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01 June 2024, Volume 45 Issue 3 Previous Issue    Next Issue

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OIL AND GAS EXPLORATION

Precursor and Mechanism of Hydrocarbon Generation for Shale Oil in Lucaogou Formation, Jimsar Sag WANG Jian, LIU Jin, PAN Xiaohui, ZHANG Baozhen, LI Erting, ZHOU Xinyan 2024, 45 (3):  253-261.  doi: 10.7657/XJPG20240301 Abstract ( 374 )   HTML ( 30 )   PDF (6824KB) ( 434 )   Save In order to clarify the differences in hydrocarbon-generating precursor and mechanism of the shale oil between the upper and lower sweet spots of the Lucaogou formation, the source rocks of the Lucaogou formation in the Jimsar sag were characterized ultra-microbiologically using field emission scanning electron microscopy, electron probe, and Fourier transform infrared spectroscopy experiments. The results show that the main hydrocarbon-generating precursor of the shale oil in the upper sweet spot is lamalginite (Microcystis), with straight-chain aliphatic series in dominance, and the main hydrocarbon-generating precursor in the lower sweet spot is telalginite (Tasmanian algae), which is rich in branched-chain aliphatic, aromatic, and sulfoxide functional groups. Due to the significantly higher activation energy required for the cleavage of long straight-chain saturated hydrocarbons than that for branched-chain hydrocarbons, as well as the lower bond energies of carbon-sulfur and carbon-nitrogen bonds, the activation energy of the precursor of the shale oil in the lower sweet spot is lower than that in the upper sweet spot. Consequently, early-stage hydrocarbon generation occurs, leading to the formation of high-density crude oil rich in non-hydrocarbon bitumen at low maturity, which is the primary reason for the relatively heavy and viscous nature of the crude oil in the lower sweet spot. Figures and Tables | References | Related Articles | Metrics

Thermal Evolution History of Shale in Da’anzhai Member and Its Petroleum Geological Significance in Central Sichuan Basin JIANG Qijun, LI Yong, XIAO Zhenglu, LU Jungang, QIN Chunyu, ZHANG Shaomin 2024, 45 (3):  262-270.  doi: 10.7657/XJPG20240302 Abstract ( 298 )   HTML ( 321 )   PDF (821KB) ( 331 )   Save The Da’anzhai member of the Lower Jurassic Ziliujing formation is the most favorable layer for the development of continental shale oil in the Sichuan basin, and has huge potential in shale oil exploration. However, there is a lack of systematic research on the thermal evolution history of this formation. Using the simulation system for petroliferous basins, the differences in the thermal evolution and hydrocarbon generation of the shales in Da’anzhai member between the northern part and the central part of the central Sichuan basin were comparatively analyzed, and their impacts on shale oil enrichment were discussed. The thermal evolution degree of the shale of Da’anzhai member in the study area gradually increases from southwest to northeast, and the shale can be divided into a highly matured zone and a matured zone on the plane. The highly matured zone is located in the northern part of the study area, with vitrinite reflectance ranging from 1.3% to 1.7%, mainly developing Type Ⅲ organic matter. The early oil generation occured in the early Late Jurassic, and the oil generation peaked at the end of Late Jurassic, experiencing two phases of hydrocarbon generation. The matured zone is located in the central to southern parts of the study area, with vitrinite reflectance ranging from 0.9% to 1.3%, mainly developing Type Ⅱ1-Ⅱ2 organic matter. The sedimentary thickness of the Jurassic is relatively small, the early oil generation occured at the end of the Late Jurassic and reached the peak in the Early Cretaceous, with only one period of hydrocarbon generation. Compared with the northern area, a large set of organic-rich shales deposited in the central area, which provieded a solid material basis for shale oil in the Da’anzhai member. However, the tectonic uplift and stratum erosion since the Paleogene posed a certain destructive effect on the preservation of oil and gas in this area. Figures and Tables | References | Related Articles | Metrics

Optimization of Geological Sweet Spots for Shale Oil in Fengcheng Formation in Well Maye-1, Mahu Sag LI Na, LI Hui, LIU Hong, CHEN Fangwen, YANG Sen, ZOU Yang 2024, 45 (3):  271-278.  doi: 10.7657/XJPG20240303 Abstract ( 281 )   HTML ( 9 )   PDF (940KB) ( 308 )   Save The Fengcheng formation in the Mahu sag is a typical alkaline lacustrine deposit characterized by mixed provenance, complex lithology, overall oil possibility, and scattered sweet spots. To efficiently explore and develop the shale oil, it is necessary to optimize geological sweet spots for the shale oil. Based on the results of high-pressure mercury injection and rock pyrolysis experiments, the reservoir and shale oil mobility of the Fengcheng formation in Well Maye-1 were evaluated, a model for optimizing geological sweet spots for the shale oil was constructed, and the vertical distribution of geological sweet spots for the shale oil was assessed. The results show that porosity, total organic carbon content, brittle mineral content, and difference between free hydrocarbon content and 100 times of total organic carbon content are parameters for respectively evaluating the reservoir performance, oil-bearing property, brittleness, and shale oil mobility of the Fengcheng formation. A model for optimizing geological sweet spots for the shale oil was constructed by using these four parameters, with sweet spot factors for Class Ⅰ, Ⅱ, and Ⅲ shale oil geological sweet spots in Well Maye-1 being greater than 0.282 3, ranging from 0.011 1 to 0.282 3, and less than 0.011 1, respectively. Class Ⅰ shale oil geological sweet spots in the Fengcheng formation in Well Maye-1 are mainly distributed in the upper part of the second member of Fengcheng formation and in the third member of Fengcheng formation, with lithology dominated by mudstone and dolomitic mudstone. Figures and Tables | References | Related Articles | Metrics

Identification of Fluid in Highly Saline Tight Reservoirs of Fengcheng Formation in Maxi Slope Area MAO Rui, BAI Yu, WANG Pan, HUANG Zhiqiang 2024, 45 (3):  279-285.  doi: 10.7657/XJPG20240304 Abstract ( 193 )   HTML ( 6 )   PDF (2125KB) ( 238 )   Save The Permian Fengcheng formation in the Maxi slope area of the Junggar basin is characterized by highly saline tight reservoirs deposited in alkaline lakes, and the relationship between oil and water in these reservoirs is complicated, which leads to difficulties in fluid identification. A thermal neutron macroscopic capture cross-section of the highly saline formation was constructed by using lithoscanner logging data, and an oil-sensitive factor was constructed by using the difference between the thermal neutron macroscopic capture cross-section from logging and the thermal neutron macroscopic capture cross-section of the brine-saturated formation. Furthermore, a salinity-sensitive factor was constructed by using the ratio of chlorine element relative yield to total porosity. Then, a fluid identification chart was established by intersecting the oil-sensitive factor with the salinity-sensitive factor. The actual application shows that this fluid identification chart can accurately assess reservoir fluid properties and provide a basis for selecting formation test layers. Figures and Tables | References | Related Articles | Metrics

Pore Throat Structures and Fluid Occurrences of Reservoirs in Fengcheng Formation, Mahu Sag ZHU Yue, WU Shunwei, DENG Yusen, LIU Lin, LEI Xianghui, NIU Youmu 2024, 45 (3):  286-295.  doi: 10.7657/XJPG20240305 Abstract ( 235 )   HTML ( 13 )   PDF (4537KB) ( 256 )   Save In order to reveal and compare the microstructures of sandstone and shale reservoirs, and the fluid occurrences within different sizes of pores in the Fengcheng formation of the Mahu sag, the experiments including high-pressure mercury intrusion (HPMI), nuclear magnetic resonance (NMR), and large-view splicing SEM were conducted to quantitatively characterize the pore throat size and fluid occurrence characteristics of the two types of reservoirs. The NMR experimental results and the HPMI experimental results before and after extraction of the original samples and the pressurized oil-saturated sample were compared to reveal the distributions of bound and movable fluids within pores of different sizes. The results indicate that sandstone and shale do not differ significantly in the sizes of pores and throats, which are dominantly 0.01-10.00 μm in pore diameter and <10.00 nm in throat radius, respectively, indicative of mesopores and fine throats. Shale has slightly larger pore diameters but smaller throat radii than sandstone. Shale mainly develops tubular pores such as intercrystalline pores and honeycomb-like dissolution pores. Sandstone has an equal distribution of tubular and spherical pores, with the proportion of spherical pores such as intergranular pores and intergranular dissolution pores increasing as the pore size increases. Fluid occurrence and mobility are controlled by multiple factors such as mineral composition and pore size. The oil-wet properties of organic matter, dolomite and pyrite, and the strong capillary confinement of intergranular pores in clay minerals, reduce the mobility of shale oil, and the movable fluids are mainly distributed in mesopores-macropores with diameters greater than 300 nm. Combining the reservoir physical properties and movable fluid distribution, it is determined that the favorable shale oil block in the study area is the Ma 51X well block, both shale and sandstone in the well block are favorable targets for development. Figures and Tables | References | Related Articles | Metrics

Exploration Breakthrough and New Insights of Baijiantan Formation in Mahu Sag and Its Periphery BIAN Baoli, SU Dongxu, JIANG Wenlong, WANG Xueyong, PAN Jin, LIU Longsong, JIANG Zhongfa 2024, 45 (3):  296-305.  doi: 10.7657/XJPG20240306 Abstract ( 235 )   HTML ( 13 )   PDF (22055KB) ( 129 )   Save In order to clarify sandbody distribution patterns and hydrocarbon accumulation model of the Baijiantan formation in the Mahu sag, Junggar basin, and evaluate its hydrocarbon exploration prospects, the drilling, logging, seismic and experimental data were comprehensively analyzed to understand the sedimentary patterns and hydrocarbon accumulation characteristics of the second member of the Baijiantan formation (Bai-2 member). It is found that the Bai-2 member represents a braided-river delta-beach bar-turbidite fan sedimentary sequence, with three types of sandbodies of underwater distributary channel, beach bar and turbidite fan. Channel sandbodies are dominant in braided-river delta front; beach bar sandbodies are developed in shore-shallow lake; controlled by slope breaks, multiple turbidite fans are developed in deep lake to semi-deep lake, with turbidite fan sandbodies distributed in a lobate pattern. Thus, a sedimentary pattern of underwater distributary channel-beach bar-turbidite fan was established. Nine major strike-slip fault systems are found in the study area. Among them, three types of fault combinations such as through-type, associated-type, and relay-type strike-slip faults effectively connect the Permian Fengcheng formation source rocks and serve as efficient vertical pathways for hydrocarbon migration. The Bai-2 member follows a hydrocarbon accumulation model characterized by strike-slip faults connecting source rocks, fault-sandbody configuration controlling reservoir, and hydrocarbon enrichment in high-quality reservoirs. Figures and Tables | References | Related Articles | Metrics

Genesis of Dolomite and Its Controls on Reservoir Spaces in Lower Yingshan Formation-Penglaiba Formation, Northern Tarim Basin TIAN Jiaqi, LI Guorong, LIU Yongli, LI Xiaoxiao, HE Zhao, HE Sai 2024, 45 (3):  306-316.  doi: 10.7657/XJPG20240307 Abstract ( 222 )   HTML ( 8 )   PDF (20251KB) ( 127 )   Save To determine the genesis of dolomite in the lower Yingshan formation-Penglaiba formation of the Middle-Lower Ordovician in northern Tarim basin, this paper investigates the dolomitization in the target interval through the observations of core samples and thin sections and the analysis of cathodoluminescence, X-ray diffraction order degree, stable carbon and oxygen isotopes, strontium isotopes, and rare earth element compositions and partition patterns, and by combining petrological characteristics with geochemical characteristics. The results show that silty to microcrystalline dolomites and silty to fine-grained anhedral dolomites were formed from syndepositional dolomitization in high-salinity seawater which was primarily originated from the seawater under low-temperature surface evaporation; silty to fine-grained euhedral dolomites were formed from shallow-burial dolomitization in early diagenetic period, with fluids sourced from Ordovician seawater and an increasing temperature with the increase of burial depth; and saddle-like dolomites were formed from hydrothermal dolomitization in early diagenetic period, with fluids sourced from Ordovician seawater as well as later deep-seated magmatic hydrothermal fluid. Reservoir spaces can’t generate from syndepositional high-salinity seawater dolomitization, but may be formed after the dissolution of the precipitated gypsum due to regional constraints and intense evaporation. Eeuhedral dolomite can form under early diagenetic shallow-burial dolomitization, which promotes the development of intercrystalline pores where dissolution fluid may easily enter in late diagenetic stage, forming intercrystalline dissolution pores and dissolved pores. Early diagenetic hydrothermal dolomitization is unfavorable for the formation of reservoir spaces. Figures and Tables | References | Related Articles | Metrics

RESERVOIR ENGINEERING

NMR Logging-Based Productivity Analysis and Sweet Spot Evaluation for Shale Oil QIN Jianhua, LI Yingyan, DU Gefeng, ZHOU Yang, DENG Yuan, PENG Shouchang, XIAO Dianshi 2024, 45 (3):  317-326.  doi: 10.7657/XJPG20240308 Abstract ( 294 )   HTML ( 9 )   PDF (1650KB) ( 296 )   Save Shale oil horizontal wells in the Lucaogou formation within the Jimsar sag vary greatly in productivity, with notable differences in water production rate. Main factors controlling this phenomenon remain unclear. Moreover, the existing sweet spot classification criteria fail to meet the requirements for fine development of shale oil in this area, and the interpretation of oil saturation and mobility based on the cutoff values from nuclear magnetic resonance (NMR) logging cannot realize precise identification of shale oil sweet spots. In this paper, based on the results of NMR logging and laboratory NMR testing, and through frequency division processing, NMR logging-based pore structure characterization by fluids, and elastic oil displacement simulation, the distribution of different types of fluids in shale oil reservoirs was characterized detailedly. The pore sizes for oil/water occurrence were delineated, and a model for evaluating movable oil amount was established to quantitatively characterize the fluid occurrence, pore size distribution, movable oil quantity, and other parameters. By integrating single-well testing and production data, the factors controlling horizontal well productivity were elucidated. The results show that horizontal well productivity is much more correlated to the large-pore light oil proportion (LOP) and movable oil porosity (MOP) than to porosity, oil saturation, NMR MOP and other parameters. The water influence index reflects the extent of formation water’s impact on shale oil flow, and given the same MOP, a smaller water influence index corresponds to a higher productivity and a lower water cut of a horizontal well. Based on large-pore LOP, water influence index and MOP, the shale oil sweet spots are classified into Class Ⅰ, Class Ⅱ and Class Ⅲ, with rapid decline in daily oil production and significant rise in water cut, which can serve as the basis for finely evaluating shale oil sweet spots in the Lucaogou formation. Figures and Tables | References | Related Articles | Metrics

Microscopic Oil Mobility in Tight Conglomerate Reservoirs Under Different Development Modes, Mahu Sag WAN Tao, ZHANG Jing, DONG Yan 2024, 45 (3):  327-333.  doi: 10.7657/XJPG20240309 Abstract ( 248 )   HTML ( 5 )   PDF (2794KB) ( 189 )   Save In order to evaluate the oil mobility in the tight sandy conglomerate reservoirs of the Triassic Baikouquan formation in the Mahu sag, the distribution characteristics of movable oil in typical rock samples from Type Ⅰ and Type Ⅱ reservoirs were compared through imbibition, centrifugation, and huff-n-puff tests. For the low-permeability conglomerate reservoirs in the Mahu sag, the imbibition oil recovery is related to the pore structure of the rock. The higher the proportion of small pores, the better the imbibition effect. After 144 hours of oil displacement by imbibition, the recovery rate can reach 30.9%, but the oil displacement process is slow, with low utilization of large pores. Under reservoir pressure of 40 MPa and reservoir temperature, during three cycles of CO2 huff-n-puff process, the recovery percent of each round increase, with the highest increase observed in the first cycle, reaching an oil exchange ratio of 27%. As the huff-n-puff cycle increases, the increment in recovery percent gradually decreases, and the oil exchange ratio of N2 huff-n-puff in the first cycle is 15%. Therefore, CO2 huff-n-puff has the best development effect. Figures and Tables | References | Related Articles | Metrics

Influences of Low-Temperature Oxidation on Oil Recovery During Oxygen-Reduced Air Flooding in Guo-8 Block of Yuguo Oilfield XIAO Zhipeng, ZHANG Yanbin, LI Qihang, LI Yiqiang, HAN Jifan, YAN Qian, WU Yong’en 2024, 45 (3):  334-339.  doi: 10.7657/XJPG20240310 Abstract ( 237 )   HTML ( 8 )   PDF (964KB) ( 169 )   Save Oxygen-reduced air injection is an effective technique for developing low-permeability oil reservoirs. Under reservoir conditions, oxygen-reduced air can undergo low-temperature oxidation reaction with crude oil, thereby enhancing oil recovery. Regarding the inadequate understanding of the mechanism underlying the oxygen-reduced air flooding for enhanced oil recovery (EOR) in the Guo-8 block of the Yuguo oilfield, isothermal oxidation experiments and long-core displacement experiments were conducted to investigate the influences of oil oxidation process and generated substances on EOR. The results of the isothermal oxidation experiments indicate that sedimentary substances are generated during the low-temperature oxidation process of light oil. With the increase of temperature, the degree of oxidation significantly increases, with the sedimentation of heavy components reaching 1.25×10-3 g/g at 89°C, 3.43×10-3 g/g at 100°C, and 5.02×10-3 g/g at 120 ℃. The results of the long-core displacement experiments demonstrate that the sedimentation of heavy components at different oxidation temperatures affects EOR. With temperature increasing, the timing of gas channeling delays, the sweeping effect improves, and the final recovery increases to 52.77%, 58.89%, and 65.23% at temperatures of 89°C, 100°C, and 120°C, respectively. Figures and Tables | References | Related Articles | Metrics

Production Decline Analysis for Multi-Layer Commingled Production Wells in Tight Gas Reservoirs LIU Jie, WEI Keying, LI Ning, YANG Yingzhou, HAO Junhui, LI Linqing, SHI Wenyang 2024, 45 (3):  340-345.  doi: 10.7657/XJPG20240311 Abstract ( 206 )   HTML ( 5 )   PDF (733KB) ( 133 )   Save Main pay zones of tight gas reservoirs are usually multiple layers of stacked channel sandbodies. Commingled production of these layers is commonly challenged by unclear contribution from each layer and undefined boundaries of sandbodies. Considering the morphological characteristics and different boundary sizes of channel sandbodies in the layers, and according to the principle of equivalent flow volume, a model of multi-layer commingled production well in tight gas reservoir was established. Then, based on the theory of modern production decline analysis, a method for determining the boundaries of channel sandbodies in tight gas reservoirs was proposed, and the production decline analysis charts for multi-layer commingled production wells were plotted. Finally, the production decline was discussed by boundary size, amount, and position of channel sandbodies, and the impacts of multi-layer channel sandbodies on production decline were clarified. The study shows that the production deline of multi-layer commingled production wells in tight gas reservoirs exhibits five stages. In the middle unsteady flow stage, it is possible to diagnose whether the boundary sizes of the sandbodies in each layer are equal. The smaller the range of channel sandbodies, the fewer the wide sandbodies, the smaller the proportion of wide sandbody, the poorer the stable productivity of the reservoir, and the more likely the increase in production decline rate occurs in the early and middle unsteady flow stages. The established method of production decline analysis provides a basis for evaluating the producing degree of each layer and determining reservoir stimulation treatments. Figures and Tables | References | Related Articles | Metrics

Imbibition Replacement Rules of Bedding Shale in Lucaogou Formation in Jimsar Sag，Junggar Basin TIAN Gang, ZHU Jian, PU Pingfan, XIA An, DONG Zhuo, WU Jiayi, WANG Fei 2024, 45 (3):  346-354.  doi: 10.7657/XJPG20240312 Abstract ( 206 )   HTML ( 6 )   PDF (1041KB) ( 178 )   Save In order to investigate the production of crude oil during the imbibition period after hydraulic fracturing of the bedding shale in the Permian Lucaogou formation in the Jimsar sag, core imbibition replacement experiments and nuclear magnetic resonance (NMR) technology were combined to quantitatively describe the relative content of crude oil in different pores. Cores from the upper sweet spot in Jimsar sag were used in the experiments to identify the impacts of gravity, anisotropy, gravity differentiation, and hydraulic fracture width on imbibition replacement and quantitative characterization was conducted. The results show that during the spontaneous imbibition process of bedding shale, gravity plays a dynamic role, and the recovery of top imbibition is higher than that of horizontal imbibition. Anisotropy has a significant impact on imbibition of bedding shale, with a larger imbibition displacement of fracturing fluid into parallel bedding and a shorter period to reach imbibition equilibrium compared to vertical bedding, and imbibition recovery of parallel bedding is higher than that of vertical bedding. Gravity differentiation means that during the imbibition at the bottom of the core, the crude oil is displaced by imbibition and stays on the surface of the core to form an oil film, which prevents the fracturing fluid from further entering the matrix, deteriorating the imbibition effect. The recovery of imbibition at the bottom differs by 14.12% from the recovery of imbibition at the top. Given a simulated hydraulic fracture width of 2 mm, the volume of liquid involved in imbibition replacement is limited, causing a rapid decline of water saturation within the simulated fracture, which restricts further imbibition. Therefore, the fracture height should be oriented to pass through parallel bedding, so that the fracture width and the stimulated reservoir volume can be increased. Figures and Tables | References | Related Articles | Metrics

Simultaneous CO2 Huff-n-Puff Test in Highly Sensitive Reservoirs in Upper Wuerhe Formation, Mahu Sag SONG Ping, CUI Chenguang, ZHANG Jigang, LIU Kai, DENG Zhenlong, TAN Long, YU Xike 2024, 45 (3):  355-361.  doi: 10.7657/XJPG20240313 Abstract ( 200 )   HTML ( 4 )   PDF (2185KB) ( 208 )   Save In order to explore the post-fracturing EOR technologies for efficient development of highly sensitive tight conglomerate oil reservoirs in horizontal wells in the Mahu sag, a simultaneous CO2 huff-n-puff test was carried out in the Mahu 1 well block. The results show that simultaneous CO2 huff-n-puff can enhance oil recovery of highly sensitive tight conglomerate reservoirs, and its oil displacement mechanisms mainly include extraction, miscibility, competitive adsorption, and expansive displacement. Fracture communication is the main cause of gas channeling. Through field regulation and control, synchronous soaking of well groups and gas channeling wells was achieved, ensuring the field implementation effect. Soaked by fracturing fluid, the clay minerals in the tested well group hydrate and expand, causing pore throat blockage, which affects CO2 swept range and results in a low interim oil exchange ratio. The simultaneous CO2 huff-n-puff test achieved favorable stimulation effects, with an interim oil increment of 3,983 tons and an oil exchange ratio of 0.36 in the tested well group. This test provides technical ideas and field experience for horizontal wells in enhancing oil recovery of highly sensitive tight conglomerate reservoirs after fracturing. Figures and Tables | References | Related Articles | Metrics

APPLICATION OF TECHNOLOGY

Establishment and Application of Rock Mechanical Parameter Profile to Tight Reservoirs in Yongjin Oilfield GAI Shanshan, WANG Zizhen, LIU Haojie, ZHANG Wensheng, YU Wenzheng, YANG Chongxiang, WANG Yuping 2024, 45 (3):  362-370.  doi: 10.7657/XJPG20240314 Abstract ( 261 )   HTML ( 10 )   PDF (3814KB) ( 296 )   Save In order to study the fracability evaluation method for low-permeability tight reservoirs, experiments were conducted on six core samples from Well Y301 and Well Y3 in the Yongjin oilfield, Shawan sag, Junggar basin, and the parameters such as rock mineral composition, porosity, stress-strain curves, P-wave velocity, and S-wave velocity were obtained. The experiment results agreed well with logging data, and an empirical rock mechanical model was established for the study area. Meanwhile, based on the equivalent medium model, a new model considering mineral composition and pore structure characteristics was developed for calculating rock brittleness index. Then, a method for constructing the rock mechanical parameter profile of low-permeability tight reservoirs based on logging data was established and applied in Well Y301. The application results show that the Qigu formation in Well Y301 has good fracability, which lays a foundation for the comprehensive evaluation of fracability of tight sandstone reservoirs. Figures and Tables | References | Related Articles | Metrics

A Logging-Based Method for Calculating Water Saturation in Continental Shale Reservoirs: A Case Study of Lianggaoshan Formation in Fuxing Block, Southeastern Sichuan Basin CHENG Li, YAN Wei, LI Na 2024, 45 (3):  371-377.  doi: 10.7657/XJPG20240315 Abstract ( 203 )   HTML ( 5 )   PDF (717KB) ( 203 )   Save Continental shale reservoirs are characterized by low porosity, ultra-low permeability, high clay mineral content, rapid mineral composition variation, and strong formation heterogeneity. Therefore, the water saturation calculated with Archie formula or conventional mathematical statistical models often introduces large errors. To improve the calculation accuracy of water saturation in continental shale reservoirs, taking the shale from Lower Jurassic Lianggaoshan formation in the Fuxing block of southeastern Sichuan basin as an example, the limitations of existing methods for calculating water saturation were analyzed, and the feasibility of applying the composite wave impedance reconstructed from the combination of P wave and S wave in array acoustic logging and logging density to calculate water saturation was demonstrated. Based on this analysis, a method for calculating water saturation in continental shale reservoirs was proposed. This method considers the influence of rock minerals and effectively avoids the limitations of electrical logging and non-electrical logging, and finally improving applicability. The application of this method has yielded favorable results in multiple wells in the shale reservoirs of Lianggaoshan formation, southeastern Sichuan basin, with calculated water saturation closely matching those from core analysis, and absolute errors ranging from 1.3% to 2.2%, meeting the requirements for well logging evaluation. Figures and Tables | References | Related Articles | Metrics