Petroleum Science最新文献

{"title":"Study on an improved saturation parameter method based on joint inversion of NMR and resistivity data in porous media","authors":"Peng-Ji Zhang ,&nbsp;Bao-Zhi Pan ,&nbsp;Yu-Hang Guo ,&nbsp;Li-Hua Zhang ,&nbsp;Zhao-Wei Si ,&nbsp;Feng Xu ,&nbsp;Ming-Yue Zhu ,&nbsp;Yan Li","doi":"10.1016/j.petsci.2025.03.024","DOIUrl":"10.1016/j.petsci.2025.03.024","url":null,"abstract":"<div><div>CO₂ storage capacity is significantly influenced by the saturation levels of reservoir rocks, with underground fluid saturation typically evaluated using resistivity data. The conductive pathways of fluids in various states within rock pores differ, alongside variations in conductive mechanisms. To clarify the conductivity of water in rocks across different states, this study employed a three–pore segment saturation model, which corrected for the additional conductivity of clay by categorizing water into large–pore segment, medium–pore segment, and small–pore segment types. Addressing the heterogeneity of tight sandstone reservoirs, we classified distinct pore structures and inverted Archie equation parameters from NMR logging data using a segmented characterization approach, yielding dynamic Archie parameters that vary with depth. Ultimately, we established an improved saturation parameter method based on joint inversion of NMR and resistivity data, which was validated through laboratory experiments and practical downhole applications. The results indicate that this saturation parameter inversion method has been effectively applied in both settings. Furthermore, we discussed the varying conductive behaviors of fluids in large and medium pore segment under saturated and drained states. Lastly, we proposed a workflow for inverting saturation based on downhole data, providing a robust foundation for CO₂ storage and predicting underground fluid saturation.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 6","pages":"Pages 2312-2324"},"PeriodicalIF":6.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144572572","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":"Characterization and optimization of oil–gas interfacial tension during CO2/N2 injection in heavy oil reservoirs: Experimental study and regression model","authors":"Chao Zhang ,&nbsp;Chao Yu ,&nbsp;Zi-Han Gu ,&nbsp;Kun Liu ,&nbsp;Ping-Keng Wu ,&nbsp;Zhao-Min Li","doi":"10.1016/j.petsci.2025.03.032","DOIUrl":"10.1016/j.petsci.2025.03.032","url":null,"abstract":"<div><div>CO₂/N₂ injection in heavy oil reservoirs has been demonstrated to enhance oil recovery (EOR) and facilitate CO₂ capture, utilization, and storage (CCUS). Interfacial tension (IFT) is a crucial parameter for characterizing oil recovery, but it can be influenced by real-time changes in reservoir pressure and temperature during gas injection. The impact of the CO₂/N₂ ratio on the oil–gas IFT under varying temperature and pressure conditions remains unclear. Therefore, a systematic study was conducted to investigate the effects of multiple parameters on the oil–gas IFT during development processes, and a three-dimensional (3D) database and a regression model of IFT were established using experimental data. The results show that IFT is strongly correlated with density difference, moderately correlated with pressure and CO₂ proportion, weakly correlated with saturates content and resin content, and nonlinearly correlated with temperature, aromatics content, and asphaltene content, respectively. Moreover, it has been observed that an increase in pressure or CO₂ proportion can lead to a reduction in IFT. However, the impact of temperature changes on IFT varies across different pressure ranges. We introduce a new parameter, the equivalent interfacial tension pressure during temperature changes (EITP), to characterize this effect and discuss the reasons for the emergence of EITP, providing new insight into optimizing the CO₂/N₂ injection ratio in the reservoir. This study aims to reveal the advantages of oil–gas interface characteristics under the influence of multiple parameters in promoting low-carbon and efficient development of heavy oil reservoirs, and to explore the significance of CO₂/N₂ for enhancing heavy oil recovery.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 6","pages":"Pages 2516-2534"},"PeriodicalIF":6.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144572901","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":"Synergistic stabilization of emulsions by microspheres and surfactants for enhanced oil recovery","authors":"Yu-Hui Yang ,&nbsp;Chu-Yu Kang ,&nbsp;Ting-Feng Liu ,&nbsp;Hang Li ,&nbsp;Hui-Min Yu ,&nbsp;Zhuo-Zhuang Liu ,&nbsp;Hai-Ming Fan","doi":"10.1016/j.petsci.2025.03.041","DOIUrl":"10.1016/j.petsci.2025.03.041","url":null,"abstract":"<div><div>During oil displacement, surfactants often encounter challenges such as emulsion instability and channeling, which can compromise their efficiency. To address these issues, polymer microspheres were synthesized via reverse microemulsion polymerization using acrylamide, 2-methyl-2-acrylamidopropane sulfonic acid, and stearyl methacrylate as monomers, with <em>N</em>,<em>N</em>-methylenebisacrylamide as the crosslinker. The microspheres were then combined with sodium alkyl alcohol polyoxyethylene ether carboxylate to enhance emulsion stability and expand the swept volume of surfactant. A stable reverse microemulsion system was prepared using the maximum water solubilization rate as the indicator, and microspheres were synthesized based on this system. The ability of the microspheres to enhance emulsion stability was systematically evaluated. The plugging performance and enhanced oil recovery (EOR) efficiency of the microsphere/surfactant composite system were assessed through core seepage and oil displacement experiments. The experimental results demonstrated that microspheres were successfully prepared in a water-in-oil reverse microemulsion system with a solubilization rate of 42%. The emulsion stability was evaluated under an oil-to-water ratio of 7:3, a temperature of 80 °C, and a salinity of 44,592 mg/L, by manually shaking the test tube five times. It was observed that the complete phase separation time of the emulsion increased from 10 to 120 min after the addition of microspheres. Under different permeability conditions (100 × 10⁻³, 300 × 10⁻³, 500 × 10⁻³ μm²), the recovery efficiency of the composite system increased by 4.5%, 8.3%, and 4.8%, respectively, compared to a single surfactant system. The microspheres developed in this study enhanced emulsion stability and increased the swept volume of surfactant within the formation, significantly boosting its oil recovery efficiency.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 6","pages":"Pages 2535-2545"},"PeriodicalIF":6.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144572902","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":"Systematic modeling and methodological approaches for optimizing gas storage facility design with fluctuating hydraulic characteristics","authors":"Shi-Tao Liu ,&nbsp;Cheng-Yu Li ,&nbsp;Jun Zhou ,&nbsp;Zi-Chen Li ,&nbsp;Zhan-Peng Ye ,&nbsp;Jing-Hong Peng ,&nbsp;Yun-Xiang Zhao ,&nbsp;Guang-Chuan Liang","doi":"10.1016/j.petsci.2025.04.009","DOIUrl":"10.1016/j.petsci.2025.04.009","url":null,"abstract":"<div><div>As the proportion of natural gas consumption in the energy market gradually increases, optimizing the design of gas storage surface system (GSSS) has become a current research focus. Existing studies on the two independent injection pipeline network (InNET) and production pipeline network (ProNET) for underground natural gas storage (UNGS) are scarce, and no optimization methods have been proposed yet. Therefore, this paper focuses on the flow and pressure boundary characteristics of the GSSS. It constructs systematic models, including the injection multi-condition coupled model (INM model), production multi-condition coupled model (PRM model), injection single condition model (INS model) and production single condition model (PRS model) to optimize the design parameters. Additionally, this paper proposes a hybrid genetic algorithm based on generalized reduced gradient (HGA-GRG) for solving the models. The models and algorithm are applied to a case study with the objective of minimizing the cost of the pipeline network. For the GSSS, nine different condition scenarios are considered, and iterative process analysis and sensitivity analysis of these scenarios are conducted. Moreover, simulation scenarios are set up to verify the applicability of different scenarios to the boundaries. The research results show that the cost of the InNET considering the coupled pressure boundary is 64.4890 × 10⁴ CNY, and the cost of the ProNET considering coupled flow and pressure boundaries is 87.7655 × 10⁴ CNY, demonstrating greater applicability and economy than those considering only one or two types of conditions. The algorithms and models proposed in this paper provide an effective means for the design of parameters for GSSS.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 6","pages":"Pages 2546-2569"},"PeriodicalIF":6.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144572903","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":"Effects of organic-inorganic transformation and interaction on the occurrence of nanopores within the organic-rich shale during thermal maturation: Insights from the hydrous pyrolysis experiments in a closed system","authors":"Yong Tang ,&nbsp;Chu-Xiong Li ,&nbsp;Hong Cheng ,&nbsp;Su-Yang Cai ,&nbsp;Xiao Li ,&nbsp;Qi-Lin Xiao ,&nbsp;Meng-Lin Zheng ,&nbsp;Jin Pan","doi":"10.1016/j.petsci.2025.02.024","DOIUrl":"10.1016/j.petsci.2025.02.024","url":null,"abstract":"<div><div>The organic-inorganic transformation and interaction act as the critical role in the occurrence of nanopores within the organic-rich shales during thermal maturation. Hydrous pyrolysis experiments were conducted on the organic-rich mudrock collected from the Upper Cretaceous Nenjiang Formation of the Songliao Basin, China in a closed system. The pore types and pore network, and organic and inorganic compositions of pyrolyzed shales were detected from the early to over mature stages (%<em>R</em>_o = 0.61–4.01). The experimental results indicate that geochemical transformation of organic matters and minerals and the interaction control the formation and evolution of nanoporosity. In oil window mineral matrix pores are infilled by the generated oil, K-feldspar dissolution by organic acids promotes clay illitization to form illite, and the catalytic effects of clays (e.g. illite) in the complex of organic matter and clays may promote the in-situ retained oil cracking to generate natural gas, resulting in the early occurrence of organic-matter pores in the complex within oil window. Due to significant primary cracking of solid kerogen to generate extractable liquid oil, pore volume for storing fluids presents a persistent increase and approaches the maximum at the end of oil window. In gas window intensive oil cracking facilitates the hydrocarbon migrating out of the source home and pyrobitumen formation, resulting in the significant occurrence of modified mineral matrix pores and organic-matter pores. Pore volume for hosting hydrocarbons presents a slight decrease at %<em>R</em>_o = 1.36–2.47 due to pyrobitumen formation by oil secondary cracking. The organic-inorganic interaction favors clay illitization, quartz dissolution, and pyrite and carbonate decomposition, which facilitate the occurrence of nanoporosity. Pyrobitumen within the complex with illite and organic matters are much more porous than that hosted in modified mineral matrix pores and microfractures. The catalytic effects of clays are supposed to be responsible for this. This study improves our understanding of the formation and evolution pathways of nanoporosity and the underlying controls in organic-rich shales during thermal maturation, and hence should be helpful in evaluating the sweet spots for shale-oil and shale-gas plays in a sedimentary basin.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 5","pages":"Pages 1823-1838"},"PeriodicalIF":6.0,"publicationDate":"2025-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144222222","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":"Hydrocarbon generation reaction kinetics study on supercritical water conversion of centimeter sized medium and low maturity organic-rich shale","authors":"Tian Xie ,&nbsp;Qiu-Yang Zhao ,&nbsp;Hui Jin ,&nbsp;Ye-Chun Wang ,&nbsp;Lie-Jin Guo","doi":"10.1016/j.petsci.2025.02.020","DOIUrl":"10.1016/j.petsci.2025.02.020","url":null,"abstract":"<div><div>Accurate prediction of the composition of pyrolysis products is the prerequisite for achieving directional regulation of organic-rich shale pyrolysis and conversion products. In this paper, the classical segmented pyrolysis kinetics model and a new refined pyrolysis kinetics model were used to forecast the composition distribution of hydrocarbon generation products co-heated by supercritical water and medium and low maturity organic-rich shale. The prediction accuracy of the two reaction kinetics models for the composition of pyrolysis products of organic-rich shale was compared. The reaction path of hydrocarbon generation in centimeter sized organic-rich shale under the action of supercritical water was identified. The results show that the prediction accuracy of the classical segmented pyrolysis kinetics model was poor at the initial stage of the reaction, and gradually increased with increasing time. The prediction error can reach less than 25% when the reaction time was 12 h. The new refined model of reaction kinetics established is better than the classical reaction kinetics model in predicting the product distribution of pyrolysis oil and gas, and its prediction error is less than 14% in this paper. The reaction paths of hydrocarbon generation in centimeter sized organic-rich shale under supercritical water conversion mainly include organic-rich shale directly generates asphaltene and saturated hydrocarbon, asphaltene pyrolysis generates saturated hydrocarbon, aromatic hydrocarbon and resin, saturated hydrocarbon, aromatic hydrocarbon and resin polymerization generates asphaltene, and saturated hydrocarbon, resin and asphaltene generates gas. The reason for the difference of centimeter sized and millimeter sized medium and low maturity organic-rich shales hydrocarbon generation in supercritical water is that the increase of shale size promotes the reaction path of polymerization of saturated hydrocarbon and aromatic hydrocarbon to asphaltene.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 5","pages":"Pages 2203-2214"},"PeriodicalIF":6.0,"publicationDate":"2025-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144222204","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":"TOC","authors":"","doi":"10.1016/S1995-8226(25)00172-4","DOIUrl":"10.1016/S1995-8226(25)00172-4","url":null,"abstract":"","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 5","pages":"Pages i-ii"},"PeriodicalIF":6.0,"publicationDate":"2025-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144222351","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":"Correlating the carbonic acid reaction with tight sand and pure minerals during geological carbon storage","authors":"Yong-Peng Sun ,&nbsp;Guo-Liang Li ,&nbsp;Si-Zhe Zeng ,&nbsp;Jia-Wei Liu ,&nbsp;Xian-Fei Du ,&nbsp;Cai-Li Dai","doi":"10.1016/j.petsci.2025.03.045","DOIUrl":"10.1016/j.petsci.2025.03.045","url":null,"abstract":"<div><div>CO₂ injection into geological formations has been proven to be an effective approach for carbon storage. When dissolved in formation water, CO₂ forms carbonic acid that induces mineral dissolution at pore surfaces under acidic conditions. Comprehensive understanding of geochemical interaction between carbonic acid and reservoir rocks is crucial for assessing environmental impact on geological formations. This study focuses on a tight oil sandstone reservoir. After characterizing basic petrophysical properties and mineral composition of rock samples, a series of carbonic acid corrosion experiments with both core and corresponding pure mineral samples were carried out, respectively. Dissolution solutions collected during the experiments were analyzed to examine the variations of ion concentrations in both core and pure mineral solutions. The carbonic acid–pure mineral corrosion kinetics were investigated. The correlations between carbonic acid with core and pure mineral corrosion scenarios were established from the sample mass, reaction rate, and ion concentration. The results show that after corrosion, the mass of calcite and dolomite in the rock sample decreased by 66.7% and 27.3%, respectively. When the corrosion was stabilized, the concentrations of Ca²⁺ and Mg²⁺ in the core solution were 72.9 and 74.4 mg/L, respectively, which was 40.5–41.3 times higher than that of Na⁺. The reaction kinetics analysis of carbonic acid–rock revealed a two-stage reaction in the pure mineral corrosion process, rapid reaction stage, and slow reaction stage, with different reaction rate constants and reaction orders for each ion. With the correlation between carbonic acid reaction with core and pure minerals, an effective and rapid evaluation method with pure minerals for the carbonic water–rock reaction is established, which costs a shorter time and is easier to investigate. This study provides a simple and faster method to evaluate the carbonic acid corrosion reaction during geological carbon storage.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 5","pages":"Pages 2142-2153"},"PeriodicalIF":6.0,"publicationDate":"2025-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144222360","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":"Optimization of plunger lift working systems using reinforcement learning for coupled wellbore/reservoir","authors":"Zhi-Sheng Xing ,&nbsp;Guo-Qing Han ,&nbsp;You-Liang Jia ,&nbsp;Wei Tian ,&nbsp;Hang-Fei Gong ,&nbsp;Wen-Bo Jiang ,&nbsp;Pei-Dong Mai ,&nbsp;Xing-Yuan Liang","doi":"10.1016/j.petsci.2025.03.009","DOIUrl":"10.1016/j.petsci.2025.03.009","url":null,"abstract":"<div><div>In the mid-to-late stages of gas reservoir development, liquid loading in gas wells becomes a common challenge. Plunger lift, as an intermittent production technique, is widely used for deliquification in gas wells. With the advancement of big data and artificial intelligence, the future of oil and gas field development is trending towards intelligent, unmanned, and automated operations. Currently, the optimization of plunger lift working systems is primarily based on expert experience and manual control, focusing mainly on the success of the plunger lift without adequately considering the impact of different working systems on gas production. Additionally, liquid loading in gas wells is a dynamic process, and the intermittent nature of plunger lift requires accurate modeling; using constant inflow dynamics to describe reservoir flow introduces significant errors. To address these challenges, this study establishes a coupled wellbore–reservoir model for plunger lift wells and validates the computational wellhead pressure results against field measurements. Building on this model, a novel optimization control algorithm based on the deep deterministic policy gradient (DDPG) framework is proposed. The algorithm aims to optimize plunger lift working systems to balance overall reservoir pressure, stabilize gas–water ratios, and maximize gas production. Through simulation experiments in three different production optimization scenarios, the effectiveness of reinforcement learning algorithms (including RL, PPO, DQN, and the proposed DDPG) and traditional optimization algorithms (including GA, PSO, and Bayesian optimization) in enhancing production efficiency is compared. The results demonstrate that the coupled model provides highly accurate calculations and can precisely describe the transient production of wellbore and gas reservoir systems. The proposed DDPG algorithm achieves the highest reward value during training with minimal error, leading to a potential increase in cumulative gas production by up to 5% and cumulative liquid production by 252%. The DDPG algorithm exhibits robustness across different optimization scenarios, showcasing excellent adaptability and generalization capabilities.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 5","pages":"Pages 2154-2168"},"PeriodicalIF":6.0,"publicationDate":"2025-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144222361","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":"Evolution of multi-cluster fracturing in high-density layered shale considering the effect of injection scheme","authors":"Xiao Yan ,&nbsp;Haitao Yu ,&nbsp;Peng Zhang","doi":"10.1016/j.petsci.2025.03.008","DOIUrl":"10.1016/j.petsci.2025.03.008","url":null,"abstract":"<div><div>Shale oil reservoir is generally characterized by well-developed bedding planes, and multi-cluster fracturing is the most effective technique to achieve stable shale oil production. In this paper, a multi-cluster fracturing model for a horizontal well in shale with high-density bedding planes is established. The fracture morphology, fracture geometry, fracturing area and multiple fracture propagation mechanism are analyzed under simultaneous fracturing, sequential fracturing, and alternative fracturing. Results show that in the case of small cluster spacing and three clusters, the growth of the middle fracture is inhibited and develops along the bedding planes under both simultaneous fracturing and alternative fracturing. For sequential fracturing, the increase in the interval time between each fracturing advances the post fracturing fracture deflecting to the pre-existing fractures through the bedding planes. The reactivation of the bedding planes can promote the extension of the fracturing area. Increasing the injection rate and the number of clusters promotes the activation of bedding planes. However, it is preferable to reduce the number of clusters to obtain more main fractures. Compared with modified alternating fracturing and cyclic alternating fracturing, alternating shut-in fracturing creates more main fractures towards the direction of the maximum in-situ stress. The fracturing efficiency for high-density layered shale is ranked as simultaneous fracturing &gt; alternative fracturing &gt; sequential fracturing.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 5","pages":"Pages 2109-2122"},"PeriodicalIF":6.0,"publicationDate":"2025-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144222473","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}