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.

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.

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 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 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.

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.

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.

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.

In response to the increasing contradiction between high energy consumption for ultra-heavy oil development and high quality development of oilfield in the context of “carbon neutrality and emission peak” target, Xinjiang Oilfield, through mechanism research and field practice, has continued its research and achieved significant results in maintaining efficient expansion of steam chamber, breaking through reservoir seepage barrier blockage, improving the steam flooding and gravity drainage efficiency in shallow and thin layers, and achieving efficient and balanced fluid production in long horizontal sections of horizontal wells: the gas-assisted technology is employed to achieve the insulation, pressure retention and energy boosting of steam chambers, and the oil-to-steam ratio can be increased by up to 20%; the vertical well pattern and reservoir upgrading and expansion technologies are utilized to improve the seepage characteristics of Class Ⅲ ultra-heavy oil reservoirs, and the drainage rate can be increased by 20% to 40%; the fully confined production method is adopted, resulting in an increase in VHSD produced liquid temperature from 100 ℃ to 150 ℃ and a 50% increase in oil recovery rate; a further research on the mechanism of thermal recovery flow control device (FCD) is conducted, and the reservoir-wellbore coupling optimization design method is improved, so the production degree of the horizontal section of horizontal wells can be increased by 20%. During the “14th Five-Year Plan” period, Xinjiang Oilfield will conduct a further research of solvent-assisted SAGD, waterless SAGD and temperature-controlled hydrothermal fracturing technologies, and gradually improve the series of low-carbon and high-efficiency development technologies for shallow ultra-heavy oil. The research can provide technical guidance for the development of similar reservoirs.

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.

SW Beier Sag is currently a key exploration block with high oil reserves in Hailar Basin. In order to identify the influence of hydrocarbon migration on hydrocarbon accumulation, a "four-in-one” comprehensive determination method of hydrocarbon migration path, which was based on hydrocarbon source analysis, with hydrocarbon distribution characteristics as an indicator, migration numerical simulation as a constraint and geochemical tracing as a supporting evidence, was adopted to study the hydrocarbon migration paths and patterns of Nantun Formation in the study area. The results indicated that there were three hydrocarbon migration paths in Nantun Formation. One path was to migrate laterally from NW Beier Sub-sag to West Beier Slope along its short axis; the second path was to migrate from SW Beier Sub-sag to Huhenuoren Tectonic Belt along its short axis; and the third path was to accumulate hydrocarbon from NW and SW Beier Sub-sags to Huhenuoren Tectonic Belt and migrate to the southwest along the strike of tectonic ridge and fault. On the basis of the identification of migration paths, three types of lateral hydrocarbon migration patterns were summarized, including the migration along the strike of tectonic ridge and fault, the "stepped" migration along synclinal fault and the "toothbrush-like” migration along reverse fault. There were significant differences in the hydrocarbon accumulation sites and reservoir types controlled by the various migration patterns. The results of the study are of some significance for the next selection of favorable zones in the study area and for oil and gas exploration in similar areas.

Abstract: In response to the problem that the basic properties of oxidized carbon and pyrolysis carbon generated in the in situ combustion of super heavy oil in Block Jin 91, Liaohe Oilfield and the in-situ combustion characteristics were not well understood, experiments on low temperature oxidation and pyrolysis of super heavy oil were conducted with reaction still, the composition of produced gas and the micro morphology, element content and thermogravimetric loss of coke were analyzed by gas chromatograph, field emission scanning electron microscope, energy dispersive X-ray spectrometer and thermogravimetric analyzer, and the activation energy of coke combustion was solved by iso-conversional methods (Friedman and OFW). The results showed that, after low temperature oxidation at250 ℃, the super heavy oil was partially converted into oxidized carbon; after pyrolysis at 400 ℃, the super heavy oil was converted into pyrolysis carbon and modified oil. The relative contents of oxygen and sulfur elements in oxidized carbon were significantly higher than those in pyrolysis carbon. The surface of oxidized carbon was characterized by the inter-melted of coke particles with different particle sizes, and the porous structure of oxidized carbon became more obvious with the increase of temperature. The surface pyrolysis carbon became irregular micro blocks, and many raised particles appeared on the pyrolysis carbon surface with the increase of temperature. The formation of oxidized carbon was helpful to establish combustion front; the combustion activation energy of pyrolysis carbon was lower, conducive to maintaining the stable propagation of the combustion front. The study provides a theoretical guidance for the in-situ combustion in super heavy oil development.

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.

The Liaohe Depression has already entered the high maturity stage of exploration. The deepening exploration in mature exploration area cannot be limited to the scope of geophysical technology progress, drilling level improvement and revolution of oil and gas reservior stimulation technology, but should be reflected in the accurate grasping and innovative understanding of the objective existence of subsurface geological conditions. To address the problems that the conventional oil and gas exploration is difficult to achieve oil and gas discovery on a large scale and conventional exploration ideas are difficult to adapt to new unconventional oil and gas targets, the ideas of deepening geological understanding and reconstructing reservoir formation model were applied to innovate reservoir accumulation model in the Qingshui Depression of Western Sag to newly discover oil reserves of 2 800×10⁴t in rocky oil and gas reservoirs; a new "two-element“ evaluation model was created in Leijia area, which realized the surface-to-body transformation of unconventional oil and gas target evaluation; the exploration unit was reconstructed in the Member 3, Shahejie Formation of the Eastern Sag, and a new exploration unit was discovered and the Well X47 was deployed and implemented to obtain high production gas flow. A number of achievements were made during the exploration of oil and gas in mature exploration area of Liaohe Depression, which provided ideas and methodological reference for the exploration of similar type of mature area.

Rational and efficient development of oil shale resources is of strategic significance for energy security and economic development of China. The underground in-situ conversion technology of oil shale had unique advantages compared with surface destructive distillation technology, providing a new direction for oil shale exploitation in the future. In this paper, the development status of underground in-situ conversion technology of typical oil shale was systematically analyzed, and the process characteristics were summarized, such as electric conduction heating, thermal fluid heating, radiation heating and combustion heating. Combined with existing studies, the next study targets were proposed from the aspects of reservoir fracturing, underground reservoir space closure, efficient heating and new energy applications. The study can provide technical reference for green and efficient exploitation of oil shale.

In response to the problems of low water flooding control degree in conglomerate reservoirs and extremely imperfect well networks in Wellblock Bai 21, Baikouquan Oilfield in the Junggar Basin, the reservoir engineering method and reservoir geology are used as guidance to conduct fine research on reservoir architecture by applying dynamic and static data, analyze reservoir structure, sedimentation, reservoir in-homogeneous characteristics and oil and water distribution law, and improve the injection-production well patterns. The study results show that The idea of water injection optimization and adjustment “different strategies for different layer systems, adjustment and control by zone, classification by single well, and optimization of method” proposed in the article is very effective for the Baikouquan Oilfield. By carrying out the study on the distribution characteristics of the remaining oil and the reservoir injection and production well patterns in the Triassic system of Wellblock Bai 21, 56 dominant seepage channels were identified through comprehensive analysis by applying flowline simulation technology, and the submitted producing petroleum geological reserves were 975.00×10⁴t, and the accumulated oil increase was 16.60×10⁴t. This study has a reference effect for the improvement of injection and production well patterns and efficient tapping of similar 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.

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.

In response to unclear sources of associated gas during thermal stimulation by steam injection, laboratory experiments were conducted on crude oil, core and formation water samples from Block Qi 40, Liaohe Oilfield with high-temperature and high-pressure reaction still to explore the generation mechanism and influencing factors of associated gas. The study results showed that, crude oil was the main source of associated gas in thermal recovery and mainly took place in aquathermolysis, and reservoir minerals played a catalytic role in the aquathermolysis; the starting temperature of associated gas production was 150 ℃, and its production increased with the increase of temperature, when the temperature reached 300 ℃, the joint action of aquathermolysis and heavy oil pyrolysis led to a sharp increase of associated gas production; at 250 ℃, the aquathermolysis of crude oil was basically completed after 9 days, after which there was no significant increase in associated gas production. The study is of guiding significance for the full utilization of associated gas in thermal recovery of Liaohe Oilfield by steam injection.

A study on the influence of water saturation on the in-situ hydrogen production effect from heavy oil was carried out through combustion tube experiments to study the feasibility of technology on in-situ hydrogen production during fire flooding in reservoirs after steam injection development. The results show that the presence of water enhances the convective heat transfer effect and provides a high-temperature environment for the fracture of C-C and C-H in hydrocarbons and promotes the reversible reactions such as hydrothermal cracking, coke gasification, and water-steam conversion of heavy oil to move toward hydrogen production, which improves the in-situ hydrogen production effect. The temperature is 715.1 ℃, and the hydrogen volume fraction is up to 1.03% when the water saturation reaches 24.58%. The results verified the feasibility of in-situ hydrogen production from heavy oil during fire flooding in heavy oil reservoirs after steam injection development, and the study has significant reference value for improving the in-situ hydrogen production effect from heavy oil during fire flooding.

The gas storages converted from deep carbonate gas reservoirs are characterized by large high and low pressure variations, stress sensitivity, and strong heterogereity. Using conventional methods to calculate its injection-production capacity will lead to large errors in production capacity. In response to the above problems, stress sensitivity is considered. The binomial productivity equation was revised in view of the influence of stress sensitivity and gas physical property changes, and on this basis, a calculation method of injection-production capacity suitable for the gas storage converted from deep carbonate gas reservoirs was established. Example calculations are carried out in conjunction with the Shapingchang Carboniferous Gas Reservoir in the Sichuan Basin, the influencing factors are analyzed, and the results show that: for type Ⅰ and Ⅱ pore-fracture collocation model reservoirs, the reasonable gas production rate of gas wells is controlled by outflow dynamics under low pressure and limited by erosion flow under high pressure, while the reasonable gas injection rate is controlled by outflow dynamics under high pressure and limited by erosion flow under low pressure; for type Ⅲ pore-fracture collocation model reservoirs, the reasonable gas injection and production rates of gas wells are mainly controlled by the outflow dynamics. The influence of stress sensitivity on the maximum gas injection rate of the gas well is 0.81%~9.69%, and the influence of the change of gas physical parameters is 5.15%~35.29%; under the existing wellbore structure conditions, when the gas injection rate is 55×10⁴ to 70×10⁴ m³/d, the frictional pressure loss can reaches to 10 MPa; when the inner diameter of the tubing increases from 62.0 mm to 112.0 mm, the maximum gas injection volume increases to 2.6 times. The research results can provide technical support for the calculation of the injection-production capacity of deep carbonate gas storages, and have guiding significance for the construction and operation of such gas storages.

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.

Since the PVT test consistency test method is inapplicable to high-temperature reservoirs, a systematic test method was proposed for the consistency of phase state test results in high-temperature hydrocarbon reservoirs, in which the equilibrium constant calculation method at high temperature was used to modify the material balance method, Hoffman method and equilibrium constant method, and to test the consistency between the component data of the phase state test and the constant-volume depletion test data with such two methods and the component verification method, so as to judge the test results more accurately. A consistency test was conducted between the component data and the constant-volume depletion test data of two fluid samples taken from high-temperature hydrocarbon reservoir, namely Condensate Gas Sample A from Well Bozi 104 and Volatile Oil Sample B from Well Bozi 7 in Tarim Oilfield. The results verified the validity and reliability of the method in this paper. This study is important to clarify the phase characteristics of formation oil and gas, especially volatile oil and condensate gas at high temperature.

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.

In view of the strong heterogeneity of the glutenite oil reservoir, an in situ emulsification enhanced oil recovery technology was proposed. The emulsification performance, interfacial tension reduction performance and oil displacement performance of the new W/O emulsification system (DMS) were studied, and at the same time the results were compared with the polymer/surfactant binary system used in the oil field. The experimental result shows that under different water contents, DMS can emulsify with crude oil to form W/O emulsion. With the increase of water content, the viscosity of emulsion increases. When the water content is 70%, the viscosity reaches the maximum value, which is 9 times of the viscosity of crude oil, much higher than the viscosity of binary system, and the fluidity control ability is stronger. DMS can be directionally adsorbed on the oil-water interface and reduce the oil-water interfacial tension to 0.12mN/m. Under the influence of DMS, oil and water are emulsified in situ to form W/O emulsion with a particle size of 0.5-6.0μm. In the glutenite core, DMS flooding and subsequent water flooding can improve the recovery by 18.6%. Under the permeability max-min ratio of 10, dual flooding and subsequent water flooding can improve the recovery by 24.0%, while DMS flooding and subsequent water flooding can improve the recovery by 35.3%, showing better fluidity control and the ability to improve the water absorption profile. The research result will provide theoretical support for enhanced oil recovery of glutenite oil reservoir

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.

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.

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.

A microfracturing-based expansion technology for horizontal wells was proposed to improve the seepage conditions around the horizontal wellbore, because the infill horizontal wells were not connected to the original wells in composite well pattern under steam flooding and gravity drainage in the heterogeneous reservoirs, Qigu Formation, F Oilfield, Xinjiang Oilfield. The feasibility of microfracturing-based expansion technology and the change characteristics of expanded reservoir were analyzed by laboratory core test, geomechanical finite element simulation and thermal numerical simulation. The results show that he reservoir was high in high quartz while low in clay mineral content, and well developed with pores, which was favorable for water flooding for expansion; in the process of stable pressurization, the spread range of the injection fluid was expanded to reduce the effective confining pressure of the surrounding reservoir and significantly improve the expansion effect; the displacement and porosity of the expanded reservoir in longitudinal direction were obviously better than that in transverse direction, which is conducive to the connection of upper and lower injection-production wells. After five rounds of steam stimulation for preheating after microfracturing-based expansion, the oil wells were connected quickly. In the preheating period, the periodic oil production and oil-steam ratio were significantly improved, and the productivity of horizontal section was greatly enhanced. The study results provide a reference for improving the connectivity among injection and production wells in composite well pattern under steam flooding and gravity drainage.