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.

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.

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

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

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.

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.

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 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 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.

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.

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.

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

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

To solve the problem of difficultly predicting the productivity for tight gas reservoirs after fracturing, based on the seepage mechanism and considering the stress sensitivity of the formation and the effect of formation improvement after fracturing, a linear heterogeneous composite zone fractured well model applicable to the inversion of fracture pump-stop is established, the fracture parameters and formation parameters are determined by using the established model and numerical well tests, and the relationship between productivity and fracture scale before and after fracturing is established by applying SPSS regression method, to obtain the The relationship between productivity and fracture scale before and after fracturing was established by applying SPSS regression method, to obtain the productivity prediction method for tight gas reservoirs after fracturing. The study shows that the double logarithmic characteristic curves of shut-in pressure change after hydraulic fracture pump-stop can be divided into fracture linear flow stage, transition stage, interfacial flow stage, outer zone linear flow stage and boundary effect stage; the newly established productivity prediction method is applied to Well Block X in Yulin Gas Field, with the average error of productivity prediction of 16.1% and good applicability; the effects of different fracturing parameters on productivity are, in descending order, discharge volume, sand addition volume, and fracturing fluid volume, with the optimal fracturing discharge volume of 3.36-4.83 m³/min, the optimal sand addition volume of 56.95-77.66 m³, and the optimal fracturing fluid volume of 167.09-259.91 m³.The study results have certain guidance for optimizing the fracturing design and post-fracturing productivity prediction of tight gas reservoirs.

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 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.

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

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

In recent years, several condensate reservoirs supplied with hydrocarbons from Carboniferous-Permian coal-measure source rocks have been identified in the Bohai Bay Basin, showing considerable exploration potential. To address the problems of poorly understood hydrocarbon generation characteristics and unclear exploration directions in the study area, it is urgent to reconceptualize the hydrocarbon supply capacity of coal-measure source rocks. To this end, the Huanghua Depression in the Bohai Bay Basin was taken as the research object, and the spatial distribution, hydrocarbon generation potential and hydrocarbon generation characteristics of different lithologies of coal-measure source rocks in the Huanghua Depression were comprehensively analyzed through multivariate data statistics such as cores, well logging, mud logging and oil production testing, based on the analysis of the difference of sedimentary filling characteristics of tectonic units in the basin, and the evaluation model of sedimentary units established by using the numerical simulation technology for the basin.The hydrocarbon generation pattern of Carboniferous-Permian coal-measure source rocks in the Bohai Bay Basin was clarified, and a favorable hydrocarbon accumulation zone in the study area was predicted. The result shows that for the Carboniferous-Permian coal-measure source rocks in the Huanghua Depression, the coal rock is the marker bed, and three types of hydrocarbon generation lithologies are developed: mudstone, carbonaceous mudstone and coal rocks, among which the mudstone is thick and continuous with high hydrocarbon generation potential; the hydrocarbon generation simulation shows that the primary hydrocarbon generation is dominated by oil production from mudstone, and the secondary hydrocarbon generation is dominated by mixed oil and gas production from various hydrocarbon source rocks; three types of hydrocarbon generation patterns are developed: early subsidence type, late subsidence type and continuous subsidence type, and the hydrocarbon generation areas of continuous subsidence and late subsidence types are the most favorable for in-situ oil and gas accumulation in the buried hill. The results of the study can provide technical support and data for theoretical research and exploration deployment of oil and gas accumulation by hydrocarbon supply from coal-measure source rocks in the study area.

The formation process of metamorphic buried-hill reservoirs in Bohai Oilfield was complicated, which was affected by tectonic movement, weathering and leaching, paleogeomorphology and other geological factors, resulting in the diversified reservoir space and extremely strong non-homogeneity. However, the existing reservoir physical properties evaluation methods had problems such as low quality of collected data, strong multi-solutions and poor real-time accuracy. For this reason, the metamorphic buried-hill reservoir in Bohai Oilfield was taken as a target area, the field outcrop sampling was carried out, interval transit time and microdrill drilling experiments were carried out to obtain the interval transit time and mechanical specific energy values of rocks with different physical characteristics, and a mathematical model of physical property index and reservoir porosity were established. The study shows that the interval transit time of the outcrops of the Archaeozoic metamorphic rocks of the Bohai Oilfield ranges from 371.75 to 617.29 μs/m, and the mechanical specific energy value ranges from 297.43 to 1207.47 MPa. The value of the mechanical specific energy shows an exponential function to decrease with the increase of the interval transit time, and the porosity shows a logarithmic function to decrease with the increase of the physical property index. The method has been popularized and applied in the metamorphic buried-hill reservoir of Bohai Oilfield, and the compliance rate with the logging interpretation results has reached more than 85%. This study provide reference and basis for the identification of metamorphic buried-hill reservoirs.

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.

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.

The current formation pressure prediction methods based on the undercompaction theory are essentially empirical models, which are not generalizable, and the prediction accuracy is constrained by various factors. For this reason, the quantitative study of anomalous formation pressure was carried out from the perspective of rock pore volume and fluid volume. According to the theory of elastic mechanics of porous media, the quantitative evaluation model of anomalous formation pressure and pressure coefficient under the effect of undercompaction was established by comprehensively considering the factors such as temperature, stress, fluid composition, and depth change. The model is applicable to the evaluation of anomalous formation pressure with undercompaction as the main genesis, and has high accuracy. The simulation results show that the formation pressure increases under the effect of the undercompaction, but the pressure coefficient may increase, remain unchanged or decrease due to the increase of burial depth, and the influence of the increase of burial depth on the pressure coefficient shall not be neglected; the undercompaction can form both anomalous high pressure and anomalous low pressure; the changes of the formation pressure and the pressure coefficient are related to the physical properties of the fluid and the rock, and the increment of the formation depth as well as the initial depth; the influences of the compression coefficient of the fluid and the increment of the formation depth are relatively significant, while the influences of other factors are relatively weak. The research results break through the previous knowledge of the relationship between undercompaction and anomalous high pressure, and enrich and develop the theory of undercompaction.

The hybrid sedimentary shale oil is complex in lithology, with many mineral types and rapid lateral changes in the "sweet spot".The conventional logging is not sensitive to the lithology, physical properties and oil-bearing properties response, while the NMR logging requires petro-physical experimental calibration and long interpretation period, so there is a lack of effective on-site "sweet spot" rapid evaluation technology. To address the above problems, the shale oil reser-voir in the Lucaogou Formation of the Jimsar Sag of the Junggar Basin is taken as an example to study the response characteristics of gas logging, carbonate minerals, drilling time and other logs to the lithology, physical properties and oil-bearing properties of hybrid sedimentary shale oil based on the interpretation of NMR logging, so that the internal connection is clarified and sensi-tive parameters are selected to achieve the rapid evaluation of parameters and "sweet spots" of shale oil reservoir. The study shows that the lithology, physical properties and oil saturation of the hybrid sedimentary shale oil all have obvious responses on the logging data, among which, carbo-nate content and dolomite percentage can effectively reflect the main lithologies such as siltstone, dolomitic siltstone, psammitic dolomite, dolomicrite and dolomitic limestone, the carbonate con-tent and total hydrocarbon/drilling time are sensitive to the porosity, and the carbonate content, humidity ratio and total hydrocarbon are sensitive to the oil saturation. Based on the interpretation model of logging sensitive parameters such as porosity and oil saturation, the accuracy can reach 71.0%.Compared with the NMR logging, the identification rate of "sweet spot" of Class I oil formation is over 90%, thus achieving rapid and accurate evaluation of "sweet spot" of shale oil in the process of drilling. The results of the study are useful for improving the drilling catching rate of the "sweet spot" in horizontal wells of hybrid sedimentary shale oil and for reducing costs and increasing efficiency.

To address the problem that the main controlling factors of hydrocarbon enrichment in the Putaohua reservoir in the Sanzhao Sag of the Songliao Basin are unclear, the main controlling factors of hydrocarbon accumulation are comprehensively analyzed by using test data and seismic data, and a hydrocarbon enrichment model is established to provide a theoretical basis for hydrocarbon exploration. The results of the study show that the sedimentary microfacies controls the distribution of favorable reservoirs; the oil source faults and sand bodies form the dominant transportation channels; two major types of tectonic-lithologic traps and lithologic traps have been developed in the Sanzhao Sag, which are subdivided into four subcategories: nose-like tectonic-lithologic traps, fault-lithologic traps, low-amplitude anticline-lithologic traps, and single sand body up-dip thin-out traps, and these facilitated traps control the distribution of oil and water in the study area, forming a hydrocarbon accumulation model of reservoir control by sedimentary microfacies, transport control by oil source faults and sand bodies, and enrichment control by traps. This study can provide effective theoretical guidance for the exploration of the Putaohua reservoir in the Sanzhao Sag of the Songliao Basin.

Aiming at the problems of low recovery of water flooding, high cost and high carbon emission of thermal recovery in conventional heavy oil reservoirs, anionic viscosity reducer and salt-resistant polymers were preferred based on the low-temperature and high-salt properties of reservoirs in Chunguang Oilfield. The water cut reduction and oil production increase mechanisms of hot-water flooding, single viscosity reducer flooding, and composite flooding were clarified based on indoor physical simulation experiments. The kinetic equations of the reaction of viscosity-reducing composite flooding were established. The numerical simulation method of viscosity-reducing composite flooding was developed in CMG-STARS software. Well-pattern spacing and injection-production strategy of viscosity-reducing composite flooding were optimized for conventional heavy oil reservoirs in Chun 2 unit. The results show that the viscosity-reducing composite flooding could give full play to the synergistic effect of viscosity enhancement of the displacing phase and viscosity reduction of the displaced phase, and it has the advantages of low system dosage, low carbon emission, and significant recovery enhancement; the viscosity-reducing composite flooding is suitable for five-spot pattern, the injector-producer distance should be less than 200 m; the optimal injection slug volume is 0.5 times of the pore volume and the injection to production ratio is 1.05 with the mass fraction of the viscosity-reducing agent at 0.25%. Practice shows that the water cut in wells was reduced by more than 30%, and the daily oil production was increased by 5 t/d after the viscosity-reducing composite flooding was implemented in extra-high water cut (water cut of 96%) reservoir at the late stage. This study confirms the feasibility of this technology applied in the field. It provides a reference to improve the effect of the development of conventional heavy oil reservoirs and realize the reduction of industrial emissions.

The sandy braided channel bar is an important reservoir type for oil and gas development with complex internal inhomogeneity. To address the problems of poorly understood sedimentary characteristics, architecture model and residual gas distribution rule of the braided channel bar in the Lower He8 Member of the Sulige Gasfield, a study was conducted with the analytic hierarchy process as a guide, in combination with the analysis of architectural elements and the data from ancient outcrop, modern sedimentation, coring and dense well pattern logging. The results show that the braided river sand bodies have the characteristics of mutual superposition in the longitudinal direction and large contiguous distribution in the horizontal direction, and the variation of the accommodable space controls the contact relationship of the sand bodies, and four types of sand body vertical superposition patterns are proposed during the rise and fall of the datum; as the sand body is internally hierarchical, the different seepage barriers (interbeds) are formed during the deposition of the braided river, which are divided into five types, such as river bottom stagnant mud and gravel deposits, channel bar silt layer, side-deposited fine-grained deposits, abandoned river fill deposits and overbank fine-grained deposits, and the silt layer is the main factor controlling the oil and gas seepage inside the channel bar; according to the difference of water flow energy characteristics and deposition characteristics in different locations of the channel bar, the channel bar is divided into the architectural elements such as head, center, wing, tail and silt layer, etc. The tail is obviously more inhomogeneous than the head, and the upper part of the channel bar with more developed silt layer is more inhomogeneous than the lower part; the tail and upper parts of the channel bar are the residual gas enrichment areas. The results of the study are useful for the exploration and development of reservoirs in the study area and similar braided river depositional environment.

The lithology of conglomerate is rich and variable, the pore structure is complex, the classification of reservoir type is difficult, without standardized evaluation parameters. Taking the conglomerate reservoirs of the Upper-Lower Karamay Formation in District Min-7 of Karamay Oilfield of Xinjiang as the object of study, based on the high-pressure mercury injection data of the reservoir rocks of the Formation 106, the classification scheme of the conglomerate reservoirs was established by using the clustering analysis method; the classification parameters of the conglomerate reservoirs were simplified and clarified by the methods such as the variance calculation and the validity of this method was verified by the use of the discriminant analysis in the end. The results show that the non-homogeneity of the conglomerate reservoir in the study area is strengthened as the physical properties become better and the pore-throat size becomes larger, reflecting the complexity of the conglomerate pore structure; the clustering analysis after data preprocessing can effectively classify the reservoirs, and there are significant differences between the classes; based on the quantification of parameter centralization and dispersion, six parameters for reservoir classification, such as the median pressure and the average pore-throat radius, are preferred; after the validation of the discriminant analysis, the accuracy of classification is still as high as 95.80% after the parameter preference, indicating that the method has high classification accuracy and is not geographically restricted, which makes it valuable for generalization.

There are significant heat loss, high water cut, and poor development effects during the recovery process of heavy oil reservoirs. Taking the Mackay River Reservoir in Canada as the research object, the numerical simulation model of hot solvent-assisted gravity drainage technology was constructed, and characteristics of SAGD, VAPEX, and hot solvent-assisted gravity drainage recovery were compared. The parameters are optimized for production pressures, injection rates, and injection temperatures of hot solvents. The results show that the hot solvent-assisted gravity drainage technology is better than SAGD and VAPEX in terms of injection and production differential pressure, oil recovery, and oil recovery rate; in the actual development process, the optimal conditions for the application of hot solvent-assisted gravity drainage technology are as follows: the bottomhole production pressure is 700 kPa, the injection rate is 160 m³/d, and the injection temperature is 275 ℃. The results of the three-dimensional experiments further validate the results of the numerical simulation calculations. This study provides a reference for efficiently developing shallow heavy oil reservoirs.

In recent years,nanoparticles have gradually received widespread attention in tertiary oil recovery.At present,the mechanism and development status of nanoparticle are not well understood.For this reason,the paper systematically analyzes research progress of nanoparticle flooding in recent years and summarizes the mechanisms of oil displacement by nanoparticles,including nano-size effects,reduction of interfacial tension,alteration of wettability,disjoining pressure,emulsification,prevention of asphaltene flocculation,and catalytic cracking.It also explores the significant application potential of nanoparticle-driven oil displacement materials in various reservoir types,such as high water cut reservoir,low permeability reservoir,tight oil reservoir,and shale oil reservoir.The paper identifies challenges and development prospects for nanoparticles in oil development and provides references and basis for further research and large-scale application of nanoparticles in enhanced oil recovery.

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

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 the unclear effect law of the shale gas adsorption-desorption on the deliverability of production wells, based on the seepage characteristics and deliverability equation of tight gas wells, a deliverability model considering shale gas adsorption-desorption was established with reference to the gas seepage differential equation and in combination with the Langmuir isothermal adsorption equation; the deliverability and open flow capacity of shale gas wells under different desorption time were calculated based on the drilling and completion and dynamic monitoring data of shale gas wells, and the effect of adsorbed gas was transformed into additional resistance coefficients based on the information of back-pressure well testing to form a trinomial deliverability calculation equation, and this equation was used to study the effect of adsorbed gas on shale gas deliverability calculation. The results show that the adsorbed gas will cause a higher initial deliverability calculation value of shale gas wells, and the calculated open flow capacity is relatively stable after 10 d of desorption; the adsorbed gas content has a greater influence on the deliverability of shale gas wells, and the adsorption pressure has a smaller influence on the deliverability; the error between the results of the trinomial deliverability calculation and the analytical method model calculation is less than 12%, and the results are more reliable. The research results can be used as a reference for the deliverability evaluation of shale gas wells.

To clarify the vertical dominant reservoir and favorable exploration zone of No.8 coal seam in the Benxi Formation of the Yichuan-Shangzhenzi Block in the Yishan Slope of the Ordos Basin,the cores of No.8 coal seam in the Benxi Formation of the Yichuan Area were selected,and the sedimentary environment and coal-forming evolution characteristics of No.8 coal rock were comprehensively analyzed through experiments such as macro coal rock classification,microscopic component identification,major and trace element analysis.The results indicate that the No.8 coal rock of the Benxi Formation is the mixed accumulation product of bright coal,semi-bright coal,and dull coal.The organic components of the coal rock are mainly vitrinite,followed by inertinite.The inorganic components mainly consist of clay minerals such as kaolinite and illite-montmorillonite mixed layer,containing a small amount of quartz and feldspar.The middle and lower parts of the coal are rich in organic components,and the bright coal is well-developed,which constitutes a high-quality coal seam.The evolution degree of coal facies and coal rock is the main controlling factor of hydrocarbon accumulation,and the low water-covered forest swamp is the favorable exploration zone.This understanding is highly significant for the analysis of the enrichment law of No.8 coal seam in the Benxi Formation in the Yichuan area and has an excellent guiding significance for the exploration and development of coalbed methane.

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.

To address the problem of poor fluid permeability and reduced production capacity caused by strong stress sensitivity in tight reservoirs, a core from a tight reservoir in the Jidong Oilfield was selected for full-diameter core displacement experiments and in situ CT scanning experiments to study the pore structure and oil-water two-phase permeability characteristics of tight reservoirs under the stress sensitivity. The study shows that with the increase of net stress, the stress sensitivity increased, the throat and larger pores in the core were compressed and deformed, some of the ultra-fine pores were even closed, the falling speed of the relative permeability of the oil phase and the rising speed of the relative permeability of the water phase increased, and the two-phase permeability curve gradually shifted down; the saturation of irreducible water and residual oil increased, the co-permeability point shifted to the right, the two-phase permeability zone gradually became smaller, and the efficiency of water-oil displacement decreased; it indicated that after water breakthrough in the oil well, the water cut increased significantly, the oil-water production period was shorter, the breakthrough of water displacement was rapid, and the efficiency of water-oil displacement decreased.The impact of stress sensitivity on oil-water two-phase seepage law and recovery factor was mainly reduced by supplementing formation energy. The study results have important guidance significance for the development of technical solutions for tight reservoir development.

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.

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.

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