Petroleum Science最新文献

{"title":"Near-wellbore 3D velocity imaging inversion method based on array acoustic logging data","authors":"Zi Wang ,&nbsp;Wen-Zheng Yue ,&nbsp;Yu-Ming Zhu ,&nbsp;Nai-Xuan Ji ,&nbsp;Shan-Shan Fan","doi":"10.1016/j.petsci.2025.06.023","DOIUrl":"10.1016/j.petsci.2025.06.023","url":null,"abstract":"<div><div>The characterization of subsurface formations via the analysis of near-wellbore velocity profiles represents a crucial method in geophysical exploration. This technique enables the evaluation of key parameters, including rock brittleness, wellbore stability, fracturing effects, and invasion extent, thereby enhancing comprehension of formation structures and informing exploration strategies. However, traditional near-wellbore formation velocity imaging methods exhibit two principal limitations. First, these methods lack azimuthal sensitivity, yielding results averaged across all directions. Second, they are computationally intensive and impractical for well-site environments. To address these drawbacks, we developed a rapid 3D velocity imaging method for array acoustic logging instruments equipped with azimuthal receivers, capable of producing 3D imaging results efficiently. The workflow entails the following steps: (1) Band-pass filtering of logging data to mitigate scattered wave interference caused by formation heterogeneity near the wellbore; (2) combination of receivers with varying detection ranges in each direction to derive radial velocity sequences, followed by integration of ray-tracing theory to obtain 2D velocity distributions; and (3) synthesis of final 3D velocity imaging results via interpolation of these 2D datasets. In the velocity sequence extraction process, we significantly reduced the computational load by employing an adaptive time window, ensuring rapid and stable application in well-site settings. We utilized the finite difference method to construct well models with heterogeneous formations. The compressional and shear wave 3D velocity imaging results derived from synthetic data correlated with the model, demonstrating the azimuthal sensitivity of our proposed method. Furthermore, we applied this method to a well in West China, successfully identifying the azimuth of near-wellbore anisotropy.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 11","pages":"Pages 4504-4519"},"PeriodicalIF":6.1,"publicationDate":"2025-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145698107","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Petroleum recovery from salt cavern through natural gas displacement: Insights from a gas–oil two-phase flow model with gas dissolution and exsolution","authors":"You-Qiang Liao ,&nbsp;Tong-Tao Wang ,&nbsp;Tao He ,&nbsp;Dong-Zhou Xie ,&nbsp;Kai Xie ,&nbsp;Chun-He Yang","doi":"10.1016/j.petsci.2025.06.005","DOIUrl":"10.1016/j.petsci.2025.06.005","url":null,"abstract":"<div><div>The challenge of wide brine source and its additional problems come from the economy (energy consumption and other costs), security (re-dissolution of surrounding salt rocks), and environment (groundwater pollution by brine) of salt cavern oil storage are worth examining to improve the efficiency of oil storage. Against this background, this work presented an operating mode of salt cavern oil and gas co-storage and using natural gas displacement for petroleum recovery. A gas–oil two-phase flow model with gas dissolution and exsolution was proposed to evaluate the application prospects of the new method precisely. Numerical studies indicated that the gas void fraction at the wellhead under quasi-steady state conditions is approximately 0.153, which belongs to bubbly flow, and the pressure at the wellhead of the central tube increased from 5.54 to 6.12 MPa during the entire transient flow stage, with an increase of 10.47%. Compared to the traditional method of using brine as the working fluid, the pump pressure rises from 2.92 to 14.01 MPa. However, if the new mode can be linked with the salt cavern gas storage and when the initial wellhead gas pressure exceeds 13 MPa, the energy consumption of the new method will be lower than that of the traditional brine-based operational mode. A new empirical formula is proposed to determine the two-phase flow pattern under different operating parameters. A special focus was given to energy consumption for oil recovery, which grows roughly in accordance with the operating pressure and oil recovery rate. However, the energy cost per volume of crude oil remains almost unchanged. This work provided a new solution for the serious brine problem and is expected to achieve petroleum recovery through natural gas displacement.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 4226-4239"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384369","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Can clay-rich reservoirs in predominantly-freshwater lacustrine shale systems serve as primary exploration targets in low-medium maturity? A case study of the Triassic Yanchang Formation of the Ordos Basin","authors":"Enze Wang ,&nbsp;Maowen Li ,&nbsp;Xiaoxiao Ma ,&nbsp;Menhui Qian ,&nbsp;Tingting Cao ,&nbsp;Zhiming Li ,&nbsp;Sen Li ,&nbsp;Zhijun Jin","doi":"10.1016/j.petsci.2025.06.020","DOIUrl":"10.1016/j.petsci.2025.06.020","url":null,"abstract":"<div><div>Whether clay-rich shale reservoirs with low-medium maturity can serve as primary exploration targets remains a focal point of debate in the academic community. Clarifying the exploration potential of clay-rich shale reservoirs is crucial for the future exploration and development of lacustrine shale. The Triassic Yanchang Formation in the Ordos Basin has been one of most productive lacustrine shale oil systems in China, with substantial oil production capacity already established. While the primary productive layers are currently fine-grained siltstone interbeds, however, it remains a highly debated issue whether the volumetrically more significant clay-rich reservoirs can become viable exploration targets in the near future. To address this issue, we examined the exploration potential of different lithofacies assemblages in Member 7 (Mbr 7) of the Triassic Yanchang Formation, using a borehole in the Tongchuan area of the southern Ordos Basin as an example. We identified favorable exploration targets and assessed whether clay-rich reservoirs formed predominantly-freshwater conditions can become viable exploration targets. The results indicate the presence of six lithofacies in clay-rich reservoirs of Mbr 7 of the Yanchang Formation, with two main lithofacies assemblages: laminated organic-rich shale and massive mudstone. From the perspective of sandstone distribution, the sandstone interlayers within laminated organic-rich shale are primarily formed by gravity (hyperpycnal) flows, while sandstones deposited in delta front environments are typically associated with massive mudstone. Laminated organic-rich shale deposition occurred in an anoxic, deep-water environment characterized by high primary productivity, whereas massive mudstone formed in environments with high sedimentation rates and substantial terrigenous debris influx. Currently, the exploration potential of sandstone interlayers exceeds that of clay-rich reservoirs, with the greatest potential observed in the sandstone interlayers associated with laminated organic-rich shale formed by gravity (hyperpycnal) flows. Comparative analysis reveals that clay-rich reservoirs with low to medium maturity present great challenges for exploitation, making interlayer-type reservoirs the main focus of exploration at this stage. Nevertheless, clay-rich reservoirs in closed systems with high thermal maturity and organic matter content also hold considerable potential.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 3925-3938"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384471","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Real-time NMR investigation of water infiltration mechanisms and pore structure evolution in fractured sandstone near-wellbore regions","authors":"Sheng-Feng Wu,&nbsp;Yong-Fa Zhang,&nbsp;Yu Zhao,&nbsp;Chao-Lin Wang,&nbsp;Jing Bi,&nbsp;An-Fa Long,&nbsp;Yan Li","doi":"10.1016/j.petsci.2025.06.018","DOIUrl":"10.1016/j.petsci.2025.06.018","url":null,"abstract":"<div><div>During the exploitation of sandstone gas reservoirs, natural fractures near the wellbore affect water infiltration and pore evolution; however, the impact mechanisms of these fractures remain unclear. This study utilized real-time nuclear magnetic resonance (RT-NMR) technology to investigate the influence of near-wellbore fracture angle (<em>α</em>) at 0°, 15°, 30°, and 45° on water infiltration, migration patterns, and pore evolution mechanisms during water injection. Throughout the experiments, <em>T</em>₂ curves and magnetic resonance imaging (MRI) were monitored in real time during the water injection process. The pore evolution and water infiltration were translated by the evolution of <em>T</em>₂ curves and MRI. The results show that increasing injection pressure (<em>P</em>_inj) transforms adsorption pores into seepage pores, leading to enhanced pore damage. Pore damage predominantly occurs during the rapid pressurization stage and is concentrated around the near-wellbore fracture. The maximum infiltration area and rate were observed at <em>α</em> = 0°, while the minimum values occurred at <em>α</em> = 45°, which can be attributed to the significant influence of <em>α</em> on water infiltration and migration pathways. The increasing inclination of the infiltration front with <em>α</em> is attributed to the fact that the rate of water infiltration along the fracture wall is always higher than that at the fracture tip. In field fracturing, it is recommended to adjust the perforation direction to align with the natural fracture orientation and optimize pressurization strategies by reducing the slow pressurization duration while extending the rapid pressurization stage. These findings can provide important guidance for setting fracturing sections and optimizing injection parameters in sandstone gas reservoir exploitation.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 4195-4210"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384366","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Synthesis kinetics of B-COPNA resin monitored by the transformation of functional groups using in-situ FTIR spectroscopy","authors":"Yuan-Qin Zhang ,&nbsp;Ling-Rui Cui ,&nbsp;Hong-Yan Shen ,&nbsp;Jun-Ping Shen ,&nbsp;Hong-Fang Ma ,&nbsp;Jun Xu ,&nbsp;Fa-Hai Cao","doi":"10.1016/j.petsci.2025.06.003","DOIUrl":"10.1016/j.petsci.2025.06.003","url":null,"abstract":"<div><div>B-COPNA resin, synthesized from the light fraction of ethylene tar (ETLF), is a superior precursor of the carbon materials. An in-depth understanding of the COPNA resin preparation process and strict control of crosslinking degree are crucial for controlling carbon materials performance. Therefore, the synthesis kinetics of B-COPNA resin prepared from ETLF was investigated using <em>in-situ</em> FTIR in this work. The synthesis kinetic models of B-COPNA resin were established for the first time. To express the kinetic model, the concentration changes of C–H in aromatic rings and O–H in PXG monitored by <em>in-situ</em> FTIR were selected as two indicators to calculate concentration of other compounds and describe the synthesis kinetics. Then confirmatory experiments were conducted, and the <em>ρ</em>^<em>2</em> (&gt;0.9900), F-values (&gt;10F_0.05) and parameter errors (below 3%) of kinetic models verify that concentration changes of C–H and O–H can be used to describe synthesis kinetics of B-COPNA resin. Based on the results of confirmatory experiments, the synthesis kinetic model of B-COPNA resin in the ETLF system is established successfully using concentration changes of O–H as an indicator, whose appropriateness and feasibility are proved by the <em>ρ</em>^<em>2</em> (0.9960) and F-values (&gt;10F_0.05). These models could accurately describe the synthesis rate of B-COPNA resin.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 4282-4291"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384368","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Lignin in oilfield application: Current trends and future perspectives","authors":"Na-Na Song ,&nbsp;Mei-Chun Li ,&nbsp;Xue-Qiang Guo ,&nbsp;Ya-Xuan Zhang ,&nbsp;Ming-Yuan Xin ,&nbsp;Jin-Sheng Sun ,&nbsp;Kai-He Lv ,&nbsp;Chao-Zheng Liu","doi":"10.1016/j.petsci.2025.07.003","DOIUrl":"10.1016/j.petsci.2025.07.003","url":null,"abstract":"<div><div>With the depletion of shallow and mid-depth oil and gas resources, exploration and development have increasingly shifted toward deep and ultra-deep reservoirs. However, high bottom-hole temperatures and pressures, along with complex geological conditions, pose significant challenges. Additionally, growing environmental regulations restrict the use of conventional petroleum-derived chemicals such as polyacrylamide, sulfonic acid resins, and sulfonic acid asphalt. In recent years, lignin has demonstrated significant potential in petroleum exploration and development due to their sustainability, biodegradability, and excellent thermal, chemical, mechanical, and rheological properties. This article reviews the structure, classification, preparation, and modification methods of lignin, followed by a systematic discussion of its applications in oilfield operations. In drilling fluids, lignin and its derivatives serve as rheological regulators, fluid loss control agents, and shale inhibitors, contributing to enhanced cuttings transport and wellbore stability. In fracturing fluids, they function as thickeners and breaker agents, improving fracturing efficiency while protecting the reservoir. In enhanced oil recovery, lignin-based polymers act as surfactants and profile control agents, reducing interfacial tension between water and rock surfaces and increasing the effective permeability of sandstone reservoirs. Furthermore, in oilfield wastewater treatment, lignin-based materials effectively remove oil-water mixtures, heavy metal cations, and solid particles through filtration, adsorption, and flocculation.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 4292-4315"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384415","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental investigation of particle settling characteristics in narrow fractures with rough walls","authors":"Hai Qu ,&nbsp;Yan-Bin Yao ,&nbsp;Mao Sheng ,&nbsp;Xian-Zhi Song ,&nbsp;Gen-Sheng Li ,&nbsp;Ying Liu ,&nbsp;Xiao-Dong Liu","doi":"10.1016/j.petsci.2025.07.012","DOIUrl":"10.1016/j.petsci.2025.07.012","url":null,"abstract":"<div><div>Particle settling in narrow rough fractures is a common but poorly understood phenomenon during hydraulic fracturing. This study first constructs a large slot with two rough surfaces to simulate rock fractures and employs the particle image velocimetry to measure particle settling. Results show that particle settling in the rough slot is more complex than in the smooth slot. Rough pathways significantly change particle settling characteristics. The rough-walled slot alters the classic settling process by creating preferential pathways, localized trapping, and vortex-driven redistribution. Particles settle along preferential pathways, increasing settling velocity. The wall retardation effect becomes more prominent for large particles, reducing the settling velocity. Particle settling induces vortices throughout the rough surface, affecting particle behavior. Higher particle volume fractions increase settling non-uniformity, leading to unstable fluid flow within fractures, characterized by high vorticity and upward flow. The frequent interplay between particles and particle-walls, and fluid resistance complicates particle trajectories and settling behavior. Fluid viscosity significantly changes settling patterns and promotes particle clusters, forming chain-like and curtain-like clusters in rough fractures. An innovative model is proposed to predict settling velocity in rough fractures.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 4211-4225"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384367","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Structural determinants of asphaltenes behavior: Heteroatom-driven aggregation dynamics and viscosity enhancement in heavy oil systems","authors":"Guan-Dong Wang ,&nbsp;Peng-Cheng Zou ,&nbsp;Si-Si Cheng ,&nbsp;Yong Hu ,&nbsp;Xue-Yu Wang ,&nbsp;Ji-Chao Fang","doi":"10.1016/j.petsci.2025.07.025","DOIUrl":"10.1016/j.petsci.2025.07.025","url":null,"abstract":"<div><div>Heavy oil, constituting a significant portion of global oil reserves, presents unique challenges in extraction and processing due to its high viscosity, largely influenced by asphaltenes and their heteroatom content. This study employs molecular dynamics (MD) simulations to investigate the self-aggregation and adsorption mechanisms of heteroatom/non-heteroatom asphaltenes, comparing linear and island structural configurations. Key findings reveal that linear heteroatom asphaltenes form dense, multi-layered aggregates, while island heteroatom asphaltenes exhibit stronger aggregation energy. On solid surfaces, linear asphaltenes display multi-layered adsorption, whereas island asphaltenes adopt a dispersed structure with higher adsorption energy, making them more resistant to removal. Compared to non-heteroatom asphaltenes, heteroatom asphaltenes significantly enhance the aggregation energy of the asphaltene itself and the interaction energy with light oil components, reducing the diffusion capacity of oil droplets and increasing viscosity. Although the viscosity of island heteroatom asphaltene oil drops is the largest, the role of heteroatom in linear asphaltene is more obvious, and linear heteroatom asphaltene and non-heteroatom show great differences in properties. Additionally, heteroatom-containing oil droplets exhibit stronger interactions with solid surfaces, driven by the influence of heteroatom asphaltenes on lighter oil components. These insights provide a deeper understanding of heavy oil viscosity mechanisms, offering a foundation for developing targeted viscosity-reduction strategies and optimizing heavy oil recovery and processing techniques.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 4316-4328"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384417","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Microscopic accumulation mechanism of helium in shale gas: Insights from molecular simulation","authors":"Bing You ,&nbsp;Jian-Fa Chen ,&nbsp;Qing-Yong Luo ,&nbsp;Hong Xiao ,&nbsp;Mei-Jun Li ,&nbsp;Xiao-Qiang Liu","doi":"10.1016/j.petsci.2025.06.019","DOIUrl":"10.1016/j.petsci.2025.06.019","url":null,"abstract":"<div><div>Shale gas in southern China is found to contain economically valuable helium (He), which is inconsistent with conventional perspective that hydrocarbon gases in shale would dilute He to sub-economic levels. The adsorption of gases in the nanopores of organic matter is considered a crucial factor influencing the shale gas composition. The adsorption behaviors of He, methane (CH₄) and their mixtures in kerogen nanopores were performed by the Grand Canonical Monte Carlo simulation. The molecular simulations of pure He reveal that He can be adsorbed in shale and the adsorption capacity of He increases with the burial depth of shale. Before the hydrocarbon generation from kerogen, He has been continually generated in shale, the simulations further demonstrate that pure He can be partially preserved in shale as adsorbed gas phase. The simulations of competitive adsorption between CH₄ and He show that the adsorption selectivity of CH₄/He is consistently higher than 1.0 under the simulated conditions. This indicates that the previously adsorbed He will be displaced by CH₄ and subsequently concentrated in hydrocarbon gas as free gas phase during the process of hydrocarbon gas generation from kerogen. After the termination of hydrocarbon gas generation, He continues to be generated in shale and preferentially concentrated in free shale gas. Therefore, the concentration of He in shale gas will gradually increase with the generation time of He. In addition, our simulations indicate that high pressure and deep burial depth can enhance the adsorption of He in kerogen, suggesting that deeply buried organic-rich shale probably retains more adsorbed helium. Molecular simulations of He adsorption provide new insights into the accumulation process of He in shale gas and are of great significance for assessing helium resource potential in shale gas.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 3915-3924"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384470","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Insights into occurrence and distribution of pore water in gas shales: Comparison between thermogravimetry and water vapor sorption","authors":"Peng-Fei Zhang ,&nbsp;Jun-Jie Wang ,&nbsp;Shuang-Fang Lu ,&nbsp;Jun-Qian Li ,&nbsp;Neng-Wu Zhou ,&nbsp;Hai-Yong Wang ,&nbsp;Wei-Zheng Gao ,&nbsp;Guo-Hui Chen ,&nbsp;Jun-Jian Zhang ,&nbsp;Wen-Biao Li","doi":"10.1016/j.petsci.2025.07.007","DOIUrl":"10.1016/j.petsci.2025.07.007","url":null,"abstract":"<div><div>Connate water strongly restricts shale gas enrichment and production, and most artificially injected water is confined in shale pore networks owing to low water recovery during hydraulic fracturing, which leads to a more complex pore water distribution. However, previous studies have focused on the water vapor sorption of gas shales rather than liquid pore water. This study clarifies the occurrence and distribution of pore water and the controlling factors by conducting thermogravimetry (TGA) under liquid water saturation and water vapor sorption experiments on four gas shales from the Wufeng Formation in South China. Nuclear magnetic resonance (NMR) T₂ and T₁–T₂ technologies were used to monitor the dynamic changes and states of moisture, and the microscopic pore structures during water vapor sorption were detected using low-temperature nitrogen adsorption-desorption. The results indicate that TGA is adequate for determining the adsorbed, bound, and movable water contents. These four gas shales are characterized by high adsorbed and movable water contents, and some bound water. The adsorbed water primarily occurs in tiny pores (&lt;100 nm), controlled by organic matter, followed by clay minerals. The movable water, typically associated with quartz, primarily exists in pores of &gt;100 nm, particularly macropores of &gt;1000 nm. The bound water predominantly correlates with pores ranging from 10 to 2000 nm in clay minerals. The water vapor sorption process of the gas shale is well clarified. Water molecules primarily adsorb on the clay mineral's hydrophilic surface, followed by oxygen functional groups in the organic matter. Therefore, clay minerals control water vapor sorption at low relative humidity (RH &lt;0.75), whereas organic matter primarily affects vapor sorption at high RH. The TGA of liquid water-saturated gas shales can clarify the water distributions in full-scale pore networks, whereas the water vapor sorption method primarily discloses the moisture in small nanopores (&lt;100 nm) but ignores most bound and movable water. This paper provides insight into liquid water distribution and occurrence states within shale pore networks, contributing to a better understanding of gas–water–rock interaction systems in-situ and hydraulic fracturing shale gas formations.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 3939-3959"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384472","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}