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.

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.

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 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.

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

Inadequate comprehension of the pore structure and physical properties of shale reservoirs impedes precise calculation of shale oil reserves and efficient development seriously. This study focuses on the core holes of Xinyishen-9, Liye-1, and wells Fanye-1 in the Paleogene Shahejie Formation within the Jiyang Depression. The pore structure of shale reservoirs is comprehensively characterized using N₂ adsorption, high-pressure mercury injection,physical properties measurement, and other experimental methods. Additionally, we determined the physical property cutoffs through a comprehensive approach involving irreducible water saturation method, pressed mercury displacement method, minimum flow pore-throat radius method, and oil testing method. The findings indicate that the nitrogen adsorption experiment primarily characterizes the small pores of shale samples. The pore morphology in the study area predominantly comprises ink bottle, transition, and flat types, mainly featuring nano-scale pores with a radius ranging from 1.50 to 40.00 nm and an average pore radius of 16.00 nm. Moreover, the high-pressure mercury injection experiment focuses on characterizing mesopores and macropores of shale, revealing a pore throat radius range of 0.03 ~ 66.13 μm. The lower limit of shale reservoir porosity falls within the range of 1.30% to 3.82%, while permeability's cutoff is between 0.03 ~ 0.12 mD, the minimum flow pore-throat radius is 14.60~23.50 nm and average value is 17.76 nm. The research outcomes offer valuable parameter indexes and technical support for reserve calculation and reservoir evaluation in Jiyang Depression's shale oil exploration.

The Banzhongbei Gas Storage in the Dagang Oilfield is located on the upcast side of the Banqiao Fault, which is a fault block gas storages and a semi-anticlinal structure cut by faults. The loading capacity of faults and capping formation determines the high limit pressure for the gas storage operation. To address the lack of consideration of mechanical integrity in determining the upper limit pressure of gas storage operation, this study evaluates the hydraulic sealing ability of the cap rock and the stability of faults in the study area from the perspective of geomechanics. This evaluation is based on comprehensive data including 3D seismic interpretation results, XMAC logging stress interpretation results, and rock mechanics tests. It utilizes the theory of rock brittle fracture to determine the upper limit pressure for the safe operation of gas storage considering mechanical integrity. The results show that the upper limit pressure of the hydraulic sealing capacity of the cap rock in the Banzhongbei Gas Storage is 39.30 MPa, and the weak point of fault stability is at the intersection of two faults with a minimum activation pressure of 30.57 MPa. By considering the upper limit of cap rock hydraulic sealing capacity and fault stability, the upper limit pressure for the operation of the Banzhongbei Gas Storage is determined to be 30.57 MPa, which is reasonably close to the design operating upper limit pressure of 30.50 MPa. The research findings have significant guiding for the design of upper limit pressure for gas storage operation.

Under high temperature conditions,the degradation of polyacrylamide filtrate reducer molecules leads to a significant decrease in filtrate reduction efficiency.To address this issue,a high temperature resistant hyperbranched polymer filtrate reducer(JHPAS)was synthesized through copolymerization of hyperbranched monomer allyl pentaerythritol(APE)with 2-acrylamido-2-methylpropane sulfonic acid(AMPS),acrylamide(AM),and sodium styrene sulfonate(SSS).A novel clay-free water-based drilling fluid was formulated using JHPAS,and its filtrate reduction mechanism was analyzed.The rheological properties and filtrate performance under high temperature and high salt conditions were evaluated.The results demonstrate that JHPAS exhibits excellent thermal stability and has the ability to create a network structure in an aqueous solution. It adsorbs onto the surface of superfine CaCO₃,forming a compact filter cake in clay-free water-based drilling fluid,effectively plugging the pores on the filter cake and consequently reducing the filtrate loss of drilling fluid.The developed clay-free water-based drilling fluid maintains consistent rheological properties and demonstrates effective filtrate loss reduction even after exposure to 200 ℃ aging for 16 hours and saturated sodium chloride brine.The API filtrate loss and high-temperature,high-pressure filtrate loss are measured at 5.5 mL and 7.6 mL,respectively.These research findings contribute to advancing the exploration and utilization of hyperbranched polymers in drilling fluids for in deep and ultra-deep reservoirs.

In order to better monitor the production performance of oil and gas reservoirs and improve the production capacity of oil and gas fields, this paper reviews the principles, interpretation methods, and application effects of four commonly used transient well testing technologies. It analyzes the problems existing in transient well testing technology and proposes future key research directions. The results show that the currently commonly used transient well testing technologies mainly suffer from serious inter-well interference, complex characteristics of testing curves, low accuracy of testing interpretation, and low efficiency and high losses in conventional testing of complex fault block reservoirs. While new types of testing technologies such as numerical well testing, vertical interference testing, and low-frequency pulse testing can address these issues. The future development trends of transient well testing technology lie in deep and ultra-deep testing processes, evaluation of low-permeability tight reservoir testing data, assessment of fracturing effects, and integrated application of data. Emphasis can be placed on technical breakthroughs in numerical well testing and multi-layer testing. Through a comprehensive analysis of transient well testing technology, this study can provide technical references for on-site testing and offer new perspectives for subsequent technological developments.

The fourth member of the Upper Triassic Xujiahe Formation in the Tianfu Area of the Sichuan Basin (referred to as the T₃x₄) is characterized by thick sandstone layers interbedded with thin mudstone layers,making it a crucial exploration target for tight sandstone gas reservoirs.However,due to limitations in seismic vertical resolution,thin mudstone layers are hard to be determined by conventional methods,hindering the precise characterization of sandstone in this interval.This limitation has impeded the understanding of the distribution patterns of sand bodies in the basin and identification of favorable target areas.To address these issues, this study integrates drilling data with seismic facies and establishes a mapping relationship between the two.Under the constraint of natural gamma-ray curves,optimal inversion frequency parameters were sought to enhance the accuracy of inter-well sand body prediction.The distribution characteristics of the T₃x₄ sandstone in the Upper Triassic Xujiahe Formation were well characterized with waveform indication simulation method.The results indicate that the T₃x₄ sandstone exhibits characteristics of being thick in the west (55.0 to 100.0 m) and thin in the east (15.0 to 50.0 m).Compared to the third member of the Xujiahe Formation,the transition zone of sand body thickness variation (slope break zone) has migrated towards the interior of the craton.Analyzing data from 18 wells within the seismic working area,it was observed that beneath the slope break zone,the sandstone has a high average porosity (8.0%) and a large reservoir thickness (45.4 m).Considering tectonic evolution, sedimentary facies distribution,sandstone thickness,and porosity variations,it is proposed that the T₃x₄ follows a pattern of structures control slope break zones,and slope break zones control reservoirs.Regions below the slope break zones exhibit favorable reservoir properties with good physical characteristics and significant thickness,making them promising exploration areas.The study results provide valuable insights for the in-depth exploration of the T₃x₄.

The reservoirs with low permeability in the western part of Block Ⅲ of District Ⅰ to District Ⅲ in Xingshugang Oilfield in Daqing Oilfield experienced various development stages,such as natural energy,water flooding,and polymer flooding,leaving a complex distribution of residual oil and a pressing need to improve development efficiency.Therefore,Block Ⅲ was divided into three regions featured by:normal polymer flooding,casing-damaged polymer flooding,and polymer follow-up water flooding based on the study of residual oil and analysis results of development effectiveness,so as to develop proper technical strategies for improving development effectiveness with artificial core displacement and numerical simulation techniques.After years of chemical flooding,residual oil in the normal polymer flooding region is sporadically distributed at the edges of sand bodies and areas with low permeability.In the casing-damaged polymer flooding region,the producing performance of oil layers is poor due to casing damage,and the remaining oil reserves there is high.Based on the conditions described above,optimization is carried out in three aspects:development method,oil displacement system,and well pattern design with the full consideration of different regional characteristics.For normal polymer flooding regions and polymer subsequent water flooding regions,a five-spot well pattern dilution of regular polymer flooding was adopted with a well spacing of 175 meters and a plug size of 0.40 times of the pore volume.While for casing-damaged polymer flooding region,a local infilled five-spot well pattern of regular polymer flooding is applied with a well spacing of 140 meters and a plug size of 0.70 times of the pore volume.An increase of 3.53 percentage points is predicted in recovery rate.After the implementation of these measures,the cumulative injection of polymer pre-plugs in Block Ⅲ is estimated to be 0.10 times the pore volume,an expected oil increase of 9 780 tons.This study can provide reference for improving development efficiency in polymer flooding blocks.

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

Accurate prediction of liquid holdup provides important basis for flow pattern identification and pressure drop calculation in wellbores. Slug flow is the most common flow pattern in heavy oil wellbores. High-viscosity fluids in the wellbore will exacerbate gas-liquid two-phase slippage, resulting in poor prediction accuracy of existing holdup models applied to high-viscosity fluids. Therefore, a new model for liquid holdup in gas-liquid two-phase slug flow in inclined pipes with different viscosities is proposed. This proposal is based on experimental observations and theoretical derivations. The holdup experiments of slug flow are conducted in a multiple phase pipe flow experimental platform, in a test string with an inner diameter of 60 mm. The influence of viscosity on liquid holdup and flow pattern transitions is studied based on the data of slug flow patterns and liquid holdup obtained with different viscosities and different inclinations in the experiments. The study shows that an increase in liquid viscosity will intensify the viscous resistance between the liquid phase and the pipe wall, resulting in a rise in liquid holdup. While the effect of viscosity on liquid holdup will change the transition boundaries between slug flow and other flow patterns. A new model for liquid holdup in gas-liquid two-phase slug flow in inclined pipes is established. This model is based on the Kora liquid holdup relationship formula and uses mixed-phase viscosity instead of liquid-phase viscosity. The model is validated by experimental and literature data, with confirmed higher accuracy. This research can provide technical support for predicting pressure drop in heavy oil wellbores.

Coalbed methane is one of the typical types of self-generated and self-stored gas reservoirs.Methane gas is mainly generated by the thermal evolution of organic carbon in coal seams and adsorbed in large quantities on the surface of pores.The content of organic components is crucial for the gas generation and storage capacity of coal seams.However,the reservoir structure of coalbed methane is complex,with interbedded development of organic coal-rock component structures and inorganic leat.The strong heterogeneity within the layers and the difficulty in visualizing the longitudinal coal seam structure in a single well greatly hinder the evaluation of organic matter abundance and efficient development of coalbed methane in single wells.Full-diameter CT scanning is an important experimental technique for large-scale core analysis in recent years.The grayscale values obtained by this technique are closely related to the composition of coal and rock.The higher the grayscale value,the higher the ash content,density,and mineral content of coal and rock,and vice versa.Taking the Daning-Jixian Block as the research object,this study combines full-diameter CT scanning technology with wellbore interpretation technology to explore the relationship between rock grayscale and logging data such as gamma, density,and sonic transit time.A mathematical model for digital well logging inversion of coal seam structure is established,and combined with the relationship between grayscale and organic components,a method for evaluating organic matter abundance in single wells using full-diameter CT scanning is proposed.The comparison between the inverted cross-section of Well A1 in the study area and the real grayscale cross-section obtained by full-diameter CT scanning shows a high degree of similarity,and the distribution pattern of inverted grayscale values is consistent with that of real CT grayscale values,indicating that the inversion model can effectively reflect the heterogeneity structure changes within the coal seam.The digital wellbore inversion and organic matter abundance evaluation method can provide strong technical support for fracturing section selection and production capacity prediction of coalbed methane wells in the study area.

Imbibition is an important mechanism for fracturing development in shale reservoirs,and the maximum imbibition distance is a direct indicator for evaluating the scope of imbibition,which is of great significance for the development of shale reservoirs.In order to determine the maximum imbibition distance of shale reservoirs,a calculation method of imbibition distance of countercurrent imbibition in shale reservoirs was developed according to the principles of filtration theory and numerical methods and based on the characterization of the capillary curve of shale reservoirs.The results were compared to the results of laboratory experiments so as to verify the reliability of the calculation method and analyze the influencing factors of the maximum imbibition distance.The research shows that the maximum imbibition distance increases linearly with the increase of permeability,but the time required to reach the maximum imbibition distance decreases exponentially;the ratio of oil/water viscosity has no effect on the maximum imbibition distance,however,the greater the viscosity of crude oil,the longer the time required to reach the maximum imbibition distance;when the reservoir permeability is 0.05 mD,with the contact angle of 45 ° and the interfacial tension of 50 mN/m,the maximum imbibition distance is 2.2 m,taking 170 d,which takes longer time.This study provides reference for evaluating the range of imbibition distance in shale reservoirs.

Due to the significant variation in fluid distribution,complex pore structure,and relatively low percolation capacity of the Chang 8 reservoir in the Fuxian Area of the Ordos Basin,five representative rock samples from the study area were selected for testing and analysis.The primary controlling factors affecting fluid mobility were analyzed using thin section casting, scanning electron microscopy (SEM),X-ray diffraction clay mineral analysis (XRD),and constant velocity mercury injection experiments.The results indicate that the movable fluid saturation in tight sandstone reservoirs ranges from 26.31% to 50.61%,with an average of 35.15%.The pore throat radius for movable fluid is between 0.10 μm and 0.50 μm;the T₂ cutoff value falls within the range of 6.69 ms to 49.90 ms,and the minimum pore throat radius for movable fluid is between 0.16 μm and 0.36 μm.The permeability of a reservoir exerts greater control over the mobility of fluids than porosity.The median radius,maximum pore throat radius,and average pore throat radius exhibit a positive correlation with movable fluid,with the median radius exerting a greater influence.Higher feldspar content facilitates the formation of feldspar dissolution pores,resulting in greater movable fluid saturation.Type Ⅰ and Type Ⅱ reservoirs exhibit high kaolinite content,with pores filled with dispersed particles.Type Ⅲ reservoirs exhibit high illite and mixed-layer illite content,with pores bridged and segmented,leading to pore throat plugging.These research findings provide valuable insights for enhancing the recovery of tight oil reservoirs.

To address the issues of unclear distribution characteristics and enrichment control factors of medium-low maturity shale oil reservoirs in the Jiaolige Sag,Ludong Depression,a study on the oil-bearing characteristics of shale oil reservoirs was conducted through methods such as 2D NMR analysis,nano-CT scanning,and identification of kerogen microscopic components.A comprehensive evaluation standard for identifying shale oil sweet spots was established based on factors such as shale lithofacies,reservoircapabilities,oil-bearing characteristics,andmobility.The results show that the degree of development,density,lithology,and other structural characteristics of shale lamination and bedding are the primary influencing factors on the oil-bearing characteristics and distribution.The layered siltstone,composed of coarse grained clastics and laminated felsic shale,exhibits excellent pore microstructure and connectivity.The specific surface area is less than 15 m²/g,and the average pore size of nitrogen adsorption is greater than 8 nm,which is a highly favorable reservoir.The total organic carbon (TOC)content of class Ⅰ+Ⅱ "sweet spot" exceeds 1%,with the reservoir exhibiting medium and large pores accounting for over 25%.The pore size within the reservoir space is greater than 8 nm,indicating a medium to good oil bearing potential and mobility,leading to relatively enriched oil and gas.These findings offer valuable technical support for identifying favorable targets for shale oil development in the study area,as well as for deploying and evaluating test areas.

The imbibition of fracturing fluid can alter the original gas-water occurrence in reservoirs,thereby affecting the production behavior of shale gas wells.However,through dynamic displacement and nuclear magnetic resonance experiments,combined with previous research results,we analysis of the original gas-water distribution in pores,the effects of fracturing fluid imbibition on gas occurrence in through-pores and blind-pores,and the relationship between gas well production behavior and fracturing fluid imbibition were carried out.The study reveals that the occurrence of original gas and water in pores is related to mineral types,fracture apertures,and reservoir humidity.There is bound water in small pores and pore corners.The adsorption area of methane in large pores decreases with increasing reservoir humidity,and the amount of adsorbed gas is influenced by the proportion of organic matter pores and maturity.A zone affected by imbibition exists near fractures,where fracturing fluid imbibition can promote desorption of adsorbed gas,displace free gas in non-equilibrium imbibition through-pores,and compress free gas in equilibrium imbibition through-pores and blind-pores.The gas displaced from non-equilibrium imbibition through-pores is one of the main sources of free gas in hydraulic fractures.Only when the fracturing fluid retained in the wellbore,fracture and influence area is discharged,was gas be produced from various areas,resulting in the phenomenon that the gas production curve lags behind the water production curve,and the fracture drainage resistance is much smaller than that of the matrix pore,which is the main reason for the "L"type decline of gas production and water production curve.The research findings focus on the impact of fracturing fluid imbibition on the occurrence and production of gas,contributing to the enrichment of shale gas reservoir protection theories.This has guiding significance for the efficient development of gas wells.

In the process of high-pressure air injection development in low-permeability reservoirs,the mechanism of crude oil oxidation is unclear,and there is difficulty in predicting enhanced oil recovery potential.In order to solve these problems,low-temperature oxidation experiments and physical simulation experiments of air injection in long core were conducted to analyze the differences in oil and gas composition before and after oxidation reactions under different reservoir conditions,reveal the characteristics and laws of crude oil low-temperature oxidation,investigate the development transition potential from water flooding to air flooding in low-permeability reservoirs,and evaluate the oil displacement effect of air injection.The results show that with the increase in oxidation temperature,the oxygen consumption of crude oil rises;while after the oxidation,the light components of the oil sample decrease and the medium and heavy components increase.Excessive water saturation reduces the heat effect of crude oil oxidation.The sensitivity factors of crude oil oxidation in terms of sensibility from large to small are pressure,temperature,and water saturation.So,air flooding has a better oil displacement effect,with an oil displacement efficiency of up to 41.20%.However,excessively high gas injection pressure can cause gas channeling.After reaching the economic limit by water flooding,development mode switched to air flooding can improve oil displacement efficiency,but the increment of oil displacement efficiency during the air flooding is relatively small,with an ultimate oil displacement efficiency of 50.92%.Therefore,in actual development process,oxygen-reduced air flooding should be adopted,and gas injection parameters should be optimized so as to control gas channeling and enhance oil recovery rate.The research results can provide a theoretical basis and technical support for the development of low-permeability reservoir by air flooding.

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

In order to address the coexistence of inorganic and organic pores in shale reservoirs, a dual-continuum approach was developed to establish a percolation mathematical model for the flow of oil and water phases in shale. This model takes into consideration the wetting and flow characteristics of oil and water phases within both inorganic and organic pores in shale. By employing the proposed model, we obtained matching results from oil-water spontaneous imbibition experiments conducted on shale and determined both the inorganic and organic pore permeability, facilitating accurate calculation of oil content within shale reservoirs. Furthermore, a comprehensive study was carried out to investigate the dynamic characteristics and influential laws of the permeation process in shale. The study results indicate that the permeability of inorganic pores ranges from 10^-8 to 10^-5 D, while that of organic pores ranges from 10^-10 to 10^-7 D. As the permeability through inorganic pores increases, the rate of spontaneous imbibition in shale also increases. However, when the ratio of organic pore permeability to inorganic pore permeability is less than 10^-3, the impact of organic pore permeability on self-imbibition rate is insignificant. These findings have significant implications for a thorough assessment of permeability and reserves in shale reservoirs.

To address the lack of consensus on the slug flow pattern and control factors in the middle section of reservoir fractures, the flow pattern of slug in fracture is studied, the influence and fluctuation characteristics of key parameters of slug flow are analyzed, such as fracture diameter and gas-liquid phase flow rate. The results indicate that the two-phase slug flow presents periodic characteristics in the fracture by using micro-scale flow simulation experimental device of two phase (gas and liquid) migration and production,. From formation to disappearance, the gas slug can be divided into three stages: formation, expansion and dominance. The fracture diameter is linearly negatively correlated with the slug frequency and linearly positively correlated with the fluctuation range of gas and liquid phase flow. As the liquid flow rate was set at 15.00, 20.00, 25.00 and 30.00 cm³/min, the variance ratio of slug frequency decreased with increasing gas flow rate, being 0.130,0.012,0.009 and 0.007, respectively.Similarly, the variance ratio of liquid holdup decreased with increasing gas flow rate, being 1.503,1.175,0.918 and 0.820, respectively. The findings have guiding significance for the study of slug flow mechanism in the process of coalbed methane development.

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

Due to the large fluctuation of pressure difference between injection and production wells during the preheating and start-up process of SAGD steam injection cycle in continental heterogeneous ultra-heavy oil reservoirs in Xinjiang Oilfield,it is difficult to control on site.Steam is easy to enter the oil layer of high permeability horizontal section,which is easy to cause local preferential connection or steam channeling in horizontal section.The development of steam chamber is not balanced, which leads to the low utilization degree of horizontal section,thus affecting the production effect of SAGD.Therefore,the development method of putting electric heaters into the horizontal section of SAGD in double horizontal wells is proposed.The oil layer between injection and production wells is uniformly heated by the principle of heat conduction,and the key operation parameters of SAGD electric heating preheating start-up are optimized,including SAGD electric heating start-up wellbore pretreatment,fluid replacement cycle operation parameters and SAGD production time.The SAGD electric heating preheating start-up operation process is formed.SAGD electric heating preheating start-up field test was carried out in the shallow ultra-heavy oil double horizontal well of FHW01TW Well Group in Chong A Well Area of Xinjiang Oilfield.The preheating startup time was reduced from 320 days to 163 days,3.79×10⁴ t steam was saved and 4 846.6 t CO₂ emission was reduced.This technology will become one of the important means to reduce CO₂ emission in SAGD development of shallow double horizontal wells.

CO₂ flooding and storage have the potential to significantly mitigate greenhouse gas emissions and contribute to achieving carbon neutrality objectives. Nevertheless, current methods for calculating CO₂ storage capacity primarily concentrate on rough estimates of static CO₂ storage, neglecting variations in CO₂ storage during actual production processes. In view of the above problems, the process of CO₂ flooding and storage is divided into gas phase zone, two-phase or near-miscible phase zone, diffusion zone and oil phase zone by using CO₂ dissolution, CO₂ swept volume and oil displacement mechanism. Based on the four-zone method, the CO₂ storage capacity is calculated, and the dynamic CO₂ storage capacity under varying hydrocarbon pore volume multiples, injection pressure and gas injection rate is obtained. The research results are applied to the low permeability reservoir of W oilfield. The results show that the pore volume multiple, pressure and gas injection rate of injected hydrocarbons are positively correlated with the total storage capacity. When the pressure increases from 12 MPa to 30 MPa, the total amount of CO₂ storage increases by 15.53×10⁴ t; when the gas injection rate increases from 5 t/d to 30 t/d, the total amount of peak CO₂ storage increases from 3.51×10⁴ t to 12.62×10⁴t. The research results can provide new ideas for the development of CO₂ flooding and storage projects in similar reservoirs.

Oil and gas resources are rich in Zhuanghai Area of Jiyang Depression. The proven reserves are high in the Neocene and buried hill strata, while the degree of drilling and understanding of the Paleogen is low, and the characteristics of the Paleogen reservoirs and the genesis mechanism of high-quality reservoirs are poorly understood. For this reason, we have studied the petrological characteristics, type of diagenesis, spatial characteristics of clastic reservoirs and the controlling factors of high-quality reservoirs in the Lower Dongying Member-Shahejie Formation in Zhuanghai Area through the means of analysis such as cores, thin sections, scanning electron microscopy, etc. The results show that the clastic reservoirs of the Lower Dongying Member-Shahejie Formation in Zhuanghai Area have a small distribution range and thin thickness, and the reservoirs are dominated by sandstones deposited rapidly near sources with low rock maturity. The compaction is the main reason for destroying the pore space of the reservoirs. The cementation, mainly carbonate cementation, has caused further damage to the pore space. The dissolution of organic acid is an essential factor for forming secondary pore space and increasing pore space in the reservoir. The overall pore type is dominated by secondary pores and primary pores are only retained to a relatively high degree in the reservoirs of the Lower Dongying Member in the northwest source area, and the reservoir fractures are few. The high-quality reservoirs is mainly controlled by three conditions: sedimentary conditions, diagenetic modification, and fracture communication. The glutenite reservoirs are favorable exploration targets with high rock maturity, far from calcium sources, close to acid sources, and fracture communication. This study can provide the geological basis for the exploration and development of the Paleocene system in Zhuanghai Area.

Deep shale reservoirs are characterized by high closure pressure,high formation temperature,and high elastic modulus,making it challenging to achieve high conductivity fractures through fracturing.To effectively support and maintain pressure fractures in deep shale gas reservoirs,taking the deep shale of the Weiyuan Block in Sichuan as an example,based on an self-developed testing platform of API fracture conductivity,this study investigated the impact of high closure pressure (82.8 MPa) and high formation temperature (160 ℃) on the conductivity of supported fractures.The differences in conductivity under different types and combinations of proppants are compared,and the adaptability of self-supported fractures under deep shale conditions is analyzed.The results indicates that the high closure pressure is the main controlling factor for the decrease of fracture conductivity.Under the high closure pressure of 82.8 MPa,the positive effect of increasing sand concentration on conductivity is no longer evident;the high-temperature environment increases the degree of proppant breakage and embedment,with higher temperatures resulting in lower conductivity;the fracture conductivity of 40/70 mesh ceramsite proppant is significantly greater than that of 70/140 mesh quartz sand and micro-nano proppants;the conductivity of quartz sand and ceramsite (mass ratio of 1∶1) placed in sections is more economical and has higher conductivity than the whole mixed placement;the convex points on the wall of self-supported fractures are easily crushed under high closure pressure,showing strong stress sensitivity in conductivity,which is not conducive to maintaining conductivity in the later stages of production.The results of this study provide theoretical support for the design of fracturing parameters and optimization of conductivity in deep shale gas reservoirs.

The application range of oil-based drilling fluids is extensive.To reduce the cost of oil-based drilling fluids,a new low-cost formulation with a low oil-water ratio and low soil content was developed.This was achieved by selecting affordable oil-based base fluids,developing new single-dose high-efficiency emulsifiers,reducing the oil-water ratio,and decreasing the addition of organic soil.The performance of the new formulation was evaluated in the laboratory.According to experimental results,the oil-water ratio of the drilling fluid can be adjusted within the range of 65:35 to 85:15.The organic matter content is limited to 2.0% or lower,with a density of 1.4 to 2.2 g/cm³ and temperature resistance up to 200 ℃.The demulsification voltage is greater than 800 v,high temperature and high pressure fluid loss is less than 3 mL,and the unit cost of oil-based drilling fluid is reduced by over 15% compared to the fluid prepared with No.3 white oil.This fluid is suitable for -25 ℃ conditions and can meet construction needs during winter in the Liaohe Oilfield.The low-cost,low oil-water ratio,low-soil oil-based drilling fluid has been successfully applied in shale oil and tight oil formations in Liaohe Oilfield.Field application results demonstrate its stable performance,good plugging and anti-collapse capabilities,excellent emulsification stability,good low-temperature resistance,and significantly reduced unilateral cost.These research findings contribute to the expansion of the application scale of oil-based drilling fluid and can meet the technical requirements for the low-cost,safe,and efficient development of unconventional oil and gas reservoirs.

To improve the seismic interpretation accuracy and seismic data information extraction capacity of deep-water sedimentary formation, seismic forward modeling was conducted on the slope deposits with canyons. The seismic reflection characteristics of cleuch, channels and canyons dominated by turbidity flow and block transposition are analyzed. The fine forward modeling of the natural levee complex of channels is carried out. The comprehensive analysis suggests that the width-depth ratio of the cleuch dominated by block transport is low and symmetrically filled, and the interior is mainly chaotic weak amplitude reflections. While the canyons dominated by turbidity flow has a large width and depth, the interior of which is an undulating high amplitude reflections; the smaller the angle between the top and bottom interfaces of the formation, the greater the error between the true pinch-out point and the seismic reflection pinch-out point; the decrease in thickness of the natural levee complex of channels results in a lower seismic reflection frequency and enhanced amplitude; the amplitude of the channel when it is saturated with water is stronger than that when it is saturated with gas. Hence the seismic response characteristics of multi-type deep-water sedimentary bodies with different morphological attributes are further clarified, which can effectively improve the accuracy of comprehensive interpretation of seismic data in deep-water sedimentary formations.

Rock brittleness is a key indicator controlling rock fracturing, determining the formation of an effective fracture network during fracturing. Studying the characteristics of rock brittleness and fracturing behavior through acoustic emission signals can directly reveal the relationship between rock fracturing and brittleness. However, the relationship between acoustic emission signal characteristics and rock fracturing patterns has not yet been established, making it difficult to accurately determine the brittleness characteristics of rocks. Therefore, based on the wavelet packet decomposition method, this study divides rock acoustic emission signals by energy frequency bands and builds the relations between different brittle rock fracturing patterns and the energy distribution of acoustic emission signals. Through the analysis of the three-dimensional spatial distribution characteristics of acoustic emission signals, a rock brittleness index evaluation method based on the energy distribution of acoustic emission signals is proposed. The study shows that the energy characteristics of acoustic emission signals are related to rock brittleness, with the main frequency of energy distribution mostly below 750 kHz. The higher the content of brittle minerals in the rock, the larger the proportion of energy signals,the more concentrated the energy distribution of rock fracturing acoustic emission signals, the stronger the mutability of rock fracturing, the more apparent the transition between fracture tension, shearing, and mixed evolutionary expansion modes, and the greater the brittleness index. The results can provide reference and guidance for research on rock fracturing warning and other related aspects.

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

In order to explore effective approaches to enhance oil recovery in the late stage of water-flooded development in reservoirs with medium-low permeability and high-ultra-high water content,this study,taking Nanhu Oilfield as an example,deepens the understanding of reservoir microscopic characteristics through mineral analysis and SEM methods,and investigates the feasibility and application effects of dispersed particle gel in improving oil recovery using the combination of nuclear magnetic resonance and mercury injection methods.The results show that Nanhu Oilfield is featured with well-developed large pore channels, obvious speed sensitivity and water sensitivity.Severe water breakthrough is the main reason for inefficient development,while key factors for improving development effectiveness include low-rate water injection,maintaining reservoir energy,and controlling water channeling.The dispersed particle gel can effectively inhibit water breakthrough and improve the mobilization ability of residual oil in medium and small pores. The oil recovery ratio in small pores of the core samples, in medium pores increased by 52.83 percentage points by 34.60 percentage points,respectively,after dispersed particle gel flooding,and the oil recovery increased,and the overall recovery ratio increased by 33.14 percentage points,indicating a significant improvement in development effectiveness.The findings of this study can provide references for improving the development effectiveness of reservoirs with high water content.

When evaluating the lateral closure performance of fractures in arenaceous shale formation,The SGR uses a constant derived from statistics as the lower limit,which leads to a significant deviation between the evaluation results and exploration practice.In view of the aforementioned issue,the minimum shale content of fault rock required for lateral closure of faults in arenaceous shale formation is determined by using fault dip angle,diagenetic time of fault rock compaction,shale content of target reservoir and diagenesistime of compaction.The results show that the minimum shale content of fault rock is a variable value based on the closure mechanism,which addresses the issue of insufficient constant value in SGR method and effectively improves the accuracy of lateral closure evaluation.This method has been applied to the evaluation of the lateral closure of the arenaceous shale reservoir in the southern section-2 of the F3 fault in the Huhenuoer tectonic zone of the western Beier Depression in the Hailar Basin,and the finds are as follows:at measuring points 5,7,8 and 12-15,the F3 fault closes laterally towards the inner side of the sandstone reservoir in the southern section-2,while at the remaining measuring points,it does not close laterally,which is consistent with the main distribution of oil and gas observed at measurement points 7,8,12 and 14.The research results are of great reference significance for the distribution characteristics of fault-type oil and gas reservoirs in arenaceous shale formation of oil and gas bearing basins,and indicate the direction of oil and gas exploration.

To address the issue of the ambiguous understanding of the distribution characteristics and development degree of structural fractures in Leikoupo Formation of Pengzhou Gas Field,taking into account the influence of sedimentary microfacies,layer thickness and bedding plane,a prediction approach of structural fractures in carbonate strata based on engineering geomechanics was established.Taking the fourth member of Leikoupo Formation in PZ-6 well area as an example,the finite element method was employed to assess the trans-scale structural fractures of the well area and individual wells.The results demonstrate that the structural fractures in the well area are mainly oblique fractures,and the fracture linear density in the fault area is approximately 1.3 per metre.The fracture line density of algal dolomite flat and dolomite lime flat is greater than that of other sedimentary microfacies.The relative error between the statistical results and the prediction results of fracture line density in the well area is 6.83%,and the well location can be preferentially deployed in the above two sedimentary microfacies.The prediction results of structural fractures in single wells are in accordance with the logging results by 91.23%,and the formation fracture coefficient at the bedding plane is greater than 1.2,indicating that the structural fractures at the bedding plane are more developed.The thin layer is influenced by the layer,and the principal stress change is more obvious.During the construction,well leakage can be prevented in accordance with the distribution of single well structural fractures.The research results are of great significance to clarify the distribution characteristics of structural fractures,optimal selection of horizons and well location deployment in Leikoupo Formation of Pengzhou Gas Field.

During the drilling process of stratified shale oil reservoirs,if the wellbore stability is not well enough,it is prone to frequent incidents such as wellbore collapse and stuck pipe.A numerical model for the stress around the wellbore and a collapse zone prediction method in shale oil reservoir is developed to reveal the influence of bedding plane on wellbore collapse and enlargement of shale oil reservoir in accordance with MG-C strength criterion and multi-weak plane criterion.Also,the collapse and enlargement patterns for single and multiple weak planes under different stress mechanisms are calculated.The results show that the presence of multiple weak planes causes simultaneous damage to the matrix and weak planes,leading to more complex wellbore collapse patterns.While collapse expansion induced by weak planes is significantly higher than that of the matrix.Compared to the strike-slip stress mechanism,the collapse of wellbore under normal stress mechanisms shows a more significant change with stress ratio,and the collapse risk is higher.Under normal stress mechanisms,when the stress ratio exceeds 1.5,the wellbore expansion rate exceeds 100% and wellbore increases sharply.The research findings provide theoretical guidance for preventing wellbore collapse during drilling in shale oil reservoirs under different regional stress mechanisms.

Deep tight reservoirs present intricate geological conditions, posing challenges in accurately calculating gas saturation. To address the issue, the structural belt of northern Kuqa in Tarim Basin is taken as an example. Based on the theories of rock conductivity and acoustics, using petrophysicaltesting methods and data analysis techniques, combined with mercury intrusion porosimetry and nuclear magnetic resonance data, the reservoirs are divided into four categories based on their pore structures.According to the parameters of rock fractures, the relation equation between water saturation and acoustic parameters at different conditions of pore structures is established. An innovative saturation calculation model based on acoustic parameters and pore structure classification has been developed. According to the research results, compared with Archie equation of electrical petrophysical variations in rocks and Gassmann-Wood saturation equation, the simulator better matched with the test data. This method has proven to be feasible. The method provides a new approach to calculate the saturation of deep tight reservoirs using non-electric logging data, and promote efficient exploration and development in deep tight gas reservoirs.

To address the issues of high production decline rate and low recovery rate in the early stage of tight oil development,considering the rock and fluid properties of Fuyu tight oil reservoir, numerical simulation methods were used to study the effects of injection timing and injection pressure on the effect of CO₂ huff-n-puff.The engineering parameters were optimized, the characteristics of reservoir pressure distribution and interfacial tension distribution are analyzed,the operability of CO₂ huff-n-puff development of tight oil is studied.The results indicate that CO₂ huff-n-puff should be implemented when the oil reservoir pressure coefficient drops to around 0.65.At this time,CO₂ can fully contact with crude oil,which is beneficial for the dissolution,thereby improving the recovery efficiency.As the injection pressure approaches the minimum miscible pressure,CO₂ in a separate phase enters the matrix,making full contact with the tight oil deep within.The dissolved miscible phase improves the development effect.After reaching dissolution equilibrium,the interfacial tension between CO₂ and tight oil increases rapidly over time,the time of well shut-in can be determined at this moment.The optimal engineering parameters for CO₂ huff-n-puff recovery in this study are:the injection volume is 8000 t,the injection rate is 120 t/d, the injection pressure is 27 MPa,and the time of well shut-in is 30 d. According to this scheme, the increase of crude oil production is calculated to be 3 084 t,and the oil replacement ratio is calculated to be 0.39. The in-situ test of horizontal well also confirms that the application of CO₂ huff-n-puff technology in Fuyu tight oil reservoir increased the recovery rate by 1.38 to 3.33 percentage points.The research results are of great significance for further expanding the application of CO₂ huff-n-puff technology in tight oil reservoirs.

In the southern part of Songliao Basin, Chaganhua Area, the lithology of the Huoshiling Formation volcanic rocks is complex and variable. Traditional methods such as two-dimensional intersection and step-by-step classification based on conventional well logging data are difficult to accurately identify the lithology of volcanic rocks. To address the issues, a proposal is developed to use machine learning algorithms for intelligent identification of volcanic rock lithology. By observing sample cores and thin section analysis, the lithology of volcanic rocks in the sampled section is determined. The logging data set of the coring section is divided into training set and test set. The training set is used to match the object function, and the test set is brought into the model to predict results, and use integrate models with ensemble learning to conduct blind well prediction.The fusion model establishes a quantitative mathematical relationship between the characteristics of each well log curve, integrates the characteristics of multiple machine learning, and improves the learning efficiency of the model based on accurate lithology data set labels.The results show that the prediction accuracy of the integrate model for blind wells achieves 95.10%. The model has wide applicability, which can accurately identify and predict the lithology of volcanic rocks. This study can provide support for the intelligent exploration of volcanic rock oil and gas.