The authigenic acid acidizing technology is one of the main measures for stimulation high temperature (ultra-high temperature) and low permeability tight oil and gas reservoirs. The research progress of authigenic acid acidizing technology was comprehensively analyzed, and the acid-rock reaction characteristics of authigenic acid, the main acid-generating mechanism of authigenic acid, and the research progress of authigenic organic acid, authigenic hydrochloric acid, authigenic hydrofluoric acid and composite authigenic acids were introduced, the influence of the type of authigenic acid, hydrogen supply capacity, cost, retardation capability, corrosion inhibition capability and other factors on the field application of acidizing work fluid was analyzed, and the application of authigenic acid in acidizing operation was prospected. This study can provide a reference for the development, popularization and application of autogenic acid acidizing technology.

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.

The conventional acid fracturing working fluid system has problems such as too fast acid-rock reaction and short effective distance, the microencapsulated solid acid is one of the effective means to solve this problem, and it is commonly used for deep acid fracturing of unconventional oil and gas reservoirs. This study describes the mechanism of action, structure and performance characteristics of microencapsulated solid acids, summarizes the research progress of acid fracturing technology with microencapsulated solid acid, and indicates the main research directions of acid fracturing technology with microencapsulated solid acid in the future. This study can provide technical support for the stimulation of ultra-high temperature carbonate reservoirs, and provide theoretical guidance for the research and application promotion of acid fracturing technology with microencapsulated solid acid.

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.

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.

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.

For the change in unpropped fracture conductivity after fracturing in tight sandstone gas reservoirs, an experimental method for unpropped fracture conductivity evaluation with fracture wall simulation was established to investigate the damage mechanism of conductivity in terms of the microscopic morphology, roughness, strength and other aspects of the fracture wall, and to clarify the variation law of fracture conductivity. The study shows that after the fracture was exposed to water, the wall clay was hydrated and compacted under stress, and the average height of the wall was decreased by 8.5%; meanwhile, the fracture wall was softened and the average hardness decreased by 34.3%. The more frequent the change in production nozzle size, the higher the conductivity of the unpropped fracture under high stress; the fracture conductivity of the third well opening was 91.7%-98.5% lower than that of the first well opening; the conductivity of misaligned fractures was 18.1-140.4 times that of non-misaligned fractures. With the formation water displacing fracturing fluid after fracturing, the conductivity of the final fracture was 3.45 times that of the original fracture. In this paper, the conductivity damage mechanism in the production of tight gas reservoirs was defined, and the variation law of unpropped fracture conductivity under the action of different factors was clarified, which provides a basic theoretical basis for the protection of unpropped fractures in tight sandstone gas reservoirs.

To reveal the macro heterogeneity of shale oil reservoirs in the Chang 7 oil reservoir formation, Ganquan area in the southeastern part of the Yishan Slope, Ordos Basin and its control on oil distribution, the macro heterogeneity of the Chang 7₁ and Chang 7₂ oil reservoir sub-formations was quantitatively characterized and compared by means of barrier bed and interbed identification statistics, permeability statistics and Lorenz curve construction, and the influence of macro heterogeneity on oil distribution was analyzed by the method of correlation analysis and multifactor overlay. The results of the study show that the average number of interbeds developed in the Chang 7₁ and Chang 7₂ shale oil reservoirs in the study area is 3.8 and 5.1 respectively, and the permeability of the sand body is dominated by composite rhyme and is strongly heterogeneous; the average number of barrier beds developed is 3.4 and 2.8 respectively, and the average thickness of single barrier bed is 6.0 and 4.9 m respectively; Chang 7₁ exhibits slightly weaker intra-layer heterogeneity and stronger inter-layer heterogeneity than Chang 7₂. The rhythmicity of the shale oil sandstone reservoir has obvious influence on the oil saturation, and the barrier bed with thickness greater than 10.0 m have obvious capping effect on oil and gas, while the "physical" barrier beds and interbeds constitute lateral shielding for oil and gas accumulation. The barrier bed is more developed in Chang 7₁ than Chang 7₂, and the oil and gas are more abundant in Chang 7₂. In the plane, the distribution of oil-gas accumulation area is strip-like, mostly located in the area with large sand thickness, good continuity and permeability of greater than 0.2 mD.The thickness of oil layer varies slightly in the direction of sand body extension along the river, but varies more in the direction of vertical river extension. The conclusion of the study can provide theoretical reference for the evaluation of the favorable area and the selection of development parameters for the Chang 7 sandwich type shale oil in the southeastern part of the Yishan slope of Ordos Basin.

In order to clarify the generation and decomposition characteristics of methane hydrate and its influencing factors, a high-pressure fully transparent double-reactor test platform was designed and built to conduct initial and secondary generation and decomposition tests of methane hydrate with high-purity methane and deionized water as the study objects. During the tests, the samples were stirred or not stirred to make a comparison. The experimental results showed that the hydrate generation included four stages: induction, rapid generation, slow generation and stabilization. Stirring could promote the hydrate generation. At the speed of 400 r/min, the lower reactor consumed 93.6% more methane than the upper reactor. Meanwhile, the memory effect was more obvious, and the induction time in the secondary generation was shortened by 62.5 %, and the methane consumption was increased by 254.0% compared with the primary generation. There is much for reference of the study for the development of hydrate.

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.

It is difficult to exploit the crude oil with conventional technology due to high viscosity, high flow resistance and poor flow capacity of crude oil in heavy oil reservoirs. A conclusion was made in this paper to summarize the study of heavy oil modification additives (catalysts and hydrogen donor), point out the existing problems, and outline the future study directions. The study shows that the existing heavy oil modification catalysts are disadvantaged by unclear catalytic mechanism, poor universality, high cost, regeneration difficulties, easy deactivation and environmental pollution. In addition, the uneven mass transfer and severe reaction conditions of hydrogen donor in heavy oil modification reaction will lead to limited hydrogen supply. Therefore, the future study of heavy oil modification additives is to further explore the modification mechanism of heavy oil at the molecular level, and develop modification additives with wide application scope, high activity and controllable cost in combination with complex formation conditions. The study provides a reference for studying and developing heavy oil modification additives and applying the EOR technology in oil fields.

The Dina 2 condensate field in Tarim Oilfield is a fractured sandstone gas reservoir with characteristics such as high temperature and high pressure, low porosity and low permeability, and medium-high cementation strength, and the traditional view is that there is no sand production problem for this type of reservoir, but since the start of production in 2009, sand samples have been taken from 21 wells and the sand production is common, which has become a key technical problem affecting the stable production of the gas field. To this end, a porous elastic-plastic 3D sand production fluid-solid coupling model was established, and a numerical simulation method was adopted to carry out a full range of sand production rate prediction for the Dina 2 Gasfield. The study shows that the sand production process in Dina 2 Gasfield can be divided into four stages according to the sand production rate: small amount of sand production, incremental sand production, intensifying sand production and stable sand production; the area of heavy sand production is around Wells X-6, X-7 and X-8, and the amount of sand production gradually decreases from the middle of the gas field to the surrounding area, and the key sand production layer is located in E1-2 km² Formation of Kumugeliemu Group. It was verified on the basis of the field measurement data that the prediction error of the sand production rate is within 15%, indicating the practicality of the prediction method. This study can provide technical support for the formulation of reasonable sand control measures and efficient development of the oilfield.

In order to deepen the understanding of the diagenetic environment, evolution mode and pore development mechanism of the reservoir in the Second Member of Shahejie Formation of Qibei Slope, the characteristics of alkaline environmental diagenesis, diagenetic evolution mode, alkaline environmental genesis mechanism and its influence on pore development of the dense sandstone reservoir in the Second Member of Shahejie Formation were studied by means of rock (cast) thin section, scanning electron microscopy and X-ray diffraction analysis. The results show that there are various alkaline environment diagenesis phenomena in the reservoir, such as quartz dissolution, multi-phase carbonate mineral cementation and metasomatism, anhydrite metasomatism and alkaline clay mineral assemblage; the current reservoir diagenctic stage is in the mesogenetic A₂ sub-stage, and the diagenetic environment has experienced alkaline-acidic-alkaline changes during the whole diagenetic evolution; in the early diagenetic stage, the formation of the alkaline diagenetic environment was closely related to the saltwater lake basin environment in the same sedimentary stage. In the mesogenetic A₂ sub-stage, due to the enrichment of metal cations, the acidic water source was reduced and heavily depleted, resulting in the increase of the pH value of the pore water medium and a return to the alkaline diagenetic environment; the multi-phase carbonate cement formed in the alkaline environment filled the pores in large quantities, which significantly reduces the reservoir space, and at the same time, the early alkaline fluid medium in the reservoir also suppressed the dissolution modification intensity of the acidic fluid to the reservoir, but the quartz dissolution in the alkaline environment formed a large number of secondary pores, which is the main mechanism of pore development in the reservoir within the study area. The research results are of guiding significance for predicting the distribution of high-quality reservoirs in the study area.

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.

In view of the problems of production decline of unconventional gas wells, large differences and low accuracy in the EUR (predicted ultimate recovery factor) results, the theoretical basis and advantages and disadvantages of the various methods such as Wattenbarger linear flow method, PLE power exponential decline model method, and SEPD extended exponential decline model method were compared and analyzed to evaluate the objects of use, required data and applicable conditions of various methods. At the same time, the prediction results of the four models of PLE, SEPD, Duong and LGM in the linear flow stage and the quasi-boundary flow stage were compared with the prediction results of the numerical simulation well, and practical applications were carried out. The research result shows: Various commonly used production decline methods for unconventional gas wells are suitable for different formation flow regimes; Wattenbarger linear flow, quasi-constant flow pressure, and horizontal well multi-stage fracturing model are more suitable for flow conditions with variable production and variable bottom-hole pressure. PLE and Duong models are more accurate for prediction within 2a. This study provides a reference for production prediction of unconventional gas wells.

In order to further clarify the detailed description of the distribution characteristics of the micro remaining oil in the reservoir in the middle and high water-cut stage, CT nondestructive analysis was combined with conventional displacement test to analyze the distribution characteristics and influencing factors of micro remaining oil in different displacement stages by means of in-situ comparison technology. The results show that the production effect of micro remaining oil is affected by the size of micro pore throat, the connectivity of pore throat and the spatial distribution of pore throat, etc. The characteristics of remaining oil distribution and occurrence are affected jointly by the main driving force formed by various micro forces and the micro pore throat structure. In the water flooding stage, the production effect is mainly affected by the micro-pore structure, the micro remaining oil in the large pore channel with good connectivity can be migrated for a long distance, with high production effect, while the oil droplets in the small channels with poor connectivity will only be thinned slightly along the edge, with poor production effect. Polymer-surfactant composite flooding is followed by water flooding is conducted, the heterogeneity of micro-pore throat distribution is the most important factor affecting the production effect, and the production effect of low-permeability and high-permeability cores with high micro-heterogeneity is more obvious. Different injection and production strategies should be applied in different development stages of the oilfield. Homogeneous intervals with large pores should be selected for development in water flooding stage, while heterogeneous intervals with poor water flooding sweep effect should be preferentially selected for development in the polymer-surfactant composite flooding stage. The results of the study are of guiding significance for the occurrence and enhanced oil recovery of micro remaining oil in the reservoirs.

The shale oil resources in Member 2 of Kongdian Formation of Cangdong Sag, Bohai Bay Basin are abundant, but there are few studies on the reservoir characteristics, occurrence, mobility and its correlation. To this end, the argon ion polishing field emission scanning electron microscopy, neutron scattering, high pressure mercury injection and low-temperature nitrogen adsorption experiments are adopted to describe the microscopic pore structure of the shale oil reservoir in Member 2 of Kongdian Formation, to compare the difference in pore volume before and after extraction with the saturation-centrifugal NMR results, and to reveal the characteristics of shale oil occurrence and mobility. The results of the study show that in the shale oil in Member 2 of Kongdian Formation, the nanometer-sized intra-granular pores, dissolution pores, organic pores and micron-sized micro-fracture and other reservoir spaces are mainly developed; the shale oil is mainly occurred in the pores with diameters ranging from 20-40 nm and 80-200 nm; the high saturation of movable oil in the felsic shale indicates that it has better pore connectivity and seepage capacity, which is conducive to the transportation of shale oil. The mineral content and pore structure in shale reservoirs jointly control the mobility of shale oil. Pores with a pore size less than 50 nm have a larger specific surface area and have a stronger adsorption capacity for shale oil, which is not conducive to the flow of shale oil. The study results have important guidance for the exploration and development of shale oil.

To further improve the evaluation accuracy of CO₂ storage potential in saline layer, a new method for calculating the theoretical tectonic CO₂ storage volume was proposed based on the material balance equation of CO₂ tectonic storage process and the accurate calculation of underground volume of CO₂ storage. As found in the results, the error of theoretical tectonic CO₂ storage volume calculated by the new method was smaller than that of area method and volume method, which was only about 10%; the new method can predict the theoretical tectonic storage volume under both CO₂ pressurized and pressure-retaining underground storage conditions; both theoretical tectonic CO₂ storage volume and formation pressure showed a trend of increasing with the increase of injection time or injection-production ratio. The new method is of great significance to the study of CO₂ tectonic storage and real-time dynamic control.

To address the problem of unclear distribution of high-quality reservoirs in He8 Member in Daning-Jixian Area, the reservoir development characteristics and influencing factors were analyzed from petrology and mineralogy, diagenesis and other aspects by using cast thin section, X-ray diffraction, cathodoluminescence and scanning electron microscope. The results show that the rock type of the He8 member reservoir is mainly lithic quartz sandstone, and the lithology is mainly of medium and coarse sandstone; the type of reservoir space includes intergranular dissolution pore, feldspar dissolution pore, lithic dissolution pore and clay mineral intercrystalline pore, etc. The reservoir has low-porosity and low-permeability physical properties, but it is a dense reservoir with good porosity-permeability correlation; the compaction is the main factor for the dense reservoir in the study area, the average compaction reduction rate is 80.16%, the average cementation reduction rate is 17.00%, the dissolution can improve the reservoir properties, the average dissolution increase pore rate is 7.34%; the high-quality reservoir does not exist in the middle or at the top or bottom of the sand body, its development in the sand unit follows the distribution pattern “Upper and lower sides of the sand body center”; under the influence of factors such as compaction resistance, dissolution conditions and various types of cementation properties, the high-quality reservoirs are mostly developed in quartz sandstone and medium and coarse sandstone. The research results can provide reference for the accurate prediction of high-quality reservoirs in the study area.

To improve the development effect of oil wells after fracturing in tight reservoirs, based on the Block ZD of Henan Oilfield, the permeability-stress sensitivity relationship of matrix and fracture was determined by fracture-variable-conductivity physical experiments, and the numerical simulation was applied, to determine the optimal values of CO₂ huff-n-puff parameters in different reservoirs of tight oil reservoirs. The result shows that in the injection and shut-in stages, the affected area of CO₂ is getting wider and wider, the crude oil viscosity in the affected area decreases significantly, and the CO₂ is produced with the crude oil in the production stage, and the range of production is larger; the oil exchange rate increases and then decreases with the increase of CO₂ injection volume or shut-in time, which is positively correlated with the CO₂ injection rate and negatively correlated with the huff-n-puff period; the better the reservoir physical properties, the lower the optimal CO₂ injection volume and injection rate, and the shorter the optimal shut-in time and the longer huff-n-puff cycles. The CO₂ huff-n-puff test was carried out in Well ZA4121 in four types of reservoirs, and the accumulated oil increment was 303.4 t, which achieved a good development effect with an oil exchange rate of 0.16 t/t. The research results can provide reference for the study and application related to CO₂ huff-n-puff after fracturing in tight reservoirs.

The stratigraphic space stacking pattern and sedimentary characteristics of alluvial fan controlled by paleo gully geomorphology are more complicated, making it difficult to conduct the study of sedimentary characteristics with existing model. Guided by the research results of the modern Baiyanghe alluvial fan and combined with seismic, core, well logging, physical properties, oil-bearing characteristics and other data, the fluvial alluvial fan controlled by paleo gully geomorphology in Shawan Formation, Chunguang Oilfield was systematically studied in terms of palaeogeomorphology, lithofacies characteristics, microfacies distribution and other sedimentary characteristics, and a dynamic sedimentary evolution model was established. The results of the study show that this area was featured by two-channel paleo gully geomorphology, and the formation went through the filling process of gully-filling-progradation-retrogradation, with unbalanced deposition. Limited by the regional location, sedimentary subfacies were developed only at the middle and rear of the fan. The early stage was a flood period, and the fan was dominated by sedimentation. Controlled by the paleo gully geomorphology, the restricted channelized fan deposits were also developed. From the middle to the end of the fan, gravity current deposition was converted to traction current deposition. The late stage was a flood regression period, and with the filling and consolidation of the strata, the unrestricted fan deposits were developed and dominated by sheet flow deposit. On the basis of fine identification of sedimentary microfacies, the classification and evaluation criteria for reservoirs were established, the study results were applied to the northwest of Chunguang Oilfield, and three favorable areas were selected, and new wells were deployed to achieve breakthrough in the paleo-gully alluvial fan reservoirs. The study results have deepened the understanding of sedimentary evolution characteristics of alluvial fans controlled by different landforms and have important significance for the study of sedimentary characteristics of paleo-gully alluvial fan reservoirs.

Numerical simulation of acoustic wave is very important for the study of anisotropy characteristics of shale and the study of shale acoustic wave correction in highly inclined well. In order to study the anisotropic characteristics of shale acoustic wave, an equivalent shale model composed of argillaceous and sand layers was established on the basis of equivalent medium theory, the calculation methods of the stiffness coefficient and acoustic wave velocity of the equivalent shale model were derived from the elasticity theory, and the influences of the elastic parameter, thickness, angle and density of the lamina on the stiffness coefficient and the elastic wave velocity of the equivalent shale model were analyzed. The study shows that the thickness ratio of argillaceous layer to sandy layer affected the stiffness coefficient of equivalent medium. The stiffness coefficient of equivalent shale model increased with the increase of parameter ratio. Lamet coefficient of argillaceous layer affected the relationship between P-wave velocity and lamina angle and the extreme value of S-wave velocity, but had no effect on SH wave. The acoustic wave velocity was increased with the increase of shear modulus or parameter ratio of the argillaceous layer, and the shear modulus had a great effect on the relationship between the three wave velocities and the lamina angle. When the lamina density was constant, the P-wave velocity was decreased gradually and stabilized with the increase of lamina angle, the S-wave velocity increased first and then decreased, and the SH wave velocity decreased gradually. When the lamina angle was constant, the three wave velocities were decreased gradually with the increase of lamina density. This study plays a guiding role in the shale acoustic numerical simulation and acoustic logging correction.

In order to study the stimulation mechanism of dimethyl ether (DME) in the development of heavy oil reservoir, reveal its mass transfer law in both oil and water phases and its swelling and viscosity reduction effect on heavy oil, a heavy oil sample from a certain block in Dagang Oilfield was selected to carry out PVT and sand-packed tube displacement experiments under high temperature and high pressure conditions. The results show that DME is a good viscosity reducer for heavy oil, easily dissolved in water and more easily dissolved in crude oil, and has strong diffusion effect in both oil and water phases; the water can be used as a carrier to inject DME into the subsurface, and the carrying capacity of DME can be increased by adding ethanol or ethylene glycol; for heavy oil with low viscosity, the DME water flooding can be carried out on the basis of water flooding, with significant oil increase effect, while for heavy oil with high viscosity that cannot form effective drive For heavy oil with high viscosity that cannot form effective displacement, the water or CO₂ can be considered as a carrier for DME huff-n-puff. The study results are of great significance for the application of DME in the production of heavy oil.

To address the problem of unclear microscopic pore structure characteristics of tight sandstone in Block XAB, by using the experiments such as high-pressure mercury injection (HPMI), nuclear magnetic resonance (NMR), cast thin section (CTS) and scanning electron microscopy (SEM), the microscopic pore distribution and connectivity characteristics of tight sandstone reservoirs in Block XAB was studied; the relationship between parameters such as effective pore throat radius, effective porosity and effective movable porosity and macroscopic physical properties was clarified, and the microscopic and macroscopic characteristics of typical pore structure reservoirs was identified and evaluated. The results of the study show that the target reservoir had many pore types and a wide range of pore sizes, but the overall pore size was less than 2 μm, and the pore throat was dominated by large pore-fine throat ink bottle type connectivity; the pore throat with pore size larger than the effective pore throat radius had a small proportion of the total pore volume, but it contributed more than 90% to the permeability; the pore size distribution range measured by NMR was wider than that of HPMI, and the effective movable porosity excluded the existence of unmovable water in the isolated large pores; there was a strong positive correlation with the effective porosity obtained by HPMI, and a high index relationship with the permeability; the pore throat radius had an important role in controlling the microscopic pore structure and macroscopic reservoir quality; the target reservoir pore structure can be classified into three types, i.e., type Ⅰ, Ⅱ and Ⅲ, and the average effective movable porosity was 2.93%, 0.78% and 0.15%, respectively, as the reservoir pore structure parameters became worse. The study results are of great significance for the effective evaluation of the target reservoir and its efficient development.

To address the problem of difficult quantitative diagnostic techniques for tight oil horizontal well production profiles, the tight oil horizontal well temperature profile predicting model is used as the forward model, and a tight oil horizontal well distributed temperature sensing (DTS) data inversion model is established based on the simulated annealing (SA) algorithm, forming a DTS-based tight oil horizontal well production profile interpretation method, to achieve the quantitative inversion interpretation of the tight oil horizontal well production profile and fracture parameters. The result shows that the tight oil horizontal well temperature profile is sensitive to the following factors in descending order: fluid production, fracture half-length, permeability, integrated heat transfer coefficient of wellbore, porosity, fracture conductivity, and thermal conductivity of reservoir rocks, and the main controlling factors affecting the temperature profile of tight oil horizontal wells are fracture half-length and formation permeability distribution. The inversion model was used to invert the measured DTS data from three different production stages of one field well, and the average compliance rate between the production profile interpretation results and the commercial software interpretation results was 87.39%, which verified the reliability of the production profile interpretation method for tight oil horizontal wells. The study results have important guidance for the quantitative interpretation of the tight oil horizontal well production profile.

To understand the sedimentary characteristics and sedimentary patterns of the Triassic Shaofanggou Formation in the North Santai High area of the eastern Junggar Basin and clarify the constraints on reservoir development, a study on the sedimentary patterns of the Shaofanggou Formation and its control on reservoir development was carried out on the basis of sedimentology and in combination with the data such as core, thin section, grain size and conventional physical properties. The study shows that there are nine typical petrographic types developed in the Shaofanggou Formation, namely channeled interlaminated conglomerate phase, platy interlaminated conglomerate phase, massive laminated conglomerate phase, channeled interlaminated sandstone phase, platy interlaminated sandstone phase, massive laminated sandstone phase, wave-formed sand laminated sandstone phase, parallel laminated siltstone phase and massive laminated mudstone phase; the Shaofanggou Formation is mainly dominated by braided river delta phase, and the sedimentary microphases include 10 types such as floodplain, abovewater braided river channel, channel bar, natural dike, underwater braided river channel, interdistributary area, underwater natural dike, estuary bar, prodelta mud and beach bar, among which, underwater braided river channel, estuary bar and beach bar reservoirs have the best physical properties, with average porosity of 17.31%, 20.66% and 21.81%, and average permeability of 6.89, 7.05 and 12.98 mD, respectively. The reservoir properties in this area are mainly controlled by sedimentation, and the high-quality reservoirs are mainly developed in underwater braided channels, estuary bar and beach bar microphase. The study can provide a theoretical basis for further fine exploration and development of oil and gas within the study area.

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 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.

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.

In view of poor understanding of the tectonic development pattern and hydrocarbon accumulation law in Damiao Sag, Erlian Basin, the tectonic development pattern, reservoir development mode, and hydrocarbon accumulation law and high yield of Damiao Sag, Erlian Basin were studied based on the sedimentary facies study and logging-seismic joint inversion technology, so as to determine the resource potential and favorable target areas of Damiao Sag, Erlian Basin. The study results show that alluvial fan - fan delta - lake sedimentary system is mainly developed in the early stage of Damiao Sag; the glutenite in the alluvial fan, the fine sandstone in the remote distal bar and the glutenite in the shallow lake are developed with excellent reservoirs, and the semi-deep and deep lake mudstone is developed with good source beds; the favorable hydrocarbon accumulation is mainly distributed around hydrocarbon-rich sags, and Ai′ershan Formation and Member 1 of Tengge′er Formation are selected as the favorable exploration targets in Damiao Sag, Erlian Basin, with an estimated resource of 150.44×10⁴t, one well deployed, and an expected production capacity of 10 t/d. The study results are of great significance for the development of replacement areas of favorable oil and gas resources in Erlian Basin.

Aiming at the geological characteristics of marine carbonate gas reservoirs in Qixia Formation in northwest Sichuan such as complex structure, ultra-deep burial, high temperature and high pressure, thin reservoirs and well-developed fractures, an embedded discrete fracture numerical simulator was prepared with ant tracking technology and embedded discrete fracture numerical simulation method on the basis of 3D seismic data to optimize the parameters of gas reservoir development and predict the development potential of gas reservoirs. The results showed that, it was more suitable to employ ant tracking technology to predict natural fractures in the early stage of gas reservoir development, and the embedded discrete fracture numerical simulator, compared with conventional reservoir simulators, had incomparable advantages in capturing the fluid that migrated in fractures, significantly improving the numerical simulation accuracy of fractured gas reservoirs; the development well type was optimized as highly deviated well and horizontal well for Qixia Formation gas reservoirs, the reasonable spacing between development wells was 1,600 to 1,800 m, the optimal length of horizontal well was 600 m, and the optimal half-length of artificial fracture was 100 m. There is much for reference of the study results for the efficient development of similar carbonate gas reservoirs.

Nanoparticles are widely used in oil and gas reservoir development because of their extremely small size, large specific surface area and low dosage, but little research has been reported on the phase permeability curves of nanofluids. Therefore, through literature research, the effects of factors such as the number of capillary, wettability, temperature and net effective pressure on the shape of phase permeability curves before and after the oil displacement by nanofluids are reviewed, the mathematical modeling methods for constructing the phase permeability curves are summarized and discussed, and the method of obtaining phase permeability curves that is applicable to nanofluids is preferred in combination with the characteristics of nanofluids. This study can provide certain theoretical references and guidance for the accurate acquisition of phase permeability curves of nanofluids, the establishment of numerical models of phase permeability and the in-depth study of the mechanism of oil displacement by nanofluids.

The direction of shale gas exploration has gradually changed from medium-deep shale to deep shale, but the unclear differences in the pore structure characteristics of medium-deep to deep shales and the unknown controlling factors have restricted the understanding of the reservoir formation and accumulation mechanism of deep shale gas. To this end, a comparative study of geological characteristics, rock characteristics and pore structure of the medium-deep to deep shales of the Longmaxi Formation in the Changning and Dingshan areas of southern Sichuan Basin was conducted on the basis of field emission scanning electron microscopy (SEM), high-pressure mercury injection, nitrogen adsorption experiments and organic geochemical parameters. The study shows that: The differences in carbonate minerals and quartz content between the medium-deep and deep shale samples in the southern Sichuan Basin are relatively large, and the medium-deep and deep shale samples both have higher clay mineral contents; the organic matter of the medium-deep shale in Changning area is uniformly developed but with small pores, and the dissolution pores and intergranular pores are more developed, whereas the primary intergranular pores and organic matter pores of the deep shale in Dingshan area are more developed, and the organic matter pores are larger; the pore volume and specific surface area of the medium-deep shale in Changning area are mainly contributed by micropores, whereas the pore volume and specific surface area of the deep shale in Dingshan area are mainly contributed by mesopores and macropores; the differences in mineral components caused by different depositional environments are one of the main factors resulting in the differences in the pore structure of the 2 sets of shales. The research results are of great significance for further understanding of the reservoir formation mechanism of deep shales.

To address the problems of difficult fluid evaluation while drilling for Palaeocene reservoirs in the Southwest Zone of Bozhong Sag, strong multi-solution, and contradictory response characteristics of mud logging and well logging data, a water content analysis based on light hydrocarbon sensitive parameters, well field light hydrocarbon carbon ring dominance analysis, biodegradation analysis based on alkane series comparison, and a method for evaluating well field light hydrocarbon fluids based on mathematical algorithms such as principal component analysis and support vector machine were established, and the example applications were performed. The evaluation results show that the reservoir water content plate based on light hydrocarbon sensitive parameters and the biodegradation degree interpretation plate based on alkane series comparison are effective in identifying fluid properties in the study area; the well field light hydrocarbon carbon ring dominance analysis method can be used for comparative analysis of reservoir genesis and origin, and has obvious advantages over conventional mud logging methods in evaluating fluids in complex reservoirs with multi-stage charging; the light hydrocarbon analysis method based on mathematical algorithms such as principal component analysis and support vector machine has a high compliance rate of about 85% in evaluating the fluid properties of complex reservoirs. This technical method has been applied in the study area with good results, which provides a new idea for the evaluation of complex reservoir fluids while drilling and has a good application prospect.

To address the problem that conventional reservoir numerical simulation software cannot accurately simulate the fracture propagation during the development of pressure drive water injection of tight oil; based on the dynamic fracture propagation law during the development of pressure drive, the fracture propagation model is organically coupled with the oil-water two-phase seepage model of tight oil reservoir, a pressure drive water injection model was established, and the problem was solved by the finite difference method. The model was applied to the five-point injection and recovery well network of Well Cluster X8 in an oilfield to study the production dynamic characteristics of pressure drive development under high-speed constant displacement and step increasing displacement. The result shows that the injection displacement is positively correlated with the fracture propagation velocity; under the same injection displacement, the fracture propagation speed in the near-wellbore zone of the water injection well is faster; dynamic fracture made the pressure and injected water propagate along the fracture propagation direction; in a five-spot pattern well network with a cumulative injection volume of 3×10⁴m³, compared with the step increasing displacement with high-speed constant displacement method, the fracture propagation length is increased by 11.9 m, and the oil-water front edge migration lags by 4.2 m; corresponding to corner wells, the effective time was 5 days later, the water breakthrough time was 31 days later, and the staged recovery degree was 0.45 percentage points higher; the step increasing displacement pressure drive method improved the affecting area of the injected water, delayed the water breakthrough time of the production well, and improved the development effects of the reservoir. The research results can provide technical support for pressure drive development water injection design of tight reservoirs.

Block J-XC is a common heavy oil reservoir with high porosity and permeability, shallow reservoir burial, and thin thickness. Due to high viscous resistance in the water flooding process, small effect range of water flooding, low reservoir productivity and low recovery rate by water flooding, it is necessary to change the development method and employ polymer flooding method to enhance the oil recovery. On the basis of polymer injectivity evaluation, the injection parameters and injection-production relationship of polymer flooding were optimized by core flow test and numerical simulation, including the mass concentration of polymer injection, injection volume, injection rate, well pattern, well spacing, injection-production ratio, so as to obtain the best injection parameters and injection-production relationship. The result shows that the injectivity and high utilization efficiency of the polymer were actualized under the conditions of 2 100×10⁴ relative molecular mass of the polymer, 1 500 mg/L injection mass concentration and 0.400 times of pore volume; the optimal reservoir engineering parameters were a five-spot pattern, a reasonable injection-production well spacing of 150 m, an injection rate of 0.070 times the pore volume per year, and an injection ratio of 1.1 to 1.2 for different thicknesses of oil reservoirs according to their optimal single-well daily injection volumes. The pilot test in the field proves the significant effect of increasing oil and decreasing water cut in the target well cluster. As of June 2021, the cumulative injection rate of polymer is 0.228 times the pore volume, and the cumulative oil increase is 5.06×10⁴t, the recovery factor is enhanced by 6.75 percentage points and the water cut is decreased by 15.8 percentage points. There is much for reference of the results to the optimization of polymer flooding parameters and reservoir engineering design in shallow ordinary heavy oil reservoirs.

To address the problem that the main controlling factors of single shale gas well production in Weiyuan Block, Sichuan Basin are unknown, based on the geological and engineering data and production data of 132 gas wells which have been put in production for more than a year in the area, an analytical study was conducted by the gray correlation method. The study shows that, the main controlling factors affecting the first-year cumulative production of a single shale gas well are proppant dose, number of fracturing stages, median vertical depth of horizontal wells, fracturing section length, fracturing fluid volume, porosity, pressure coefficient and sanding intensity. It was clear that the machine learning method was higher in accuracy after comparison of the machine learning method and the traditional empirical formula method to predict the first year's cumulative output and initial output. Meanwhile, based on the analysis of the main controlling factors, the machine learning method applicable to the study area was preferably selected as the support vector machine method, and its prediction accuracy was higher than 90%. The study has an important implication to the productivity evaluation of similar shale gas blocks.

In view of the problems of high condensate oil reservoir, cold damage caused by wax precipitation and low recovery efficiency by water flooding, were the microbial high throughput sequencing analysis and experimental evaluation method for chemical flooding and used the core physical simulation and CT scanning and other means to propose the enhanced high pour-point oil recovery technology through microbial + chemical compound flooding combination and research the microbial-chemical compound flooding formula. The system has the advantages of chemical flooding greatly improving the oil displacement efficiency and microbe reducing the waxy composition of crude oil. Finally, the slug combination of microbial and chemical flooding formula is optimized by physical model experiment. The experimental result shows that: The microbial + chemical compound flooding can improve the oil displacement efficiency by 35.19% than the water flooding, and if compared with the single chemical compound flooding, it can improve the oil displacement efficiency by 7.27%, and the oil increment increases by1.16 t/t. This research provides an effective replacement technology for the mode conversion and enhanced oil recovery in the late development stage of high condensate oil reservoir.

To deepen the understanding of the sedimentary environmental characteristics and organic matter enrichment mechanism of the marine shale of the Wufeng Formation-Longmaxi Formation in the Zigong area of the southern Sichuan Basin, a comprehensive study was carried out on the sedimentary environmental characteristics of the Well Z303 by conducting experiments on organic geochemistry and elemental geochemistry. The results of the study show that: The organic matter abundance of marine shales in the target area is high, with an average TOC content of 2.15%; the mineral composition is dominated by quartz and clay minerals, and the redox environment is the main controlling factor for organic matter enrichment in the Zigong Area; the organic matter enrichment conditions during the deposition period of the Wufeng Formation and Lower Longmaxi Formation are more superior than those during the deposition period of the Middle and Upper Longmaxi Formations, forming favorable shales rich in organic matter and high in brittle minerals.It is the preferred target for shale gas exploration and development in the study area.