Journal of Natural Gas Geoscience最新文献

{"title":"Regulation and transformation mechanism of supercritical carbon dioxide on shale reservoirs","authors":"Xuan Lin,&nbsp;Zhuo Li,&nbsp;Liwei Liu,&nbsp;Zhenxue Jiang,&nbsp;Leilei Yang","doi":"10.1016/j.jnggs.2026.08.002","DOIUrl":"10.1016/j.jnggs.2026.08.002","url":null,"abstract":"<div><div>Continental shale oil reservoirs in China exhibit strong heterogeneity, with complex fluid occurrence and distribution patterns that lead to low shale oil and gas recovery rates. Therefore, CO₂ injection for reservoir stimulation is a highly promising key technology for shale oil development. This study conducted supercritical carbon dioxide (SC–CO₂) soaking experiments under high-temperature and pressure conditions (100 °C, 25 MPa) and characterized the pre- and post-soaking reservoir changes using methods such as X-ray diffraction (XRD), gas adsorption, and high-pressure mercury intrusion. It systematically analyzed the reservoir stimulation mechanisms of SC-CO₂ in four lithofacies shales of the Funing Formation in the Suibei Basin—felsic-clayey, felsic-dolomitic, felsic, and dolomitic shales. These findings indicate that after SC-CO₂ soaking, carbonate minerals and organic matter dissolve preferentially, resulting in a passive increase in the relative contents of quartz and clay minerals. The resulting reconstruction of shale mineral composition alters the pore structure, whereas adsorption-induced swelling of clay minerals reduces micropore volume. Carbonate dissolution generates secondary pores, significantly increasing throat radius. However, secondary mineral precipitation clogs pore throats, intensifying reservoir heterogeneity and reducing mesopore volume. Owing to differences in mineral composition, the stimulation effects of SC-CO₂ vary among the four lithofacies. Felsic shales, with high quartz content, exhibit strong resistance to dissolution and are less affected by SC-CO₂. Dolomitic and felsic-dolomitic shales, with contain high carbonate content minerals, are highly sensitive to SC-CO₂ because of intense dissolution. Felsic-clayey shales, which are rich in clay minerals, exhibit complex pore dynamic equilibrium constrained by mineral transformation and particle migration. This study provides a theoretical basis for CO₂ injection to enhance oil recovery while achieving carbon sequestration in shale oil reservoirs.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 4","pages":"Pages 265-283"},"PeriodicalIF":0.0,"publicationDate":"2026-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148981001","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":"Characteristics and genesis mechanism of low-permeability sandstone reservoirs in the Miocene Sanya Formation in the northern slope zone of the Yinggehai Basin, China","authors":"Jinhai Yang,&nbsp;Lin Hu,&nbsp;Gaowei Hu,&nbsp;Maguang Xu,&nbsp;Mengtian Gao","doi":"10.1016/j.jnggs.2026.08.001","DOIUrl":"10.1016/j.jnggs.2026.08.001","url":null,"abstract":"<div><div>The Neogene Sanya Formation in the northern slope zone of the Yinggehai Basin has significant hydrocarbon exploration potential. However, its reservoirs are characterized by medium-to-low porosity and ultra-low permeability, and the mechanisms responsible for reservoir densification remain poorly understood, thereby restricting further deployment of oil and gas exploration. This study comprehensively utilizes core observation, core analysis, logging and well testing data, and basin simulation technology to investigate the fundamental characteristics of the reservoir, the mechanisms responsible for its densification, and the primary controlling factors of pore development. The results indicate that the Sanya Formation is dominated by submarine fan sandstone bodies, with lithic quartz sandstone as the predominant lithology. The reservoirs exhibit relatively low primary porosity, while secondary dissolution pores constitute the dominant pore type. However, incomplete dissolution results in poor pore connectivity. The ultra-low permeability of the reservoir is primarily controlled by intense late-stage compaction under conditions of a high geothermal gradient, together with pore-throat blockage by authigenic minerals. Among these minerals, fibrous and hair-like authigenic illite is identified as the key factor responsible for the sharp decline in reservoir permeability. Organic acids generated from the underlying Oligocene source rocks migrated upward through faults and fractures, promoting the dissolution of feldspar and lithic fragments in the Sanya Formation and thereby enhancing secondary pore formation. The formation of reservoir “sweet spots” is controlled by the coupling of sedimentation and diagenesis. In the near-source depositional system, low-permeability reservoirs are predominant, and the occurrence of reservoir “sweet spots” is mainly controlled by grain size. In contrast, the far-source depositional system is characterized by well-sorted sandstones with low clay-matrix content, abundant chlorite, and relatively high feldspar content. More extensive dissolution in these sandstones enables the preservation of high-permeability reservoirs even at a burial depth exceeding 3700 m, making them favorable targets for deep oil and gas exploration and development.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 4","pages":"Pages 237-251"},"PeriodicalIF":0.0,"publicationDate":"2026-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148980998","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":"Hydrocarbon exploration in the Ordos Basin, China: Experience implications, fundamental research, and future priorities","authors":"Yuting Hou,&nbsp;Xiao Hui,&nbsp;Daofeng Zhang","doi":"10.1016/j.jnggs.2026.08.003","DOIUrl":"10.1016/j.jnggs.2026.08.003","url":null,"abstract":"<div><div>The Ordos Basin, China's largest hydrocarbon production base, hosts abundant petroleum resources and is characterized by diverse exploration plays. This paper systematically reviews the history of hydrocarbon exploration in the basin, summarizes key insights, identifies existing fundamental research challenges, and proposes future exploration directions. This study synthesizes the evolutionary process of six major hydrocarbon fields and breakthrough advances in petroleum exploration, with particular emphasis on elucidating the theoretical frameworks, exploration methodologies, and practical outcomes in two key unconventional domains: shale oil and deep coalbed methane. The continuous breakthroughs in the basin's hydrocarbon exploration consistently reflected the core idea of liberating mind. The progressive exploration achievements demonstrate the “practice-cognition-repractice-recognition” cognitive approach, which yields significant implications for theoretical advancement, technological innovation, and management models. Overcomeing current exploration bottlenecks necessitates in-depth fundamental research on hydrocarbon source rock characterization, fault system architecture, and whole petroleum systems. Future strategic priorities should target four key domains: intra-source unconventional resources, large-scale reserve expansion of low-permeability reservoirs, efficient precision exploration in shallow formations, and frontier high-risk exploration for new plays and new strata. These efforts will support sustainable hydrocarbon production in the basin, and offer a reference template for analogous basins worldwide.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 4","pages":"Pages 253-264"},"PeriodicalIF":0.0,"publicationDate":"2026-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148980999","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":"Eutrophication mechanisms and hydrocarbon potential of Cenozoic excellent source rocks in offshore China: A critical review","authors":"Dujie Hou,&nbsp;Jiahao He,&nbsp;Qian Huang,&nbsp;Yingzhong Zhu,&nbsp;Rui Hu,&nbsp;Wei Si,&nbsp;Hai Liu,&nbsp;Xiong Cheng,&nbsp;Lin Wei","doi":"10.1016/j.jnggs.2026.07.001","DOIUrl":"10.1016/j.jnggs.2026.07.001","url":null,"abstract":"<div><div>Development of excellent source rocks in offshore China is closely associated with eutrophication, which provides an important foundation for the hydrocarbon generation. This review analyzes the origins of lacustrine and marine excellent source rocks in offshore China, focusing on six major eutrophication mechanisms: hydrothermal fertilization, volcanic fertilization, granite weathering coupled with fluvial transport, moderate salinization, closed to semi-closed bays, and upwelling currents. These mechanisms promote plankton blooms, particularly those of algae, by supplying abundant nutrients (e.g., P, Fe, Mn, Zn, N, and Si) to aquatic environments or by creating favorable environmental conditions (e.g., low-energy hydrodynamic settings, anoxic conditions, and moderate salinity), thereby providing the material basis for the development of organic-rich source rocks. Previous studies indicate that the widely developed lacustrine excellent source rocks in offshore China (e.g., the Shahejie Formation in the Bohai Bay Basin, the Wenchang Formation in the Pearl River Mouth Basin, and the Liushagang Formation in the Beibu Gulf Basin) developed in semi-deep to deep lacustrine environments formed during intense rifting, together with nutrient-rich hydrothermal activity, volcanic activity, and terrigenous inputs that facilitated the proliferation of dominant algal communities. In contrast, the formation of marine excellent source rocks (e.g., the Yacheng Formation in the Qiongdongnan Basin) is closely related to nutrient accumulation in closed to semi-closed bays and the upward transport of nutrients by upwelling currents. These environmental conditions promoted the flourishing of aquatic organisms and enhanced the quality of source rocks. This review highlights the influence of eutrophication in controlling hydrocarbon potential, providing a theoretical basis for understanding the development of excellent source rocks in offshore petroliferous basins and offering new insights into the formation of giant gas fields, biogenic gas, and natural gas hydrates.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 4","pages":"Pages 215-235"},"PeriodicalIF":0.0,"publicationDate":"2026-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148980997","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":"Grading evaluation of deep shale reservoirs based on Bayesian optimized LightGBM algorithm","authors":"Luchuan Zhang,&nbsp;Yibo Li,&nbsp;Lei Zhang,&nbsp;Li Zhang,&nbsp;Junwei Pu,&nbsp;Yong Li,&nbsp;Dianshi Xiao,&nbsp;Zhiyuan Li,&nbsp;Haichuan Ma","doi":"10.1016/j.jnggs.2026.06.002","DOIUrl":"10.1016/j.jnggs.2026.06.002","url":null,"abstract":"<div><div>Conventional approaches, including multivariate regression, empirical formulas, and petrophysical models, often fail to adequately capture the complex nonlinear relationships between logging curves and reservoir parameters, resulting in limited accuracy for grading prediction of shale reservoirs. This study focuses on deep shale reservoirs within the Wufeng Formation (O₃<em>w</em>) and the first submember of the first member of the Longmaxi Formation (S₁<em>l</em>¹₁) in the western Chongqing area. A shale reservoir classification model based on a Bayesian-optimized LightGBM algorithm was developed, and the SHAP algorithm was employed to quantitatively evaluate the contribution of individual logging curves. Subsequently, the proposed model was applied to the grading evaluation of deep shale reservoirs within the target area. The results demonstrate that, compared with the regression-based strategy, the classification-based strategy achieved significant improvements in model complexity, computational efficiency, and reservoir identification performance. A classification model of shale reservoir was established using the classification scheme, yielding weighted precision and weighted recall values of 89.7% and 89.6%, respectively, for the LightGBM algorithm. These values are superior to those obtained using the RF algorithm (87.52% and 86.96%, respectively) and the SVM (83.61% and 81.8%, respectively), on the testing dataset. DEN, GR, and CNL logs were identified as the most critical logging curves for identifying Type I and Type III shale reservoirs, whereas DEN, AC, and CNL logs exhibited heightened importance in identifying Type II reservoirs. Furthermore, the logging curves exerted complex nonlinear influence on the model decision-making process. The grading evaluation results show that Type I reservoirs are predominantly developed in the upper O₃<em>w</em> and the first sublayer of S₁<em>l</em>¹₁. Overall, the Bayesian-optimized LightGBM algorithm facilitates efficient and accurate identification of shale reservoir types, thereby offering a novel approach for shale reservoir classification and evaluation.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 3","pages":"Pages 183-197"},"PeriodicalIF":0.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148640617","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":"Corrigendum to “Reservoir characteristics and effect on methane adsorption capacity in marine–continental transitional shale: The Carboniferous Yanghugou Formation in the Weiningbeishan area (eastern North Qilian orogenic belt), China” [J Nat Gas Geosci 10 (2025) 399–413]","authors":"Donggang Wang,&nbsp;Yu Ma,&nbsp;Yanyun Ma,&nbsp;Wenzhong Wu,&nbsp;Kun Yu","doi":"10.1016/j.jnggs.2026.06.001","DOIUrl":"10.1016/j.jnggs.2026.06.001","url":null,"abstract":"","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 3","pages":"Page 213"},"PeriodicalIF":0.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148640608","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":"Discovery of Chahan strike-slip anticline and prediction of favorable gas plays in the northern Qaidam Basin, China","authors":"Guihong Wang,&nbsp;Yongshu Zhang","doi":"10.1016/j.jnggs.2026.06.004","DOIUrl":"10.1016/j.jnggs.2026.06.004","url":null,"abstract":"<div><div>For many years, the exploration of natural gas in the large structural belts of the northern Qaidam Basin has yielded unsatisfactory results, which may be related to the traditional interpretation of deep-seated paleo-anticlinal traps based on the dual-layer structural model. Through seismic data interpretation and structural analysis, it is concluded that the dominant structural style of this area is mainly of synsedimentary compressional strike-slip structures that developed in the late Himalayan period. Strongly deformed structures occur as a ruptured anticlines with faults extending to the surface, resulting in low-abundance traps of underfilled gas accumulations. In contrast, the gentle anticline of Chahan, which developed as a synsedimentary overlying anticline over uplifted fault blocks associated with deep compressional strike-slip movement, exhibits more favorable conditions for hydrocarbon accumulation. Because deformation related with strike-slip belt is primarily concentrated along fault zones, the intervening sags generally experience relatively weak deformation, which is conducive to the preservation of gas reservoirs and therefore represents favorable targets for gas exploration as long as there is a gas source rocks. The Pingdong Sag, located between the Altun, Jianshan, and Eboliang structural belts, experienced gentle deformation during the Cenozoic and exhibits relatively complete distribution of three Mesozoic–Cenozoic tectonic layers, containing all geologic elements of a gas system. The deep-buried Jurassic source rocks within the sag are characterized by larger thickness and stable distribution and are currently in the stage of gas generation, suggesting that major gas accumulation occurred during the late Himalayan period. The fault-block structures developed in the lower Cenozoic tectonic layer provided effective migration and accumulation system. The lower Youshashan Formation (N₂¹) delta front sandstone bodies and overlying mudstone intervals form favorable reservoir-caprock assemblages, while the lacustrine mudstones and evaporites in the upper tectonic layers (N₂², N₂³, Q) offer an effective regional sealing conditions for gas preservation. The analysis suggests that the Chahan anticline, located above the source-rock and developed contemporaneously with major gas-generation phase, has the potential to host a large gas field. Furthermore, subtle traps beneath the regional sealing strata, including low-amplitude anticlines, fault-block traps, lithological traps on tectonic setting, and fault–sandstone combination traps within the sub-sags of the Pingdong Sag, constitute favorable exploration targets for natural gas. This study also has reference significance for natural gas exploration in regions characterized by tectonic settings similar to those of the Qaidam Basin.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 3","pages":"Pages 159-172"},"PeriodicalIF":0.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148640616","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":"High-temperature and high-pressure experimental investigation of interlayer-controlled water invasion in carbonate bottom-water gas reservoirs","authors":"Yisheng Hu,&nbsp;Mingdi Zhang,&nbsp;Chenhui Shi,&nbsp;Langtao Zhu,&nbsp;Zhouhua Wang,&nbsp;Ping Guo,&nbsp;Jian Zheng","doi":"10.1016/j.jnggs.2026.06.005","DOIUrl":"10.1016/j.jnggs.2026.06.005","url":null,"abstract":"<div><div>Carbonate bottom-water gas reservoirs commonly exhibit complex gas-water distributions, and the limited understanding of the factors controlling water invasion has hindered their efficient development. In this study, full-diameter physical models representing different gas-water distribution patterns were constructed using field cores, and a high-temperature, high-pressure physical simulation method was developed to investigate interlayer-controlled water-invasion behavior. Two representative configurations—the barrier-bed-reservoir type and the reservoir-interlayer-reservoir type—were examined. The effects of aquifer-to-reservoir volume ratio, pressure-depletion rate, barrier-bed sealing area, interlayer thickness, and interlayer permeability on water invasion were systematically evaluated. The results show that barrier beds and interlayers act as flow barriers that retard bottom-water encroachment, delay water breakthrough, prolong the water-free gas-production stage, and help maintain gas deliverability and recovery after breakthrough. Increasing interlayer thickness or decreasing interlayer permeability prolongs the gas-expansion-dominated depletion stage and improves gas recovery, whereas a larger barrier-bed sealing area suppresses bottom-water encroachment and preserves gas-flow capacity. A smaller aquifer-to-reservoir volume ratio slows bottom-water advance, extends the water-free production period, and mitigates water-induced gas-flow impairment, thereby supporting sustained gas productivity. In addition, reducing the pressure-depletion rate delays water invasion and alleviates the decline in gas production per unit pressure decline (GPPD), which improves gas recovery during the gas-water co-production stage and increases the ultimate recovery factor. The proposed method and findings provide experimental support for performance prediction and production-strategy optimization in carbonate bottom-water gas reservoirs influenced by barrier beds and interlayers.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 3","pages":"Pages 199-211"},"PeriodicalIF":0.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148640609","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":"The new evaluation method of gas well productivity in ultra-deep fractured tight sandstone gas reservoirs: Case study of the ultra-deep fractured gas reservoir in the Kuqa Depression, Tarim Basin, China","authors":"Songbai Zhu,&nbsp;Zhikai Lü,&nbsp;Ji Zhao,&nbsp;Haifa Tang,&nbsp;Chen Dong,&nbsp;Baohua Chang,&nbsp;Qiuhai Fan,&nbsp;Hanlin Wang","doi":"10.1016/j.jnggs.2026.06.003","DOIUrl":"10.1016/j.jnggs.2026.06.003","url":null,"abstract":"<div><div>Ultra-deep fractured gas reservoirs in the Kuqa Depression, Tarim Basin, are generally characterized by deep burial, high formation pressure, tight matrix permeability, and multi-scale fracture systems development. Consequently, gas well production capacity varies significantly among blocks and individual wells. In particular, the daily gas production of some wells exceeds 10 × 10⁶ m³ every day, which is 3–5 times higher than that of adjacent wells. Existing studies provide limited research on productivity calculation models for ultra-deep fractured gas reservoirs, creating an urgent need to systematically investigate the factors affecting gas well productivity and to establish effective production capacity evaluation methods. Based on an analysis of the correlations among factors including geology, drilling and completion, a productivity prediction model incorporating non-Darcy flow, stress sensitivity, and material balance effect was established. The results show that: (1) The factors affecting the productivity of gas wells include tight reservoir matrix, geological characteristics of fracture development, drilling-induced pollution, completion-induced pollution, well type, the matching degree of perforation and fractures, production well clearance under large pressure differentials, and wellbore pressure loss. (2) Fracture characterization parameters were constructed through regression analysis critical to gas well productivity parameters, including fracture dispersion coefficient, fracture linear density, and flowback rate, etc. (3) The contribution ratio of the fracture system to the matrix system exhibits a logarithmic relationship with reservoir permeability range. (4) A complete production capacity evaluation process was formed, and the error between the productivity calculated by the proposed model and the test result for Well A-1 is less than 2%.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 3","pages":"Pages 173-181"},"PeriodicalIF":0.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148640610","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":"Improvement of SRV evaluation simulation algorithm using Displacement Discontinuity Method considering fracturing of adjacent wells","authors":"Guangsheng Cao,&nbsp;Ying Liu,&nbsp;Qingchao Cheng,&nbsp;Yujie Bai,&nbsp;Ning Zhang,&nbsp;Mingyu Qi,&nbsp;Jianhua Li","doi":"10.1016/j.jnggs.2026.05.003","DOIUrl":"10.1016/j.jnggs.2026.05.003","url":null,"abstract":"<div><div>China holds vast tight-oil resources; however, their poor reservoir quality requires hydraulic fracturing, typically combined with horizontal wells, for efficient development. Nevertheless, multi-stage fracturing is strongly influenced by in-situ stress conditions, fracture interactions, and operational parameters, resulting in unpredictable fracture geometries and suboptimal stimulation designs. Conventional models either lack sufficient accuracy or are computationally expensive for field-scale optimization. To address these limitations, this study develops an improved Displacement Discontinuity Method (DDM)—based multifracture propagation model that couples fluid flow with rock deformation. The model enables real-time updating of reservoir properties under fracturing-induced stress changes and incorporates the effects of adjacent-well fracturing through dynamic data synchronization between local fracture solutions and a global block model. On this basis, an SRV quantification workflow is established for the rapid and accurate estimation of porosity and permeability evolution. The model was applied to Wells T28 and T104 in block P8 of the Daqing Oilfield. The results show that the model achieves fracture-geometry fitting accuracies of 91% and 93%, respectively, outperforming finite-element simulations (88% and 85%). In addition, the model yields production-history matching accuracies of 93% and 95%, demonstrating its reliability and practical value for optimizing tight-oil recovery.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 3","pages":"Pages 147-158"},"PeriodicalIF":0.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148640667","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}