in the Baikouquan Formation，and far-source lithologic reservoirs in the middle-upper Triassic Formation. The far-source lithologic reservoirs in the middle-upper Triassic Formation are relatively shallow in burial depth，highly enriched，and productive，making them an important field for rapidly increasing reserves and production. Furthermore，the adjacent-source volcanic buried-hill reservoirs and intra-source and near-source stratigraphic overlap reservoirs in the Fengcheng Formation-Upper Wuerhe Formation have large beneficial areas and abundant resources，which are the key fields for seeking major breakthroughs and significant discoveries. Through the comprehensive consideration of the key breakthrough areas for multi-layer exploration，which takes advantage of large-scale resources，multiple layers，and shallow burial，three Class I potential areas（the west and east slopes of Well Pen1 West Sag and the Dongdaohaizi Sag）and two Class II potential areas（the west slope of Fukang Sag and the northeast slope of Shawan Sag）have been selected from the lower assemblage in the central Junggar Basin.

Abstract:The utilization of pore space in aquifers for compressed air energy storage（CAESA）has the advantages of great potential，wide distribution，and flexible layout，especially in oil-bearing aquifers where better implementation conditions are often available. The core of the CAESA system is the sealing performance of the energy storage space. A large amount of research has been conducted on similar projects，such as oil and gas reservoir formation，natural gas storage facilities，and CO₂ geological sequestration，which can serve as useful references. However，research and practical applications on the sealing performance of compressed air energy storage are still very limited. Firstly，the main characteristics of the energy storage system were analyzed，and the key components of the storage system were standardized and named. Based on this，the key issues of energy storage space and its sealing performance were further identified. The concept of trap was introduced into the compressed air energy storage system，and for the first time，the storage system was clarified into five types based on this concept. By employing the method of engineering analogy，a detailed comparative study was conducted on the requirements for sealing natural oil and gas reservoir formations，natural gas storage in an aquifer，CO₂ storage in a saline layer，and CAESA from 14 aspects. The differences in sealing requirements for compressed air storage were identified，and the key research areas for sealing of compressed air storage were clarified. In order to provide a reference for the study of sealing，a systematic review was conducted to analyze the current research status and shortcomings of related fields on the sealing mechanisms of caprock and faults and the evaluation methods. It was pointed out that compressed air storage requires a more refined understanding of sealing to support the economic goals of the storage. It was believed that concise physical meanings，consideration of various main sealing mechanisms and structural sealing effects such as thickness，easy quantification，and physics-based evaluation indicators or methods will be the key research directions. Based on these understandings，it is recommended to measure the sealing ability of the reservoir wall using the sealing potential，and then a sealing potential evaluation framework based on the maximum sealing pressure was proposed.

Abstract:The extensive desorption experiments conducted on shale have promoted research in the fields of shale gas components and carbon isotopes，but the research on identifying gas migration through gas components is still relatively weak. This study focused on the shale in the seventh member of the Triassic Yanchang Formation（Chang 7 shale）in the central Ordos Basin and conducted comparative desorption experiments to explore the gas components and carbon isotopes in the shale by systematically collecting shale samples from different structural areas. In combination with the regional geological background，a detailed analysis of the controlling factors of gas migration was conducted，and the migration patterns of shale gas were clarified，providing a reference for the research on gas migration. The research results show that the organic matter abundance of the Chang 7 shale in the study area is high，and the hydrocarbon generation capacity is strong. The average values of total organic carbon content，free hydrocarbon content，and pyrolysis hydrocarbon content are 4.10%，3.29 mg/g，and 6.43 mg/g，respectively. The volume of desorbed gas is relatively low，with an average value of 1.39 m³/t. Through systematic analysis of the characteristics of the desorbed gas components，it is found that Chang 7 shale gas is oil-type gas，and it is pyrolysis gas originating from kerogen. Based on the strength of the migration process，the Chang 7 shale gas can be divided into three types：in-situ generated gas，in-situ residual gas，and migrated and accumulated gas. In-situ generated gas is mainly stored in the shale reservoirs within the hydrocarbon generation center zone that have not undergone significant migration. It has the characteristics of high desorption gas content，low N₂ content，high CO₂ content，and heavy carbon isotopes. The migrated and accumulated gas is concentrated in the high parts of the structure or near the fault zones，presenting characteristics such as low desorbed gas content，high N₂ content，low CO₂ content，and light carbon isotopes. In-situ residual gas lies between in-situ generated gas and migrated accumulated gas and is mainly distributed in the transitional area around the hydrocarbon generation center.

Abstract:Interfacial effects and intermolecular forces dominate in shale nanopores，and the classical theory of continuum medium mechanics has limitations or even failures，thus becoming a key issue limiting the development of shale oil and gas storage and flow theories，as well as mathematical simulations. In order to address this issue，the interaction between alkane molecules in shale oil and graphene walls in shale nanopores and the adsorption/retention characteristics of multi-component alkanes in shale oil were studied. By using molecular dynamics simulation，single-component and multi-component systems of shale oil were constructed to analyze the adsorption behavior and retention phenomena of different alkane molecules in the pores，as well as the effects of van der Waals forces，pore sizes，and other factors on the strength of the interactions and the characteristics of adsorbed layers. The simulation results show that the interaction strength between alkane molecules and graphene walls increases nonlinearly with the increase in the number of carbon atoms in alkane molecules due to the irregularity of molecular arrangement and nonlinear van der Waals forces. In the single-component system of shale oil，the number of adsorption layers of alkane molecules increases with the increase in the interaction strength between alkane molecules and graphene walls，but the adsorption strength gradually decreases with the increase in the number of adsorption layers；in the multi-component system of shale oil，there are obvious component differentiation and heavy hydrocarbon retention phenomenon.

Abstract:The tight siltstone reservoirs of the lower Triassic M Formation in the Western Canadian Basin are rich in oil and gas resources，but it has a series of problems such as fine grain size，low porosity and permeability，complex sedimentary and diagenesis processes，large differences in rock fabric between layers，and strong vertical and horizontal heterogeneity，resulting in low accuracy in geological sweet spot prediction and difficulties in oil and gas exploration and development. To better understand the reservoir characteristics and achieve efficient development，research on the restoration of the reservoir densification process should be deepened. Based on the core description and thin section analysis，X-ray diffraction，scanning electron microscopy，and high-pressure mercury injection were comprehensively used to determine the reservoir pore development characteristics and diagenetic types of the three main layers of the lower Triassic M Formation in the study area. On this basis，the evolution process of diagenesis-reservoir formation was further clarified，and the causes of reservoir densification were divided. The results show that the pores in the tight siltstone reservoirs of M Formation are dominated by residual intergranular pores and dissolution pores，and the pore throat radius is concentrated between 10 and 150 nm，which belongs to tight siltstones with ultra-low porosity and ultra-low permeability. The diagenesis types are dominated by compaction，cementation，and metasomatism. The present diagenesis falls between the middle stage A and middle stage B. The dissolution is relatively developed in the LE layer. Due to the influence of sedimentary environments，the processes of porosity variation in the three main layers differ greatly. LC layer is dominated by compaction-based porosity reduction，supplemented by carbonate cementation-based porosity reduction. In the LE layer，carbonate cementation is the main factor of porosity reduction，and dissolution has improved the reservoir properties. LG layer has a higher shale content，and early compaction is the primary mechanism for porosity reduction. Based on the diagenesis and porosity variation，the causes of densification in the LC，LE，and LG layers are classified as primary mixed origin，secondary cementation origin，and primary fine-grained origin，respectively.

Abstract:The 4th Member of Xujiahe Formation（Xu4 Member）in Guang’an area of central Sichuan has favorable conditions for natural gas accumulation and broad prospects for exploration and development. However，the reservoir exhibits poor physical properties，characterized by high water saturation and challenging reserves production. The gas reservoir is currently in the early stags of exploration and development. Clarifying the lower limit of reservoir physical properties is essential to understanding the sweet spot characteristics and its genesis，as well as comprehensively evaluating gas reservoirs. Therefore，this study utilized experimental analysis and production test data from Xu4 Member reservoir in Guang’an area. Three methods were employed：porosity-permeability statistical analysis，minimum flow pore-throat radius method，and seven submethods of empirical statistical method，porosity-permeability intersection method，water film thickness method，mercury injection parameter method，J function method，production test method，and distribution function curve method were used to ascertain the lower limits of porosities and permeability of the reservoir respectively. In order to avoid the large deviation caused by a single method，the arithmetic mean values of the results obtained by each method were used as the final lower limit values of the physical properties of Xu4 Member sandstone reservoir in Guang’an area. The results indicated that Xu4 Member reservoir in Guang’an area primarily consists of medium-fine-grained feldspathic lithic sandstone，exhibiting a moderate to high level of compositional maturity and a high level of structural maturity as a whole. The average porosity of the reservoir is 5.98%，while the average permeability is 0.86×10^-3 μm sup>2.Overall，this reservoir is a tight reservoir with low porosity and permeability. It has high water saturation，averaging 65.17%，and strong heterogeneity. The lower limits of porosity determined by the seven submethods are 3.2%，6.5%，6.1%，6.5%，8.1%，3.2%，and 9.5%，respectively，and those of permeability are 0.193×10^-3，0.189×10^-3，0.055×10^-3，0.163×10^-3，0.089×10^-3，0.123×10^-3，and 0.211×10^-3 μm²，respectively. By calculating the arithmetic mean value，the final lower limits of porosities and permeability of Xu4 member reservoir in Guang’an area are 6.2% and 0.146×10^-3 μm²，respectively.

Abstract:One of the main reasons for the complex mineral composition，significant differences in lithology，and obvious differences in the production capacity of different gas wells after hydraulic fracturing in the Chang 8 reservoir in the Ordos Basin lies in the differences in the morphologies of the fracture networks formed by fracturing the reservoir rocks，which depends on the brittleness of the reservoir rocks. By taking Wuji，Ansai，and Shun 98 blocks in the Ordos Basin as the research object，representative rock samples were selected to carry out rock mechanics experiments，X-ray diffraction whole-rock mineral analysis experiments，and rock pore throat structure analysis. The dynamic and static mechanical parameters，mineral composition and content，and pore throat structure of the dense sandstone were obtained，and the dynamic brittleness index，static brittleness index，and mineral brittleness index of the rock were further calculated. The results show that the dynamic modulus of elasticity of rocks in the Chang 8 dense sandstone reservoir in the study area is larger than the static modulus of elasticity；the dynamic Poisson’s ratio is larger than the static Poisson’s ratio，and the dynamic and static mechanical parameters in the same block have a certain linear relationship.The transformation model of the dynamic and static mechanical parameters was established，featuring static brittleness index >dynamic brittleness index > mineral brittleness index for the same rock samples. Based on the graphs of each mineral content and the static brittleness index，it is clear that the brittle minerals in tight sandstone reservoirs in Wuji-Ansai block of the Ordos Basin are mainly quartz and carbonatite；there are differences in brittleness indexes among the blocks，featuring static brittleness index in Shun 98 block > static brittleness index in Ansai block > static brittleness index in Wuji block. According to the experimental results，the brittleness index is affected by the composition of rock minerals and the rock porosity，pore connectivity，and non-homogeneity. Under the premise of the same mineral composition，a weaker rock non-homogeneity means better pore connectivity and larger pore diameter，as well as greater brittleness.

Abstract:In order to accurately and efficiently characterize the spatial distribution characteristics of porosity in tight oil reservoirs and evaluate the interpretability of machine learning models，the Z-Score method was used to normalize the feature attributes，and the Optuna hyperparameter optimization framework was applied to optimize the hyperparameters of the model. A porosity prediction model based on the LightGBM algorithm was established，and the prediction performance was comprehensively compared with GBDT and XGBoost algorithm models. The SHAP algorithm was used to visually interpret and analyze the output results of the LightGBM model. The research results indicate that the LightGBM model has prediction determination coefficients of 0.984 and 0.855 on the training and testing datasets，respectively. The model has high prediction accuracy and strong generalization ability，and its overall prediction performance is better than the GBDT and XGBoost models. The interpretability of the LightGBM model results was analyzed by using the SHAP algorithm. The results show that the five most important logging parameters affecting the LightGBM porosity prediction model are density，array induction resistivity，natural gamma，interval transit time，and photoelectric absorption cross-section index. In the porosity prediction example of X tight interval of a single well in the research area，the LightGBM model achieves a prediction accuracy of 93.9%，which is higher than the prediction accuracy of the GBDT and XGBoost models at 86.53% and 89.08%，respectively. The training duration is 0.016 s，which is 0.096 times and 0.025 times the training duration of GBDT and XGBoost models，respectively. The prediction duration is 0.01 s，which is 0.42 times and 0.19 times the prediction duration of GBDT and XGBoost models，respectively. The prediction efficiency of the LightGBM model has significant advantages over the GBDT and XGBoost models. The LightGBM model has smaller prediction errors for porosity in the cored interval，stronger prediction ability，and can better fit low porosity values. This method could solve the problem of obtaining complete and accurate porosity distribution in single well tight intervals and improve the accuracy and efficiency of porosity prediction，which has a certain reference value for the evaluation and efficient exploration and development of tight oil reservoirs.

Abstract:geometric dimensions and conductivity of fracture networks，which is of great significance for the optimal deployment of well patterns and the optimization of fracturing parameters in shale gas wells. A true thickness-domain horizontal well-controlled complex structure modeling method was established in response to the complex geological characteristics caused by multiple factors，such as the structure and stress of normal pressure shale gas wells in complex tectonic regions. A well-seismic combined natural fracture network prediction method was formed based on the correlation between seismic attributes and drilling dynamics，such as mud loss and overflow. Local densification was used to characterize the deformation characteristics of the reservoir under complex stresses. The simulation research on the extension of the fracture network was carried out. The research results show that the magnitude and orientation of in-situ stress will affect the extension morphology of the fracture network. The development of natural fractures is conducive to forming complex fracture networks. The fluid injection intensity plays a key role in increasing the length of hydraulic fractures and expanding the stimulated volume. The sand addition intensity determines the effectively propped fracture length and conductivity.Moderately reducing the number of clusters per stage can effectively increase the single-well controlled reserves and development benefits of normal pressure shale gas wells. During well placement，reducing the angle between the horizontal section and the minimum principal stress and selecting the natural fracture development area with moderate in-situ stress is the prerequisite for achieving high production in normal pressure shale gas wells. During fracturing，increasing the sand addition intensity and fluid injection intensity and reducing the number of perforation clusters are effective ways to increase the stimulated volumes and form complex fracture networks. Through the integrated analysis of geology and engineering for factors affecting the fracture network extension，it is suggested that the fracture network volume and the single-well productivity be increased and the development benefits of normal pressure shale gas reservoirs be enhanced.

Abstract:Tight conglomerate reservoirs exhibit abundant hydrocarbon resources，and multi-stage fracturing of horizontal wells is typically employed to construct three-dimensional（3D）complex fracture networks in low-permeability reservoirs for enhancing productivity. However，the strong heterogeneity of conglomerates leads to unique fracture propagation mechanisms，ambiguous influence patterns of dominant controlling factors，and significant challenges in fracturing design and fracture morphology prediction，thereby constraining efficient volumetric stimulation. A heterogeneous cubic conglomerate model containing spherical gravels was established using the continuum-discontinuum element method（CDEM）to simulate the 3D fracture propagation process during fracturing. Key parameters，including failure modes，gravel penetration rate，stimulated reservoir volume（SRV），and fractal dimension，were quantitatively characterized. The Pearson correlation coefficient method was applied to analyze correlations between seven influencing factors （e. g.，permeability，gravel strength，cementation surface strength，and horizontal stress difference）and fracture parameters. The weights of dominant controlling factors were determined using the coefficient of variation method，and a multi-parameter nonlinear evaluation model for SRVand fractal dimension was developed based on the least squares regression. The study demonstrates that stress characteristics are the primary controlling factors for SRVand the fractal dimension of fractures. Horizontal stress difference shows significant negative correlations with both SRV and fractal dimension（correlation coefficients：-0.563 9 and -0.611 7，respectively），with corresponding weights of 31.2% and 28.5%. Gravel content exhibits a strong positive correlation with gravel penetration rate. Gravel failure predominantly follows Mode-I failure， generating low-complexity fractures. However，increased gravel strength and reduced cementation surface strength induce gravel-bypassing behavior，promoting fracture bifurcation and enhancing fractal dimension. Additionally，fractal dimension is negatively correlated with injection displacement，and high injection displacement leads to the formation of a simplified fracture system dominated by the main fracture. Permeability exhibits higher sensitivity to fractal dimension（weight：11.5%）than to SRV（6.58%），reflecting constrained fracturing fluid filtration under low-permeability conditions，which inhibits fracture propagation scale，and fracture complexity is constrained by the flow capacity of reservoirs.

Abstract:To gain an in-depth understanding of the microscopic flow characteristics and residual oil migration during viscoelastic particle flooding，this study established a pore-scale numerical model for viscoelastic particle-water-oil three-phase flow based on digital core. By tracking the dynamic evolution of the oil and water distribution field and analyzing the spatial structure changes of flow paths，the characteristics and evolution laws of flow paths during viscoelastic particle flooding were systematically revealed.Simulation results indicate that compared with conventional water flooding，dynamically branching flow paths are formed in the porous medium due to the plugging effect on the pore channels or increasing the flow resistance of viscoelastic particles in the pore channels. The evolution of these flow paths exhibits three distinct stages：path reconstruction，where the number of flow paths rapidly decreases from 60 to 25；path optimization，where the standard deviation of the weight increases from 5.00 to 10.00，accompanied by a 22% reduction in residual oil volume fraction；and dynamic equilibrium，where the number of flow paths remains around 15，and the residual oil volume fraction further decreases from 0.26 to 0.13. Quantitative analysis further shows that the resistance regulation and pressure fluctuations during viscoelastic particle flooding prompt fluids to enter previously unmobilized regions，improving displacement efficiency. The volume fraction of mobilized zones increases to 0.50-0.70，and the overall oil recovery is increased by 35% compared to the end of water flooding. The research reveals the dynamic evolution characteristics of the flow path during the viscoelastic particle flooding and clarifies the relationship between its microscopic regulatory mechanism and the macroscopic oil recovery efficiency.

Abstract:CO₂ foam flooding，as an enhanced oil recovery technology integrating the advantages of chemical flooding and gas flooding，significantly enhances crude oil production in complex reservoirs by synergistically utilizing the interfacial modulation capabilities of surfactants and the mobility control characteristics of CO₂. In recent years，it has demonstrated substantial potential in the development of unconventional oil and gas reservoirs，including heavy oil，shale oil，and tight oil. This paper reviewed the principle and influencing factors of CO₂ foam stability，the methods to improve the stability of CO₂ foam，the enhanced oil recovery mechanism under CO₂ foam flooding，and its application in unconventional oil reservoirs such as heavy oil and shale oil. Firstly，the principle of CO₂ foam stability was fundamentally governed by the following factors：the structures and properties of the liquid film， including drainage dynamics and gas diffusion rates； the hydrophilic-lipophilic balance of surfactants， and the Gibbs-Marangoni effect induced by interfacial tension gradients at bubble surfaces. Then，the effects of reservoir environments such as temperature，pressure，salinity，and crude oil on the stability of CO₂ foam were analyzed. The increase in temperature and salinity had an adverse effect on the formation and stability of foam. The rise in pressure had a positive impact on CO₂ foam stability. The light and heavy components of crude oil had different effects on foam stability. The methods of polymers，ionic fluids，nanoparticles，and the synergistic effect of surfactants and nanoparticles were proposed to improve the stability of CO₂ foams. Finally，the enhanced oil recovery mechanism of CO2 foam flooding was explained：the foam selectively blocks in the porous medium through the Jamin effect to improve the sweep efficiency，achieve crude oil emulsification/viscosity reduction，reduce the oil-water interfacial tension，change wettability，improve the mobility ratio of oil phase and displacement phase，and increase the fluidity of crude oil. Based on this enhanced oil recovery mechanism，the application of CO₂ foam flooding in unconventional oil and gas reservoirs for enhanced oil recovery（EOR）is summarized.

Abstract:Shale oil-water saturation is a core parameter for evaluating the potential and development feasibility of shale oil reservoirs. Currently，the primary methods for analyzing oil and water saturation include the atmospheric pressure dry distillation method，the distillation extraction method，the alcohol grinding extraction method，and the nuclear magnetic resonance（NMR）method. Due to the characteristics of shale，such as its rich organic matter，low water content，and high mud content，the wall-sticking phenomenon and pore heterogeneity of parallel rock samples in commonly used analysis methods can cause greater deviations in experimental results. Meanwhile，the lack of calibration for the NMR method results in significant differences in the results compared to other methods. Based on the improved extraction method，this paper establishes a calibration method for analyzing the water saturation of shale oil using T₁-T₂ spectrum analysis through an experiment that combines alcohol immersion extraction and NMR measurement. The water saturation of the same shale rock sample was accurately analyzed through the alcohol immersion extraction method. The alcohol extraction time was determined to be 40 days based on the variation relationship of the extracted water volume with time. The oil washing time was determined to be 30 days based on the variation relationship of the crude oil in the rock sample with the oil washing time. The correction method of the extracted water volume was determined based on the drying temperature of the clay-bound water. The T₁-T₂ spectra of fresh rock samples and saturated water rock samples were analyzed，and a T₁-T₂ spectrum interpretation chart for the oil-water distribution in Jiyang shale was established based on the effective pore T₂ cutoff value，thereby rapidly obtaining the oil-water saturation. The fresh rock samples from multiple closed coring wells in shale oil reservoirs were analyzed，and the oil saturation of the effective reservoir space in the Jiyang shale oil reservoir is mainly between 45% and 80%，with no correlation with the depth of the rock sample. A larger effective porosity means a higher oil saturation，and oil content is high in reservoirs with well-developed laminae.

Abstract:The profile control and displacement technology using nanomaterials has outstanding advantages at the material scale，which has shown significant effects in pilot tests of representative blocks in different reservoirs. However，the unclear mechanism of the profile control and displacement system fundamentally hinders the large-scale application of the technology. In order to investigate the profile control and displacement effect and mechanism of two typical nanomaterials，nanoemulsion and nanosphere，carbonate reservoirs were taken as the research objects. The complexity of its pore structure was recognized based on the cast thinsection made from real cores，and three types of reservoir micromodels were designed and fabricated according to the characteristics，including pore-type，fracture-type，and vuggy-type reservoirs. Microfluidic experiments were carried out by using the profile control and displacement system in single and combined modes to obtain the images before and after the action and capture the microscopic phenomena during the profile control and displacement process. The profile control and displacement phenomena were combined with numerical change laws，and the effects of different profile control and displacement measures on increasing production in various carbonate reservoirs were discussed from the aspects of qualitative description and quantitative analysis. Meanwhile，the microscopic profile control and displacement mechanisms of the two nanomaterials were clarified. The experimental results show that using nanoemulsion and nanosphere for profile control and displacement can promote the effective mobilization of residual oil after water flooding in the three types of carbonate reservoir micromodels. Among them，the pore-type reservoir has the highest oil recovery；the fracture-type reservoir has the highest increase in production，while the vuggy-type reservoir has relatively poor performance. The nanoemulsion can improve the microscopic displacement efficiency by reducing the interfacial tension and changing the wettability to produce the remaining oil in the dominant flow area. The profile control and displacement effect of the nanosphere is mainly reflected in blocking the initial water flow channels to make the subsequent fluid turn into the unswept areas to further expand the swept areas.

Abstract:Winsor Ⅲ microemulsion flooding is an effective means to solve the low production percentage of high-temperature，high-salinity and low-permeability reservoirs，but the research on the construction and mechanism understanding of Winsor Ⅲ microemulsion flooding system is insufficient. In this paper，the Winsor Ⅲ microemulsion system with temperature resistance and salt resistance was constructed through the solubility test，oil-water interfacial tension test，and phase behavior test of two types of surfactants and their composite systems under the conditions of simulated reservoirs. Then，the feasibility of the system in enhancing oil recovery of low-permeability reservoirs was explored through core displacement experiments，contact angle testing experiments，and visual core displacement experiments. The mechanisms of enhancing oil recovery were analyzed from two aspects：changes in wettability and solubilization and emulsification. The results show that alcohol ether carboxylate surfactant ST 982-B can construct a Winsor Ⅲ microemulsion system at the mass fraction of 0.3%-0.5%；the microemulsion system can effectively enhance oil recovery of low-permeability reservoirs by 7.8%-9.7%. The microemulsion system can effectively improve the rock wettability，and the“denudation”of oil film after solubilization and emulsification of the system further enhances the oil displacement efficiency.

Abstract:A large amount of W/O emulsions will be formed during reservoir formation and waterflood development，which brings many challenges to chemical flooding for the subsequent enhanced oil recovery. Therefore，the formation theory of crude oil emulsions（W/O，O/W，and W/O/W），the performance variation rules，and the instability behaviors of W/O/W emulsions were studied in detail to clarify the formation rules of multiple crude oil emulsions and their influencing factors. The viscosity increase of W/O emulsions can be divided into two processes with the increase in water content：linear increase and exponential increase. The W/O emulsion emulsified by chemical emulsification forms W/O/W emulsion in oil reservoirs. A higher water content of W/O emulsion indicates a larger droplet size of W/O/W emulsion. Its performance is mainly affected by the droplet size and the percentage of the produced water phase in the W/O emulsion. A stronger ability of the chemical agent to produce the internal water phase of the W/O emulsion means a smaller droplet size of the formed W/O/W emulsion. A higher mole concentration of chemical agents indicates a stronger emulsification ability and a stronger ability to produce the internal water phase. The viscosity of the W/O/ W emulsion is affected by its droplet size，the strength of the interfacial film，and the internal water phase. A lower droplet size means less water phase in the W/O droplet，higher interfacial film strength，and lower viscosity of W/O/W emulsion. The stability of W/O/W emulsion is mainly affected by its droplet size and droplet coalescence rate. The smaller droplet size of the W/O/W emulsion formed by the emulsification of chemical agents means a slower droplet coalescence rate and stronger stability. The initial dehydration rate decreases with the increase in chemical agent concentration. However，as the percentage of the produced water phase intensifies，the final dehydration rate and the time to reach the stable dehydration increase. With the increase in the oil-water ratio，the density of W/O droplets increases，and the initial dehydration rate slows down. In addition，the percentage of the produced water phase in the W/O emulsion decreases with the increase in the oil-water ratio，and the final dehydration rate decreases. As the temperature increases，the initial dehydration speed is accelerated，and the time to reach the stable dehydration stage is shortened. Finally，the final dehydration rate is increased.

Abstract:Casing damage in the horizontal screen section of thermal recovery wells has long been a critical challenge hindering the efficient and sustainable development of heavy oil reservoirs. Clarifying the main controlling factors of casing damage in these sections and establishing parameter limits to prevent casing damage are crucial for guiding the safe development of thermal recovery wells in heavy oil reservoirs. Based on thermo-mechanical coupling theory，a finite element model incorporating parameters such as steam injection temperature，dryness，wall thickness of the horizontal screen，and the screen phase angle was developed. Based on the control variable method，numerical simulations were conducted to analyze the influence of steam injection parameters（temperature and dryness）and structural parameters of the horizontal screen（wall thickness，phase angle，pore diameter，and pore density）on casing damage under the combined effects of fully compensated axial thermal expansion，overlying rock pressure of horizontal screen，and formation expansion-induced stresses on the horizontal screen. The results demonstrate that the primary controlling factors for casing damage in the horizontal screen section are the wall thickness of the screen，steam injection temperature and dryness，and phase angle of the screen. Increasing the wall thickness of the screen significantly reduces stress and mitigates casing damage risks. Elevating steam injection temperature and dryness in the horizontal screen section of thermal recovery wells enhances heavy oil recovery，and it substantially increases stress on the horizontal screen section，thereby amplifying casing damage risks. The screen exhibits optimal collapse resistance at a 30° phase angle，with stresses rising by 13.2%，25.6%，and 2.8% at 60°，90°，and 150° phase angles，respectively. The safety ranking of phase angles follows 30°，150°，60°，90°. Pore density and diameter show relatively minor impacts on casing damage. Based on these findings，four technical limit charts for casing damage prevention are established. These charts enable rapid determination of casing damage prevention strategies for the horizontal screen sections of thermal recovery wells.