Petroleum Exploration and Development最新文献

{"title":"Total play system of natural gas in the northern continental margin of the South China Sea","authors":"Gongcheng ZHANG ,&nbsp;Ying CHEN ,&nbsp;Sijie HONG ,&nbsp;Congjun FENG ,&nbsp;Jin LIAO ,&nbsp;Mo JI ,&nbsp;Shixiang LIU ,&nbsp;Panrong WANG ,&nbsp;Gaowei HU ,&nbsp;Anqi LI ,&nbsp;Jianrong HAO ,&nbsp;Ke WANG ,&nbsp;Jia GUO","doi":"10.1016/S1876-3804(26)60674-X","DOIUrl":"10.1016/S1876-3804(26)60674-X","url":null,"abstract":"<div><div>For the next exploration direction and integrated evaluation and optimization of targets for the northern continental margin of the South China Sea, this paper proposes the concept of the “total natural gas play system” based on the principles of systems theory. Integrating over 60 years of exploration achievements in the four major basins, the paper studies the basic geological conditions, hydrocarbon accumulation models and distribution characteristics of the system. With the core principle of “source-heat controlling natural gas and play-stratigraphy controlling accumulation”, it analyzes the distribution law of natural gas reservoirs covering “intra-sag, sag margin, extra-sag” and multi-stratigraphic sequences. The study shows that under the joint control of source and heat, the northern continental margin of the South China Sea can be divided into two major gas areas: the southern area dominated by coal-type gas and the northern area dominated by oil-type gas, with the former as the main body. Based on the distribution location of hydrocarbon kitchen, the total gas plays are classified into three types: intra-sag, sag margin and extra-sag. In the oil-type gas area of the northern coastal zone, the proportion of intra-sag natural gas is relatively high; in the coal-type gas area of the southern offshore zone, the proportions of intra-sag and sag margin natural gas are relatively large; while the scale of gas accumulation in the extra-sag plays is relatively small. Finally, it is clearly pointed out that the southern offshore zone is the main direction for the next natural gas exploration in the northern South China Sea. Specifically, in the offshore zone, the intra-sag play and middle-deep layers of the sag margin play in the Yingzhong sag should be focused for the Yinggehai Basin; the intra-sag play and sag margin play in the central depression are targets for the Qiongdongnan Basin; the middle-deep layers of the intra-sag play are targets for the Baiyun sag of the Pearl River Mouth Basin. Furthermore, in the northern depression zone of the Pearl River Mouth Basin within the coastal zone, the main exploration directions include the middle-deep layers of the intra-sag play in the Huizhou sag and the middle-deep layers of the intra-sag play in the Enping sag; in the Beibu Gulf Basin, the main directions are the middle-deep layers of the intra-sag play in the Weixinan sag and the middle-deep layers of the intra-sag play in the Haizhong sag.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 46-60"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147425664","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Global coal-rock gas resource potential and distribution","authors":"Guoxin LI ,&nbsp;Ruiyin CHEN ,&nbsp;Zhixin WEN ,&nbsp;Junfeng ZHANG ,&nbsp;Zhengjun HE ,&nbsp;Jiarui FENG ,&nbsp;Hailiang KANG ,&nbsp;Qingyang MENG ,&nbsp;Chao MA ,&nbsp;Ling SU","doi":"10.1016/S1876-3804(26)60672-6","DOIUrl":"10.1016/S1876-3804(26)60672-6","url":null,"abstract":"<div><div>Based on the data of regional geology, seismic, drilling, logging and production performance obtained from 94 major petroliferous basins worldwide, the global coal resources were screened and statistically analyzed. Then, using established definition methods and evaluation criteria for coal-rock gas in China, and by analogy with the tectono-sedimentary and burial-thermal evolution conditions of coal rocks in sedimentary basins within China, the geological resource potential of global coal-rock gas was estimated mainly by the volume method, partly by the volumetric method in selected regions. According to the evaluation indicator system comprising 14 parameters under 5 categories and the associated scoring criteria, the target basins were ranked, and the future research targets for these basins were proposed. The results reveal that, globally, coal rocks are primarily formed in four types of swamp environments within four categories of prototype basins, and distributed across five major coal-forming periods and eight coal-accumulation belts. The total geological coal resources are estimated at approximately 42×10¹² t, including 22×10¹² t in the strata deeper than 1 500 m. The global geological coal-rock gas resources in deep strata are roughly 232×10¹² m³, of which over 90% are endowed in Russia, Canada, the United States, China and Australia, with China contributing 24%. The top 10 basins by coal-rock gas resource endowment, i.e. Alberta, Kuznetsk, Ordos, East Siberian, Bowen, West Siberian, Sichuan, South Turgay, Lena–Vilyuy and Tarim, collectively hold 75% of the global total. The Permian, Cretaceous, Carboniferous, Jurassic, and Paleogene–Neogene account for 32%, 30%, 18%, 10%, and 7% of total coal-rock gas resources, respectively. The 10 most practical basins for future coal-rock gas exploration and development are identified as Alberta, Ordos, Kuznetsk, San Juan, Sichuan, East Siberian, Rocky Mountain, Bowen, Junggar and Qinshui. Propelled by successful development practices in China, coal-rock gas is now entering a phase of theoretical breakthrough, technological innovation, and rapid production growth, positioning it to spearhead the next wave of the global unconventional oil and gas revolution.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 16-30"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147426473","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A multi-scale capillary-core-reservoir approach to determining cluster spacing for volume fracturing: A case study of Chang 7 shale oil of Triassic Yanchang Formation, Ordos Basin, China","authors":"Jianming FAN ,&nbsp;Rui CHANG ,&nbsp;Youan HE ,&nbsp;Zhouhua WANG ,&nbsp;Xintong ZHANG ,&nbsp;Bo WANG ,&nbsp;Liangbing CHENG ,&nbsp;Kai XU ,&nbsp;Ameng WU ,&nbsp;Huang LIU ,&nbsp;Hanmin TU ,&nbsp;Ping GUO ,&nbsp;Shuoshi WANG ,&nbsp;Yisheng HU","doi":"10.1016/S1876-3804(26)60684-2","DOIUrl":"10.1016/S1876-3804(26)60684-2","url":null,"abstract":"<div><div>This paper proposes an approach to determing the optimal cluster spacing for volume fracturing in shale oil reservoirs based on three scales, i.e. microscopic capillary displacement, large-scale core imbibition, and macroscopic reservoir nuclear magnetic resonance (NMR) logging. Through flow experiments using capillary with different diameters and lengths, and large-scale core counter-current and dynamic imbibition tests, and combing with the NMR logging data of single wells, a graded optimization criterion for cluster spacing is established. The proposed approach was tested in the shale oil reservoir in the seventh member of the Triassic Yanchang Formation (Change 7 Member), the Ordos Basin. The following findings are obtained. First, in the Chang 7 reservoir, oil in pores smaller than 8 μm requires a threshold pressure, and for 2–8 μm pores, the movable drainage distance ranges from 0.7 m to 4.6 m under a pressure difference of 27 mPa. Second, the large-scale core imbibition tests show a counter-current imbibition distance of only 10 cm, but a dynamic imbibition distance up to 30 cm. Third, in-situ NMR logging results verified that the post-fracturing matrix drainage radius around fractures is 0–4 m, which is consistent with those of capillary flow experiments and large-scale core imbibition tests. The main pore-size range (2–8 μm) of the Chang 7 reservoir corresponds to a permeability interval of (0.1–0.4)×10⁻³ μm². Accordingly, a graded optimization criterion for cluster spacing is proposed as follows: for reservoirs with permeability less than 0.20×10⁻³ μm², the cluster spacing should be reduced to smaller than 4.2 m; for reservoirs with permeability of (0.2–0.4)×10⁻³ μm², the cluster spacing should be designed as 4.2–9.2 m. Field application on a pilot platform, where the cluster spacing was reduced to 4.0–6.0 m, yielded an increased initial oil production by approximately 36.6% over a 100-m horizontal reservoir section as compared with untested similar platforms.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 191-204"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147427374","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Features and controlling factors of source-to-sink system during the fault-depression transition in a marine rift basin: A case study of Paleogene Oligocene Lingshui Formation in Qiongdongnan Basin, China","authors":"Wu TANG ,&nbsp;Xiaojun XIE ,&nbsp;Yaning WANG ,&nbsp;Lianqiao XIONG ,&nbsp;Jinxin YU ,&nbsp;Shiqi WANG ,&nbsp;Zhen ZHAO","doi":"10.1016/S1876-3804(25)60638-0","DOIUrl":"10.1016/S1876-3804(25)60638-0","url":null,"abstract":"<div><div>Guided by the analysis of source-to-sink system, this study investigates the Paleogene Oligocene Lingshui Formation in the Qiongdongnan Basin by comparing the geological characterizes in land and sea areas and integrating outcrop, core, drilling, logging and 3D seismic data, to systematically analyze the characteristics of the source, transport pathway, and sink during the deposition of Lingshui Formation, and reveal the patterns, controlling factors and petroleum geologic significance of the source-to-sink systems. The results are obtained in five aspects. First, during the fault-depression transition, the Qiongdongnan Basin received sediments from the provenances presenting as segments in east-west and zones in north-south, primarily with the Indosinian granites in the Shenhu Uplift in the east and the Yanshanian granites in the west. Overall, the sources are young in the southern and northern parts and old in the interior of the basin. Second, three types of sediment transport pathways are identified: paleo-valleys, fault troughs and trough-valley transitional zones. Third, based on differences in sediment supply modes, the unique source-to-sink systems during the fault-depression transition in marine rift basins are categorized into three types: exogenous, endogenous and composite. Fourth, the characteristics of these source-to-sink systems are primarily controlled by provenance, paleogeomorphology, and sea-level changes. Provenance lithology and scale dictated the composition and volume of sedimentary deposits. Paleogeomorphology influenced erosion intensity in the provenance and the development of paleodrainage systems, thereby affecting the distribution and types of sedimentary systems. Additionally, sea-level changes decided the extent of the provenance, but also regulated the sediment distribution patterns through oceanic processes such as waves and tides. Fifth, the exogenous source-to-sink systems may form large-scale reservoir bodies, the endogenous systems develop secondary pores due to presence of soluble minerals, and the composite systems demonstrate reservoir properties varying from area to area.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"52 5","pages":"Pages 1235-1246"},"PeriodicalIF":8.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145398588","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Carbon isotope fractionation and production patterns of adsorbed and free gas during deep coal-rock gas production","authors":"Xianggang DUAN ,&nbsp;Wenbiao LI ,&nbsp;Zhiming HU ,&nbsp;Jun WANG ,&nbsp;Qun ZHAO ,&nbsp;Yonghui XIA ,&nbsp;Zhanrong MA ,&nbsp;Yingying XU ,&nbsp;Mingyan SUN","doi":"10.1016/S1876-3804(25)60644-6","DOIUrl":"10.1016/S1876-3804(25)60644-6","url":null,"abstract":"<div><div>Taking deep coal-rock gas in the Yulin and Daning-Jixian areas of the Ordos Basin, NW China, as the research object, full-diameter coal rock samples with different cleat/fracture development degrees from the Carboniferous Benxi Formation were selected to conduct physical simulation and isotope monitoring experiments of the full-life-cycle depletion development of coal-rock gas. Based on the experimental results, a dual-medium carbon isotope fractionation (CIF) model coupling cleats/fractures and matrix pores was constructed, and an evaluation method for free gas production patterns was established to elucidate the carbon isotope fractionation mechanism and adsorbed/free gas production characteristics during deep coal-rock gas development. The results show that the deep coal-rock gas development process exhibits a three-stage carbon isotope fractionation pattern: “Stable (I) → Decrease (II) → Increase (III)”. A rapid decline in boundary pressure in stage Ⅲ leads to fluctuations in isotope value, characterized by a “rapid decrease followed by continued increase”, with free gas being produced first and long-term supply of adsorbed gas. The CIF model can effectively match measured gas pressure, cumulative gas production, and <em>δ</em>¹³C₁ value of produced gas. During the first two stages of isotope fractionation, free gas dominated cumulative production. During the mid-late stages of slow depletion production, the staged pressure control development method can effectively increase the gas recovery. The production of adsorbed gas is primarily controlled by the rock’s adsorption capacity and the presence of secondary flow channels. Effectively enhancing the recovery of adsorbed gas during the late stage remains crucial for maintaining stable production and improving the ultimate recovery factor of deep coal-rock gas.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"52 5","pages":"Pages 1314-1328"},"PeriodicalIF":8.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145398567","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Propagation characteristics of multiple clusters of fractures in fully coupled wellbore-perforation-fracture fracturing","authors":"Peng YANG ,&nbsp;Yushi ZOU ,&nbsp;Shicheng ZHANG ,&nbsp;Jianmin LI ,&nbsp;Xiaohuan ZHANG ,&nbsp;Xinfang MA ,&nbsp;Lifeng YANG","doi":"10.1016/S1876-3804(25)60647-1","DOIUrl":"10.1016/S1876-3804(25)60647-1","url":null,"abstract":"<div><div>Based on the Low Frequency Distributed Acoustic Sensing (LF-DAS) fiber optic monitoring and downhole hawk-eye imaging, the fluid and sand distribution and perforation erosion of all clusters during hydraulic fracturing were evaluated, and then a fully coupled wellbore-perforation-fracture numerical model was established to simulate the whole process of sand-carrying fluid migration and analyze key influencing factors. The proppant and fracturing fluid exhibit divergent flow pathways during multi-staged, multi-cluster fracturing in horizontal wells, resulting in significant heterogeneity in the fluid-proppant distribution among clusters. Perforation erosion is prevalent, and perforation erosion and sand inflow ratio have phase bias. The trajectory of proppant transport is controlled by the combined effects of inertia of particle migration and gravity settlement. The inertial effect is dominant at the wellbore heel, where the fluid flow rate is high, hindering particles turning into perforations and causing uneven sand distribution among clusters. The gravity settlement is more pronounced toward the wellbore toe, where the fluid flow rate is low, leading to enhanced phase-bias of slurry distribution and perforation erosion. Increasing the pumping rate reduces the influence of gravity settlement, mitigating the phase bias of sand inflow and perforation erosion. However, the large pumping rate limits the sand inflow efficiency near the heel clusters, and more proppants accumulate towards the toe clusters. High-viscosity fluids improve particle suspension, achieving more uniform proppant placement within wellbore and fractures. Larger particle sizes exacerbate sand inflow differences among clusters and perforations, limiting the proppant placement range within fractures.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"52 5","pages":"Pages 1351-1365"},"PeriodicalIF":8.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145398578","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Waterflooding strategies for Cretaceous carbonate reservoirs with high permeability zones in the Middle East","authors":"Yong LI,&nbsp;Fengfeng LI,&nbsp;Chao YANG,&nbsp;Jiaheng CHEN,&nbsp;Yihang CHEN,&nbsp;Lei SHAO,&nbsp;Haiyang SU,&nbsp;Liang SUN","doi":"10.1016/S1876-3804(25)60641-0","DOIUrl":"10.1016/S1876-3804(25)60641-0","url":null,"abstract":"<div><div>Based on the waterflooding development in carbonate reservoirs in the Middle East, this study analyzes the geological characteristics and waterflooding behaviors/patterns of different types of high permeability zones (HPZs), and proposes rational waterflooding strategies and modes. Four types of HPZs, i.e. sedimentation-dominated, sedimentation-diagenesis coupling, biogenic and composite, are identified in the carbonate reservoirs in the Middle East. Based on their distribution patterns, flow mechanisms, and waterflooding behaviors/patterns, five waterflooding modes are established: (1) the mode with stepwise-infilled areal vertical well pattern, for composite HFZs in patchy distribution; (2) the mode with regular row vertical well pattern for Type I channel “network” HFZs (with dominant water flow pathways at the base), and the mode with irregular differentiated vertical well pattern for Type II channel “network” HFZs (where multi-stage superimposition leads to “layered flooding”), for sedimentation-diagenesis coupling HFZs; (3) the mode with row horizontal wells through bottom injection and top production, for biogenic HFZs characterized by thin, contiguous distribution and rapid advancing of injected water along a 工-shaped path; and (4) the mode with progressive waterflooding through edge water injection via vertical well and oil production via horizontal well, for sedimentation-dominated HFZs characterized by thick, contiguous distribution and flood first in upper anti-rhythmic reservoirs. Development practices demonstrate that the proposed waterlooding modes are efficient in the highly heterogeneous carbonate reservoirs in the Middle East, with balanced employment of reserves in the adjacent reservoirs and enhanced oil recovery.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"52 5","pages":"Pages 1275-1290"},"PeriodicalIF":8.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145398564","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Mechanisms of hydrated ion bridges in the development of low and ultra-low permeability reservoirs","authors":"Xu JIN ,&nbsp;Fenglu CUI ,&nbsp;Yining WU ,&nbsp;Xiaoqi WANG ,&nbsp;Siwei MENG ,&nbsp;Chenjun ZHANG ,&nbsp;Xiaodan LIU ,&nbsp;Jiaping TAO ,&nbsp;Man SHEN ,&nbsp;Fengchao WANG","doi":"10.1016/S1876-3804(25)60642-2","DOIUrl":"10.1016/S1876-3804(25)60642-2","url":null,"abstract":"<div><div>This study focuses on the hydrated ion bridge (HIB) effect at the oil-rock interface in low- to ultra-low-permeability oil reservoirs. It systematically summarizes the research methodologies, formation mechanisms, interaction strength, and disruption mechanisms of HIB, and discusses the influencing mechanisms of HIB on the occurrence state and mobility of crude oil. On this basis, the key challenges inherent in the current HIB research are analyzed, and prospective directions for future development are proposed. Currently, research in this field primarily relies on experimental characterization techniques and molecular simulation methods. The microscopic interactions involved in HIB formation mainly include electrostatic interactions, hydrogen bonds and van der Waals forces. Notably, the hydrogen bonds between polar molecules in crude oil and hydrated ions serve as the primary sites for disrupting the HIB effect. The interaction strength of HIB is collectively modulated by ion type and concentration, reservoir solution environment, mineral type of reservoir rocks, and polar components in crude oil, which subsequently influence the occurrence state and mobility of crude oil. Systematic challenges persist in HIB-related research across three dimensions: research methodologies, scale integration and geological complexity. Specifically, the dynamic evolution mechanism of HIB remains inadequately elucidated; a discontinuity exists in the connection of spatiotemporal cross-scale modeling and prediction; and the reproducibility of actual geological environments in experimental settings is insufficient. Future research may pursue breakthroughs in the following three aspects: (1) developing in-situ dynamic experimental characterization techniques and machine learning-augmented simulation strategies; (2) establishing a framework for cross-scale model fusion and upscaling prediction; and (3) conducting in-depth studies on HIB under the coupled effects of complex mineral systems and multi-physical fields.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"52 5","pages":"Pages 1291-1300"},"PeriodicalIF":8.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145398565","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A new type of unconventional natural gas resources: Overpressure-dissolved gas","authors":"Yuhong XIE","doi":"10.1016/S1876-3804(25)60648-3","DOIUrl":"10.1016/S1876-3804(25)60648-3","url":null,"abstract":"<div><div>In overpressure reservoirs, natural gas often coexists in a three-phase mixed form of continuous free state, dispersed free state and water-saturated dissolved state. However, the latter two have not received sufficient attention. In response to this situation, based on detailed characterization of typical overpressure dissolved gas in the Yinggehai-Qiongdongnan basin and the experiment results of natural gas dissolution with high-temperature and overpressure, the concept of “overpressure-dissolved gas” was proposed and its basic features, formation conditions and resource potential were summarized. It refers to the natural gas present in the gas-water transitional zone and the saturated dissolved gas zone within the overpressure reservoirs. The formation of overpressure-dissolved gas requires two basic conditions: the pressure coefficient typically greater than 1.5, and a relatively high gas saturation in the reservoir (10%–35%). Overpressure-dissolved gas exists in the strata from shallow to deep with a multi-stage superimposed pattern; there are at least four combination types: overpressure- dissolved gas with multiple gas caps, overpressure-dissolved gas with single gas cap, gas-bearing water layer without gas cap, and dissolved gas-bearing water layer without gas cap. The basic geological elements required for the formation of overpressure-dissolved gas include the gas source, reservoir, cap rock, gas-water transitional zone and overpressure body. The conditions of gas source, reservoir and cap rock determine the scale of the overpressure-dissolved gas zone. High temperature, high pressure and low-permeability reservoirs control the solubility of natural gas and the thickness of the gas-water transitional zone. The physical properties of sandstone determine the combination types of overpressure-dissolved gas. Changes in pressure control the transformation of different existing states of overpressure-dissolved gas. The overpressure-dissolved gas in the Yinggehai-Qiongdongnan Basin has considerable huge resource potential. Once breakthrough is achieved in this area, it will usher in a new era of natural gas exploration in the overpressured basin.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"52 5","pages":"Pages 1366-1377"},"PeriodicalIF":8.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145398579","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A saturation model of lacustrine shale oil considering the influence of organic matter: A case study of the first member of the Cretaceous Qingshankou Formation of Changling Sag in southern Songliao Basin, NE China","authors":"Dianshi XIAO ,&nbsp;Zhuo LI ,&nbsp;Min WANG ,&nbsp;Wei DANG ,&nbsp;Xiaoquan XIE ,&nbsp;Baifeng HAN","doi":"10.1016/S1876-3804(25)60636-7","DOIUrl":"10.1016/S1876-3804(25)60636-7","url":null,"abstract":"<div><div>Taking the shale oil of the first member of the Cretaceous Qingshankou Formation of Changling Sag in southern Songliao Basin as an example, this paper establishes a saturation model of lacustrine shale oil considering the influence of organic matter on clay-bound water conductivity. Based on the fluid characterization results of sealed samples and two-dimensional nuclear magnetic resonance, the differential influence of organic matter on clay-bound water conductivity was quantitatively revealed, and the conductivity mechanism and rock-electrical relationships of lacustrine shale were systematically analyzed. The results show that there are two conductive networks for lacustrine shales, i.e. the matrix free water and the clay-bound water. The bound water cementation index <em>m</em>_sh was introduced to reflect the impact of organic matter on clay-bound water conductivity, and it is positively correlated with the effective porosity. When there is sufficient rigid framework support and well-developed pores, organic matter is more likely to fill or adsorb onto clay interlayers. This reduces the ion exchange capacity of the electrical double layer, leading to an increase in <em>m</em>_sh and a decrease in the conductivity of clay-bound water. The overall conductivity of shale is controlled by the clay-bound water conductivity, and the relative contributions of the mentioned two conductive networks to formation conductivity are affected by the effective porosity and <em>m</em>_sh. The larger the effective porosity and <em>m</em>_sh, the more the contribution of the matrix free water to formation conductivity. According to the experimental results, the proposed saturation model yields a significantly higher interpretation accuracy in oil saturation than the Archie model and the Total-shale model.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"52 5","pages":"Pages 1209-1221"},"PeriodicalIF":8.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145398664","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}