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.

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.

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 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.

In response to the problem of high longitudinal non-homogeneity and unclear mechanism of hydraulic fracture initiation and propagation in grain-type shale oil reservoirs, the combination of discrete element fracture simulation and hydraulic fracturing physical modeling experiments was used to study the influence of factors such as vertical geostress difference, viscosity of fracturing fluid, pumping process, and perforation cluster spacing on the fracture propagation pattern of grain-type terrestrial shale oil reservoirs. The results show that: The de-viscosity and slip of weak structural surfaces between layers is an important reason for the stagnation of longitudinal propagation of fracture height in grain-type shale oil reservoirs, and the smaller the vertical principal stress difference is, the easier the laminar surfaces are activated, and the growth of fracture height is suppressed; the use of alternating pumping of high-viscosity and low-viscosity fracturing fluids is conducive to the realization of balanced longitudinal and transversal propagation of hydraulic fractures, and the realization of 3D development of reservoirs; the reduction of the perforation cluster spacing and the increase in the number of perforation clusters can significantly increase the area of hydraulic fractures and the reservoir drainage area. The study results are of great significance for realizing the deep penetration stimulation of grain-type shale oil reservoirs in the longitudinal direction and increasing the production of a single well.

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

To address the issues of low single-well production capacity,immature engineering technology,and difficulty in development profitability of China's normal pressure shale gas,and to explore reasonable development approaches,taking Fayetteville Shale Gas Field in the United States and Dongsheng Shale Gas Block in China as examples,based on the geological characteristics of the two gas fields,the evaluation and comparison are conducted in terms of favorable area evaluation,single well productivity and engineering costs.The study shows that the evaluation of favorable areas for shale gas in Dongsheng Block is comparable to Fayetteville,but Dongsheng Block is still in the early stages of development,with greater burial depth and more complex geological conditions.It is necessary to combine the characteristics of later development,learn from the experience of Fayetteville,and further refine and deepen the zoning classification evaluation.The modes of Fayetteville and Dongsheng Shale Gas Field are partition compound development.The supporting engineering technology is gradually improved.For all that,the intensity of block fracturing fluid and sanding in Dongsheng are lower than those in Fayetteville,resulting in a lower average single well EUR.Continuous studied is needed.Both Fayetteville Gas Field and Dongsheng Block adhere to the goal of continuous cost reduction.The comprehensive cost per well keeps decreasing,but further efforts are required in Dongsheng Block,aiming to lower the comprehensive cost per well to within 3 000×10⁴ to 3 500×10⁴ yuan.The geological resources of normal pressure shale gas in China are abundant,which is the main source for enhancing reserves and production.By further clarifying favorable areas,tackling supporting engineering technologies,reducing overall costs,the comprehensive benefit development will be realized,which is of great strategic significance for the long-term stable production of shale gas in China.

As a new technology to enhance oil recovery, nanofluid flooding has advantages over traditional surfactants and polymer solutions flooding. However, the current research on the mechanism of this technology is not systematic. Based on the research progress of nanofluids at home and abroad,this study summarizes the main EOR mechanism of nanofluid flooding. Meanwhile,the current difficulties faced by this technology and the future research direction are pointed out.The results show that the EOR mechanism of nanofluids flooding includes: reducing oil-water interfacial tension;forming a wedge-shaped film in three-phase (oil-water-solid) zone, which results in the pressure of structural separation; improving the mobility ratio to expand the swept area; altering the wettability of rock;enhancing foam stability; reducing injection pressure and selecting the porous channels of water plugging.Future research can focus on improving the stability of nanofluids, reducing costs, conducting synergistic studies on the mechanisms of enhanced oil recovery, and developing efficient nano-flooding systems.This study lays a theoretical and experimental foundation for the large-scale application of nanofluids in enhanced oil recovery process.

To address the problem of poorly understood structural characteristics of weathered volcanic reservoirs and lack of effective delineation methods, the four phase patterns of weathered volcanic rocks are established and classified from top to bottom, namely, strongly weathered clay phase, weathered hydrolysis phase, weakly weathered leaching and disintegration phase and unweathered parent rock phase, by taking weathered volcanic rocks in Shixi High, Junggar Basin as a study object and combining petrophysical experiments, FMI imaging data and comprehensive well logging and mud logging data. The weathered volcanic reservoir composite index and weathering composite index were constructed by using well logging data to finely classify the phases of weathered volcanic rocks, and the weakly weathered leaching and disintegration phase was clearly defined as the dominant phase of weathered volcanic rocks. The application in Shixi High, Junggar Basin is remarkable and provides a reference for the study of phases of the same type of volcanic reservoirs.

The deep shale gas of Wufeng Formation-Longmaxi Formation in the western Chongqing is an essential area for the next exploration and development of shale gas in China. However, the shale petrographic components in this block are complex and spatially variable, and the fine description of the distribution characteristics of sedimentary facies and lithofacies is lacking, which affect the identification and preference of shale gas “sweet spot” sections. To this end, the sedimentary facies and lithofacies of the deep shale of Wufeng Formation-Longmaxi Formation in western Chongqing were studied in detail through core thin section, scanning electron microscopy, Xray diffraction, FMI imaging, nuclear magnetic resonance, organic carbon analysis and other research tools. The results show that the whole study area is in the deposition of offshore shelf phase, which can be divided into three subfacies: shallow water shelf, semi-deep water shelf, and deep water shelf that have different controlling effects on the shale gas; 10 main lithofacies are developed, and the lithofacies are more stably deposited from the northwestern to the southeastern part of the area, and Longyi₁¹ layer develops three main lithofacies: siliciclastic shale, mud-rich siliciclastic shale, and mud-siliciclastic shale. According to the distribution characteristics of the sedimentary facies and lithofacies, it is predicted that the resource potential of this section in Well Z203 Area is huge, and it is a favorable exploration area in the next step. The results of this study deepen the understanding of the vertical distribution of shale reservoirs in the study area and provide data support for the subsequent efficient development of shale gas.

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.

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.

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.

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 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.

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.

Sichuan Basin is rich in marine shale gas resources. From Paleozoic to Cenozoic, the basin has experienced multiple tectonic movements, forming complex structural styles and variable sedimentary environments, featuring with uneven distribution of shale gas resources. In order to clarify the distribution law of high-quality shale, taking the Longmaxi Formation shale in southern Sichuan-eastern Sichuan Region as an example, comprehensive analyses including whole-rock X-ray diffraction, geochemical testing, basin simulation, and drilling and logging data analysis were conducted. The distribution law and main controlling factors of high-quality shale were discussed from the perspectives of sedimentation, reservoir formation, and structure, and favorable areas for shale gas exploration and development were delineated. The results show that high-quality shale in the southern Sichuan-eastern Sichuan Region is mainly distributed in the semi-deepwater to deepwater continental shelf facies; an R_o value of 2.5% to 3.5% is conducive to the development of high-quality shale; and fold structures play a significant controlling role in the enrichment and distribution of shale gas. The research results can provide theoretical basis for shale exploration and development in southern Sichuan-eastern Sichuan Region.

To address the issues of unclear understanding of the variation law of clay minerals and micro-porosity structure within low permeability tight sandstone reservoirs before and after water flooding, the Chang 2 and Chang 6 Reservoirs in Yanchang Oilfield of Ordos Basin were taken as research objects. The types and contents of rock and clay minerals, the characteristics of microscopic pore throat structure are studied by using experimental methods such as casting thin sections, X diffraction and high pressure mercury intrusion, and the variation law of reservoirs before and after water flooding was analyzed. The results show that the microscopic heterogeneity of Chang 6 tight reservoir is stronger than that of Chang 2 low permeability reservoir. After water flooding, the content of illite/Montmorillonite mixed layer and illite in Chang 2 Reservoir increased, chlorite content and illite/smectite mixed layer ratio decreased, and the content of illite/smectite mixed layer, chlorite content and illite/smectite mixed layer ratio in Chang 6 Reservoir decreased. When the pore throat radius is large, the injected water improves the pore throat. On the contrary, the pore throats are damaged by the injected water. The larger the core permeability is, the faster the pressure propagation velocity is, the faster the injected water advances, and the more water is visible at the outlet end. This study can provide technical reference for water flooding development of low permeability tight sandstone 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.

The rapid decline of fracture flow conductivity after fracturing of salt-bearing reservoirs leads to the rapid decline of production, so the enhancement of fracture flow conductivity becomes the key to improve the development effect of this type of reservoir. By taking the salt-bearing reservoir in Mahu area of Junggar Basin as the research object, and based on the mineral component data of the reservoir, the salt content of the reservoir was classified, and based on this, the creep performance of the reservoir and the dissolution law of the salt rock, as well as the influence of the proppant particle size, the sanding concentration, and the fluid medium on the flow conductivity were investigated, and the effects of the creep effect of the reservoir, the salt dissolution effect, and the embeddedness of the proppant on the fracture width were quantitatively analyzed. The study shows that: The higher the salt mineral content of the salt rock, the more obvious the characteristics of its creep mechanical behavior; the higher the temperature, the lower the fluid mineralization and viscosity, and the higher the rate of salt dissolution; the fracture width is mainly affected by the embedment effect of the proppant, the creep effect of the salt-bearing reservoir and the salt dissolution effect on the fracture surface, and the embedment effect of the proppant and the creep effect of the salt-bearing reservoir lead to a decrease in the fracture width, and the fracture width increases due to the dissolution effect of the salt rock on the fracture surface. The fracturing fluid and high-concentration, large-size proppant prepared by using clear water can significantly enhance the fracture conductivity. The research results have been successfully tested in the field and show the direction for efficient fracturing of salt-bearing reservoirs.

In order to clarify the distribution characteristics of tight reservoirs in the Upper Triassic Xujiahe Formation in the northern part of the Western Sichuan Depression, we obtained reservoir sedimentary microfacies types and mineral composition characteristics by core description, logging interpretation and X-ray diffraction mineral analysis, combined with the diagenesis obtained from the rock thin section and field emission scanning electron microscopy observation, pore permeability and mercury injection test and the analysis results of the reservoir pore structure, and carried out a study on the factors influencing the tightness of reservoirs in the Member 2 of the XujiaheFormation.A comprehensive classification evaluation standard was established for the reservoirs Member 2 of the Xujiahe Formation in Northwest Sichuan. The result shows that the main reason for the development of tight reservoirs in the Member 2 of the Xujiahe Formation is that the reservoir porosity is controlled by lithology, and the differences in mineral components make the sandstone in the Member 2 of the Xujiahe Formation characterized by strong cementation, moderate compaction and weak fracture. The study results provide a basis for the screening of favorable sites for the development of tight reservoirs in this area and the favorable target areas for further exploration of tight gas reservoirs.

Oil-water flow characteristics in different temperature regions are unknown during the thermochemical flooding in ultra-heavy oil reservoirs. The effects of hot water and oil displacement agents on oil displacement efficiency and the change rule of relative permeability at different temperatures were quantitatively investigated, and the impact of hot water and oil displacement agents on the oil flooding and their interaction were analyzed by using microscopic visualization experiments and one-dimensional physical simulation experiments. The experimental results show that the oil phase relative permeability increases in high-temperature oil displacement agent flooding when the temperature is 70 ℃, and the water phase relative permeability changes are negligible when the temperature is 150 ℃, the synergistic effect of hot water and oil displacement agent is more significant, and the relative permeability of the oil phase and water phase increases significantly under high-temperature oil displacement agent flooding after hot water flooding and direct high-temperature oil displacement agent flooding; the role of oil displacement agent weakens at the high-temperature restriction, and the hot water significantly enhances the oil displacement efficiency after the temperature is more than 200 ℃. The oil displacement efficiency of the oil displacement agent increases first and then decreases After the temperature exceeds 200 ℃. Thermochemical flooding can realize the beneficial development of ultra-heavy oil reservoirs through the successive driving and synergistic action of hot water and oil displacement agents in different temperature regions. This study can provide a reference for thermochemical flooding to enhance the recovery of ultra-heavy oil reservoirs.

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 the lack of deep understanding of the reservoir characteristics of the Shahejie Formation in the Jiyang Depression, it affects the exploration and development of shale oil. Taking key coring wells of the lower sub-section of the Member 3 and the upper sub-section of the Member 4 of the Paleogene Shahejie Formation of in the Jiyang Depression as the study object, X-Ray Diffraction was used to determine the mineral composition of shale reservoirs, and the shale was classified into mudstone Shale, limestone and dolomite, the mudstone in the lower sub-section of the Member 3 of the Shahejie Formation is relatively developed, and dolomite in the upper sub-section of the Member 4 of the Shahejie Formation is relatively developed; the reservoir space and pore size of shale with different lithologies were quantitatively described with the scanning electron microscopy, and the predominant lithology of shale reservoirs was analyzed. The results of the study show that the medium to large pores were developed in dolomite, and the oil are mainly occurred in the dolomite intergranular micropores and dissolved pores; the medium to small pores were developed in mudstone, and the oil were mainly filled in the intergranular micropores and intergranular micro-fractures; the small pores were developed in limestone, and the oil were mainly occurred in the intergranular micropores and locally in the dissolved pores; the dominant lithologies of shale reservoirs were, in order of preference: dolomite, mudstone and limestone; the oil content and oil test data of different lithologies showed that the upper sub-section of the Member 4 of Shahejie Formation in the Jiyang Depression is a high-production oil section, and it can be determined as the “sweet spot”reservoir of the Shahejie Formation in the Jiyang Depression. The study results have guidance significance to the exploration and development of shale oil in Jiyang Depression.

Against the backdrop of the gradual depletion of conventional oil and gas resources, unconventional oil and gas resources, represented by tight oil resources, are increasingly gaining importance in energy development and utilization. However, compared to conventional reservoirs, the pore structure of tight oil reservoirs is highly complex, featuring with wide distribution of pore sizes, diverse pore types, and well-developed pore throats. All these factors pose significant challenges to the exploitation of tight oil reservoirs. Therefore, a thorough research on the pore structure and spontaneous imbibition mechanism in tight oil reservoirs is crucial for improving tight oil recovery rates. Based on this, through literature review, this paper provides an overview of the research on the pore structure and imbibition mechanism of tight oil reservoirs, introducing characterization methods for pore structure, research progress on tight oil pore structure, the impact mechanism of pore structure on tight oil imbibition mechanism, and summarizing and prospecting the research progress in this field. This study can provide reference for the development of crude oil production in tight oil reservoir and promote the development of tight oil recovery technology.

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 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 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.

In order to solve the problem of decreasing viscosity and oil displacement effect of the oil displacement system due to polymer aging of the chemical displacement in a certain block in Dongying, Hejian, Huabei Oilfield, the microscopic oil displacement mechanism of branched pre-crosslinked gel particles (B-PPGs) as well as the oil displacement effect of parallel cores were clarified based on a variety of experimental means such as viscosity and viscoelasticity tests, particle size distribution measurements, nuclear magnetic resonance (NMR) tests, and parallel core displacement. The results show that the branched structure of B-PPG molecules has better water solubility, which can improve the apparent viscosity of the solution; the B-PPG reticulated molecular structure enters into the formation in a crushed or deformed manner, which improves the mobility ratio and increases the sweep efficiency of the non-homogeneous reservoirs; when the permeability gradient of the main reservoir is 7.4, the recovery enhancement of the B-PPG system with a mass concentration of 2000 mg/L is 20% higher than that of the water displacement. The study shows that: The B-PPG system has good viscoelasticity, strong deformation ability, and ideal salt resistance, which can form an effective seal in the highly permeable layer and substantially increase the recovery rate. This study provides a reference for improving the profile of high-temperature and high-salt reservoirs, sealing the preferential channels of high permeability, and substantially increasing the reservoir sweep efficiency and recovery rate.

In response to the unclear understanding of the main controlling factors for multiphase oil and gas enrichment of the Ordovician oil reservoirs in Tahe Oilfield, the basin simulation technology was used to reconstruct the thermal evolution history and hydrocarbon generation history of the Lower Cambrian source rocks, and oil and gas migration and accumulation processes of typical profiles. The research shows that the Lower Cambrian source rocks in Tahe Area have entered a mature stage from the early Caledonian period and are currently in a high maturity-wet gas stage. They have developed three thermal evolution models of intermittent burial, continuous burial, and long-term shallow burial, corresponding to three hydrocarbon generation models of dual peak, strong oil and weak gas, and single peak. The differential thermal evolutions of source rocks lead to the history of oil and gas evolution with multiple stages of filling, vertical migration, and lateral adjustment and transformation in the Ordovician. The oil and gas phases present an orderly distribution pattern of light-medium-heavy oil reservoirs. The thermal evolutions of the Lower Cambrian source rocks in different structural belts in Tahe Area show a trend of increasing from northwest to southeast, showing a clear positive correlation with the differences in oil and gas phases, reflecting the characteristics of "source control". The thermal evolution characteristics controlled the distribution of current oil and gas reservoirs in the Himalayan period. Research indicates that the hydrocarbon generation intensities in the salt zone and Tuofutai of Tahe Oilfield are high, and the total amount of hydrocarbon generation during the Himalayan period is relatively large, making it a favorable area for further exploration and development. The research results have certain guiding significance for the evaluation of deep oil and gas resources and targets in Tahe Oilfield.

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.

The Aogula Fault Zone in the Songliao Basin exhibits complex kinematic characteristics, making the study of the spatiotemporal matching relationships of various reservoir-forming controlling factors challenging, which brings challenges to the accurate characterization of reservoir morphology. To address this issue, a comprehensive analysis of geological, seismic interpretation, and drilling data was conducted to understand the structural development history and fault causes. Based on the understanding of reservoir formation, the mechanisms of fault-controlled oil and gas accumulation were clarified. The fault-dense zone in the study area can be divided into two levels, and the faults are classified into three types based on their relationship with stratigraphic position. The study reveals that the Aogula Fault Zone is composed of two antithetic "S"-shaped main faults, experiencing three stages: faulting, sagging, and inversion. During the faulting stage, the activity intensity and elongation percentage of the fault zone are the highest, gradually weakening during the sagging stage, accompanied by multiple reverse regulating faults, and strengthening again during the inversion stage. Oil-source faults serve as vertical migration pathways connecting source rocks and traps, controlling the formation of fault-related traps and providing favorable conditions for oil and gas migration and accumulation. The research results can provide theoretical support for further exploration targeting and reserve enhancement.

In a case study of heavy oil reservoirs in IX6 Well Block, Xinjiang Oilfiled, physical simulation test of multi-media assisted steam flooding was conducted to address such problems as prominent vertical contradiction in the late stage of steam flooding in heavy oil reservoirs and serious steam channeling in the high-permeability layer. Firstly, the gelling performance and viscosity reducing effect of gel were evaluated, and then the combination mode of multi-phase synergistic steam flooding was optimized by full-diameter core. The results show that after the high-permeability layer was plugged by gelling, the subsequently injected multi-phase media effectively entered the low-permeability layer and drove the remaining oil in the low-permeability reservoir. Nitrogen was injected after viscosity reducer injected to effectively enhance the elastic energy and fluidity of crude oil, which was conductive to expanding the sweep volume of steam. The multi-phase synergistic steam flooding development mode of plugging control, viscosity reduction and pressurization is the best combination mode, which can improve the oil recovery rate by 23.65 percentage points. The study results can provide technical reference for the improved late development effect of steam flooding in heavy oil reservoirs.

Rock thin section image is one of the most direct and effective means to identify shale laminae. Using image color segmentation to identify shale laminae is a conventional method.When it is applied to the marine-continental transitional shale with complex and diverse laminae morphology, the identification effect depends on the local features of the image and is greatly affected by the laminae morphology. To address the above problems, we propose a method to identify marine-continental transitional shale laminae structure by converting rock slice thin images into frequency domain images using two-dimensional discrete Fourier transform, extracting frequency domain image features with principal component analysis technology, and establishing characterization parameters of shale laminae structure development degree. The method was applied to the analysis of rock thin section images of the target reservoir in the study area, and the application results showed that: The method is more applicable to the complex and diverse marine-continental transitional shale shale strata than the conventional method, and the conformation rate of laminae identification reaches more than 90%. The method can provide strong support for shale structure analysis and anisotropy evaluation.

12 samples of X coal from the Benxi Formation were collected in the DJ Block at the eastern edge of Ordos Basin,in order to explore the pore structure of deep and ultra-deep coal formations.The full pore size distribution characteristics of X coal were characterized by multi-experiment splicing method,based onthe three-dimensional reconstruction technology of digital core CT scanning and tests of high-pressure mercury intrusion,liquid nitrogen adsorption,and carbon dioxide adsorption.The study also compared and analyzed the distribution differences between the micropores,mesopores,and macropores in deep,medium,and shallow coal formations and their effects on adsorption and permeability.The results show that the reserving space of coal reservoirs is dominated by micropores and macropores,with fewer mesopores.In deep X coal formation,micropores and macropores on average account for 44.1% and 53.9%,respectively.While in shallow-to-medium X coal,micropores and macropores on average account for 34.8%,64.1%,respectively.The adsorption nanopores in deep coal are more developed.However,the development of micron-scale fractures in shallow-to-medium coal is better than that in deep coal.Through the analysis of the full pore size distribution characteristics,it is concluded that the proportion of macropore volume in shallow-to-medium X coal is higher,and the permeability is an order of magnitude higher than that of deep X coal,while the proportion of micropore volume in deep X coal is higher,indicating stronger adsorption capacity.Through quantitative characterization of the full aperture,the pore distribution characteristics of the reservoir at all levels are clarified,which provides data and theoretical support for the occurrence state and production mechanism of coalbed methane.

In the late stage of steam huff and puff or steam flooding for the heavy oil reservoir, the oil-steam ratio is only 0.1 to 0.2, which leads to high energy consumption and carbon emissions. To address the issue, a recovery method that utilizes low-viscosity oil injection assisted heavy reservoir with gas huff and puff has been proposed to improve the development effect. Through indoor test and reservoir numerical simulation, the mechanism and applicability are studied, and the technical boundary are delimited. The study shows that the mechanism of heavy reservoir with gas huff and puff assisted by low-viscosity oil injection is mainly viscosity reduction by dilution, solution gas drive, swept volume expansion and facies change by emulsification. The oil-carrying rate (volume ratio of produced heavy oil to injected low-viscosity oil) can reach 1.00-3.00, and the energy consumption and the water production is low. The new method is suitable for conventional heavy oil reservoirs and extra-heavy oil reservoirs, especially for deep zones, thin interbedded and small fault blocks. This study has guiding significance for reservoir screening and engineering design of heavy reservoir with gas huff and puff assisted by low-viscosity oil injection.

A research for the optimization of oil recovery rate and water injection method was conducted with numerical simulation and field practice so as to improve the accuracy of numerical simulation of fractured reservoirs and provide effective water injection strategies.In the study,a buried hill reservoir in JZ25-1S oilfield in the Bohai Bay Basin,a large fractured reservoir, is taken as a study object. With the use of digital core technology and multiphase flow simulation, the characteristics of micropores and throats in the upper and lower semi-weathered crust and the characteristics of relative permeability curve are defined. The results indicate that development degree of microfractures plays an important role in controlling the shapes of relative permeability curve and the capillary curve of matrix block; the more developed the microfractures in the core, the higher the oil displacement efficiency, and the more conducive to matrix imbibition; the length and frequency of microfractures follow a power-law distribution, with a power-law index of approximately 1.5; in the initial stage of development, the production are mainly from the fracture system, while in the middle and later stages of development, the production from the matrix system gradually increases; the cumulative production contribution ratio of the fracture system to the matrix system is approximately 2∶1;the recovery rate is expected up by 4.5 percentage points through the optimization of the oil recovery rate in the initial stage and utilization of cyclic water injection during the water-cut rising stage. This study provides important guidance for development strategies and water injection schemes for fractured reservoirs.

Doushantuo Formation is one of the important shale gas exploration target formations in the west Hubei of China. In view of the weak research on the paleo-environment of this formation, the paleo-environmental evolution law of the Doushantuo Formation in the Yichang Area of the west Hubei was analyzed through the collection of core samples for the testing of TOC, major elements and trace elements, and the favourable formations for the enrichment of the Doushantuo Formation were clarified. The study shows that the Member 1 and Member 3 of Doushantuo Formation are of organic-lean strata, and the Member 2 and Member 4 are of organic-rich strata, in which the Member 2 is significantly enriched in Ca, Mg, P, Ba, Sr, Zn, U, Mo, and Cu, and the Member 4 is significantly enriched in Ca, Si, P, Mo, U, Ba, and V. Member 1 and Member 3 have dry climate, high salinity, mainly oxidizing environment, and low paleoproductivity; the Member 2 has alternating warm-wet and dry-hot climate, high salinity, and frequent alternation between oxidizing and oxygen-poor environment; and the Member 4 has warm-wet climate, low salinity, and oxygen-deficient environment. Doushantuo Formation has weak paleohydraulic forces which was deposited in a strong euxinic basin, and Member 2 and Member 4 have higher paleoproductivity. Favorable block is located in the deep-water inter-platform basin at the west of Yichang City, the middle of Member 2 is a shale gas-rich favorable formation, in which the thickness of organic-rich strata with TOC>2.00% is more than 20 m, deposited in an oxygen-poor and oxygen-deficient environment, with the highest paleoproductivity, and it is the geological "sweet spot" of Doushantuo Formation shale gas exploration. The study results provide geochemical basis for the shale gas exploration of Doushantuo Formation in west Hubei of China.

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.

In response to the problem of unclear understanding of geochemistry and depositional environment characteristics of terrestrial shale in the first member of Qingshankou Formation of Changling fault depression in the southern Songliao Basin, the experiments on organic geochemistry, molecular geochemistry and elemental geochemistry were systematically carried out to clarify the hydrocarbon generation potential of terrestrial shale in the study area, and to explore the controlling effect of depositional environment characteristics on the enrichment of organic matters. The study results show that the terrestrial shale in the first member of Qingshankou Formation is rich in organic matters, with an average TOC of 1.71% and an average chloroform asphalt "A" of 0.52%, which has good hydrocarbon generation potential. The types of kerogen are mainly Ⅰ and Ⅱ₁, and the thermal evolution of organic matter is at a mature stage, with the average pyrolysis parameter T_max of 447 ℃ and average R_o of 1.06%; the C₂₇-C₂₉ regular sterane indicates that the organic matter of the shale is mainly originated from lower-order aquatic organisms, such as algae, and partly imported from higher-order plants, the ratio of trace elements and biomarker compound parameters indicate that the paleoproductivity level is high, and the shale is originated from saline-water and brackish-water reducing environment, which is favorable for organic matter preservation; the chloroform asphalt "A" has a positive correlation with P/Ti and Sr/Ba, which suggests that the paleoproductivity and the preservation conditions jointly control the organic matter enrichment of shale. According to the evaluation criteria of shale oil "sweet spot" of TOC>2.00% and S₁>1 mg/g, the favorable area is determined to be 5 000 km², and the geological reserves calculated by volumetric method is 54.7×10⁸t. The study is of strategic significance for the evaluation of shale oil resource potential in the southern Songliao Basin.