In view of the unclear distribution pattern of in deep high-quality K₁g₃ sandstone reservoirs in Jiudong Oilfield, Jiuquan Basin, the diagenetic characteristics, diagenetic evolution, diagenetic facies and high-quality reservoir distribution of sandstone were studied according to casting slice, scanning electron microscope, physical properties and other data. The results showed that the deep K₁g₃ sandstone in Jiudong Oilfield had three types of diagenetic characteristics, and the sandstone with Type Ⅱ and Ⅲ diagenetic characteristics was developed from Type Ⅰ iron-bearing dolomite cemented tight sandstone under the differential action of acidic dissolution fluid. There were three stages of acid dissolution fluid. The fluid was atmospheric freshwater in the first two stages, and was organic acid fluid in the third stage. The atmospheric freshwater then became a acidic fluid that contributed the most to sandstone dissolution. K₁g₃ sandstone could be divided into 4 types of diagenetic facies and 2 diagenetic facies belts. Type B diagenetic facies were high-quality reservoirs with high porosity and permeability, Type D diagenetic facies were reservoirs with medium porosity and low permeability, and Types A and C diagenetic facies were ankerite-bearing cemented tight and heterogeneous reservoirs. The main oil-producing area to the west of Chang2 Fault was a Type B diagenetic facies band, the expanded-margin area to the east was a Type D diagenetic facies band, and Types A and C diagenetic facies were not developed in general. The study results are of providing important reasons for the development plan adjustment and expanded-margin exploration and deployment of Jiudong Oilfield.

Low-permeability reservoirs are rich in reserves, with great commercial value, but they are defective in poor porosity and permeability, high reservoir heterogeneity, poor water absorption capacity, etc., increasing the technical difficulties in development. To address these defects, the technology of enhancing oil recovery in low-permeability reservoirs was discussed based on extensive reference. The study results show that low-permeability reservoirs (10.0-50.0 mD) were principally developed by polymer flooding, polymer-surfactant binary flooding, microbial flooding and in-depth profile control and surfactant flooding, extra-low-permeability reservoirs (1.0-10.0 mD) chiefly developed by surfactant flooding, foam flooding and nano-material flooding, and ultra-low-permeability reservoirs (0.1-1.0 mD) primarily developed by imbibition, CO₂ flooding, N₂ flooding and air flooding, etc. It is the development trend of low-permeability reservoir development in China to gradually improve the oil-displacement mechanism of the replacement medium, develop economical and efficient environment-friendly oil displacement system and promote its application in the field practice. This study provides technical support for efficient development of low-permeability reservoirs.

CO₂ stimulation technology is effective in enhanced oil recovery conventional and unconventional oil reservoirs. The advances in the application of CO₂ stimulation technology was summarized from in-house laboratory investigation to application and practice in key fields, and the field tests with different technical routes were reviewed and analyzed. The application results indicated that with wide application range in different oil products and different reservoirs, CO₂ stimulation technology achieved good results in the mines at home and abroad. The reservoirs will be developed with the technologies of CO₂ composite stimulation, CO₂ synergistic stimulation, and supercritical CO₂ stimulation and nanoparticle-assisted CO₂ stimulation in the future. Supercritical CO₂ stimulation and nanoparticle-assisted CO₂ stimulation are still under the laboratory experiment. Their practicability should be further studied and verified by field application. In the context of achieving the target of carbon neutralization by 2060, the application scale of CO₂ stimulation technology will be further expanded. This study will also provide technical support for the promotion and application of CO₂ stimulation technology.

Carbon capture, utilization and storage (CCUS) is an effective carbon treatment technology. In the context of carbon neutrality, the CCUS technology in China will usher in a trillion-dollar industrial trend. At present, a significant progress has been made in all aspects of CCUS technology, but large-scale applications still face many challenges. By investigating the domestic and international CCUS technology literature and the CCUS projects in operation and planned to be built worldwide, the current development status and research progress of CCUS technology at home and abroad are summarized, and the challenges and future development prospects of CCUS are further clarified. The study shows that the current carbon capture efficiency is less than 90%, and the cost of carbon capture accounts for 60%-85% of the total cost of CCUS projects. The research and development of carbon capture technology should focus on pre-combustion capture (such as ethanol, ammonia and natural gas processing industries) and post-combustion capture to improve carbon capture efficiency and reduce carbon capture costs; the CO₂ utilization technology is currently at the industrial demonstration stage, and breaking the high-temperature and high-pressure environmental bottleneck and finding suitable catalysts to improve carbon utilization efficiency are the key research directions for the next stage of CO₂ utilization technology; the CO₂ storage in oil and gas fields and saline aquifer shall be further researched and promoted on a large scale in terms of an improvement of CO₂ enhanced oil and gas recovery and an increase of CO₂ storage potential; In CCUS projects, challenges such as achieving economic profitability, technological innovation, cost reduction and efficiency, and policy subsidy incentives need to be overcome; new energy sources coupled with CCUS, such as hydrogen and geothermal energy from oil and gas fields, will become a new model for CCUS promotion in the future. This study has implications for accurately grasping the research direction of CCUS technology, promoting the progress and innovation of CCUS technology, and accelerating the leapfrog development of CCUS technology.

In order to better understand the remaining oil research methods, a comprehensive summary of remaining oil research methods and applications in the world was conducted by means of investigation and research. The result shows that the analysis methods of sedimentary micro-phase, micro structure and reservoir flow unit take the basic geological research as the starting point and are the basis for remaining oil research; the core analysis method, micro-seepage simulation, physical simulation and nuclear magnetic imaging technology are important tools for micro-remaining oil research and describe the characteristics of remaining oil distribution from the micro perspective; the material balance method and numerical simulation technology are important tools for macro-remaining oil research and are also the basic data for oilfield development adjustment; the logging technology, chemical tracer monitoring method, four-dimensional seismic method and other methods are useful supplements to remaining oil research methods; for the dynamic analysis method, the data obtained from multiple disciplines need to be synthesized and applied, debunked, and verified against each other to obtain accurate remaining oil research results. This result provides reference for the study of the remaining oil in the middle and late stages of development.

The theory of the natural gas hydrate petroleum system is applied to discusses the progress of research on the complex dynamic physicochemical process of natural gas formation and decomposition,the research progress,problems and development trend of the natural gas hydrate petroleum system are analyzed,and the following conclusions are obtained:most natural gas hydrate gas sources are closely related to the biodegradation; the main factors affecting the temperature-pressure critical curve of the natural gas hydrate are the components of natural gas and pore water,while the ground temperature gradient and permafrost thickness do not change the gas hydrate temperature-pressure critical curve; the static elements and dynamic processes at critical moments of the gas hydrate petroleum system and the coupling relationship between them play an important role in the gas hydrate petroleum system.The study of the gas hydrate petroleum system not only provides a theoretical basis for the process of gas hydrate accumulation,but also provides technical support for the exploration and development of gas hydrate.

Heavy oil reserves account for more than 2/3 of the discovered crude oil resources in the world. Due to the high viscosity and poor fluidity of heavy oil, its recovery is difficult, with high technical requirements. According to the characteristics of many types and large depth changes of heavy oil reservoirs in China, the current status of heavy oil recovery at home and abroad and the main technical direction of improving recovery efficiency were analyzed and summarized; combining with the field production performance, the adaptability, application potential and main technical challenges of existing commercial recovery technologies to different types of heavy oil reservoirs were discussed. The results show that steam huff and puff is still the main method of heavy oil recovery in China. However, most of the oil fields have entered the end period of production, and the recovery efficiency is low. At present, the application scope of mature replacement technologies (steam flooding, SAGD and in-situ combustion) is limited, so it is urgent to develop new replacement technologies. The series of heavy oil development technologies in the middle and deep layers are relatively mature, but the EOR technologies for deep, ultra-deep and complex types (such as fractured/karst cave) of heavy oil reservoirs are not yet mature. It is of more practical significance and application prospect to strengthen the research on frontier technologies such as generating steam downhole, solvent assisted, in-situ upgrading and gasification. The research results can be used for reference and guidance to expand the research field and direction of heavy oil recovery technologies.

Horizontal wells have obvious advantages in increasing the productioncapacity of oil and gas wells, but influenced by the non-homogeneity of the reservoir, the water breakthrough from horizontal wells is more common during the development of edge and bottom water reservoirs or water drive reservoirs, which brings great challenges to the efficient development of oil fields. Therefore, effective water detection and water plugging technology is one of the important means to improve the development effect of horizontal wells. To address the problem of difficult water breakthrough identification in horizontal wells, the characteristics and field applications of horizontal well water detection methods such as dynamic verification, mechanical water detection, water detection by logging and water detection with tracers were comprehensively summarized, and the problems and development directions of horizontal well water detection and water plugging methods were analyzed. This study can provide a reference for water detection and water plugging in high water-bearing inefficient horizontal wells.

In view of the extremely strong heterogeneity, complex pore structure, significant productivity difference between wells and unclear reservoir quality difference mechanism of tight sandstone reservoir, the quality difference mechanism of tight sandstone reservoir controlled by lithofacies was discussed according to comprehensive core and logging data by taking the tight sandstone reservoir in the Member 8 of the lower Shihezi Formation in southern Sulige Gasfield. It is found in the study that the results show that the reservoir quality was controlled by lithofacies by affecting the diagenetic evolution sequence, and the reservoir quality of the fine conglomerate - pebbled coarse sandstone facies was the best, followed by that of the coarse sandstone facies, with a permeability greater than 1.00 mD, and mainly developed with intergranular pores - necked throats;according to the content of lithofacies and plastic debris, the diagenetic evolution sequence of reservoirs was classified by four categories: coarse lithofacies (collective term of fine conglomerate - pebbled coarse sandstone facies and coarse sandstone facies), medium sandstone facies rich in rigid particles, medium sandstone facies rich in plastic particles, and fine sandstone facies;after experienced diagenetic sequence of weak compaction, strong cementation and strong dissolution, the coarse lithofacies had the best physical properties, and were mostly distributed as isolated lenses in sand in striped distributary channel. This distribution feature is the main reason for the obvious difference in productivity between wells. The study results provide a theoretical basis and guidance for the prediction of high-quality reservoirs and the exploration and development of tight sandstone gas reservoirs.

In view of the shallow burial, high viscosity, and strong heterogeneity of crude oil in shallow super-heavy oil reservoir in Fengcheng Oilfield, there are many challenges in the SAGD development of dual-horizontal wells. This paper aims to study SAGD development technology and supporting technologies of shallow super-heavy oil reservoir, optimize the deployment design of double horizontal wells, design SAGD cycle preheating and reservoir project, and study supporting key technologies such as drilling and completion technologies, downhole string structure, and downhole temperature and pressure measurement. According to development practice and technical and economic indicators, the technical limits of SAGD development for super-heavy oil dual-horizontal wells were formulated, and new technologies to improve SAGD development effects were comprehensively discussed, including composite well pattern development, reservoir expansion and stimulation, and solvent-assisted SAGD. The supporting technologies for shallow SAGD series development provide an important reference for the development of similar gas reservoirs.

In the dual-carbon context, how to economically, efficiently, and greenly enhance the recovery of heavy oil reservoirs by heavy oil recovery technology based on thermal recovery is a key concern of researchers. The essence of realizing commercial development of heavy oil reservoirs is to reduce the viscosity and enhance the flow capacity of heavy oil. The article systematically analyzed the viscosity-inducing mechanism of heavy oil and the viscosity-reducing mechanism of various viscosity reducers, summarized the synthesis processes of emulsifying viscosity reducers, oil-soluble viscosity reducers, and nano viscosity reducers, and evaluated the advantages and shortcomings of different viscosity reducers. The advantages and shortcomings of different viscosity reducers were evaluated. The development trend of viscosity reducers was also discussed and prospected. Sorting out the existing chemical viscosity reducers could help develop new viscosity reducer systems and enhance the recovery of heavy oil reservoirs.

In response to severe restrictions on exploration and development by high heterogeneity and poor physical properties of sandstone in Chang₆ oil-bearing formation in Huaqing Area, Ordos Basin, the accumulation conditions of tight sandstone reservoirs in Chang₆ oil-bearing formation in the study area were studied in depth according to the theories of petroleum geology, sedimentary petrology, and petroleum accumulation dynamics, in combination of various test and analysis data. The results of the study showed that the accumulative conditions of tight sandstone reservoirs in Chang₆ oil-bearing formation in Well Block B257, Huaqing Area were controlled by high-quality source rocks, favorable reservoirs and reservoir characteristics. Finally, two favorable exploration areas were identified based on the sedimentary background, tectonic conditions, reservoir conditions, source rock conditions and production conditions of the oil-bearing formation. This study indicates the direction for the exploration and development of Chang₆ tight sandstone reservoir in Well Block B257, Huaqing Area.

Usually there are multiple injection-production blocks in large depleted gas reservoirs, and too high formation pressure difference between blocks can destabilize the reservoir. In order to achieve balanced variation of formation pressure during the injection and production, an optimization model was established with the minimal variance value of formation pressure between periodic blocks as the objective function. The model combined the mathematical optimization technology with the safety and stability of the gas storage, and takes the number of production wells in each block and the injection and production volume of single well as the decision variables, and takes the total amount of gas injection and production of the gas storage, the maximum injection and production volume of single well, and the maximum formation pressure of the block as constraints. The optimization model was applied to Wen23 gas storage based on a large depleted gas reservoir, and the optimized injection-production solution for the gas storage was successfully solved under the condition of an annual gas working volume of 30×10⁸ m³/a. The results of the study showed that the optimized injection-production scheme can not only reduce the formation pressure difference between blocks and achieve a balanced change in the overall formation pressure in the gas storage, but also effectively avoid the occurrence of extremely high pressure blocks and further guarantee the safe and stable operation of the gas storage, on the premise of meeting the requirements of gas injection-production rate in the gas storage. There is much for reference of the study results for the design of the injection- production solution of the gas storage.

In view of the various problems existing in the current production profile testing for horizontal well staged fracturing, the development direction of horizontal well profile testing technology is further clarified by analyzing and comparing the technical principles and adaptability of such three testing technologies as the distributed optical fiber, the production logging and the tracer monitoring to identify advantages and disadvantages of these technologies and providing an outlook on the development trend of each technology. The research shows: The distributed optical fiber monitoring technology is stable and easy to install, but the storage capacity is large and cannot be interpreted quantitatively; the production logging technology has high precision, but it is not applicable in some cases; the tracer logging involves many types, each with its own advantages and disadvantages; In the future, the in-depth research on logging technology can be carried out from the aspects of technical equipment and data interpretation. This research can provide some technical reference for the field test selection, and also provide some new perspectives for the follow-up technical development.

Heavy oil reservoirs in Liaohe Oilfield have the characteristics of deep burial depth and multiple oil types. In order to explore the effective replacement technology in the later stage of steam injection in heavy oil reservoirs, through indoor physical simulation and field tests, the feasibility of fire flooding after stem flooding was discussed in different types of reservoirs, such as middle to deep or extra deep layered reservoir, thick massive reservoir, water-flooded heavy oil reservoir, and shallow low-permeability heavy oil reservoir. A series of technologies aiming at different types of reservoirs was formed, which include reservoir description technology for fire flooding, indoor physical simulation technology, reservoir engineering design technology, oil production technology, development effect evaluation technology, etc. The recovery degree of the reservoirs after fire flooding had been greatly improved, effectively alleviating the decline in production. The paper discussed the exploration history of fire flooding technology in Liaohe Oilfield, and systematically summarized the supporting technologies of fire flooding for developing different types of oil reservoirs. The research results can provide a reference for the fire flooding development of Liaohe Oilfield and for the similar heavy oil reservoirs.

Water-flooding oil reservoirs in Liaohe Oilfield are characterized by more faults, multiple oil-bearing series, strong reservoir heterogeneity, high shale content and complex reservoir types. In the past 10 years of development practice, combined with the difficulties in water-flooding development of various oil reservoirs, 12 core development technologies have been developed, including deep fine reservoir description, subdividing water-flooding adjustment, identification of inefficient and ineffective water cycle, fine potential tapping by combination of secondary and tertiary recovery, and multivariate injection-production regulation and control, and a set of water-flooding development technologies suitable for medium-high permeability sandstone oil reservoir, low-permeability sandstone oil reservoir and special lithologic oil reservoir have been formed. The annual oil production of water-flooding oil reservoirs has increased from 324×10⁴t/a to 360×10⁴t/a, and the water-flooding recovery ratio has increased by 3.3 percentage points. The technical countermeasures to improve the effect of water-flooding development in old oilfields have certain guiding and reference significance for the same type of oil reservoirs.

In order to clarify the characteristics and exploration and development potential of shale reservoirs in Longyi₁⁴ Sub-bed, Longmaxi Formation, Luzhou Block and to realize the longitudinal three-dimensional development of the shale reservoirs in Longmaxi Formation, Southern Sichuan, Longyi₁⁴ Sub-bed is divided into three single horizons: a, b and c, and their characteristics are analyzed, including shale thickness, organic matter abundance, mineral composition, physical characteristics, reservoir pace type and hydrocarbon showing. The result shows: Class I reservoir of Longyi₁⁴ Sub-bed in Luzhou Block is featured by an average thickness of 35.6 m, a distribution area of about 1 900 km² and geological resources of more than 8 000×10⁸m³, indicating bright prospects for exploration and development. The shale reservoir at Horizon b is of a thickness of greater than 20 m, an average TOC is greater than 2.5%, a content of brittle minerals of greater than 55%, an average porosity of 4.9%, and an average gas content of 4.5 m³/t, which demonstrates superior reservoir conditions. Compared with the current main pay - Longyi₁¹ Sub-bed, the shale reservoir at Horizon b of Longyi₁⁴ Sub-bed has higher clay content and inorganic pore proportion, which requires scientific fracturing technology and shut-in and drainage measures in the exploitation process to achieve better development results. The results of the study will provide technical support for expanding shale gas exploration and development horizons and improving the production degree of shale gas resources in Longmaxi Formation, Luzhou Block.

There are obvious differences in the effective production conditions and recoverability evaluation methods between shale oil and gas and conventional oil and gas. In order to investigate the seepage characteristics of shale oil in micro and nano pores, low-velocity seepage experiment was conducted to study the low-velocity non-Darcy seepage patterns of single-phase fluids in Qianjiang Sag, Jiyang Sag and Eagle Ford reservoirs in typical shale blocks at home and abroad. The results of the study showed that the low-rate seepage characteristics of shale oil were mainly affected by the liquid-solid boundary layer effect, slip length and seepage channel. The seepage curve of Qianjiang Sag was concave. The smaller the pressure gradient, the stronger the fluid-solid interface force, and the more obvious the non-linear section; Jiyang Sag was obviously affected by the development of rock core microfractures, and big pores such as inorganic pores and microfractures were the main flow channels at low pressure gradients, with low surface roughness and tortuosity; as the pressure gradient increased, fluid flowed in the small pores and organic pores; Eagle Ford reservoirs were influenced by the mineral composition and pore structure of the block, and the seepage characteristics presented two linear sections with different slopes, and the resistance to seepage increased as the pressure difference increased. The study clarifies the main characteristics and influencing mechanisms of low-velocity seepage of shale oil in nano and micron pores, providing a theoretical basis for formulating shale oil development plans and guiding the efficient development of shale oil.

With abundant oil and gas resources, Taian-Dawa Fault Zone is one of the most important hydrocarbon-bearing zones in Liaohe Sag. The tectonic characteristics and evolution of the Fault Zone were analyzed to explore the relationship between the tectonic evolution and hydrocarbon accumulation in the Fault Zone. A study was performed on hydrocarbon accumulation mode to work out the effect of Cenozoic tectonic evolution on hydrocarbon accumulation in Taian-Dawa Fault Zone, providing guidance in the optimization of exploration fields and targets of the Fault Zone. The results of the study showed that Taian-Dawa Fault Zone was characterized by both extensional and strike-slip inversed tectonics and its tectonic evolution was divided into three stages: faulting period, dextral slip period and depression period. The tectonic evolution significantly controlled the hydrocarbon accumulation in the Fault Zone, specifically controlling the migration of subsidence center from north to south, the reservoir development, the formation of complex petroleum migration pathways, and the matching between fault activities and hydrocarbon discharge. The hydrocarbon accumulation patterns and favorable exploration areas in the north and south of the Fault Zone were identified, providing a basis for the next exploration deployment in the Fault Zone.

Upper Paleozoic Benxi Formation, Shanxi Formation and Shihezi Formation in Yichuan-Huanglong Area are the chief target formations for exploration and development, and the natural gas enrichment and accumulation are principally controlled by the sedimentary facies and reservoir physical properties. After the evolution of marine-marine-continental transition facies-continental sedimentary system in the Late Paleozoic, the sedimentary facies types are different and the change law of reservoir physical properties is not clear yet. Therefore, the characteristics of Upper Paleozoic reservoirs in Yichuan-Huanglong Area were comprehensively studied with sedimentary evolution analysis, field outcrops, drilling cores, micro reservoir analysis, logging curves and other data. The result shows: Benxi Formation is mainly developed with tidal-flat facies, Shanxi Formation and He₈ Member of Shihezi Formation mostly developed with meandering river-braided delta facies. Tidal channel of Benxi Formation and underwater distributary channel of Shanxi Formation and He₈ Member are the most favorable reservoir facies zones. The sand bodies of the tidal channel of Benxi Formation are lenticular in shape and limited in distribution; the sand bodies of the underwater distributary channel at the front edge of the meandering river delta in Shanxi Formation are migrated and superimposed in multiple periods, with a certain scale; the sand bodies of the underwater distributary channel at the front edge of the braided river delta in He₈ Member are superimposed vertically and connected horizontally, with a blanket-shaped distribution. The reservoir of Benxi Formation is dominated by quartz sandstone, with main pore types of primary intergranular pores and secondary dissolution pores; the reservoirs of Shanxi Formation and He₈ Member are mainly composed of lithic quartz sandstone, with main pore type of lithic dissolution pore. The lithology and pore structure of the Upper Paleozoic sandstone reservoir are the main factors affecting the hydrocarbon showing. The reservoir as a whole is characterized by extra-low porosity and ultra-low permeability, but the content of quartz in the rock gradually decreases from bottom to top, the content of rock chip and fillings gradually increases, and the lithology and pore structure of the reservoirs gradually become worse from Benxi Formation to Shanxi Formation and He₈ Member. The sand bodies of the thick tidal channel of Benxi Formation and the continuously superimposed distributary channel of Shanxi Formation and He₈ Member are lithologically pure and coarse-grained, with good physical properties and high gas abundance, and they are the dominant reservoirs, will the high-quality pores developed in Benxi Formation, which is easy to accumulate natural gas. There is much for reference of the study results to the exploration, development and reserve enhancement of Yichuan-Huanglong Area.

In order to clarify the distribution law of overlying oil and gas reservoirs formed by fault conduit in hydrocarbon-bearing basins, based on the study of the conditions required for the formation of overlying oil and gas reservoirs by fault conduit, a set of prediction methods for the favorable site of overlying oil and gas reservoirs formed by fault conduit were established by determining and overlapping the distribution area of underlying oil and gas reservoirs, the area not sealed by the fault-caprock matching of underlying oil and gas reservoirs, the area sealed by the fault-caprock matching of overlying oil and gas reservoirs and the favorable site for oil-gas migration through faults, and applied to the prediction of the favorable site for the formation of hydrocarbon reservoirs from the fault-conducted Nantun Formation to the Damoguaihe Formation in the Hodomol Area of the Beier Sag in the Hailar Basin. The result shows that the favorable site for the formation of hydrocarbon reservoirs from the fault-conducted Nantun Formation to the Damoguaihe Formation in the Hodomol area of the Beier Sag in the Hailar Basin is mainly located within the 3 local areas of the nucleus of the Hodomol nasal structure, which is conducive to the formation of overlying oil and gas reservoirs from the fault-conducted Nantun Formation to the Damoguaihe Formation in the Hodomol Area of the Beier Sag, which coincides with the current distribution of discovered oil and gas in the Damoguaihe Formation in the Hodomol Area of the Beier Sag, indicating that the method is feasible for predicting favorable sites of overlying oil and gas reservoirs formed by fault conduit. The research method has important guiding significance for the exploration and development of overlying oil and gas reservoirs formed by fault conduit in hydrocarbon-bearing basins.

A great breakthrough was made in the field of Permian volcanic rock exploration in Jingyan Area, southwest Sichuan Basin, but there are various volcanic rock types, obvious differences in seismic reflection characteristics, little coring data, thin reservoirs and unclear distribution patterns; therefore, it is important to further identify the distribution of volcanic facies and high-quality reservoirs in Jingyan Area for volcanic oil and gas exploration in the area. A forward model of volcanic reservoir was established based on the real drilling data to simulate the factors affecting the variation of seismic reflection characteristics of volcanic rock, and an identification model was established for volcanic rock facies and reservoirs. On the basis of the analysis on single well cycle, lithology, lithofacies and seismic waveforms, the types and distribution of volcanic facies were determined by seismic facies, stratigraphic thickness, coherence cube, three-dimensional visualization and other methods. After fine calibration of volcanic reservoirs, the distribution of upper and lower volcanic reservoirs was determined by wave impedance, neural network inversion and other method. Finally, the areas developed with high-quality reservoirs were delineated in combination with the favorable lithofacies, reservoir thickness, fault, and fracture distribution of volcanic rocks. The study results show that there are three types of lithofacies developed in Jingyan Area, namely, eruptive facies, volcanic channel facies and overflow facies. The distribution of volcanic rocks is relatively stable, and two reservoirs are developed in this area. The development of reservoir under the eruptive facies has an obvious effect on the seismic reflection at volcanic rock bottom. As predicted by various methods, the high-quality reservoirs of volcanic rocks are mainly distributed in the west and southwest of the work area, and the superimposed area of basement rift and fractures is the next target of favorable area exploration. There is much guiding significance of the study results for the exploration of volcanic oil and gas in Jinyan Area.

Glutenite fan reservoir is one of the important reservoir types for enhancing reserve and productivity in Shengli Oilfield. In view of the problems of strong heterogeneity and low accuracy of reservoir description, on the basis of core observation, logging response analysis and seismic forward modeling, the glutenite fan in Well Y22 in the northern slope of the Dongying Sag was finely divided with well-to-seismic integration into subfacies and microfacies by such methods as fine stage division, synthetic record calibration, and numerical simulation. It is found in the study that the different sedimentary structure of sedimentary subfacies of glutenite fan brought about different reflection characteristics, and the sedimentary subfacies could be easily distinguished by waveform clustering attribute; the middle-fan subfacies of the glutenite fan in the Yanjia Area was mainly developed with two sedimentary microfacies, namely braided channel and water channel, the lithology of the braided channel was mainly composed of thick pebbled sandstone deposit, and the edge of the water channel was composed of interactive deposit of mudstone and pebbled sandstone; the regional lithology could be easily distinguished with AC, R_LLD and CNL logging curves, and accurate description by well-to-seismic integration of sedimentary subfacies and microfacies of the glutenite fan based on logging curves and variogram simulation, under the constraints of sedimentary facies and tectonic stage models. This technology can accurately describe the sedimentary facies zone of the glutenite fan, and provide technical support for the deployment of glutenite fan exploration and later productivity construction.

Nearly 20 passive continental margin basins developed on both sides of the South Atlantic Ocean, and a number of major oil and gas discoveries obtained in deep-water areas, however, a lack of understanding of the geological characteristics of the passive continental margin basins resulted in the low level of exploration in deep-water areas, and the amount of oil and gas resources to be discovered was enormous. For this reason, on the basis of comprehensive analysis of a large amount of data and cases, and fully combining the study results and understanding in recent years, the key geological characteristics of the passive continental margin basins in the middle and southern part of both sides of the South Atlantic Ocean were systematically summarized, and the impact of the geological features on the exploration of oil and gas was deeply analyzed. The study shows that igneous rocks of 3 orogenic types and 3 active phases are widely developed throughout the rifting period in the basin complex on both sides of the South Atlantic Ocean; in the southern section, the thick, seaward-tilted reflective wedges are widely developed in the volcanic passive continental margin basin; in the middle section, the salt rock planar distribution and thickness change rule of the salt rock development type basin complex has both similarity and difference between the two banks, and the salt cementation of the subsalt sandstone reservoir may occur; dirty salts are developed in the Gabon Basin, Santos Basin, Campos Basin, and Lower Congo Basin; the Kwanza Basin in the middle section of West Africa has become the only saltstone-hard gypsum-carbonate interbedded sedimentary basin on both sides of the South Atlantic Ocean due to the cyclonic evaporation pattern, and the thinner inter-salt carbonate layer is both a hydrocarbon source rock and a reservoir. The above geologic characteristics have a great impact on the prediction of the subsalt seismic imaging, subsalt reservoirs, hydrocarbon source rocs and inter-salt carbonate rocks, and increase the multiplicity of solutions for seismic exploration. This study provide a basis for the precise positioning of the future technical attack direction of the passive continental margin basin.

In view of the unclear genesis of calcite veins in 8# Coal Bed of Benxi Formation on Eastern Margin of Ordos Basin, the calcite vein development stages were analyzed to determine the source and formation time of vein-forming fluids by micro petrography, isotope geochemistry, fluid inclusion and other methods. The study results indicated that calcite veins (C1 and C2) in Stage 2 were developed in 8# coalbed in the study area, the diagenetic fluids of C1 calcite veins were mainly stratigraphic brine and biogas-rich organic fluids from surrounding rock and parent rock, the diagenetic fluids of C2 calcite veins were mainly liquid hydrocarbon fluids formed by the decarboxylation of organic matter, and meanwhile the formation of C1 and C2 calcite veins was affected by deep hydrothermal fluid formed by Early Cretaceous tectonic thermal events. Combined with the analysis of the hydrocarbon formation and burial history in the study area, it was clear that C1 calcite veins were formed from Late Triassic to Early Jurassic and C2 veins were formed from Late Jurassic to Early Cretaceous. Production of 8# coalbed in the study area, the calcite vein development area had a high degree of CBM enrichment, indicating bright prospects for exploration and development. The study results provide an important reference for the exploration of CBM-rich areas.

In view of great difficulties in the exploration of Permian shale gas under complex geological conditions in Xuancheng Area, Lower Yangtze Block, an effective shale gas exploration method under complex geological conditions is explored by applying a joint exploration with high-accuracy gravity prospecting, high-precision magnetic method and complex resistivity method (CR method) based on rock property testing. The study shows that The shale of Gufeng Formation in Xuancheng Area is characterized by "low magnetic intensity, low density, medium low resistivity and high polarization", the carbonaceous siliceous shale characterized by low resistivity and high polarization, and the intrusive rock (granite porphyry) that mainly affects Gufeng Formation characterized by "low magnetic intensity, low density, low resistivity and low polarization". In the shale gas exploration at Gufeng Formation, Weidun Belt, Xuancheng Area, high-accuracy gravity prospecting and high-precision magnetic method are applied to identify the areas with low magnetic intensity and low gravity and to deduce the distribution of rock mass. Then, CR profile is arranged in the area where magmatic rock is not developed, and wells are drilled for verification at the locations with low resistivity (less than 1 000.00 Ω·m) and high polarisation (more than 4.00%). A total of 50.89 m thick carbonaceous siliceous shale and siliceous mudstone of Gufeng Formation are drilled, achieving excellent application effect. This study provides an important guide to the identification of organic-rich shale formations and the selection of shale gas "sweet spot" in Xuancheng Area and even in the area with complex geological conditions in Lower Yangtze Block.

Deep HPHT wells have the characteristics of complex wellbore temperature field changes and large changes in the physical properties of drilling fluids, multiplying the difficulties in accurate prediction of the equivalent circulating density (ECD) of drilling fluid. To this end, based on the drilling data of deep HPHT wells in a study area in the South China Sea, the characteristics of response between the equivalent static density and rheological parameters of deep water-based drilling fluids and the temperature and pressure were investigated by means of PVT meter and rotary viscometer. The parameters of empirical model were fitted based on experimental data, while the ECD calculation model of deep HPHT wells was improved with consideration of the influence of temperature and pressure on the physical parameters of drilling fluid and the influence of subsea pressurization on the flow field and temperature field of wellbore. The study showed that, the physical properties of the water-based drilling fluid were greatly affected by high temperature and pressure, and the higher the displacement of the subsea booster pump, the higher the ECD in the wellbore. The model was used in the calculation of Well ST362-1d well in the South China Sea, and the average error was only 0.249% between the predicted value of ECD model and the measured value. The results of the study can serve as references for the optimal design of hydraulic parameters and wellbore pressure control in deep HPHT wells.

Tight sandstone reservoir in Wuqi Oilfield is disadvantaged by poor physical properties, complex pore structure, serious heterogeneity, and poor water injection effect. In response to these shortcomings, the pore structure characteristics and clay mineral composition of Chang₆ Oil-bearing Formation in Wuqi oilfield were analyzed with high-pressure mercury porosimetry, scanning electron microscope and X-ray diffraction and other tests. Nine pore structure parameters were selected as characteristic parameters, and a comprehensive evaluation standard based on reservoir pore structure was established. The reservoirs were divided into three categories: Type I (excellent), Type II (moderate) and Type III (poor). The rock samples of each type of reservoir were evaluated for sensitivity and analyzed for influencing factor. The results of the study show that the sensitivity of the three types of reservoirs was significantly different. Specifically, Type I presented low velocity sensitivity, low water sensitivity, moderately low salt sensitivity, moderately high acid sensitivity, and moderately low alkali sensitivity. Type II presented moderately low to low velocity sensitivity and water sensitivity, moderate to low salt sensitivity, low acid sensitivity, and moderate to low alkali sensitivity. Type III presented moderate to low velocity sensitivity, low water sensitivity, low salt sensitivity, moderately low to low acid sensitivity and low alkali sensitivity. The pore structure and clay mineral composition were the main reasons for the difference in reservoir sensitivity. The study results can provide a reference for optimizing water injection and reservoir stimulation for similar tight oil reservoirs.

Tight sandstone gas reservoirs are characterized by low porosity, low permeability, complex pore structure, and poor pore connectivity, and are susceptible to severe damage by the water blocking effect. For this reason, according to the water blocking mechanism and reservoir conditions of tight sandstone gas reservoirs, long cores corresponding to the formation were selected. Pressure loss evaluation and permeability damage evaluation experiments under different reservoir conditions and different water blocking degrees were carried out. Two concepts were proposed, namely pressure loss rate and permeability damage rate, to characterize the damage degree of water blocking effect to the pressure propagation process and reservoir permeability. The results show that: in the process of gas field development, the water blocking effect badly damages the reservoirs with poor physical properties and low gas permeability, and preventive measures should be implemented in advance; reservoirs with better physical properties and higher gas permeability can be determined whether optimization measures are needed based on the value of its pressure loss rate and permeability damage rate. For different reservoirs, the reasonable implementation of the water unblocking process is of great significance to the production and economic benefits of gas wells.

Geosteering drilling pre-prospecting technology can effectively improve drilling efficiency and success rate. There are three types of geosteering drilling pre-prospecting technology: near-bit pre-prospecting, seismic-while-drilling pre-prospecting, and azimuth electromagnetic wave pre-prospecting. With case study of exploration and development of complex oil and gas reservoirs, methods widely used in the geosteering drilling pre-prospecting technology were analyzed and summarized, including near-bit measurement, R-VSP, VSP-WD, bed boundary mapping, reservoir mapping while drilling, and looking ahead while drilling. All kinds of geo-steering pre-prospecting technologies can be used for measurements in different ways, but they all have certain limitations. There is a need for pre-prospecting tehcnologies to conduct further studies on the improvement of prospecting accuracy and the combined application of multiple methods, so as to provide strong technical support for casing setting depth design, formation pressure prediction, mud density window setting, detailed description of complex oil and gas reservoirs, and drilling trajectory optimization for the application of pre-prospecting technologies. The study can provide a strong reference for domestic research and field application of geosteering drilling pre-prospecting technologies.

In view of the great difficulty in classifying Carboniferous volcanic rock reservoirs in Kebai Fault Area 1 and the inconsistent classification standards, eight important parameters affecting the classification of volcanic rock reservoirs in this zone are analyzed according to the drilling, logging, testing and other data. The parameters such as lithology, lithofacies, matrix porosity, fracture porosity, permeability, reservoir space type, lithofacies thickness and volcanic mechanism facies zone are assigned according to the reservoir characteristics of the research area and related reservoir classification data are calculated. Combined with the reservoir classification results of each single well, the classification method and classification standard of Carboniferous volcanic rock reservoirs in the research area are obtained. The study results show that according to the classification indicators of volcanic rock reservoirs, the Carboniferous volcanic rock reservoirs in Area 1 can be divided into three types: Type I (0.6≤RCI<1.0), Type II (0.4≤RCI＜0.6), Type (III 0.0≤RCI<0.4), among which Type I reservoirs are the best, Type II reservoirs are the better and Type III reservoirs are the worst. The research results are applied to the reservoir classification of 16 wells that are not involved in the formulation of the standard, and the accuracy rate reaches 93.8%, indicating that the classification standard is suitable for the research area. The research results have important guiding significance for the classification and prediction of Carboniferous volcanic reservoirs in this zone.

To address the problem that there are many kinds of calculation methods for the thickness of irreducible water film in tight reservoirs, and the method cannot be accurately selected in the actual research, the calculation methods and influencing factors of irreducible water film thickness in tight reservoirs are summarized in recent years. The study shows that the calculation methods for irreducible water film thickness in tight reservoirs are divided into macroscopic calculation methods based on the ratio of irreducible water film volume to pore throat surface area and microscopic derivation methods that simplify the matrix into capillary model or from the perspective of microelements; the irreducible water film is divided into initial water film, post-displacement water film and post-imbibition water film, and the thickness of the initial water film is influenced by the relative humidity, reservoir depth and permeability of the reservoir, and the thickness of the post-displacement water film is influenced by the displacement pressure, permeability and porosity, and the post-imbibition water film thickness is influenced by the water saturation, ion mass concentration and matrix composition. This study has implications for the selection of calculation methods for the irreducible water film thickness in tight reservoirs and the study of recovery enhancement.

CO₂ geosequestration technology is an important method to mitigate the greenhouse effect, and the evaluation of leakage risk in geosequestration system is a prerequisite to ensure the safe and efficient sequestration of CO₂. To address the risk of CO₂ leakage, the influence of wellbore and caprock factors on the risk of CO₂ leakage in CO₂ geosequestration system was systematically discussed, including the quality of cementing, CO₂ corrosion and damage to the wellbore assembly by alternating stress, as well as the influence of caprock-formation ratio, caprock thickness and lithology on low-speed seepage and high-speed leakage of caprock. Finally, the wellbore leakage risk evaluation method, the caprock leakage risk evaluation method and the CO₂ sequestration system leakage risk evaluation method based on the combined action of the above influencing factors were discussed, and the advantages and disadvantages of different evaluation methods were pointed out. The study provides theoretical support for site selection, formation selection and leakage risk evaluation in CO₂ geosequestration works.

To explore the mechanism of enhancing the oil recovery of tight oil reservoirs by surfactant combined with low-salinity water flooding, in a study case of a tight sandstone reservoir in Xinjiang Oilfield, the effects of low-salinity water flooding, surfactant flooding and their combination on the recovery efficiency at different injection rates and solvent ratios are studied with self-made test equipment. The result shows: The surfactant combined with low-salinity water flooding can effectively play the synergistic advantages to improve the recovery efficiency of tight oil reservoirs. When the injection rate is too low, the surfactant can effectively modify the pore throat interface, but the energy of water flooding is insufficient. When the injection rate is too high, it is easy to induce the coning of oil-water interface, and the effect of surfactant on modifying the pore throat interface is limited, leading to oil displacement efficiency increasing first and then decreasing with the increase of injection rate. At the injection rate of 0.3 mL/min, the highest oil displacement efficiency of 89.79% is achieved with a 7∶3 mass ratio of low-salinity water (0.1% NaCl mass fraction) to sodium dodecyl-benzene sulfonate anionic surfactant (0.4% mass fraction), which is at least 29.83% higher than that of single-fluid flooding. The field application shows that the surfactant combined with low-salinity water flooding can effectively enhance oil recovery and increase monthly production by about 47% in tight reservoirs where the production is severely depleted per well. The study results can be referred for efficient development of similar tight oil reservoirs.

To address the problems of low recovery rate and poor water injection huff-n-puff effect in the depleted development of Jimsar shale oil. A study on the applicability of CO₂ huff-n-puff technology in shale oil reservoirs was carried out by means of hydrocarbon phase experiments and numerical simulation methods for reservoirs to guide the implementation of CO₂ huff-n-puff technology in the field. The results show that Compared with CH₄, CO₂ interacts better with Jimsar shale oil. Under the conditions of formation pressure and formation temperature, the solution gas-oil ratio of CO₂ in crude oil is 497.83 m³/m³, the crude oil viscosity is reduced by 70.65%, and the crude oil volume is expanded by 2.05 times; for typical shale oil wells, multi-cycle CO₂ huff-n-puff can improve the recovery rate by 9.43 percentage points and crude oil production by 31 472.40 t. With the shortening of fracture spacing and the increase of reservoir porosity, the effect of CO₂ huff-n-puff on oil enhancement gradually becomes better, and the influence of permeability and oil saturation on the effect of CO₂ huff-n-puff is relatively small. The results of the field test show that CO₂ huff-n-puff can effectively enhance the recovery rate of shale oil, and the oil enhancement effect is better under the condition of no fracture disturbance. The research results have some implications for the efficient development of shale oil.

To address the problems of unknown oil source conditions, sandbody sedimentary patterns, effective reservoir distribution and reservoir formation patterns in Subu Area, various methods such as geochemical analysis, detailed sandbody characterization and rock-mineral analysis were employed to analyze the hydrocarbon accumulation conditions in this area from three aspects, including source rock, reservoir conditions, and facies reservoir-capping assemblage, and elucidate the reasons for the vertical development of multiple abnormal pore zones. The results of the study proved that there were three accumulation modes for reservoirs in this area, including "transverse tectonic aggregation and favorable sandbody accumulation" of conventional reservoir, unconventional "tight glutenite oil and gas reservoirs" and "shale oil and gas reservoirs", and the hydrocarbon reservoirs were middle-shallow conventional reservoir and deep unconventional reservoir longitudinally and distributed as oil reservoir belt, oil-gas mixed belt and gas reservoir belt from shallow to deep. The study results were effective in the guidance for exploration breakthroughs in the area, handover of reserves and further exploration targets of the southern subsag, Ulyastai Sag.