Current Issue

  • Hydrocarbon generation characteristics and shale oil resource potential of Lianggaoshan Formation shale in Yilong-Pingchang area of Sichuan Basin

    DONG Jinghai;ZHANG Jiwei;WANG Xiandong;DONG Zhongliang;WANG Zhiguo;WANG Tao;WANG Lidong;ZHAO Linhai;Exploration Department of PetroChina Daqing Oilfield Co.,Ltd.;Exploration and Development Research Institute of PetroChina Daqing Oilfield Co.,Ltd.;

    In order to clarify hydrocarbon generation characteristics and shale oil resource potential of Lianggaoshan Formation shale in Yilong-Pingchang area of Sichuan Basin, material balance method, thermal simulation experiment and basin simulation method are used to conduct the research on the original hydrocarbon generation potential, hydrocarbon generation and expulsion efficiency and hydrocarbon generation, as well as shale oil resource estimation based on the principles of genesis and volume, and the division of shale oil resource potential zones is completed. The results show that Lianggaoshan Formation in Yilong-Pingchang area shale has large net pay thickness(40～80 m), favorable organic matter type(Type Ⅱ), moderate abundance(w(TOC) of 0.50% ～ 3.39%) and high maturity(R_o 1.0% to 1.9%). The average original hydrogen index of shale is 522 mg/g. Conditions for oil generation are abundant when the hydrocarbon generation conversion rate is 70%～95%, and the vitrinite reflectance is 1.04%～1.72%. Hydrocarbon generation of Lianggaoshan Formation shale in studied area estimated by the organic carbonhydrogen index formula method and basin simulation method are 92.26×10~8 and 94.02×10~8 t, respectively. Shale oil resources estimated by the genetic method and volume method are 25.60 ×10~8 and 27.35×10~8 t, respectively. The studied area is located in Class I favorable areas for shale oil and shale gas resource potential. Central LonggangPingchang area is Class I_A favorable area for shale oil resource potential, while northern Pingchang and areas north of Pingchang are Class I_A favorable areas for shale gas resource potential. The overlapping area of the two is favorable area for shale oil and gas resource potential. The research provides new ideas for the study of hydrocarbon generation characteristics of similar types of shale and shale oil resource potential.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1868K]

  • Sedimentary characteristics and evolution laws of Jurassic Lianggaoshan Formation in Sichuan Basin

    ZHANG Dazhi;YANG Gang;FU Youzhong;LI Xin;XIAO Limei;SHAO Hongjun;SUI Liwei;LI Jipeng;SUN Shan;LIU Ruotong;State Key Laboratory of Continental Shale Oil;Exploration and Development Research Institute of PetroChina Daqing Oilfield Co.,Ltd.;No.1 Oil Production Company of Petrochina Daqing Oilfield Co.,Ltd.;

    Well Ping'an-1 of Jurassic Lianggaoshan Formation in northeastern Sichuan Basin has made significant breakthroughs, revealing that Jurassic Lianggaoshan Formation has abundant shale oil and gas resources. However, less research on the overall exploration of Lianggaoshan Formation across the whole basin has constrained the progress of shale oil and gas exploration in Lianggaoshan Formation. Based on field outcrop, core, thin sections, electric logging and mud logging data, the overall sedimentary characteristics and areal extention of sedimentary facies in Lianggaoshan Formation are clarified by means of rock types classification, single-well sedimentary microfacies classification,well-tie facies correlation and establishment of sedimentary model. The results show that the structure in sedimentary period of Jurassic Lianggaoshan Formation is relatively unstable,forming an incomplete long-term water inflow and regression cycle, which includes lowstand system tract,lacustrine transgressive system tract and incomplete highstand system tract. Sediments in Lianggaoshan Formation are mainly lacustrine silt-fine sandstone and mud shale,with small amount of shell limestone locally developed and generally being a lake-delta sedimentary system. Vertically,1 st sub-member of upper Lianggaoshan Formation and 2 nd sub-member of upper Lianggaoshan Formation are favorable exploration intervals, and horizontally,Pingchang-Yingshan area is favorable exploration area. The research provides support for further exploration and development of shale oil in Lianggaoshan Formation.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 3903K]

  • Main controlling factors and favorable area evaluation of Permian Maokou Formation karst reservoir in Danfengchang area of Sichuan Basin

    LAN Yulong;LI Hongxi;WU Wei;OUYANG Minghua;WEN Huaguo;XU Wenli;CHEN Shizhen;MO Bowen;QUAN Hao;Geological Exploration and Development Research Institute of CNPC Chuanqing Drilling Engineering Company Limited;State Key Laboratory of Oil and Gas Reservoir Geology and Expoitation;Institute of Sedimentary Geology,Chengdu University of Technology;

    The lack of systematic research on Maokou Formation karst reservoirs in Danfengchang area of Sichuan Basin constrains the progress of oil and gas exploration and development, and urgently needs determination of reservoir development characteristics and main controlling factors of productivity. Based on cores, logging and seismic data, the rock types, reservoir space, properties, distribution and main controlling factors of karst reservoirs are analyzed, and reservoir favorable areas are divided by areally overlapping main controlling factors. The results show that karst reservoir of Maokou Formation is mainly composed of bioclastic limestone and algal limestone, with reservoir space dominated by vugs, intergranular dissolved pores, structural fractures and dissolution fractures, being ultra-low porosity-ultra-low permeability reservoir. Karst reservoir is divided as upper member and lower member. Upper reservoir mainly developed in Mao3 member and Mao2a sub-member, while lower reservoir mainly developed in Mao2b sub-member. With maximum thickness up to 19 m, upper reservoir is superior to lower reservoir in scale. The development of karst reservoirs is mainly controlled by 3 factors, including development degree of highenergy grain-beach, karst paleogeomorphology types and faults assemblage styles. Among them, faults assemblage style has major impact on reservoir karstification. 2 types of favorable areas are defined. Class Ⅰ favorable area has the best exploration potential, and high-production wells mainly distribute in this area, located 200～1 000 m away from fault. Class Ⅱ favorable area has certain exploration potential. The research can effectively guide further exploration and development in this area.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 4684K]

  • Main controlling factors of oil and gas accumulation and prediction for favorable accumulation area in the second member of Nantun Formation in Beier Sag of Hailar Basin

    WANG Bintao;ZHAO Xiaoqing;DONG Lei;JIA Shanpo;WANG Hongqiang;School of Earth Sciences,Northeast Petroleum University;Daqing Branch of China National Logging Corporation;

    Current studies on main controlling factors of oil and gas accumulation in 2 nd member of Nantun Formation in Beier Sag of Hailar Basin mostly focuses on qualitative analysis, and the lack of accurate quantitative prediction for favorable accumulation zones restricts the process of increasing reserves and production. Based on the analysis of critical conditions for reservoir distribution, the method of coupling quantitative evaluation of main controlling factors of reservoir accumulation is used to study hydrocarbon distribution law of reservoirs in the second member of Nantun Formaiton in Beier Sag. The results show that main controlling factors of hydrocarbon accumulation in the second member of Nantun Formaiton of Beier Sag are source rock, cap rock, porosity, sandstone thickness and faults. Over 89.6% of reservoirs are distributed within 3 km from hydrocarbon expulsion centers in the second member of Nantun Formaiton. Reservoir porosity and sandstone thickness of the second member of Nantun Formaiton are characterized by regular extension, presenting good development in the south and poor development in the east. A large number of reservoirs accumulate in condition of cap rock with thickness of 410 ～ 460 m. With the increase of cap rock thickness, the number of reservoirs increases first and then decreases, and areas with large faults density have relatively high accumulation probability. Main controlling factors coupling predicts 2 most favorable accumulation zones, 1 favorable accumulation zone, 1 relatively favorable accumulation zone and 1 accumulation zone in the second member of Nantun Formaiton. Case study verifies the reliability of prediction results, and the research provides guidance for oil and gas reservoirs exploration of the second member of Nantun Formaiton in Beier Sag.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1419K]

  • Method for determining compaction-diagenesis of fault zone fillers in sand-mudstone strata and its application

    ZHANG Xinyao;FU Guang;School of Earth Sciences,Northeast Petroleum University;

    In order to improve the accuracy of fault sealing evaluation in sand-mudstone strata, based on the study of compaction-diagenesis characteristics of fault zone fillers and their profile variation, compaction-diagenesis degree coefficient is determined by using buried depth, dip angle, shale volume fraction and diagenetic time of fault zone fillers. Based on the relationship between compaction-diagenesis characteristics of surrounding rock cores and the compaction-diagenesis degree coefficient, the minimum threshold value of the coefficient required by surrounding rocks compaction-diagenesis is determined. By comparing the ralavtive sizes of two cofficents, a set of methods for identifying compaction-diagenesis of fault zone fillers in sandstone-mudstone strata are established to determine whether fault zone fillers in different stratas of Gangdong fault zone in Qikou Sag of Bohai Bay Basin are compactiondiagenetic. The results show that, fault zone fillers in rocks of the top strata in Minghuazhen Formation of Gangdong Fault are non-compaction-diagenetic type, while those in other stratas are all compaction-diagenetic, which is conducive to oil and gas accumulation and preservation. Among them, fillers in the first member of Shahejie Formation exhibit the highest compaction-diagenetic degree, while those in the first, second members of Dongying Formation and Guantao Formation show the lowest degree, with oil and gas shows conisistent with that in current Gangdong Fault. The research provides theoretical basis for determining whether fault zone fillers in sandstone-mudstone stratas are compaction-diagenetic.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1191K]

  • Progress in experimental analysis techniques for shale oil

    LIU Xin;Exploration and Development Research Institute of PetroChina Daqing Oilfield Co.,Ltd.;

    Shale oil is an important strategic replacement resource for increasing reserves and production of oil and gas in China. Experimental analysis technique has laid a solid foundation for the effective exploration and development of shale oil. Aiming at the practical requirements of shale oil experimental analysis technology in Daqing Oilfield, a literature information tracking and research method is used to study the current status and progress of shale oil reservoir evaluation and experimental testing research from three aspects of reservoir properties, oil-bearing properties and mobility. The results show that the evaluation of shale oil reservoir properties includes pore quantitative characterization and accuracy determination of porosity, permeability and saturation, which are closely related to reservoir space distribution characteristics of shale mineral composition, pores and fractures. The evaluation of shale oil-bearing properties and mobility includes the comprehensive analysis of parameters such as shale oil saturation, viscosity and density, which are closely related to the distribution of micro-area oil and fluid mobility. Further development direction of shale oil reservoir evaluation is also discussed, including the emphasis on the combination of 2D-3D techniques in modern imaging analysis to achieve fine characterization of multi-scales pore structures, strengthening comprehensive characterization and dynamic evolution studies of shale reservoirs to comprehensively assess the pore structure, fluid occurrence state and dynamic variation of shale reservoirs, and paying attention to the integrated development of various experimental analysis techniques for shale oil oil-bearing properties and mobility to improve the accuracy and reliability of shale oil mobility evaluation.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1206K]

  • Numerical simulation of migration and plugging of temporary plugging agents in redirected fractures of deep coalbed methane

    REN Lan;ZHAO Ge;LIN Ran;REN Qianqiu;WU Jianfa;SONG Yi;SHEN Cheng;State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation,Southwest Petroleum University;Petroleum Engineering School of Southwest Petroleum University;Tianfu Yongxing Laboratory;Shale Gas Research Institute of PetroChina Southwest Oil & Gasfield Company;

    During the development of coalbed methane(CBM), due to the high plasticity of deep coal rock and large in-situ stress difference, temporary plugging and diversion fracturing technique is mainly used to promote complex fracture network propagation. However, field fracturing data shows that temporary plugging parameters in some fracturing stages are unreasonable, failing to achieve successful bridging and plugging of the agents within the fractures, resulting in diversion failure and consequently impacting the fracturing effect. Considering the influence of proppant sand bank on the migration of temporary plugging agents within fractures, a numerical model for temporary-plugging-agent particle migration and plugging in coal-rock hydraulic fractures is established based on the coupling of Computational Fluid Dynamics(CFD) and Discrete Element Method(DEM), exploring the bridging behavior of temporary plugging agent particles and plugging efficiency under different operational parameters. The results indicate that, when temporary plugging agent is injected, the optimal volume ratio of large-to-small particle size is 4:1. Key factors such as fracturing fluid viscosity, temporary plugging agent volume fraction and fluid injection rate affect the bridging time, plugging volume and bridging distance. The inlet fracture width shows no significant correlation with the volume of temporary plugging agent, achieving effective temporary plugging at various fracture widths. The research provides theoretical guidance for the field temporary plugging and diversion technique in deep coalbed methane and the regulation mechanism of artificial fracture networks.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1670K]

  • Dynamic reserve calculation method for abnormal high-pressure replenishing gas reservoir considering seepage barrier

    TAN Xiaohua;SHI Jiajia;ZHANG Fei;LI Tao;CHEN Sulin;LI Xiaoping;State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation;Petroleum Engineering School,Southwest Petroleum University;Chengdu Exploration and Development Research Institute of PetroChina Daqing Oilfield Co.,Ltd.;Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company;

    Conventional dynamic reserve calculation methods cannot predict the reserves of replenishing gas reservoirs. Therefore, developing a new reserve calculation method for replenishing gas reservoirs is of great significance to gas reservoir development. In replenishing gas reservoirs, fluid flow through low-permeability zones of heterogeneous reservoirs is affected by seepage barriers, which obstructs inter-reservoir gas migration. To explore the influence of seepage barriers on the development of replenishing gas reservoirs, the interlayer productivity coefficient is introduced. A physical model and a mathematical model for abnormal high-pressure replenishing gas reservoirs considering seepage barriers are established. Through iterative solutions of the mathematical model, the relationship curve between formation pseudo-pressure and cumulative gas production is plotted. The results show that when the interlayer productivity coefficient is constant, increasing the gas volume in replenishing zone does not change the initial slope of bending segment, while total reserves of gas reservoir increase with the increase of replenishing gas volume. When the gas volume in replenishing zone is constant, increasing the interlayer productivity coefficient increases the initial slope of bending segment and accelerates gas flow across seepage barriers, effectively improving the gas reservoir production. The research achieves quantitative calculation of replenishing gas and provides a new idea for reserve calculation of replenishing gas reservoirs.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1291K]

  • Adsorption laws and mechanism of nanofluids on shale surface

    ZHAO Yu;ZHANG Jian;JIANG Panglu;DENG Sen;HE Liang;GONG Lianjie;LIANG Lihao;Exploration and Development Research Institute of PetroChina Daqing Oilfield Co.,Ltd.;State Key Laboratory of Continental Shale Oil;China Petroleum Technology Development Co.,Ltd.;College of Petroleum Engineering,China University of Petroleum (Beijing);No.1 Oil Production Company of PetroChina Daqing Oilfield Co.,Ltd.;PetroChina Research Institute of Petroleum Exploration & Development;

    Nanofluids are often used to enhance oil recovery of unconventional reservoirs. In order to clarify their adsorption laws and mechanism on shale surface, Lambert-Beer law is used to study adsorption laws of nanofluids on shale surface based on the relationship between absorbance and adsorption amount. Nanofluids are mixed with shale powder and oscillated, controlling the temperature to achieve adsorption equilibrium and measuring the change in solution concentration to calculate the adsorption amount. The optimum concentration and equilibrium adsorption time of 3 different nanofluids are studied to determine adsorption types of nanofluids on shale surface and the influence of temperature on their adsorption laws, and adsorption mechanism of nanofluids changing wettability is further discussed. The results show that, equilibrium adsorption times of SD, GP and DG nanofluids are all 25 min. With the increase of temperature, equilibrium adsorption amount of nanofluids decreases in various degrees, and adsorption laws of nanofluids on shale particles surface conform to Langmuir monolayer adsorption curve. All nanofluids can change the wettability of shale surface, and SD and GP nanofluids can achieve wettability reversal of shale surface. The research provides basis for further application and promotion of nanofluids in shale reservoir stimulation.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1876K]

  • Influence of ignition temperature on displacement efficiency in heavy oil reservoirs

    WANG Jiaying;ZHAO Renbao;HE Jintang;MEN Ziyang;YUAN Yuan;SUN Ziqi;ZHANG Haiyang;REN Haitao;XU Han;TIAN Jingtong;ZHANG Lijuan;College of Petroleum Engineering,China University of Petroleum (Beijing);State Key Laboratory of Petroleum Resources and Engineering;No.1 Gas Production Company of PetroChina Xinjiang Oilfield Company;PipeChina Construction Project Management Branch;Chengdu Exploration and Development Research Institute of PetroChina Daqing Oilfield Co.,Ltd.;

    As a pontential technique to significantly enhance oil recovery in heavy oil reservoirs, in-situ combustion(ISC) still faces challenges in achieving efficient ignition, which limits its large-scale application. In view of problems of the complex distribution of water bodies in reservoirs during the late stage of steam flooding development and unclear combustion characteristics and influencing laws of ultimate displacement efficiency at different ignition temperatures, one-dimensional combustion tube experiment is conducted to study the dynamic combustion characteristics of target reservoirs at different ignition temperatures, analyzing the ISC effect in different conditions from 3 aspects including temperature propagation characteristics, oil wall formation patterns and ultimate displacement efficiency. The results show that at lower ignition temperature, the fuel deposition time is longer and oil wall forms later, with smaller oil wall thickness and higher ultimate displacement efficiency. Water in the reservoir enhances heat transfer efficiency during ISC process but reduces the intensity of combustion, shortening the effective combustion distance and reducing displacement efficiency, with more obvious effect at higher ignition temperature. Therefore, the ignition temperature should be appropriately reduced to achieve higher displacement efficiency for heavy oil reservoirs after steam flooding. The research provides lab reference for ignition parameters for ISC technique to enhance oil recovery in current reservoir water cut conditions in NY oilfield.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1800K]

  • Derivation and application of a new model for oil-water relative permeability of low-permeability sandstone reservoirs based on fractal theory

    ZHANG Zheng;CHENG Linsong;LIU Jinbao;CAO Renyi;College of Petroleum Engineering,China University of Petroleum (Beijing);

    In order to accurately predict the oil-water relative permeability in low-permeability sandstone reservoirs,a fractal dimension model for tortuous capillary bundles with non-equal diameters is constructed based on fractal theory.By combining high-pressure mercury injection experiments to calculate the fractal dimensions of pore-throat structure, an oil-water relative permeability model considering boundary layer thickness is derived. The results show that the fractal dimension model of tortuous capillary bundles with non-equal diameters couples pore size distribution and curvature. Based on mercury injection curves, the fractal dimension D_f of pore-throat size and the fractal dimension D_T of pore-throat curvature are calculated to quantitatively characterize the heterogeneity and curvature of the pore-throat structure. With the increase of gas-measured permeability, D_f decreases from 1.53 to 1.40, while with D the increase of porosity,_T decreases from 1.11 to 1.07, indicating that the heterogeneity and curvature of pore throat structure gradually decrease with the increase of permeability and porosity. The new oil-water relative permeability model achieves an average coincidence rate of 93% with experimental data, with smaller prediction error than that of the traditional Brooks-Corey model. The research provides a novel method for describing the oil-water relative permeability behavior in complex pore-throat structures of low-permeability sandstone reservoirs.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1534K]

  • Optimization of well patterns and well types and numerical simulation of enhanced oil recovery potential for tight oil in Fuyu reservoir of Mao2 block in Daqing Oilfield

    YAO Zhongwen;TANG Weiyu;State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation;Institute of Sedimentary Geology,Chengdu University of Technology;PetroChina Daqing Oilfield Co.,Ltd.;Unconventional Petroleum Research Institute,China University of Petroleum (Beijing);

    Fuyu reservoir in Mao2 block of Daqing Oilfield is characterized by thin single-layer thickness, significant variation in single-well productivity and low productivity, with unclear understanding of well type and well pattern deployment, as well as subsequent EOR measures. Based on reservoir numerical simulation methods, a numerical simulation model for the core area is established and history matching is completed. On this basis, development characteristics of different well patterns and well types are analyzed to evaluate the stimulation potential of various enhanced oil recovery(EOR) methods. The results show that, for tight oil reservoirs in Mao2 block, single-well productivity of horizontal wells is significantly higher than that of vertical wells. Although horizontal wells experience rapid production decline, their net present value is higher compared to vertical well patterns. Vertical well patterns that meet economic benifits have poor water or gas injection effect due to large row spacing, making it difficult for producers to get response, while horizontal well patterns using CO_2 huff-and-puff method can effectively enhance oil recovery during the first two cycles. The research provides references for further efficient development of tight oil reservoirs in Fuyu reservoir of Daqing Oilfield. By fully considering well deployment methods, well spacing and CO_2 huff-and-puff time, it is expected to maximize the development benifits.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1499K]

  • Experiment of liquid nitrogen fracturing assisted gas huff-and-puff to enhance shale oil recovery

    QI Hongpeng;LIANG Fengming;DENG Baokang;Wuqi Oil Production Plant of Yanchang Oilfield Co.,Ltd.;Jingbian Oil Production Plant of Yanchang Oilfield Co.,Ltd.;School of Earth Sciences and Engineering,Xi'an Shiyou University;Xi'an Shangding Energy Technology Co.,Ltd.;

    In order to improve matrix fluid flow capability of shale reservoir and solve the problem of low depletion recovery, a new method of liquid nitrogen fracturing assisted gas huff-and-puff to enhance oil recovery is proposed. This method is used to carry out N_2 and CO_2 injection cyclic huff-and-puff experiment on the cores after liquid nitrogen fracturing, and to study the influence of different gas injection media, gas injection pressure and gas injection methods on shale oil recovery. NMR T_2 spectrum test is combined to clarify the characteristics of micro-pore structure changes after liquid nitrogen fracturing assisted gas huff-and-puff. The results show that liquid nitrogen can sharply reduce the surface temperature of rock from 76.2 ℃ to-170 ℃ within 5 minutes, instantly forming thermal stress of about 303 MPa, and compressing rock with induced fractures formed. With same gas injection pressure after liquid nitrogen fracturing, cumulative recovery of 3 rounds of 3 injection modes including CO_2 huff-and-puff, N_2 huff-and-puff and N_2 huff-and-puff followed by CO_2 huff-and-puff are 57.34%, 27.35% and 50.17%, respectively. The 3 rd injection mode not only reduces CO_2 demand but also gives full play to displacement advantages of the 2 kinds of gas injection media. Core porosity increases from 6.74% to 12.04%, permeability increases from 0.024×10~(-3) μm~2 to 6.242×10~(-3) μm~2, and average pore size increases from 4.94 nm to 47.79 nm. The research provides new idea and method for efficient development of shale oil and gas.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1402K]

  • Development and application of viscoelastic-particle deep profile control agent for high water-cut reservoirs

    LI Fanlei;Engineering and Equipment Management Department,SINOPEC Jiangsu Oilfield Branch;

    Aiming at the challenges of conventional plugging agents to penetrate deep into the reservoir or deteriorating stability in harsh geological conditions, dibenzylmethane diisocyanate(MDI) and polyester polyol are selected to synthesize a block-type polymer material with alternating arrangement of flexible segments-rigid segments, forming viscoelastic-particle deep profile control agent after granulation processing. In conditions of temperature of 120 ℃ and salinity of 2.0×10~5 mg/L, tests are carried out before and after 5-days constant temperature. The elemental analysis shows that the contents of C, H and N in plugging material are basically the same, with complete particle structure and excellent temperature and salt resistance performance. The results of core plugging experiments show that, for millimeter-scale viscoelastic particle with particle size-pore throat diameter ratio of 5-30, the core plugging rate is >99.0%. For micron-scale viscoelastic particle with particle size-pore throat ratio of 1.5-14.5, the core plugging rate is >93.0%, indicating good plugging effect. Deep profile control tests of viscoelastic body in 4 well patterns of Wei 5 block in northern Jiangsu Basin demonstrate a cumulative oil production increase of 1 073 tons in each stage, with significant and sustained oil production increasing and water decreasing effects. Both laboratory research and field test show that the viscoelastic-particle deep profile control agent can be effectively applied to profile control of high water-cut reservoirs, showing promising application prospect.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1233K]

  • Fine characterization technique of natural fractures seismic response of shale oil reservoirs in Songliao Basin and its application effect

    CHEN Keyang;YANG Wei;CHEN Shumin;ZHAO Haibo;ZHANG Jinyou;WANG Cheng;ZHOU Hui;ZHAN Shifan;College of Geophysics,China University of Petroleum (Beijing);Exploration and Development Research Institute of PetroChina Daqing Oilfield Co.,Ltd.;State Key Laboratory of Continental Shale Oil;No.6 Oil Production Company of PetroChina Daqing Oilfield Co.,Ltd.;CNPC BGP Inc.;

    Shale oil is a hotspot in current studies of oil and gas exploration and developmentt. Among them, accurate prediction of natural fractures is the key parameter for improving the scale and productivity of shale oil resources. Existing high-resolution seismic data is affected by strong energy reflection wave shielding, resulting in low prediction accuracy in predicting natural fractures and failing to meet the requirements of efficient development and production of shale oil reservoirs. Therefore, a seismic fine characterization technique for heterogeneous reservoirs aiming at accurate prediction of natural fractures in shale reservoirs is proposed. By using diffusion filtering method, seismic data to be processed is treated as “heat source” for diffusion propagation and global iterative processing. The reflected wave data volume and scattered wave data volume are separated relatively amplitude preserving from the coupled seismic data volume. Based on the scattered wave data volume, seismic attributes reflecting reservoir heterogeneity such as coherence volume and ant body are extracted to accurately predict the development zone of natural fractures. The results show that, relative amplitude-preserving separation of seismic reflection wave and scattered wave fields can be achieved through seismic data volume iteration, where the separated seismic reflection waves reflect seismic response of large-scale geological structural background trends, and the scattered waves reflect seismic response of small-scale heterogeneous reservoirs. The degree of separation between seismic reflection wave and scattered wave data volumes needs to be optimized and adjusted based on geological requirements. The technique is applied for pre-drilling prediction of natural fractures in shale oil of Qingshankou Formation in Sanzhao area of Songliao Basin, with prediction coincidence rate of natural fracture with that of the original high-resolution seismic data increased from 25% to 75%. The seismic response of fractured reservoirs is accurately characterized and verified by drilling with electrical imaging logging data. The research provides important technical reference value for efficient exploration and development of similar fractured oil and gas reservoirs.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 2151K]

  • Acoustic remote detection imaging interpretation generation method based on deep neural network

    WU Xingneng;TANG Baoyong;ZHANG Chengsen;LUO Shengqiang;HAO Zhiqiang;HUANG Ruokun;DUAN Wenxing;CHEN Xu;LU Mingyu;PetroChina Tarim Oilfield Company;R & D Center for Ultra-deep Complex Reservoir Exploration and Development,CNPC;School of Geosciences,China University of Petroleum (East China);Engineering Research Center for Ultra-deep Complex Reservoir Exploration and Development,Xinjiang Uygur Autonomous Region;Key Laboratory of Carbonate Reservoirs,CNPC;Tarim Branch of China National Logging Corpo

    In recent years, acoustic remote detection imaging technique, as a logging tool for “seeing through wells and looking far”, plays crucial role in fields such as detection of fractures and vugs in carbonate rocks. However, multi-solutions in acoustic remote detection imaging interpretation and requirement for high expertise level of interpreters restrict further application of this technique. Aiming at the problem of inaccurate feature extraction in acoustic remote detection images, automatic interpretation generation method(CNN) is proposed for acoustic remote detection imaging based on deep neural network Transformer architecture. Firstly, visual features of the images are captured by convolutional neural network(CNN), and then long-distance dependency relationship of images is captured by Transformer encoder. Next, cross-modal feature fusion module is introduced to enhance the model's capability to capture mapping relationship between image and text features. Subsequently, category memory feature matrix is used to learn the features of different types of interpretative reports, further optimizing the model's interpretation performance. Finally, the same type of text vectors and text sequences are fused, ultimately yielding geological interpretation conclusions that accurately describe geological anomalies near wellbore. Field case comparing acoustic remote detection heat map imaging results with acid fracturing curves verifies the effectiveness of the method, laying foundation for the training of large-scale imaging samples. The research provides new approach for logging images interpretation(such as electrical imaging, acoustic remote detection imaging), and has broad application prospects.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 2257K]

  • Quantitative characterization and influencing factors of different CO2 storage mechanisms in saline aquifers

    HUANG Zijun;GONG Ruxiang;BO Zhenyu;ZHANG Xuena;ZHENG Yufei;ZHU Tongyu;BAI Yi;GAO Yahui;National Key Laboratory of Offshore Oil and Gas Exploitation;Tianjin Key Laboratory of Offshore Difficult-to-Produce Reserves Exploitation;Production Optimization Business Division of China Oilfield Service Limited;

    CO_2 storage in saline aquifers is an important part of carbon capture, utilization and storage(CCUS) technology, and research on sequestration mechanism in saline aquifers is of great significance to accurately evaluate CO_2 storage potential in saline aquifers. Aiming at current study of incomplete characterization of storage mechanism in saline aquifers and unclarified influencing factors, basic storage mechanisms(structural storage, irreducible storage, dissolution storage and mineralization storage) are quantitatively characterized. Based on quantitative characterization model of CO_2 storage mechanism in aquifers, influencing factors of storage are studied to analyze the influence of different permeability(0.2～10.0 μm~2) and temperature and pressure conditions(45～70 ℃, 8～13 MPa) on storage capacity. The results show that simulated CO_2 storage in saline aquifer for 100 years leads to structural storage accounting for 40.223%, dissolution storage for 41.225%, irreducible storage for 18.551% and mineralization storage for 0.001%. Among these, permeability has much influence on the proportion of storage. Field test shows that, CO_2 is injected into target aquifer at a rate of 9 t/h, with initial injection rate up 9 t/h and peak daily injection volume up to 21×10~4 m~3. Current cumulative injection of CO_2 exceeds 4 000×10~4 m~3, and successful field application provides technical support and practical conditions for subsequent related work of onshore carbon storage offshore.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1780K]

  • Method for CO2 flooding anti-channeling agent performance evaluation based on precedence diagram method and its application

    JIN Fayang;LI WenLin;GU Zhibin;Petroleum Engineering School,Southwest Petroleum University;State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation;Sichuan Baoshihua Xinsheng Oil and Gas Operation Service Co.,Ltd.;Sichuan Changning Natural Gas Development Co.,Ltd.;

    In order to optimize anti-channeling performance of anti-channeling agent and prolong the plugging time, influence of the main controlling factors affecting the performance of CO_2 flooding anti-channeling agent is studied. Firstly, based on precedence diagram method, a three-level index system for evaluating anti-channeling agent performance and weights of various indexes are screened and determined, thereby clarifying influence degree of various factors on anti-channeling effect. Then, the research is verified by performance evaluation experiment of CO_2 flooding anti-channeling agent. Finally, the visualized plate-model simulation experiment is carried out to visualize the influence of injection PV on anti-channeling effect, further exploring the influence of injection PV on anti-channeling effect. The results show that anti-channeling agent injection PV has the greatest influence on anti-channeling effect, while injection rate has the least influence. Mass fraction and fracture width of anti-channeling agent have certain influence on anti-channeling effect, and the influence degree is between that of injection PV and injection rate. The visualized plate-model simulation experiment further verifies influence degree of injection PV on antichanneling effect, which has good consistency with the theoretical research and improves the credibility of the theoretical research. The research can be used to improve the plugging effect of CO_2 flooding anti-channeling agent, better prevent gas channeling and enhance oil recovery of CO_2 flooding.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1633K]

  • Gas production characteristics of CO2 huff-and-puff in horizontal wells in heavy oil reservoirs and an improved cylinder model for calculating gas injection volume

    WANG Zhilin;GE Zhengjun;ZHAO Hongyan;SU Shuzhen;Research Institute of Exploration and Development,Jiangsu Oilfield Company,Sinopec;No.1 Oil Production Plant,Jiangsu Oilfield Company,Sinopec;

    The application of CO_2 huff-and-puff in horizontal wells can significantly improve development effect of heavy oil reservoirs. In order to clarify oil production increase mechanism and potential of CO_2 huff-and-puff in horizontal wells, and to achieve rapid and accurate calculation of injection volume of huff-and-puff in horizontal wells, long core experiments are conducted with horizontal and vertical placement. By comparing gas production characteristics and oil production differences between horizontal wells and vertical wells, orthogonal experiments are carried out to determine the main controlling factors of huff-and-puff in horizontal wells and optimal injection volume. Finally, an improved cylinder model is established based on theoretical derivation. The results show that huff-and-puff in vertical wells includes 2 stages of low-gas-content front breakthrough and “gas wall” breakthrough. The spatial and temporal differences in attic-oil production and gas-oil mass transfer between vertical wells and horizontal wells cause the difference in incremental oil of CO_2 huff-and-puff. Horizontal wells can increase oil recovery by 6.14 percentage points compared with vertical wells. CO_2 injection volume is the most sensitive factor affecting huff-and-puff effect. The improved cylinder model considers “outward expansion” of gas-drive front at heel and toe ends, introducing correction coefficients related to oil saturation and viscosity of heavy crude oil. The verification result of field application indicates that the relative error between actual calculation results and numerical-simulation optimization results is less than 10%. The research provides a rapid and effective calculation method for the formulation of huffand-puff plans for such horizontal wells.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1368K]

  • Optimization of geothermal extraction systems in oil-heat coexisting area in northern Songliao Basin

    WANG Li;HUANG Lin;HAN Xiangzhe;TIAN Yulu;MA Xiaowei;Engineering Technology Research Institute of CNPC Daqing Drilling Engineering Co.,Ltd.;Well Cementing Company of CNPC Daqing Drilling Engineering Co.,Ltd.;Jilin Petroleum Engineering Division of CNPC Daqing Drilling Engineering Co.,Ltd.;

    Geothermal energy, as a clean and renewable energy source, plays an increasingly important role in energy structure. Oil-heat coexisting area is not only rich in oil and gas resources but also abundant in geothermal reserves. Optimizing geothermal extraction methods to achieve safe and efficient co-production of hydrocarbon and geothermal energy is crucial. At present, the main geothermal development methods in oil-heat coexisting area, including production-injection systems, enhanced geothermal systems(EGS) and closed-loop geothermal systems, all exhibit technical limitations and fail to achieve safe and efficient co-production. A U-shaped well geothermal system model is established to simulate the influence of thermal conductivity, pipe diameter and injection temperature on heat extraction efficiency, identifying key factors for improving production temperature. On this basis, a multistage gradient heating geothermal extraction system suitable for the geological characteristics of Songliao Basin is designed, and the heat extraction effect is simulated. The results show that the production temperature and operational stability of this system are significantly superior to those of conventional U-shaped well system, making it an important approach for geothermal extraction in oil-heat co-production area. The research provides a novel technical pathway for efficient exploitation and utilization of geothermal resource in oil-heat coexisting area.

    2026 02 v.45;No.234 [Abstract][OnlineView][Download 1253K]
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