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.

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

The 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.

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.

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.

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 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 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.

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.

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.

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.

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

In 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.

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.

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

To address the problem of 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.

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.

In response to the technical problems such as frequent occurrence of complicated accidents due to insufficient plugging performance of oil-based drilling fluid and long cycle processing time and difficulty in transfer due to strong sensitivity to low temperature in the development of shale oil reservoir in Liaohe Oilfield, an oil-based cross-linked plugging agent and low temperature rheology improving agent were developed to form a set of strong plugging and constant rheology oil-based drilling fluid system, and the performance evaluation and practical application of this drilling fluid system were carried out. The study shows that: The density of strong plugging constant rheology oil-based drilling fluid is 1.80-2.40 g/cm³, and the low temperature resistance reaches -25 ℃ and high temperature resistance reaches over 220 ℃; the drilling fluid has good rheology and settlement stability, the primary recovery rate of shale is 100.0%, the secondary recovery rate is 97.5%, and the plugging rate for shale reaches 60%, which can efficiently slow down the pressure transfer inside the shale. The field application shows that, Strong plugging constant rheology oil-based drilling fluid system has stable rheology and is easy to adjust, with good wellbore stability and high rate of penetrate. This technology can provide a technical reference for efficient drilling of deep and ultra-deep wells in shale and other complex formations.

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.

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.

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 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.

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.

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

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

To address the problem 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.

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

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.

To address the problem of poorly understood mechanical mechanism of stress-caused brittle failure in shale, the brittle fracture model of laminated shale with longitudinal mechanical inhomogeneity was established by applying the theory of rock fracture mechanics and combining it with generalized Hooke's law on the basis of analyzing the characteristics of laminated shale, and the main influencing factors of the fracture mode of laminated shale were analyzed. The study shows that the fracture modes of laminated shale are mainly divided into shear failure and tensile failure, hard rock formations are prone to tensile failure, while soft rock formations are prone to shear failure under external stress conditions; the larger the Young's modulus of the rock formation and the smaller the Poisson's ratio, the more prone the formation is to tensile failure and vice versa; the larger the minimum horizontal principal stress and the smaller the horizontal principal stress difference, the more prone the formation is to shear failure; the variability of mechanical properties between shale layers is the fundamental reason for the brittle fracture of shale; the greater the variability between shale layers, the more brittle the rock is, and the more favorable it is for fracturing. This study can provide theoretical guidance for shale brittleness evaluation and hydraulic fracturing scheme development.

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.

Aiming at the difficulty of productivity prediction in shale gas reservoirs due to the influence of two-phase complex flow and fluid-solid coupling, the seepage field is divided into the primary modified zone, the secondary modified zone and the unmodified zone, and a multi-scale gas-water two-phase flow-fluid-solid coupling mathematical model is established by combining the multi-fluid unified transport model and the equivalent continuous non-uniform medium physical model, and the mathematical model is programmed and solved by gridless generalized finite difference. The results of the study show that the gridless generalized finite difference method can adapt to different computational domains and avoid the arithmetic instability caused by the coupling of traditional difference grids with unstructured grids; the propagation of the pressure drop leading edge in the unmodified zone is only about 20 m, and the solid displacement mainly occurs in the junction area between the secondary modified and unmodified zones; neglecting the influence of the stress field, the gas production is significantly overestimated at the early stage of gas well production, and this influence gradually decreases at the later stage of production; the shale gas reservoirs with low initial water saturation are more beneficial for development, focusing on water saturation during reservoir selection. The study results have important guidance for future numerical simulations of fluid-solid coupling and unconventional oil and gas reservoir capacity prediction.

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

The 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.

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.

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 further evaluate the adaptability of fracturing fluid and proppant to the dense sandstone reservoir in the Denglouku Formation of CL block, the commonly used fracturing fluid and proppant in the target formation were selected for core permeability testing experiments, flowback experiments, CT reconstruction experiments and reservoir conductivity experiments to comprehensively evaluate the effects of different types of fracturing fluid and proppant on the permeability of rock samples. The study shows that there is still some damage to the core after fracturing fluid flowback, and the damage rate of guar gum fracturing fluid is larger than that of slickwater fracturing fluid, mainly manifested as water-sensitivity damage, water-locking damage and residue damage, and the mechanism is that the pore structure of rock samples treated with guar gum fracturing fluid changes significantly, and the percentage of micropores with pore throat radius of 7-22 μm increases; the permeability of dense sandstone reservoir is affected by proppant embedding, and the conductivity is negatively correlated with the particle size and closure pressure. The research results can provide theoretical guidance for the preferential selection of fracturing fluid system for dense sandstone gas reservoirs in Denglouku Formation of CL block.

Generally the oil between SAGD oil production station and the joint station is transmitted by pumping, with high energy consumption, significant loss and safety hazards. At the stage of steam chamber expansion in SAGD development, there is a great amount of associated gas stably generated, which make it possible to realize self-pressurized oil transmission. Therefore, a study was conducted on the self-pressurized oil transmission technology for SAGD production station. The original gathering and transmission technology was optimized on the basis of high and stable gas cap pressure of the buffer tank in SAGD production station, and self-pressurized oil transmission was enabled without any external force. The technology can bring about such economic and social benefits as low cost, high profit, staff reduction and improved efficiency. This technology has been stably applied in three stages of SAGD development: steam chamber expansion, stable oil drainage and initial steam chamber decline, providing technical support for the promotion and application of SAGD development technology.

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