Abstract:Buried hill is an essential field of oil-gas exploration in Jiyang Depression. Deepening the formation mechanisms and es‐tablishing a predictable classification scheme of buried hills are the key to the exploration of hidden buried hills. Based on 3D seis‐mic data and drilling data，this paper analyzed the structural characteristics of buried hills，fault activity rates and equilibrium crosssection，recovered the superposed evolution processes of buried hills at key stages，established the genesis-structure classification system of buried hills，and clarified the spatial distribution law of buried hill types. The results show that the buried hills in Jiyang Depression have experienced three stages of evolution since the Mesozoic，namely，Indosinian compression and thrust，Yanshanian sinistral transtension，and Himalayan dextral transtension. The former two form the prototype and initial pattern of NW-trending bur‐ied hills，respectively，while the latter results in the formation of the NEE-trending buried hills，forming the current“sevenlongitude and four-latitude”distribution pattern of buried hills. According to the difference in the structural location and the move‐ment of buried hills during the Yanshanian and Himalayan periods，buried hills in Jiyang Depression are divided into four types：Meso-Cenozoic uplift type residual hills，Mesozoic uplift-Cenozoic sink type fault-block hills，Mesozoic sink-Cenozoic uplift typedetached hills，and strike-slip reformed type fault-block hills. Their orderly distribution fits the structures of the faulted basin. From the bulge zone，slope zone，and depression zone to the steep slope zone，the Mesozoic-Cenozoic uplift type residual hills，the Me‐sozoic sink-Cenozoic uplift type fault-block hills，and the Mesozoic uplift-Cenozoic sink type detached hills are successively devel‐oped.

Abstract:Low-maturity shale is widely distributed in Dongying Sag，which has abundant shale oil resources. However，the reser‐voir space and fractal characteristics of low-maturity shale reservoirs are not clear，which restricts the efficient development of low- maturity shale oil. In this paper，the low-maturity shale in the Upper Submember of the Fourth Member in the Eocene Shahejie For‐mation（Es₄^U）in Minfeng area of Dongying Sag was taken as the research object. The reservoir space types and the influence of lamina combinations on the reservoir space were discussed based on integrating core observation，slice analysis，organic geochemi‐cal test，X-ray diffraction，low-temperature nitrogen adsorption，and scanning electron microscopy，and the pore fractal characteris‐tics were studied. The main lithofacies of the low-maturity shale of Es₄^U in the research area are organic-rich laminated calcareous mixed shale and organic-rich laminated argillaceous mixed shale. The pores of the organic-rich laminated calcareous mixed shale are mainly mesoporous and macroporous，and those of the organic-rich laminated argillaceous mixed shale are mainly microporous，with some macropores also being developed. The predominant reservoir space in the low-maturity shales are intergranular pores，in‐terlamellar pores in clay minerals，and micro-fractures. Two laminae combinations，“micrite calcite laminae + argillaceous lami‐nae”and“sparry calcite laminae + argillaceous laminae”，are widely developed in the study area. The micrite calcite laminae and sparry calcite laminae are dominated by intergranular pores，while argillaceous laminae are dominated by interlamellar pores in clay minerals. The interlamellar fractures and intergranular pores are important reservoir spaces for shale oil. The fractal dimension D ₁ of low-maturity laminaceous shale ranges from 2.413 9 to 2.527 7，and D ₂ ranges from 2.704 6 to 2.802 1. TOC content and carbonate mineral content are weakly negatively correlated with D₁ and D₂，while clay mineral contents are weakly positively correlated with D₁. The intergranular pores and dissolution pores of carbonate minerals have smooth surfaces and simple pore space，which is con‐ducive to shale oil accumulation and flow.

Abstract:The Lower Paleozoic carbonate rocks in the Ordos Basin are characterized by substantial depositional thickness and exten‐sive distribution，with reservoirs exhibiting tight lithology，low porosity，and low permeability. The accumulation and migration of natural gas in these carbonate reservoirs are significantly influenced by storage and flow space composed of fractures and pores.Based on analytical results from core samples，thin-section observations，and production data，this study investigated the genetic types of weathering-induced fractures in Majiagou Formation of Fuxian area and their impact on hydrocarbon accumulation. The re‐sults demonstrate that weathering-induced fractures in the carbonate reservoirs are controlled by lithology，paleokarst geomorphol‐ogy，and fault scale，and they can be classified into three types：karst-collapse fractures，weathering-leached fractures，and scarprelated tensile fractures. Karst-collapse fractures predominantly develop in soluble gypsum-bearing dolomites and evaporites within residual hills；weathering-leached fractures occur in dolomitic limestones on slopes and terraces；scarp-related tensile fractures form in dolomite-poor argillaceous limestones at steep unconformity surfaces. Among these fracture types，karst-collapse fractures create effective fracture networks that enhance reservoir porosity and permeability. Scarp-related tensile fractures exhibit moderate effec‐tiveness，primarily improving permeability but failing to form complex fracture networks. Weathering-leached fractures，often me‐chanically filled，contribute minimally to reservoir porosity and permeability. According to production dynamics，the carbonate res‐ervoirs in the study area are categorized into four types：karst-collapse fracture-dominated，scarp-related tensile fracturedominated，weathering-leached fracture-dominated，and matrix-ineffective reservoirs.

Abstract:Shahejie Formation of Boxing Subsag in Dongying Sag is rich in hydrocarbon resources and holds significant exploration potential. However，the complex geological structure，rapid lateral lithological changes in lacustrine shales，strong reservoir hetero‐geneity，and significant burial depth pose substantial challenges. Multiple fault zones significantly affect the spatial distribution of the in-situ stress field，leading to frequent drilling issues such as collapse and fluid invasion. Additionally，during reservoir fractur‐ing operations，the interference between wellbore fracture networks and difficulties in fracturing key intervals directly hinder hydro‐carbon exploration and development of Boxing Subsag. The Upper Submember of the 4^th Member of the Eocene Shahejie Formation（E s₄^U）to the Lower Submember of the 3^rd Member of the Eocene Shahejie Formation（Es₃^L）（Es₄^U-Es₃^L）were taken as research ob‐jects，and mechanical experiments，logging interpretation，and seismic attribute analysis were integrated to construct a heteroge‐neous rock mechanics parameter model and determine the in-situ stress state of individual wells. Based on the finite element geome‐chanical model，the study employed elastoplastic finite element numerical simulations to characterize the in-situ stress field spatially and analyze the controlling factors and mechanisms of in-situ stress field distribution differences. Results indicate that the centralwestern part of Boxing Subsag has experienced prolonged structural activity，with major faults exhibiting extension and strike-slip characteristics. The overall trend of structural activity is from the south to the north and from the subsag center towards major faults.The overall in-situ stress state of the E s₄^U-Es₃^L falls into Class I but varies with depth in some areas. The maximum horizontal princi‐pal stress shows an NE-WN extension of high，low，and high-value variation. High in-situ stress zones are mainly concentrated near the Gaoqing-Pingnan fault corner，dominated by nearly EW-trending horizontal compression. The main controlling factors for insitu stress field distribution include reservoir lithology，structural morphology，and faults. Reservoir lithology results in uneven dis‐tribution of in-situ stress due to different mechanical properties of rock，and structural morphology influences in-situ stress proper‐ties. Faults lead to chaotic in-situ stress directions，with stress concentrations at fault tips and bends.

Abstract:This study focused on the mud shale reservoirs in the second Member of Funing Formation in Qintong Sag，Subei Basin of China，and systematically investigated the oil-solid interface adhesion mechanism of shale oil in micro-scale flow. Through de‐tailed analysis of the mineral compositions，pore structures，and fluid characteristics of shale，the flow patterns of shale oil and the oil-solid interface adhesion mechanism in different types of shale were revealed by atomic force microscopy（AFM）and laser confo‐cal microscopy. The findings indicate that shale oil in the reservoir exhibits distinct characteristics of selective production driven by pressure，whereby light components are preferentially adsorbed onto the shale walls，significantly enhancing the adhesion at the oilsolid interface. As pressure increases，heavy components start to flow，further augmenting the adhesion，but they stabilize once pressures exceed 5 MPa. Adhesion tests at the oil-solid interface demonstrate that laminated mudstone and massive silty mudstone emerge as key target shale types for enhancing shale oil recovery under low-pressure conditions. Under high-pressure conditions，the mechanism of adsorption and desorption of shale oil by laminated mudstone becomes the key research area for improving shale oil recovery in the second Member of Funing Formation in Qintong Sag.

Abstract:Commercial oil and gas flow was discovered in the Jurassic sandstones of Moxizhuang and Yongjin areas in the central Junggar Basin. The reservoir porosity and permeability are very low in some areas where the buried depth of the Jurassic reaches 6 000 m，belonging to ultra-low porosity and ultra-low permeability reservoirs. In such tight reservoirs，the charging power of crude oil，the source of oil and gas，and the migration process need to be systematically discussed. Biomarkers were used to de‐termine the source of oil and the main source rocks of crude oil in tight sandstone reservoirs to reveal the enrichment process and main controlling factors of crude oil in tight sandstone reservoirs. The slip distances of the faults in horizontal and vertical direc‐tions and the sealing properties of the faults were studied by quantitative and semi-quantitative methods，and the relationship be‐tween fault size and oil test production was clarified by combining statistics and geological analysis. Moreover，the influence of fault size and fault distance on oil and gas accumulation was explored. Micro-CT scanning，constant-rate mercury injection，nuclear magnetic resonance（NMR），and physical simulation were applied to systematically describe and characterize the pore structure parameters of sandstones and fluid accumulation models in these tight reservoirs. The results show that the crude oil is mainly from the Permian source rocks. The faults with large sizes and high activity intensity are vertical migration channels of oil and gas，and the faults with horizontal and vertical movement distances of more than 700 m and a size of more than 20 km at geological time have better oil and gas transport capacity. However，the faults with small sizes and short movement distances are mostly closed. The pore sizes of the tight reservoirs are small，mainly in the range of 163.8-207.7 μm，and the throats are 0.5-8.1 μm. The heterogeneity of the micro-pore structures leads to the differential charging and enrichment of crude oil. The oil content of reservoirs with medium porosity and coarse throat is the highest，followed by the reservoirs with large porosity and small throat，and the oil content of reservoirs with small porosity and micro throat is the lowest. The accumulation of Jurassic tight sandstone reservoirs is mainly influenced and controlled by high activity intensity，large faults，and pore structures of tight sand‐stone.

Abstract:Huagang Formation in offshore A gas field is a large composite channel deposit with horizontal migration and vertical su‐perposition of channels. The target layer has a large burial depth，few drilled wells，and poor-quality seismic data. It is difficult to identify the channel sand bodies based on seismic data，and the development accuracy requirements are not supported. Based on the classic channel deposit styles and the characteristics of drilled wells，the seismic responses of different channel deposit styles were clarified by forward modeling technology. On this basis，the composite channel zones were characterized by using strata slice tech‐nology，and single channel boundaries were accurately tracked by combining near-angle stacked data volume and far-angle stacked data volume. The Poisson impedance inversion was selected to predict the dominant sand bodies in channels quantitatively. Finally，the seismic comprehensive characterization technology was formed for the internal structures of deep single channels with few wells and stepwise constraints. Based on the characterization results，four wells were deployed in the dominant sand bodies of different channels. The actual drilling confirmed that there were different gas-water interfaces in different channels，indicating that lithologicstructural gas reservoirs formed by multiple channels were developed and have different gas-water systems，which confirmed the re‐liability of single channel characterization. All four wells have achieved an average high gas yield of 20×10⁴ m³/d after production，which further confirmed the accuracy of dominant sand body characterization. This method strongly supports the development and adjustment of the gas field，and the geological reserves and daily gas production of natural gas have achieved breakthroughs.

Abstract:Since“The Twelfth Five-Year Plan in 2011-2015，”to implement the deep integration of informatization and industrializa‐tion and accelerate digital transformation，common issues in mature oil and gas fields have been analyzed，such as high production costs，significant labor conflicts，and low operational efficiency. To address these issues，the Oilfield Exploration and Production Department of Sinopec combined pilot constructions in Shengli Oilfield and the institutional mechanism construction of oil compa‐nies and organized oil and gas field enterprises to expedite the digital and intelligent construction in oil and gas production. As a re‐sult，a standard system for the industrial Internet of Things in oil and gas production was established，and production parameter soft measurement technology based on dynamic and static data was developed. Breakthroughs were made in anomaly recognition and op‐erational optimization technology based on big data. The department independently developed a fully localized oil and gas produc‐tion informatization platform with first-level deployment that integrated all elements，effectively solving problems such as inconsis‐tent standards in the informatization construction of mature oil and gas fields，high overall investment，difficulties in efficient min‐ing and utilizing the value of massive real-time data，and the dispersed construction of production，operation，and command plat‐forms that hindered the realization of large-scale benefits. This has formed a low-cost，standardized，and scalable solution for the digital and intelligent construction of oil and gas fields and established new production operation models and labor organization methods under digital and intelligent conditions，which have been fully industrialized and applied in Sinopec’s oil and gas field en‐terprises，showing significant results. The results indicate that the digital and intelligent construction and practice of oil and gas pro‐duction are effective ways to achieve the digital transformation and high-quality development of mature oil and gas fields，playing a key supporting role in promoting the transformation of production and operation models and labor organization methods in oil and gas field enterprises，improving labor productivity，enhancing fine management levels，and increasing production operation effi‐ciency. Since“The Thirteenth Five-Year Plan in 2016-2020”，the labor productivity of Sinopec’s oil and gas field enterprises has in‐creased by 91%，and the production time rate of oil wells has increased by an average of 0.4 percentage points；maintenance fre‐quency has decreased by 0.13，and the natural decline rate of oil fields has decreased by 2.4 percentage points，achieving unmanned or less manned operations at oil and gas production sites，strongly supporting the reform and development of oil companies and lay‐ing the foundation for the construction of intelligent oil and gas fields.

Abstract:Pressure drive-based water injection technology has solved the problem of“no injection and no production”in ultra-low permeability sandstone reservoirs in Shengli Oilfield，but the law of oil-water displacement and the percentage of oil production in pores at different scales in the process of pressure drive-based shut-in and water flooding are still unclear. In order to solve the above problems，spontaneous imbibition and water flooding experiments were carried out in the ultra-low permeability sandstone reser‐voirs in Dongying Sag，and the evolution characteristics of oil-water distribution during imbibition and water flooding were studied by high temperature and high pressure nuclear magnetic resonance（NMR）. The results show that the T₂ spectrum of saturated oil in ultra-low permeability sandstone in Dongying Sag is mainly divided into single peak and double peak，and the double peaks are fur‐ther divided into left peak height and right peak height. The most oil phase in the pores of the sandstones with an unimodal T₂ spec‐trum and network pore structure can be produced through spontaneous imbibition during shut-in. For sandstones with a bimodal T₂ spectrum and dendritic pore structures，a large amount of oil phase is still unproduced after spontaneous imbibition，and the oil recovery can be further improved by water flooding. The oil in micropores and mesopores can be produced through spontaneous im‐bibition，but the contribution of oil recovery in macropores to total oil recovery is less. When spontaneous imbibition is followed bywater flooding，the recovery is further improved，and more oil in macropores and mesopores is produced，but the oil in micropores is less produced.

Abstract:To address the challenges in ordinary heavy oil reservoirs during the mid-to-late stages of steam huff and puff operations，such as low reservoir pressure，low oil-steam ratio，and channeling risks associated with conventional water injection for energy re‐plenishment，this study focused on the C reservoir in Shengli Oilfield. Reservoir numerical simulation was employed to investigate the feasibility of composite cold drive and thermal recovery. Firstly，the mechanism of three kinds of normal temperature displace‐ment media，such as viscosity reducer，polymer，and nitrogen foam，was characterized by numerical simulation. Then，the optimal normal temperature displacement medium was obtained by comparing its recovery characteristics. Finally，the feasibility of compos‐ite cold drive and thermal recovery was clarified by combining the effect of composite huff and puff operations at the production end. The results show that compared with the development effects of three different normal temperature displacement media，the input-output ratio of polymer flooding is up to 2.06，and the cumulative oil increment of nitrogen foam flooding is up to 1 884 t，but the input-output ratio is only 1.23. The cumulative oil increment of viscosity reducer flooding is only 723 t. After careful consider‐ation，polymer flooding is selected as the optimal normal temperature displacement medium. Compared with pure cold drive and pure thermal recovery，the cumulative oil production after composite cold drive and thermal recovery increases by 7 328 t and 3 034 t，respectively. Using composite cold drive and thermal recovery technology can reduce the oil-water mobility ratio，delay the pres‐sure decline，and extend the huff and puff cycle. In addition，under the premise that the pressure is supplemented，the liquid produc‐tion and the production pressure difference can be appropriately increased to improve the composite cold drive and thermal recovery effect.

Abstract:Jiyang shale oil is a terrestrial self-generated and self-accumulated reservoir with deep burial，low maturity，and high pressure coefficient. Artificial reconstruction spaces with complex flow mechanisms form after large-scale volumetric fracturing，and it isn't easy to obtain accurate physical properties of the reservoir in the stimulated spaces through conventional experiments，which presents new challenges to numerical simulation methods. In view of the unclear internal flow law of shale oil，the reservoiraround the wellbore was regarded as a grey box system，and the numerical simulation model of the horizontal well of shale oil was established based on the understanding of physical property and fracturing effect of the reservoir from the previous exploration work. The production law of the horizontal well of shale oil in Jiyang Depression was studied to investigate the internal relationship between oil production and influencing factors. The reservoir around the horizontal well was divided into an artificial main fracture zone，micro-fracture reconstruction zone，and unstimulated matrix zone in the model. By considering fracturing fluid injection into the reservoir，the production dynamics of typical horizontal shale wells of shale oil were fitted，the physical properties of the reser‐voir were deduced，and the final oil production was predicted. The influence law of the working system and fractures on develop‐ment indexes were analyzed，and the method for determining the rational well spacing for well group development was further ex‐plored，which provided support for the development and design optimization of shale oil in Jiyang Depression.

Abstract:Polymer microspheres can continue to migrate through the pore throats by the elastic deformation after plugging pore throats，achieving deep profile control and flooding in reservoirs. The successful application of polymer microspheres hinges on their excellent match with the reservoir，necessitating the study of their macroscopic core scale and microscopic pore-throat scale matching relationships. First，two sizes of polymer microspheres（MG-1 and MG-2）were synthesized，and injectivity experiments were conducted through long different permeability cores with intermediate pressure measurement points. The macroscopic match‐ing characteristics between polymer microspheres and pore throats were identified through the three-stage pressure gradient curve patterns. Second，the pore-throat models were used to carry out microfluidic displacement experiments of polymer microspheres to evaluate the microscopic matching characteristics of polymer microspheres with pore throats based on their entry and retention status in throats at different scales. The matching patterns between polymer microspheres and cores can be divided into three types：endface plugging，matching，and direct passage. Based on the pressure difference at the ends of the polymer microsphere injection and the subsequent water flooding，the upper limit of the macroscopic matching coefficient between MG-1 and pore throats was deter‐mined to be 1.3 to 1.4，with the optimal matching coefficient being 0.8 to 1.0. The microfluidic displacement results show that mi‐crospheres need to be under a certain pressure to enter smaller pores and throats. The maximum matching coefficients for MG-1 to enter and retain in cross-sectional and axial models are 1.21 and 1.47，respectively，corresponding to the optimal matching coeffi‐cient and upper limit of microscopic matching between MG-1 and pore throats. The macro-micro matching characteristics of poly‐mer microspheres with pore throats are highly consistent. The error is caused by the high-pressure gradient in microfluidic displace‐ment and the end-face effect in core flooding. Considering the macro and micro matching characteristics comprehensively，the opti‐mal matching coefficient for MG-1 with pore throats is around 1.0，with an upper limit of about 1.4. The experimental results show that it is feasible to use microfluidic displacement experiments to replace complex core flooding experiments to evaluate the match‐ing of polymer microspheres with pore throats.

Abstract:In order to solve the problems of high injection resistance and large shear viscosity loss in polymer flooding agents，the microencapsulated polymers with slow-release and thickening properties were prepared by inverse emulsion polymerization and in situ polymerization with polyurethane prepolymer as the shell material and polymer as the core material. The formulation of the emulsion and the parameters for the preparation of the polymer core and the microcapsule shell were determined by a single factor experiment. A stable inverse emulsion was formed under the conditions of a compound emulsifier with an HLB of 6.4，an oil vol‐ume ratio of 50%，and an emulsifier dosage of 10%. Under the conditions of 45% aqueous monomer dosage，certain initiator dos‐age（0.04% of polymeric monomer），reaction temperature of 45 °C，and reaction time of 4.5 h，polymer core materials were pre‐pared with a monomer conversion rate of 98.44% and an apparent viscosity of 13.37 mPa·s in the solution. Under the conditions of a shell material mixing rate of 800 r/min，reaction temperature of 50 °C，reaction time of 4 h，and shell-to-core ratio of 1∶4，micro‐encapsulated polymers were prepared. The surface of the microcapsule shell was smooth and intact，with high sphericity. The char‐acterization results show that the infrared spectrum of the microencapsulated polymer contains characteristic peaks of both polymer and polyurethane，indicating that polyurethane microcapsules have achieved the encapsulation of the polymer. The particle size of microencapsulated polymers is mainly distributed between 300 nm and 500 nm，and the median particle size is 368 nm，with good uniformity and sub-micron size. The initial viscosity of microencapsulated polymers in water is 0.5 mPa·s，which increases to 12.57 mPa·s after 5 d. The viscosity retention rate after 90 days is 94.99%，indicating good slow-release and thickening properties and thermal stability. When the shear speed is 12 000 r/min，the viscosity retention rate of microencapsulated polymers is 98.25%，indi‐cating good shear resistance.

Abstract:Fine layered water injection is a crucial method to enhance oil recovery in high water cut reservoirs. However，the design of water injection layer division and injection-production fluid allocation often lacks coordination，limiting the full realization of process synergy. To address this，under the condition of an unknown optimal number of water injection layers，a mathematical model of fine layered water injection optimization was developed. This model aimed to maximize economic net present value while considering multiple engineering and geological constraints，integrating water injection layer division and injection-production fluid allocation into a unified framework. By leveraging the Dung Beetle Optimizer，a collaborative optimization design method for water injection layer division and injection-production fluid allocation in high water cut reservoirs was proposed，enabling the integrated optimization design of key parameters for fine layered water injection. Using the Egg model as an example，this study compared the effects of three approaches：standalone optimization of injection-production fluid allocation，standalone optimization of layered wa‐ter injection parameters，and integrated fine optimization. The results indicate that for high water cut reservoirs with severe inter‐layer physical property interference，the integrated fine optimization approach significantly outperforms the other standalone meth‐ods by optimizing layer division of layered water injection wells，fluid allocation，and injection-production fluid allocation of other wells. Through automatic layer division and reorganization of water injection layers，coupled with intelligent matching and adjust‐ment of injection-production parameters，the approach effectively alleviates interlayer conflicts during the high water cut stage，op‐timizes the flow fields，and achieves balanced displacement across layers. Over a 5-year production forecast，this approach im‐proves the recovery factor by 1.08 percentage points compared to the pre-optimization scenario.

Abstract:As a classical evolution algorithm，the differential evolution algorithm has the advantages of global search ability，easy implementation，and no gradient. It has been widely used in automatic reservoir history matching. However，the setting of param‐eters in the algorithm has a significant influence on the result of history matching，and there is convergence stagnation in highdimensional problems. In order to solve the above problems，an automatic reservoir history matching algorithm was proposed based on the adaptive mutation strategy and differential evolution algorithm. Firstly，based on the principal component analysis method，the high-dimensional parameters of the reservoir model were reduced，and the reduced parameters were used as the parameters ad‐justed in the differential evolution algorithm to compress the search space of the variables and improve the search efficiency of the algorithm. Secondly，based on the adaptive mutation strategy and differential evolution algorithm，the historical experience in the search process of the algorithm was used to guide the update of the current population. When the individual of the population stopped converging，the mutation strategy of the differential evolution algorithm was switched to change the iterative update mode of the population to avoid the situation that the reservoir parameters stopped optimization and adjustment. In addition，to make the updated model parameters consistent with the prior distribution characteristics，the quantile transformation strategy was applied to transform the distribution of the updated parameters，and the data of non-Gaussian distribution was transformed into Gaussian distri‐bution so that the updated model was more in line with the constraints of the actual geological parameters. The proposed algorithm was tested and verified on a three-dimensional reservoir model. The results show that compared with the traditional differential evo‐lution algorithm framework，the improved differential evolution algorithm can improve the convergence effect of the history match‐ing solution，and the inverted reservoir model parameters are more in line with the actual geological characteristics. Under the same calculation conditions，a better history matching model can be obtained，and the data matching effect is more significant.

Abstract:Gas-water relative permeability measurement is a common method to describe the flow process in gas reservoirs with wa‐ter. However，the results of relative permeability measurements vary significantly between different test methods and types of cores.To deepen the understanding of the microscopic distribution characteristics of fluid and flow mechanism during the gas-water flow process，this paper took YB Gas Field in Sichuan Basin as the research object and used nuclear magnetic resonance（NMR）technol‐ogy to quantitatively describe the microscopic distribution of the two phases before and after relative permeability test. The distribu‐tion results were explained based on the gas-water two-phase flow mechanism obtained by the previous researchers with the visual‐ization model. The results showed that the displacement efficiencies of micron-scale（>1 μm）pores during the water displacing gas and gas displacing water are basically the same with the two test methods，but the displacement efficiency in submicron-scale（0.1–1 μm）and nanoscale（<0.1 μm）pores during water displacing gas is relatively higher. Moreover，the water in the submicron-scale and nanoscale pores is not mainly produced during the gas displacing water. For fractured and porous cores，the displacement effi‐ciencies in micron-scale pores of fractured cores are relatively low，while the displacement efficiencies in submicron-scale and na‐noscale pores are relatively high. The difference in the microscopic distribution of fluids with the two test methods is mainly caused by the different capillary forces inside the pores，while the difference between the two types of cores is primarily due to the differ‐ence in their main flow channels.

Abstract:Surfactants are extensively used in chemical flooding due to their excellent ability to reduce oil-water interfacial tension，alter rock surface wettability，and promote oil-water emulsification. It was previously believed that the middle phase microemulsion could only occur at high surfactant concentrations. Therefore，the evaluation of surfactants for chemical flooding mostly depends on interfacial tension measurement. The role of microemulsion phase behavior technology in the screening and development of surfac‐tants for tertiary oil recovery is neglected. Thanks to the technological advancement in surfactant development in the past two de‐cades，ideal middle phase microemulsions have been achieved by crude oil systems with low acid values at low surfactant concentra‐tions. As a result，it is imperative to use microemulsion phase behavior technology to guide the development of new surfactants and the performance optimization of the composite system. This paper started with the concept and classification of microemulsions and systematically introduced four emulsification types of microemulsions，namely Winsor Ⅰ，Ⅱ，Ⅲ，and Ⅳ. The formation mecha‐nism of the four types of microemulsions was described from the aspects of oil-water interfacial tension，surfactant molecular struc‐ture，and micellar morphology. The mechanism involved instantaneous negative interfacial tension theory，duplex film theory，R ra‐tio theory，and geometric arrangement theory. The microemulsion phase behavior technology was introduced in detail in terms ofphase pattern identification，composition calculation of oil，water，and surfactant in the microemulsion phase，and laboratory op‐eration. In terms of processing results of phase behavior experiments，it was introduced in detail how to calculate the solubilization index of the oil and water phases in the microemulsion through their respective volume changes and how to calculate the interfacial tension between the microemulsion phase and oil and water through the solubilization index，so as to determine the optimal salinity of the composite system. This paper hopes to attract people’s attention to the microemulsion phase behavior technology and promote its application in the research and development of surfactants for high-efficiency tertiary oil recovery，the study of oil displacement mechanism，and the optimization of composite system formulation，thus improving the technical level of compound flooding in China.