Petroleum Exploration and Development最新文献

{"title":"An iterative regularized inversion method of fracture width and height using cross-well optical fiber strain","authors":"Ming CHEN ,&nbsp;Ziang WANG ,&nbsp;Tiankui GUO ,&nbsp;Yongzan LIU ,&nbsp;Zuorong CHEN","doi":"10.1016/S1876-3804(26)60687-8","DOIUrl":"10.1016/S1876-3804(26)60687-8","url":null,"abstract":"<div><div>The forward model of optical fiber strain induced by fractures, together with the associated model resolution matrix, is used to demonstrate the interpretability of fracture parameters once the fracture intersects the fiber. A regularized inversion framework for fracture parameters is established to evaluate the influence of measured data quality on the accuracy of iterative regularized inversion. An interpretation approach for both fracture width and height is proposed, and the synthetic forward data with measurement error and field examples are employed to validate the accuracy of the simultaneous inversion of fracture width and height. The results indicate that, after the fracture contacts the fiber, the strain response is strongly sensitive only to the fracture parameters at the intersection location, whereas the interpretability of parameters at other locations remains limited. The iterative regularized inversion method effectively suppresses the impact of measurement error and exhibits high computational efficiency, showing clear advantages for inversion applications. When incorporating the first-order regularization with a Neumann boundary constraint on the tip width, the inverted fracture-width distribution becomes highly sensitive to fracture height; thus, combined with a bisection strategy, simultaneous inversion of fracture width and height can be achieved. Examination using the model resolution matrix, noisy synthetic data, and field data confirms that the iterative regularized inversion model for fracture width and height provides high interpretive accuracy and can be applied to the calculation and analysis of fracture width, fracture height, net pressure and other parameters.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 235-248"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147427391","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":"Gas-water flow mechanism during the closure process of self-supporting fractures in shale and its engineering applications","authors":"Hongzhi YANG ,&nbsp;Qiuyang CHENG ,&nbsp;Cheng CHANG ,&nbsp;Yili KANG ,&nbsp;Jianfa WU ,&nbsp;Xuefeng YANG ,&nbsp;Weiyang XIE ,&nbsp;Zhenyu ZHANG ,&nbsp;Jiajun LI","doi":"10.1016/S1876-3804(26)60683-0","DOIUrl":"10.1016/S1876-3804(26)60683-0","url":null,"abstract":"<div><div>Taking the underground shale of the Silurian Longmaxi Formation in southern Sichuan Basin as the research object, stress-sensitive experiments on self-supporting fractures and micro-visualization experiments on gas-water flow were conducted under simulated reservoir conditions to study the mechanism of microscopic gas-water flow during the fracture closure process and discuss its engineering applications. The results show that as the effective stress gradually increased from 5 MPa to 60 MPa with an increment of 5 MPa per step, the self-supporting fracture closure exhibited a two-stage characteristic of being fast in the early stage and slow in the later stage, with the inflection point stress ranging from 32 MPa to 35 MPa, and the closure degree of 47%–76%. The effective stress increase gradually rose from 5 MPa per step to 20 MPa per step, and the early fracture closure accelerated, with the maximum closure degree increasing by 8.6%. As the fracture width decreased from 500 μm to 50 μm, the gas-phase shifted from continuous to discontinuous flow, and the proportion of the critical gas-phase flow to maintain the continuous gas-phase flow increased. In the early stage of fracture closure (fracture width greater than 300 μm), the continuous gas-phase flow is controlled by the fracture width – the larger the fracture width, the smaller the proportion of the critical gas-phase flow to maintain the continuous gas-phase flow. In the late stage of fracture closure (fracture width less than 300 μm), as the fractures continue to close, the dominant role of the surface roughness of the fractures becomes stronger, and the proportion of the critical gas-phase flow to maintain the continuous gas-phase flow exceeds 70%. A reasonable pressure control during stable production and pressure reduction in the early stage (the peak pressure drop at the wellhead is less than 32 MPa) to delay the self-supporting fracture closure is conducive to the stable and increased production of gas wells.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 181-190"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147427372","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 collaborative optimization design method of platform location and well trajectory for a complex-structure well factory","authors":"Ge WANG,&nbsp;Deli GAO,&nbsp;Wenjun HUANG","doi":"10.1016/S1876-3804(26)60689-1","DOIUrl":"10.1016/S1876-3804(26)60689-1","url":null,"abstract":"<div><div>Using platform-target matching deviation, anti-collision difficulty, trajectory complexity, and total drilling footage as objective functions, and comprehensively considering constraints such as platform layout area, drilling extension limits, underground target distribution and trajectory collision risks, a model of platform location-wellbore trajectory collaborative optimization for a complex-structure well factory is developed. A hybrid heuristic algorithm is proposed by combining an improved sparrow search algorithm (ISSA) for optimizing platform parameters in the outer layer and a directed artificial bee colony algorithm (DABC) for optimizing trajectory parameters in the inner layer. The alternating iteration of ISSA-DABC facilitates the resolution of the collaborative optimization problem. The ISSA-DABC provides an effective solution to the platform-trajectory collaborative optimization problem for complex-structure well factories and overcomes the tendency of the traditional platform-trajectory stepwise optimization workflow to become trapped in local optima and yield inconsistent designs. The ISSA-DABC has a strong global search capability, fast convergence and good robustness, and can simultaneously satisfy multiple engineering constraints on drilling footage, trajectory complexity and collision risk, and enables automated, workflow-wide generation of constraint-compliant, near-globally optimal platform-trajectory configurations. Field applications further demonstrate that ISSA-DABC significantly reduces the objective function value and collision risk, yielding more rational platform layouts and well factory design parameters.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 261-271"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147425660","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":"Key scientific issues and research progress in development of shale oil in Jiyang Depression, Bohai Bay Basin, China","authors":"Yong YANG ,&nbsp;Xiaopeng CAO ,&nbsp;Shiming ZHANG ,&nbsp;Qi LYU ,&nbsp;Zupeng LIU ,&nbsp;Hongxia SUN ,&nbsp;Wei LI ,&nbsp;Guang LU ,&nbsp;Liyang CHEN","doi":"10.1016/S1876-3804(26)60682-9","DOIUrl":"10.1016/S1876-3804(26)60682-9","url":null,"abstract":"<div><div>Centering on the critical bottlenecks in the development of shale oil in the Jiyang Depression of Shengli Oilfield, key scientific and engineering issues are proposed in aspects such as the storage space and occurrence state of shale oil, the formation mechanisms of multi-scale flow spaces, the mobilization mechanisms of crude oil in pores and fractures, and the enhanced oil recovery (EOR) mechanisms during the late stage of elastic development. The research progress and mechanistic insights in recent years are reviewed with respect to experimental techniques, characteristics of pore-fracture structure and fluid occurrence, fracture evolution mechanisms, shale oil flow mechanisms and EOR techniques. Through improving the experimental methods, optimizing the testing conditions, and developing new technologies, we deeply understand the occurrence state, storage space and flow pattern of shale oil, and reveal the distribution pattern of “oil-bearing in all pore sizes and oil-rich in large pores” and the differences in fluid phase states under the confinement effect of nano-scale pores in the shales of the Jiyang Depression; depict the characteristics of “restricted vertical expansion and complex fracture networks” of induced fractures and the dynamic evolution of fracture networks during the fracturing–soaking– production process; establish a “easy flow - slow flow – stagnant flow” three-zone model and the elastic drive + imbibition drive synergistic energy replenishment mechanism; and carry out high-pressure injection to further enhance the mass transfer and diffusion capacity of CO₂ within the shale pore-fracture system, and compete for the desorption of alkanes to improve the mobilization degree of shale oil. The research achievements provide crucial support for the formation of the theory of continental shale oil development and the construction of the technical system. The future research efforts will focus on mine-scale multi-field coupling physical simulation equipment, microscopic to macroscopic multi-scale experimental methods, pore/fracture fine characterization and post-fracturing core fracture description technologies, multi-media fluid-structure coupling numerical simulation algorithms, and low-cost EOR and low-quality shale oil in-situ upgrading technologies, in order to promote the large-scale and profitable development of shale oil in the Jiyang Depression.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 167-180"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147427373","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":"Ultra-high-temperature resistant water-based drilling fluid technology for ten-kilometer ultra-deep wells","authors":"Fengbao LIU ,&nbsp;Da YIN ,&nbsp;Xuwu LUO ,&nbsp;Jinsheng SUN ,&nbsp;Xianbin HUANG ,&nbsp;Ren WANG","doi":"10.1016/S1876-3804(26)60686-6","DOIUrl":"10.1016/S1876-3804(26)60686-6","url":null,"abstract":"<div><div>Two types of ultra-high-temperature resistant water-based drilling fluid additives were designed and developed: an ultra-high- temperature resistant salt-tolerant polymer fluid loss reducer, and an ultra-high-temperature resistant micro-nano plugging agent. An ultra-high-temperature resistant water-based drilling fluid system meeting the requirements of ultra-deep well drilling was established. Laboratory test and field application were employed for performance evaluation. The ultra-high-temperature and high-salt resistant polymer fluid loss reducer exhibits a mesh-like membrane structure with numerous cross-linking points, and its high-temperature and high-pressure (HTHP) loss was 28.2 mL after aging at 220 °C under saturated salt conditions. The ultra-high-temperature resistant micro-nano plugging agent adaptively filled mud cake pores/fractures through deformation, thus reducing the fluid loss. At elevated temperatures, it transitioned to a viscoelastic state to effectively cement the rock on wellbore wall and enhanced wall stability. The ultra-high-temperature resistant water-based drilling fluid system with a density of 1.6 g/cm³ exhibits excellent rheological properties at high temperature and high pressure. Its HTHP fluid loss at 220 °C was only 9.6 mL. It maintains a stable performance under high-temperature and high-salt conditions, with a sedimentation factor below 0.52 after holding at high temperature for 7 d, and generates no H₂S gas after aging, demonstrating good lubricity and safety. This drilling fluid system has been successfully applied in the 10 000-meter ultra-deep well of China, Shenditake 1, in Tarim Oilfield, ensuring the well's successful drilling to a depth of 10 910 m.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 221-234"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147427392","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":"Geological features and exploration potential of shale oil in Jiuquan Basin, NW China","authors":"Wenhua XIAO,&nbsp;Deqiang WEI,&nbsp;Xinze LIU,&nbsp;Jun ZHAO,&nbsp;Zhenyu DONG,&nbsp;Panliang REN,&nbsp;Chaojie MAO,&nbsp;Peilin YANG,&nbsp;Xue ZHANG,&nbsp;Tiefeng LI,&nbsp;Haojin ZHANG,&nbsp;Pengpeng ZHANG","doi":"10.1016/S1876-3804(26)60680-5","DOIUrl":"10.1016/S1876-3804(26)60680-5","url":null,"abstract":"<div><div>This paper systematically analyzes the reservoir-forming characteristics and cretaceous shale oil types in four major hydrocarbon-generating sags (Qingxi, Ying'er, Huahai, and Shida) of the Jiuquan Basin, based on the data of experiments for microscopic and geochemical analysis of reservoirs. The hydrothermal alteration-induced reservoir-forming model and its reservoir-controlling effect in the Qingxi Sag are discussed, and the exploration potential of shale oil in these four sags are evaluated. (1) The Qingxi Sag is widely developed with mud shale, dolomitic shale, and laminated argillaceous dolomite in the Cretaceous, which can be defined as mixed shale as a whole. The source rocks in this area are of good quality and high maturity, formed in a saline water sedimentary environment, and rich in dolomite, with a strong hydrocarbon generation capacity and excellent oil generation conditions. The reservoir space has been significantly modified by hydrothermal process, with well-developed dissolution pores and microfractures, recording favorable reservoir conditions for shale oil enrichment. Overall, this sag has large reservoir thickness and large resource volume, making it the most realistic shale oil exploration target in the Jiuquan Basin. However, it faces challenges such as great burial depth (deeper than 4 500 m) and strong tectonic stress. (2) The Ying'er, Huahai, and Shida sags all feature sand-mud interbeds consisting of fan delta front thin sandbodies and lacustrine mud shale in the Cretaceous, having good source rock quality and favorable conditions for interbedded-type shale oil accumulation. The source rocks are insufficient in thermal evolution degree and unevenly distributed, and favorable shale oil resources are mainly endowed near the center of the sags. Reservoirs are primarily composed of siltstone to fine sandstone, suggesting relatively good reservoir conditions, generally with small burial depth (3 000–4 000 m) and the possibility of local sweet spots. It is noted that the Ying'er Sag has already produced low-mature to mature oil, qualifying it as a near-term realistic shale oil exploration area.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 138-151"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147425658","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":"Enrichment mechanism and optimal in-situ conversion recovery method of lacustrine low-to-medium maturity shale oil","authors":"Wenzhi ZHAO ,&nbsp;Wei LIU ,&nbsp;Congsheng BIAN ,&nbsp;Ruina XU ,&nbsp;Xiaomei WANG ,&nbsp;Weifeng LYU ,&nbsp;Jiafeng JIN ,&nbsp;Chuanjin YAO ,&nbsp;Chi XIONG ,&nbsp;Ruirui LI ,&nbsp;Yongxin LI ,&nbsp;Jin DONG ,&nbsp;Ming GUAN ,&nbsp;Leibo BIAN","doi":"10.1016/S1876-3804(26)60671-4","DOIUrl":"10.1016/S1876-3804(26)60671-4","url":null,"abstract":"<div><div>In-situ heating conversion is the most practical recovery method for lacustrine low-to-medium maturity shale oil. However, the energy output-input ratio must exceed the economic threshold to achieve commercial development. This paper systematically investigates the mechanism of super-rich accumulation of organic matter in continental shale, sweet spot evaluation, optimal heating windows, and appropriate well types and patterns from the perspectives of enhancing energy output and reducing energy input. (1) The super-rich accumulation of organic matter in lacustrine shale is primarily controlled by the intensity, frequency, and preservation of external material inputs, and is related to moderate volcanic and hydrothermal activities, marine transgressions, with total organic carbon content greater than or equal to 6%. (2) The quality of organic-rich intervals is related to the type of source material and hydrocarbon generation potential. The in-situ conversion-derived hydrocarbon quality index (HQI) is established, and the zones exhibiting HQI&gt;450 are defined as sweet spots. (3) Considering the characteristics of the organic matter conversion material field and seepage field, the temperature interval 300–370 °C is recommended as the optimal heating window for the Chang 7₃ sub-member of the Triassic Yanchang Formation in the Ordos Basin. Based on the advantages of thermal conductivity, permeability, and hydrocarbon expulsion efficiency along the bedding direction during in-situ heating, the “horizontal well heating + vertical well development” scheme is proposed, which has demonstrated significant enhancement in both recovery factor and energy output-input ratio, making it the optimal in-situ conversion process. The research findings provide a theoretical and technical foundation for the economical and efficient development of low-to-medium maturity shale oil.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 1-15"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147426474","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":"Orderly hydrocarbon accumulation pattern in passive continental margin basins on both sides of the South Atlantic","authors":"Zhixin WEN ,&nbsp;Zuodong LIU ,&nbsp;Ning XU ,&nbsp;Gang LI ,&nbsp;Zhengjun HE ,&nbsp;Chengpeng SONG","doi":"10.1016/S1876-3804(26)60676-3","DOIUrl":"10.1016/S1876-3804(26)60676-3","url":null,"abstract":"<div><div>Based on the plate tectonics theory, the sedimentary environment of paleotectonics along the passive continental margins on both sides of the South Atlantic Ocean was reconstructed using the paleomagnetic, regional geological, and seismic data, and the intrinsic relationships of hydrocarbon distribution in the passive continental margin basins and the differential hydrocarbon accumulation patterns were analyzed. Results show that basins on both sides of the South Atlantic experienced two major extensional phases—rift and depression—and four evolutionary stages: the Early Cretaceous Berriasian–Barremian intracontinental rift stage, the Early Cretaceous Aptian–Albian intercontinental rift to initial drift transition stage, the Late Cretaceous–Paleogene drift-related marine transgressive depression stage, and the Neogene–Quaternary drift-related marine regressive depression stage. According to basin architecture and superposition style, the passive-margin basins are classified into two principal types: rift-continental marginal depression composite and continental marginal depression-dominated. The basins in the study area were further divided into six types based on the development degree of salt tectonics and the type of dominant sand bodies, i.e. salt-free rift-continental marginal gravity-flow composite type, salt-free rift-continental marginal delta composite type, salt-bearing rift-continental marginal gravity flow composite type, delta-dominated salt-bearing rift-continental marginal delta composite type, gravity-flow-dominated continental marginal depression type, and delta-dominated continental marginal depression type. The salt-free rift-continental marginal gravity flow and delta composite basins are mainly distributed in the southern segment. The salt-bearing rift-continental marginal gravity flow and delta composite basins are mainly distributed in the central segment. The gravity-flow-dominated continental marginal depression basins are mainy distributed in the northern segment. The delta-dominated passive-margin depression basins are distributed in three segments from north to south. In different types of basins, distinctive depositional systems and source–reservoir–caprock assemblages were formed in each upper/lower structure layer. The superimposition and evolution of multi-phase prototype basins result in the orderly hydrocarbon accumulation vertically and laterally, which are “segmented along-strike, zoned across-strike, and layered vertically”.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 79-95"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147425666","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":"Staged-cumulative charging and differential accumulation of continental shale oil: A case study of Permian Lucaogou Formation shale oil in Junggar Basin, NW China","authors":"Haiping HUANG ,&nbsp;Hong ZHANG ,&nbsp;Yong MA","doi":"10.1016/S1876-3804(26)60677-5","DOIUrl":"10.1016/S1876-3804(26)60677-5","url":null,"abstract":"<div><div>In the Jimusaer Sag of the Junggar Basin, crude oils from the upper and lower sweet-spot intervals of the Permian Lucaogou Formation display a pronounced “light-heavy reversal” in oil properties that indicates a fundamental mismatch between oil composition and host rock maturity. To resolve this anomaly, this study integrates geological, geochemical, and petrophysical datasets and systematically evaluates the combined roles of thermal evolution, organofacies, wettability, abnormal overpressure, and migration-related fractionation on shale oil composition. On this basis, a “staged charging-cumulative charging” model is proposed to explain compositional heterogeneity in lacustrine shale oils. The results demonstrate that crude-oil compositions are jointly controlled by the extent of biomarker depletion, the temporal evolution of hydrocarbon charging, and the openness of the source-reservoir system, rather than by thermal maturity or organofacies alone. The upper sweet-spot interval is interpreted to have functioned as a semi-open system during early stages, in which hydrocarbon generation and expulsion were broadly synchronous, leading to preferential loss of early-generated, biomarker-rich heavy components, whereas progressive shale diagenesis at later stages promoted the retention of highly mature, light hydrocarbons. In contrast, the lower sweet-spot interval represents a relatively closed system, where hydrocarbons generated during multiple stages continuously accumulated and were preserved as mixed charges; overprinting by multi-phase fluids progressively weakened sterane isomerization signals, rendering them unreliable indicators of individual charging events or final thermal maturity. This charging behavior provides a reasonable explanation for anomalously low or distorted biomarker parameters observed in intervals of low or similar maturity. Overall, the proposed charging model reconciles the observed reversal in crude-oil properties and, by shifting the interpretive focus from static maturity assessment to charging dynamics, offers a new theoretical basis for understanding lacustrine shale oil accumulation processes, and guiding sweet-spot selection and exploration-development strategies.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 96-109"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147426472","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":"Geomodelling of multi-scenario non-stationary reservoirs with enhanced GANSim","authors":"Suihong SONG ,&nbsp;Tapan MUKERJI ,&nbsp;Celine SCHEIDT ,&nbsp;Hisham M. ALQASSAB ,&nbsp;Man FENG","doi":"10.1016/S1876-3804(26)60685-4","DOIUrl":"10.1016/S1876-3804(26)60685-4","url":null,"abstract":"<div><div>GANSim is a generative adversarial networks (GANs)-based geomodelling framework with direct conditioning capabilities. To extend GANSim for geomodelling of multi-scenario and non-stationary reservoirs, and to address its tendency to overlook single-pixel well facies conditioning data that can cause local facies disconnections around wells, an enhanced GANSim framework is proposed. The effectiveness of the enhanced GANSim is validated using a 3D multi-scenario, non-stationary turbidite fan reservoir. For reservoirs that may involve multiple geological scenarios, two GANSim geomodelling workflows are proposed: (1) training a comprehensive GANSim model that covers all possible geological scenarios; and (2) first performing geological scenario falsification and then training GANSim models only for the unfalsified scenarios. On this basis, a local discriminator architecture is designed to improve facies continuity around wells. The modelling results show that both workflows can generate non-stationary facies models that conform to expected geological patterns and honor conditioning data, and the facies discontinuity issue around wells is effectively resolved. Compared with multipoint geostatistical methods (SNESIM), GANSim exhibits superior capability in reproducing geological patterns and modelling efficiency. Although GANSim requires a long training time, once training is completed, it can be applied to geomodelling reservoirs of arbitrary scale with similar geological structures, achieving modelling speeds approximately 1 000 times faster than SNESIM.</div></div>","PeriodicalId":67426,"journal":{"name":"Petroleum Exploration and Development","volume":"53 1","pages":"Pages 205-220"},"PeriodicalIF":8.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147427393","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}