Petroleum Exploration and Development最新文献

{"title":"A fluid identification method for deep low-porosity buried-hill reservoirs based on coupled energy spectrum-time spectrum pulsed neutron logging","authors":"Qiong Zhang,&nbsp;Jiawei Zhang,&nbsp;Zhenyang Li,&nbsp;Jiling Li,&nbsp;Danian Xu,&nbsp;Zhang Zhang,&nbsp;Jilin Fan,&nbsp;Guangzu Wu,&nbsp;Jie Shang","doi":"10.1016/S1876-3804(26)60740-9","DOIUrl":"10.1016/S1876-3804(26)60740-9","url":null,"abstract":"<div><div>This work addresses the challenge of fluid identification in complex low-porosity buried-hill reservoirs in the Bohai Sea by developing a fluid identification method based on the coupled responses of energy spectra and time spectra. First, a regularized spectral decomposition algorithm is employed to analyze pulsed neutron gamma-ray spectra and obtain the carbon-to-oxygen (C/O) yield ratio, enhancing the capability of quantitatively characterizing differences in oil and water signal responses under low-porosity conditions. Second, an oil-water identification method is established by integrating energy-spectrum and time-spectrum parameters, improving the accuracy of oil-water discrimination in complex lithological environments. Finally, a gas layer identification parameter is introduced to distinguish gas-bearing zones and fluid-bearing zones, which is then combined with the oil and water identification results to form a three-phase fluid identification workflow. Field applications in drilled wells penetrating granite gneiss buried hills and carbonate buried-hill reservoirs in the Bohai Sea demonstrate that the proposed method significantly enhances the response contrast between oil and water under low-porosity conditions, substantially reduces the uncertainty of single-parameter interpretation, and enables accurate discrimination among oil, gas, and water. The method provides an effective solution for fluid identification in complex low-porosity buried-hill reservoirs in the Bohai Sea.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 4","pages":"Pages 982-993"},"PeriodicalIF":10.7,"publicationDate":"2026-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148822896","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Development status and trends of oil production engineering technology in the context of interdisciplinary integration","authors":"He LIU,&nbsp;Xu JIN,&nbsp;Qinghai YANG,&nbsp;Xiaoqi WANG,&nbsp;Siwei MENG","doi":"10.1016/S1876-3804(26)60730-6","DOIUrl":"10.1016/S1876-3804(26)60730-6","url":null,"abstract":"<div><div>This paper systematically reviews the development stages and current status of key oil production engineering domains, including injection-production engineering, artificial lift, reservoir stimulation, and workover operations. The major challenges for oil production engineering are identified in four aspects: intelligent terminal equipment and process integration, extreme-environment operations, and collaborative operational constraints; AI-driven data and modeling complexities, and advanced structural and functional materials requirements; and the need for geology-engineering integration in reservoir characterization, operational efficiency and green development. Centered on multidisciplinary integration, the concept of the Oil Production Engineering Agent is introduced as a miniaturized, intelligent, and integrated hardware-software system designed for extreme downhole environments and complex conditions, incorporating power supply, communication, sensing, computation, and actuation modules to enable environmental perception, autonomous decision-making and adaptive control. The characteristics of various agent types, including those for injection-production, lift, fracturing and workover, are analyzed, with key research directions identified in miniaturized self-powered energy management, reliable communication in high-interference environments, highly integrated multi-parameter sensing with long-term drift self-calibration, and high-reliability microsystem integration manufacturing. AI-driven decision optimization remains the core feature, requiring advances in data acquisition, governance, and fusion architectures, alongside algorithmic improvements in model performance and deployment compatibility. Additionally, advanced structural and functional materials support agent construction and extreme-environment adaptability, while geology-engineering integration continues to expand the functional scope of oil production engineering.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 3","pages":"Pages 554-573"},"PeriodicalIF":10.7,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148544576","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Generation stages and genetic types of coal-rock gas in China","authors":"Shuichang ZHANG,&nbsp;Bin ZHANG,&nbsp;Xingzhi MA,&nbsp;Yong TANG,&nbsp;Zeliang LIANG,&nbsp;Longde SUN","doi":"10.1016/S1876-3804(26)60716-1","DOIUrl":"10.1016/S1876-3804(26)60716-1","url":null,"abstract":"<div><div>Based on the molecular structure transitions, hydrocarbon composition, and reservoir characteristics changes during coal evolution, combined with the production characteristics of coal-rock gas, the generation stages and genetic types of coal-rock gas in China are investigated. The generation of coal-rock gas can be divided into five stages: low-coal-rank biogenic gas generation stage (<em>R</em>_o &lt; 0.5%), mid-coal-rank transitional gas generation stage (0.5% ≤ <em>R</em>_o &lt; 0.8%), mid-coal-rank mature gas generation stage (0.8% ≤ <em>R</em>_o &lt; 1.3%), mid-coal-rank high-maturity gas generation stage (1.3% ≤ <em>R</em>_o &lt; 2.0%), and high-coal-rank overmature gas generation stage (<em>R</em>_o ≤ 2.0%). Based on the burial depth and gas origin, the gas reservoirs are divided into three types: shallow coalbed methane, deep coal-rock gas and exogenous coal-rock gas. According to the hydrocarbon generation stage of coal, deep coal-rock gas is further classified into: mid-coal-rank transitional coal-rock gas, mid-coal-rank mature coal-rock gas, mid-coal-rank high-maturity coal-rock gas, and high-coal-rank overmature coal-rock gas. During the dynamic evolution of coal from shallow to deep depths, the coal has experienced a hydrocarbon generation evolution sequence of “biogenic gas→transitional gas→wet gas→dry gas”, and a process of “primary pores→cleat development→peak organic matter pores→densification and fracturing + fracture opening” of reservoirs formation . The occurrence state gradually shifts from “dominance of adsorbed gas” to “continuous increase in free gas proportion”, and the development modes also transform from “long-term drainage and depressurization for desorption” to “high gas production upon well opening”. In addition, there is another type of coal-rock gas which is externally sourced, with the natural gas originating from underlying strata. This type of coal-rock gas corresponds to low-rank coals with reservoir development, where gas was accumulated under the control of tectonics, with high-proportion free gas and high initial production.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 3","pages":"Pages 335-347"},"PeriodicalIF":10.7,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148558558","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Enrichment factors and strategic target areas of medium- to low-rank coal-rock gas/coalbed methane in Xinjiang, China","authors":"Yong TANG,&nbsp;Weijiang YAO,&nbsp;Min WANG,&nbsp;Dingcheng PI,&nbsp;Guozhen WANG,&nbsp;Jie XIANG,&nbsp;Ming CHENG","doi":"10.1016/S1876-3804(26)60722-7","DOIUrl":"10.1016/S1876-3804(26)60722-7","url":null,"abstract":"<div><div>To solve the problems of the poor understanding of enrichment factors, unclear exploration targets, and challenging selection of favorable areas for medium- and low-rank coal-rock gas/coalbed methane resources in Xinjiang, this paper, based on the coal-measure whole petroleum system theory, examines the main controlling factors of coal rock gas/coalbed methane enrichment and further discusses the exploration targets and favorable areas, through extensive coal petrology and coal quality analysis, gas content measurements, and well-seismic data interpretation. The study shows that the low thermal maturity, with vitrinite reflectance (<em>R</em>_o) commonly below 0.8%, is the primary reason why the actual gas content is significantly lower than the hydrocarbon generation capacity in basins such as the Junggar Basin. In addition, the coal-forming age and maceral composition characteristics also exert important controls on gas content and storage capacity. Accordingly, two exploration strategies are proposed: seeking relatively higher coal ranks and elevated geothermal gradients, and targeting older (especially Paleozoic) coal-measure strata. Further, five major exploration targets are identified: (1) post-coalification high geothermal gradient zone; (2) early deep burial and late uplift tectonic belt; (3) Upper Paleozoic coal measures with high thermal maturity; (4) coal seams with high vitrinite content; and (5) coordinated development area of the coal-measure whole petroleum system. Depending on the distribution of coal-measure strata, structural characteristics, and coal rock properties of various basins in Xinjiang, three practical exploration areas are defined: the Southern Piedmont Structural Belt and stable central region of the Junggar Basin, the Wenjisang Structural Belt and the Hongtai Slope of the Tuha Basin, and the Northern Kuqa Structural Belt of the Tarim Basin. Additionally, six peripheral strategic replacement areas are identified: Heshituoluogai, Yili, Yanqi, Santanghu, Kupu and Fujin basins. The study provides a scientific basis for selecting favorable zones to advance the large-scale exploration and effective development of coal-rock gas/coalbed methane resources in Xinjiang.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 3","pages":"Pages 433-450"},"PeriodicalIF":10.7,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148544594","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Accumulation characteristics and exploration progress of global ultra-deep oil and gas","authors":"Lirong DOU,&nbsp;Xiaobing LIU,&nbsp;Zhixin WEN,&nbsp;Zhaoming WANG,&nbsp;Yifan SONG,&nbsp;Zhengjun HE,&nbsp;Ruiyin CHEN,&nbsp;Zhenzhen WU","doi":"10.1016/S1876-3804(26)60718-5","DOIUrl":"10.1016/S1876-3804(26)60718-5","url":null,"abstract":"<div><div>Global deep Earth exploration and ultra-deep oil and gas exploration (below 6 000 m) have attracted increasing attention, with a growing number of major oil and gas discoveries. This article systematically reviews the discovery history of ultra-deep oil and gas exploration since 1937, dividing it into four major stages: onshore ultra-deep exploration and local breakthrough (1937–1982), shallow- water-dominated ultra-deep exploration and sporadic discoveries (1983–1997), onshore and offshore large-scale ultra-deep discoveries (1998–2018), and onshore over-8 000-m exploration and new breakthrough (since 2019). By the end of 2025, a total of 1 348 exploratory wells with a depth of more than 6 000 m have been drilled worldwide. A total of 305 ultra-deep oil and gas fields have been discovered in 29 basins across 20 countries, with recoverable reserves equivalent to 63.21×10⁸ t, accounting for only 0.9% of the global total reserves and indicating enormous exploration potential. The discovered reserves are highly concentrated in the Tethyan and South Gondwana petroleum realms, dominated by passive continental margin basins with a proportion of 71.25%. Reservoirs are mainly composed of Meso-Cenozoic carbonate rocks and clastic rocks. Studies show that three types of advantageous basins, including cratonic basins, passive continental margin basins and foreland basins, have their own characteristics in terms of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation. The global ultra-deep oil and gas exploration degree is extremely low, and there may exist another “golden zone” for hydrocarbon accumulation with huge resource potential. In the future, it is necessary to strengthen research on the mechanisms of hydrocarbon generation and accumulation as well as resource assessment in ultra-deep strata, and carry out integrated evaluation combining geology, engineering and intelligent technology. Internationally, efforts should be focused on new ultra-deep project evaluation and oil and gas cooperation in hydrocarbon-rich regions such as the both sides of the Atlantic, the Middle East, Central Asia-Russia and Australia. With the accelerated exploration of over-8 000-m oil and gas in China, a new peak of reserve growth is forthcoming.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 3","pages":"Pages 366-383"},"PeriodicalIF":10.7,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148544633","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Temperature-pressure history of the Cretaceous Qingshankou Formation and its relationship with Gulong shale oil enrichment in the northern Songliao Basin, China","authors":"Bo LIU,&nbsp;Jinyou ZHANG,&nbsp;Longhui BAI,&nbsp;Xiaofei FU,&nbsp;Yuchen LIU,&nbsp;Boyang WANG,&nbsp;Junchen WU","doi":"10.1016/S1876-3804(26)60724-0","DOIUrl":"10.1016/S1876-3804(26)60724-0","url":null,"abstract":"<div><div>The temperature-pressure history of the organic-rich shale in the Cretaceous Qingshankou Formation in the northern Songliao Basin was reconstructed through comprehensive analyses, including field tests, paleo-heat flow reconstruction, overpressure evolution and geochemistry. The formation and evolution process of the Gulong shale oil was reproduced, and its enrichment patterns were clarified. Influenced by tectothermal events and tectonic movements at the end of the Cretaceous Mingshui Formation deposition, the evolution of organic matter thermal maturity in the first member of Qingshankou Formation (Qing-1 Member) exhibited distinct stages, which can be divided into the Cretaceous rapid evolution stage and the Paleogene–Neogene slow evolution and stabilization stage. High paleogeotemperature drove secondary cracking of retained oil in the Qing-1 Member, forming light shale oil in the Gulong Sag. This sag experienced three phases of overpressure during the late depositional stage of the Nenjiang Formation and late depositional stage of the Mingshui Formation of the Cretaceous, and the Neogene. The first two phases were related to the oil generation peak and secondary cracking in the sag, respectively, while the third phase resulted from the inheritance of earlier overpressure, as well as sustained hydrocarbon cracking and heat-induced fluid volume expansion. Crude oil is distributed orderly in the northern Songliao Basin. Conventional oil reservoirs such as Saertu and Putaohua contain high contents of non-hydrocarbon compounds, and they are believed to have formed by hydrocarbon charging as a result of the first phase of overpressure. Tight oils in the Fuyu and Gaotaizi reservoirs, most similar to shale oil in the Qing-1 Member in terms of composition and physical properties, are characterized by high content of saturated hydrocarbons, with their hydrocarbon charging and accumulation related to the second phase of overpressure. High paleo-heat flow generated by tectothermal events is determined to be the main driving factor for the staged hydrocarbon generation of organic matter in the Qingshankou Formation. The shale of Qing-1 Member with high thermal conductivity and the Cretaceous Nenjiang shale with low thermal conductivity constitute a thermal structure with lower conducting and upper sealing. This structure has prolonged secondary cracking of hydrocarbons, widened the liquid hydrocarbon window, and helped self-sealing enrichment of the Gulong light shale oil by virtue of the third phase of overpressure.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 3","pages":"Pages 467-479"},"PeriodicalIF":10.7,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148544636","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"An intelligent injection-production model based on graph connection element driven by data and physics","authors":"Hui ZHAO,&nbsp;Yunfeng XU,&nbsp;Deli JIA,&nbsp;Xiang RAO,&nbsp;Yuhui ZHOU,&nbsp;Fankun MENG","doi":"10.1016/S1876-3804(26)60729-X","DOIUrl":"10.1016/S1876-3804(26)60729-X","url":null,"abstract":"<div><div>To address the challenges of connectivity characterization, dynamic prediction efficiency, and real-time optimization in complex reservoir injection-production systems, this study proposes a physics- and deep learning-integrated intelligent injection-production modeling framework based on the graph connection element method. The method adopts the connection element method as the physical foundation and constructs a non-Euclidean graph representation to describe interwell connectivity, enabling characterization of the physical topology and dynamic interactions within the well pattern system. By incorporating an adaptive attention mechanism into a graph convolutional network and embedding time-dependent node attributes, a physics-consistent reservoir performance prediction model is developed. Furthermore, a hybrid optimization strategy integrating differential evolution and particle swarm optimization is employed to establish an intelligent optimization framework taking the economic net present value as the objective. Based on rapid prediction of injection and production behaviors, the proposed approach enables optimization of injection-production parameters and improvement of reservoir development economics. Field applications demonstrate that the proposed intelligent injection-production model based on graph connection element accurately reproduces water-cut behavior of producers and provides quantitative uncertainty estimation. It achieves rapid history matching and dynamic response forecasting for complex injection-production systems, exhibiting high accuracy and stability. It enables optimization of production strategies with NPV as the objective, demonstrating strong engineering applicability and scalability.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 3","pages":"Pages 542-553"},"PeriodicalIF":10.7,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148544575","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Cementing and film-forming hydrophobic drilling fluid technology for long horizontal wells in deep coal-rock gas reservoirs","authors":"Jinsheng SUN,&nbsp;Hongtao LIU,&nbsp;Jinliang HAN,&nbsp;Li ZHAO,&nbsp;Pengcheng HAO,&nbsp;Shangkun ZHANG,&nbsp;Chao PENG,&nbsp;Yifu LONG,&nbsp;Fan LIU,&nbsp;Xianbin HUANG,&nbsp;Jiafeng JIN","doi":"10.1016/S1876-3804(26)60731-8","DOIUrl":"10.1016/S1876-3804(26)60731-8","url":null,"abstract":"<div><div>Through a systematic analysis of the physical properties of coal and gangue, including microscopic pore structure, surface wettability and mechanical strength, the mechanism of borehole wall collapse in deep coal formations was revealed. Based on this understanding, a wellbore-stabilizing drilling fluid concept was proposed, featuring high-efficiency plugging of medium and large pores and fractures + cementation and film-formation in micro and small pores and fractures + overall surface hydrophobic inhibition. An adaptive plugging agent and a cementing film-forming hydrophobic inhibitor were developed, and a cementing, wall-strengthening, film-forming, and hydrophobic drilling fluid system was established. The adaptive plugging agent consists of organic-inorganic hybrid polymer microspheres, which enables self-adaptive plugging of pores and micro-fractures in coal rock through flexible deformation, effectively preventing direct contact between the drilling fluid and medium-to-large pore-fracture systems in the formation. The cementing film-forming hydrophobic inhibitor contains strong adsorption groups and hydrophobic groups, which provides both cementing reinforcement and dense film-forming functions, significantly enhancing the overall structural strength of coal rock, greatly reducing surface hydrophilicity, and inhibiting hydration swelling of clay minerals. The developed drilling fluid system exhibits favorable rheological behavior, filtration-control performance and lubricity. It can substantially improve the compressive strength of rock samples and markedly reduce their linear expansion rate. Field application results demonstrate that the system delivers excellent anti-collapse, cuttings-carrying and lubrication performance, with outstanding wellbore stabilization effectiveness.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 3","pages":"Pages 574-584"},"PeriodicalIF":10.7,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148544571","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Geological characteristics and natural gas exploration targets of the Jurassic coal-measure whole petroleum system in Northwest China","authors":"Chengzao JIA,&nbsp;Junfeng ZHANG,&nbsp;Xuefeng QI,&nbsp;Wen ZHAO","doi":"10.1016/S1876-3804(26)60713-6","DOIUrl":"10.1016/S1876-3804(26)60713-6","url":null,"abstract":"<div><div>Coal-measure whole petroleum system is generally featured by dual-source multi-reservoir coupling, coexistence of three dynamic fields controlling hydrocarbon accumulation, and sequential accumulation of deep coal-rock gas (shale gas), proximal tight sandstone gas (fractured tight gas), distal tight gas/conventional natural gas, and shallow coalbed methane. To reveal the common geological characteristics of coal-measure WPS in the Jurassic coal-bearing basins in Northwest China, this paper analyzes the geological characteristics of coal-measure WPSs in Kuqa Depression of Tarim Basin and Thrust Belt of Southern Junggar Basin, such as structure and hydrocarbon accumulation. It is pointed out that the Jurassic whole petroleum system of coal measures in northwestern China is significantly different from that of the Carboniferous–Permian in North China. Four types of source-reservoir coupling accumulation models are mainly developed in the Jurassic of Northwest China, including structural-type shallow to deep conventional gas outside the source, structural-type deep to ultra-deep tight gas outside the source, near-source/in-source tight gas, and self-generating and self-preserving coal-rock gas. It is indicated that the Jurassic strata in Northwest China belong to the giant continental sedimentary region on the passive continental margin of Neo-Tethys Ocean, including six subsidence zones, and containing coal measures and coal rocks that are consistent in the region but distinct from basin to basin. Thus, this region stands as the largest Mesozoic coal-measure area and a giant natural gas accumulation area in China. Resource assessment demonstrates that the Jurassic coal-measure WPS in Northwest China holds natural gas resources up to 30×10¹² m³, in which merely 11% has been proved, and coal-rock gas accounts for 17×10¹² m³, possessing a tremendous exploration potential. Deep and ultra-deep tight gas and coal-rock gas in Kuqa Depression and Southwestern Depression of Tarim Basin, southern margin of Junggar Basin, northern margin of Qaidam Basin, and Taipei Sag of Turpan-Hami Basin will serve as key natural gas exploration targets in the future.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 3","pages":"Pages 285-305"},"PeriodicalIF":10.7,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148558555","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"In-situ porosity restoration of clay-rich lacustrine shale oil reservoirs and its implications for shale oil reserve evaluation","authors":"Longde SUN,&nbsp;Fenglan WANG,&nbsp;Zihui FENG,&nbsp;Haiyong WANG,&nbsp;Binhui LI,&nbsp;Hang JIANG,&nbsp;Jijin YANG,&nbsp;Yong SU,&nbsp;Zhejun PAN,&nbsp;Huasen ZENG,&nbsp;Xiqing XU","doi":"10.1016/S1876-3804(26)60714-8","DOIUrl":"10.1016/S1876-3804(26)60714-8","url":null,"abstract":"<div><div>To accurately evaluate the storage capacity of shale oil reservoirs under in-situ temperature and pressure conditions, we constructed a new model for determining the porosity under formation conditions, developed a HTHP shale porosity measurement system capable of operating at an overburden pressure of 70 MPa, a pore-fluid pressure of 40 MPa, and a temperature of 120 °C, and established an integrated workflow for restoring in-situ porosity in clay-rich lacustrine shale oil reservoirs. This technology system was applied to the Upper Cretaceous Gulong shale oil reservoirs in the Songliao Basin, China. The in-situ porosity in shale oil reservoirs is generally higher than that measured at normal pressure on surface. The restored porosity increases by 3.17–4.00 percentage points for ordinary shale, 1.58–1.60 percentage points for silty shale, and 1.12–1.58 percentage points for carbonates. The restored porosity increase grows regularly with burial depth, temperature, pore pressure, and pressure coefficient, reflecting the elastic dilation of clay- and organic-associated nanopores and the widening of overpressure-supported microfractures in the Gulong shales. Core depressurization was found to close these pressure-supported pores, causing conventional helium and surface nuclear magnetic resonance (NMR) measurements to systematically underestimate storage capacity, particularly in deep, clay-rich, overpressured intervals. For reserve estimation, use of ambient-condition porosity may introduce significant underestimation of original oil in place (OOIP). For the clay-rich Gulong shales, it is recommended to apply a correction factor of 3–4 percentage points to the surface-measured porosity (or surface porosity) for ordinary shale, and about 1.6 percentage points for silty shale, while only a minor correction is needed for carbonates. In-situ porosity should thus be incorporated into OOIP calculations and parameterized using clay content, total organic carbon content, pressure coefficient and burial depth. Operationally, production from clay-rich, overpressured intervals should be implemented under controlled pressure, in order to avoid elastic closure of native microfractures and preserve reservoir deliverability.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 3","pages":"Pages 306-321"},"PeriodicalIF":10.7,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148558556","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}