Natural Gas Industry B最新文献

{"title":"Machine learning identification of diagenetic facies in tight sandstones based on sandbody classification: The Fourth Member of the Triassic Xujiahe Formation, Jianyang area, Sichuan Basin","authors":"Laixing Cai,&nbsp;Yuhang Li,&nbsp;Yang Hu,&nbsp;Weijian Shi,&nbsp;Yinglin Liu,&nbsp;Tian Yang,&nbsp;Guowei Zhao","doi":"10.1016/j.ngib.2026.06.002","DOIUrl":"10.1016/j.ngib.2026.06.002","url":null,"abstract":"<div><div>Within tight sandstones, diagenetic features exhibit strong heterogeneity and intra-subfacies similarities, meaning that different rock units often share comparable mineral compositions and pore structures. These similarities result in overlapping petrophysical signatures that obscure distinct logging responses, thereby significantly reducing the reliability of conventional well-logging interpretations for predicting diagenetic facies and favorable reservoirs. To address the limitations of manual interpretation under the conditions of limited data, this study developed an integrated framework that combines sandbody classification, diagenetic events, and machine learning. The main conclusions are as follows: (1) Sedimentological analyses of field outcrops and cores reveal that the tight sandstones in the braided delta-front subfacies of the Fourth Member of the Triassic Xujiahe Formation can be divided into four sandbody types: main subaqueous channels (MSC), branch subaqueous channels (BSC), terminal subaqueous channels (TSC), and distal bars and sheet sands (DB&amp;SS). (2) Based on the quantitative characterization of diagenetic intensity, four representative diagenetic facies were identified: moderate compaction and moderate dissolution (Type I), strong compaction and weak dissolution (Type II), moderate compaction and moderate cementation (Type III), and strong compaction (Type IV). (3)Using the sedimentology-diagenesis coupling framework, a one-dimensional convolutional neural network algorithm achieved a prediction accuracy of an 81.17% for diagenetic facies through multi-parameter integration (e.g., CAL × GR, AC × DEN) and a class consolidation strategy that combines Types III and IV. (4) The internal architecture of sandbodies plays a key role in controlling the distribution of diagenetic facies and reservoir quality by regulating acidic fluid activity and cement precipitation. Favorable reservoirs (Types I and II) mainly occur in the middle-to-lower intervals of the MSC and BSC. This distribution is associated with coarse-grained, quartz-rich sandstones that promote the migration of acidic fluids and the dissolution of feldspar and rock fragments. In contrast, late-stage precipitation of authigenic carbonate and quartz results in ineffective reservoirs (Types III and IV) along the margins of the sandbodies.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 3","pages":"Pages 257-279"},"PeriodicalIF":5.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148531549","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A two-layer model–based coupled simulation study of multi-cluster hydraulic fracture propagation and proppant transport in shale","authors":"Fanhui Zeng,&nbsp;Xiaosong Bai,&nbsp;Jianchun Guo,&nbsp;Dagan Hu,&nbsp;Zhangxing Chen","doi":"10.1016/j.ngib.2026.06.008","DOIUrl":"10.1016/j.ngib.2026.06.008","url":null,"abstract":"<div><div>Effective proppant placement in multi-cluster hydraulic fractures is crucial for shale gas fracturing; however, existing numerical methods face challenges in accurately coupling dynamic fracture propagation with suspended-load transport, bed erosion, and accumulation at the field scale. To address this, a coupled solution integrating the DDM with an improved TLM was developed. This solution incorporates a logarithmic near-bed velocity profile to refine bed shear stress calculations, thereby capturing dynamic flow allocation, fracture-tip extension, and proppant bed evolution within a unified framework. The key findings are: (1) Increasing spacing from 6 m to 25 m minimizes stress interference, reducing flow allocation disparities among clusters by 96%, thereby promoting more uniform fracture propagation and bed-load transport; (2) Higher rates elevate net pressure and reduce pressure drop differences across perforations but increase shear within fractures, exacerbating proppant placement disparities; (3) As viscosity increases from 3 mPa·s to 5 mPa·s, bed-load transport differences intensify, causing a sevenfold rise in placement discrepancies; at 10 mPa·s most proppants remain suspended, transitioning to a suspended-load transport regime and nearly eliminating inter-cluster distribution differences; (4) Larger proppants tend to accumulate near fracture inlets, which can help ensure more uniform inter-cluster distribution. In contrast, smaller proppants are more susceptible to flow variations, often resulting in uneven placement across clusters. (5) Additionally, under high proppant concentrations, proppant dunes reach equilibrium sooner, and creeping motion dominates particle transport, significantly reducing inter-cluster placement non-uniformity. The proposed coupled DDM–TLM model can reasonably predict proppant behavior in multi-cluster fractures and underpins the optimization of shale gas fracturing treatments.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 3","pages":"Pages 348-368"},"PeriodicalIF":5.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148546364","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Simultaneous pre-stack prediction of lithology, geofluids, and physical properties in deep tight sandstone reservoirs based on recharacterization of reflection coefficient approximation equation and Bayesian inversion strategy","authors":"Wenqiang Yang,&nbsp;Lijun Song,&nbsp;Yue Zhang,&nbsp;Si Wu","doi":"10.1016/j.ngib.2026.06.004","DOIUrl":"10.1016/j.ngib.2026.06.004","url":null,"abstract":"<div><div>Pre-stack seismic inversion is an important tool for the quantitative interpretation of complex reservoirs. However, the increasing demands of deep tight sandstone exploration require a more integrated characterization of lithology, physical properties, and geofluid. Current inversion methodologies often treat these reservoir parameters separately, leading to fragmented understanding and redundant workflows. This study proposes a novel pre-stack seismic inversion method that simultaneously estimates lithology and physical properties of deep tight sandstone reservoirs. Its core innovation lies in establishing a direct, rock-physics-based link between seismic response and multiple reservoir attributes. The specific process involves: (1) Conducting a comprehensive rock-physics analysis to identify parameters sensitive to lithology, permeability, and geofluid types; (2) Deriving a novel reflection coefficient approximation through parameter combinations and mathematical simplification, followed by accuracy verification and feasibility assessment for seismic inversion; and (3) Implementing a model-constrained iterative reweighting Bayesian inversion scheme to reliably estimate model parameters. The effectiveness and reliability of the method have been validated through model tests and field data applications. This approach enables the identification of favorable zones within tight sandstone reservoirs, offering a feasible and efficient solution for their integrated seismic interpretation.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 3","pages":"Pages 280-299"},"PeriodicalIF":5.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148531543","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Review of the analysis and methods of natural gas pipeline network operation optimization","authors":"Deming Zhao,&nbsp;Wuchang Wang,&nbsp;Yuxing Li","doi":"10.1016/j.ngib.2026.06.001","DOIUrl":"10.1016/j.ngib.2026.06.001","url":null,"abstract":"<div><div>The expansion of natural gas consumption and pipeline construction makes integrating artificial intelligence into pipeline network operations increasingly essential. This review summarizes progress in operation optimization, gas transmission capacity evaluation, and solution algorithms. The review systematically summarizes objective functions, hydraulic/thermal and compressor constraints, and decision variables, all framed by operator objectives such as transmission capacity, economic benefits, and supply reliability. It highlights gas transmission capacity optimization and extended models, including those for hydrogen-blended and renewable energy-coupled scenarios. The review also analyzes applications of deterministic and stochastic intelligent algorithms, alongside deep learning and hyper-heuristic methods. Key findings indicate that: (1) Traditional models often lack safety, reliability, and low-carbon indicators; (2) Deterministic algorithms struggle with high dimensionality, while heuristic algorithms are prone to premature convergence; (3) Hydrogen blending and new energy integration necessitate revised constraints; and (4) Existing online dynamic optimization methods are insufficient. Finally, current shortcomings are identified, and future directions, such as advanced online dynamic optimization and cross-domain intelligence, are proposed. In conclusion, while artificial intelligence is crucial for natural gas pipeline network operations, significant limitations persist. Future research must prioritize addressing these gaps to advance the industry's intelligent, low-carbon, and reliable development.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 3","pages":"Pages 403-424"},"PeriodicalIF":5.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148531542","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Influence of CO2 or flue gas (СО2+N2) injection on the change in gas permeability of a subpermafrost hydrate-saturated reservoir: Results of experimental modeling","authors":"Evgeny Chuvilin,&nbsp;Maksim Zhmaev,&nbsp;Sergey Grebenkin,&nbsp;Kirill Maerle,&nbsp;Yongwon Seo","doi":"10.1016/j.ngib.2026.06.003","DOIUrl":"10.1016/j.ngib.2026.06.003","url":null,"abstract":"<div><div>Large volumes of natural gas stored in hydrate form within marine and subpermafrost environments represent a significant resource for potential extraction and use. Various methods for developing hydrate deposits are currently under investigation. A promising strategy for efficient methane production involves the injection of carbon dioxide (CO₂) or flue gas mixtures (CO₂+N₂). The introduction of these gases into hydrate-bearing sediments induces methane hydrate dissociation, followed by its partial replacement by CO₂ hydrate without compromising wellbore integrity. In addition, the CO₂-based approach facilitates carbon sequestration within hydrate structures, thereby reducing greenhouse gas emissions. For effective implementation, a detailed understanding of gas permeability behavior in response to CO₂ or flue gas injection into hydrate-bearing formations is essential. This response was experimentally investigated by injecting CO₂ and flue gas into sand-clay samples under pressure and temperature conditions representative of subpermafrost gas hydrate reservoirs. The experiments demonstrate that gas permeability decreases markedly during CO₂/CH₄ replacement in the model reservoir, due to the additional formation of CO₂ hydrate from residual pore water. This reduction may reach several tens of percent, particularly in reservoirs with high residual water content. Consequently, sediments with higher total saturation and lower hydration coefficients exhibit substantially reduced gas permeability following CO₂ or flue gas injection. Overall, the findings indicate that the extent of permeability reduction during CO₂ or flue gas injection is strongly governed by the initial reservoir properties and secondary hydrate formation processes. This understanding enables improved prediction and optimization of the CO₂/CH₄ replacement process for the efficient and safe exploitation of gas hydrate resources.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 3","pages":"Pages 425-436"},"PeriodicalIF":5.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148531544","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Thermo-hydro-mechanical coupled simulation of fracture propagation under cyclic loading in hot dry rock","authors":"Jia Liu,&nbsp;Yunjin Wang,&nbsp;Jiacheng Yin,&nbsp;Siyu Zhang,&nbsp;Mengyu Li,&nbsp;Qi Wu,&nbsp;Jiawei Li,&nbsp;Lei Wang,&nbsp;Fujian Zhou","doi":"10.1016/j.ngib.2026.06.007","DOIUrl":"10.1016/j.ngib.2026.06.007","url":null,"abstract":"<div><div>Cyclic-loading hydraulic fracturing generates alternating stresses and complex fracture networks in hot dry rock (HDR), but the predictive accuracy of existing models is limited by insufficient consideration of rock property degradation under cyclic loading. This study introduces an equivalent damage evolution equation to characterize the degradation of elastic modulus, permeability, specific heat capacity, and thermal conductivity, and establishes a thermal-hydro-mechanical (THM) coupled model for cyclic-loading hydraulic fracturing in HDR to simulate fracture initiation and propagation. The results show that under the cyclic hydraulic fracturing conditions examined, (1) When the natural fracture density reaches 0.006 fractures/m², the total fracture length and damaged area increase by 6.63% and 9.44%, respectively. (2) Moderately reducing fracturing fluid viscosity effectively activates natural fractures. For example, a decrease in viscosity from 15 mPa·s to 5 mPa·s results in a 12.70% increase in fracture length and a 9.91% increase in damaged area. (3) A cycle period of 20–40 min/cycle is favorable for fracture network expansion, increasing the damaged area by 9.01%–19.59% and extending the fracture length by up to 21.65%. (4) Increasing the circulation flow rate from 10 m³/min to 16 m³/min accelerates wellbore pressurization, resulting in a 9.31% increase in fracture propagation distance and a 14.05% increase in damaged area. The proposed model effectively characterizes rock property degradation induced by cyclic loading and fracture evolution in HDR, providing theoretical support for optimizing cyclic hydraulic fracturing parameters and enhancing complex fracture network development.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 3","pages":"Pages 388-402"},"PeriodicalIF":5.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148531541","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Diagenetic differences controlled by sediment composition and their implications for reservoir quality in the deep-buried Permian Urho Formation, Fukang Sag, Junggar basin","authors":"Zhicheng Cui,&nbsp;Kelai Xi,&nbsp;Xiang Shan,&nbsp;Tian Yang,&nbsp;Ke Li,&nbsp;Weikai Huang,&nbsp;Bo Peng,&nbsp;Huajun Guo","doi":"10.1016/j.ngib.2026.06.006","DOIUrl":"10.1016/j.ngib.2026.06.006","url":null,"abstract":"<div><div>Deeply buried coarse clastic reservoirs of the Permian Upper Urho Formation in the Fukang Sag, Junggar Basin, exhibit pronounced reservoir-quality heterogeneity in pore systems and lithofacies architecture. However, how provenance-controlled sediment composition regulates mineral transformation and divergent diagenetic pathways, thereby controlling reservoir quality, remains unclear. This study integrates petrographic observations, XRD, SEM, MIP, EPMA, and bulk- and micro-XRF analyses to clarify the diagenetic evolution and the factors controlling reservoir quality in these deposits. The results indicate distinct provenance-controlled diagenetic pathways in two reservoir domains: (1) Reservoirs affected by the Xiquan Uplift Provenance, which contain intermediate-mafic volcanic materials, underwent stronger chemical weathering, enhanced mechanical compaction, and widespread illite-smectite mixed-layer mineral (I/S) cementation, leading to pore systems mainly composed of intercrystalline pores within clay minerals; (2) Reservoirs sourced from the Eastern Provenance, characterized by intermediate-acidic volcanic inputs, exhibit higher textural maturity and better fluid mobility, which favored the formation of early diagenetic authigenic chlorite coatings, the preservation of residual intergranular pores, and the dissolution of laumontite and feldspar; and (3) The alteration of the tuffaceous matrix differed according to diagenetic fluid chemistry. Micro-XRF elemental maps, EPMA oxide compositions, and mineral assemblage trends indicate that K-rich conditions promoted I/S enrichment, whereas Na-rich conditions favored laumontite formation followed by selective dissolution. These contrasting diagenetic pathways exert a first-order control on reservoir-quality heterogeneity. High-quality reservoirs are mainly developed in low-matrix, grain-supported thick sand bodies and sandstone interbeds within conglomerate successions, indicating that facies type, matrix content, and framework support are key screening criteria for reservoir prediction in deeply buried coarse clastic systems.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 3","pages":"Pages 300-322"},"PeriodicalIF":5.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148531517","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Digital twin-driven nonplanar fracture reconstruction and evaluation in tight reservoirs","authors":"Ji Lu,&nbsp;Botao Lin,&nbsp;Jinyang Xie,&nbsp;Yan Jin,&nbsp;Han Meng","doi":"10.1016/j.ngib.2026.05.001","DOIUrl":"10.1016/j.ngib.2026.05.001","url":null,"abstract":"<div><div>In tight oil reservoir development, hydraulic fracture morphology critically controls post-fracturing flow behavior. However, conventional microseismic monitoring remains limited in real-time characterization of nonplanar fracture geometry. This study proposes a digital twin-driven approach for nonplanar fracture reconstruction and evaluation, enabling real-time fracture characterization in tight reservoirs. The results show that: (1) the reconstructed fracture morphology achieved a normalized relative geometric error of only 3.33% when experimentally validated against high-resolution laser scanning in a true triaxial hydraulic fracturing test, and demonstrated a computational speedup exceeding 700 times compared to the discrete element method under identical experimental conditions and specimen geometry; (2) the reconstructed fracture networks capture nonplanar propagation and fracture–natural fracture interactions, indicating that fracture complexity is jointly controlled by tortuosity and connectivity when the horizontal stress difference is below 5 MPa, but dominated by connectivity when it exceeds 5 MPa; (3) real-time fracture reconstruction enables the identification of potential inter-stage fracture communication, allowing engineers to adjust injection volume and stage spacing to mitigate interference and improve stimulation efficiency. These results demonstrate the proposed digital twin functions both as a monitoring tool and an integrated platform for real-time fracture reconstruction, evaluation, and operational optimization in tight reservoirs.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 3","pages":"Pages 323-347"},"PeriodicalIF":5.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148546365","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effect of increased propensity for non-aqueous carbon dioxide formation on wormholing in carbonate acidizing: An acid flooding study","authors":"Mohammad Khojastehmehr,&nbsp;Mohammad Bazargan,&nbsp;Mohsen Masihi","doi":"10.1016/j.ngib.2026.06.005","DOIUrl":"10.1016/j.ngib.2026.06.005","url":null,"abstract":"<div><div>Acid–rock reactions in carbonate reservoirs generate CO₂, whose phase behavior significantly influences wormhole propagation and, consequently, matrix acidizing efficiency. In this study, backpressure-controlled core flooding experiments were conducted on &gt;99% calcite plugs using 1 wt% HCl at ambient temperature. Injection rate (1–8 mL/min) and backpressure (0.1–8.2 MPa) were systematically varied, and wormhole development was quantified through pore volume to breakthrough (PVBT), CT imaging, and a Wormhole Propagation Index (WPI). The results show that (1) Despite non-monotonic behavior observed in individual cores, likely attributable to rock heterogeneity, averaged trends consistently demonstrated enhanced wormhole efficiency with reduced backpressure. (2) Reduced backpressure generally promoted wormhole propagation, resulting in thicker, less-branched channels and a reduced pore volume to breakthrough. (3) The most significant reduction in PVBT (∼15%) was observed at 8 mL/min when backpressure decreased from 8.2 MPa to 2.7 MPa. The operational significance of this reduction, however, is contingent upon specific economic and operational constraints. (4) Optimum injection rates of approximately 4.4–5.6 mL/min were identified, reflecting a balance between reaction kinetics and transport as characterized by the Damköhler number. (5) Mechanistically, non-aqueous CO₂ generated at low backpressure may redistribute flow, shield reactive surfaces, and enhance local mass transfer, thereby promoting the formation of thicker and more efficient wormholes. These results suggest that strategies favoring non-aqueous CO₂ formation (e.g., solubility-reducing additives, foam-acid systems, or chemical/thermal adjustments) could enhance wormholing efficiency in carbonate acidizing. However, extrapolation of these findings beyond the specific rocks and fluids tested necessitates further investigation.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 3","pages":"Pages 369-387"},"PeriodicalIF":5.0,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148531550","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental and numerical simulation of gas injection for enhanced oil recovery in naturally fractured condensate gas reservoirs","authors":"Bin Ju ,&nbsp;Ping Guo ,&nbsp;Yizhong Zhang ,&nbsp;Long Yang ,&nbsp;Zhouhua Wang ,&nbsp;Maolin Zhang","doi":"10.1016/j.ngib.2026.03.005","DOIUrl":"10.1016/j.ngib.2026.03.005","url":null,"abstract":"<div><div>Gas condensate reservoirs constitute important natural gas resources; however, their development is frequently hindered by condensate banking and complex multiphase flow behavior. Naturally fractured gas condensate reservoirs present additional challenges because their dual-porosity and dual-permeability structure induces strong phase redistribution and nonuniform flow between matrix and fracture systems, thereby complicating reservoir characterization and compositional simulation. In this study, integrated laboratory experiments and numerical simulations were performed for a deep, rich, naturally fractured gas condensate reservoir. Depletion, diffusion, and core flooding experiments involving CO₂, N_2, and dry gas injection were conducted using fractured core samples. A dual-porosity and dual-permeability compositional model incorporating a five-spot well pattern was established to evaluate condensate liquid recovery and to quantify mass transfer between matrix and fracture networks. The effect of matrix-fracture permeability contrast on production performance was systematically analyzed. The results indicate that matrix permeability is a primary parameter controlling recovery in gas condensate reservoirs. The ratio of matrix-fracture permeability contrasts exerts a stronger influence on condensate liquid recovery than on natural gas recovery. Pressure maintenance through gas injection is critical for improving recovery performance. When reservoir pressure declines below the dew-point pressure, early gas injection is recommended to mitigate condensate accumulation in the near-well region. Among the injected gases evaluated, CO₂ demonstrated superior pressure maintenance performance compared with N₂ and dry gas.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"13 2","pages":"Pages 164-191"},"PeriodicalIF":6.5,"publicationDate":"2026-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147828172","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}