Pub Date : 2025-09-01DOI: 10.1016/j.petsci.2025.07.024
Xu Zhao , Qing Wang , Zi-Yi Zhang
Helium is a critical raw material, but its distribution is extremely uneven. To better mitigate trade risks and get a steady and safe supply of helium, it is of the upmost importance to assess the risk associated with the investment environment in helium-rich countries. This paper establishes an indicator system including 22 indicators from five dimensions, which consist of: helium resource endowment, macro environment, operation risk, maritime risk and, bilateral relationships. The game theory model combined with variance coefficient theory and expert survey are presented to determine the combined weights. The results show that Kazakhstan, Russia and Qatar present the best comprehensive performance; Australia has the highest operation risk and, Poland and Algeria have higher maritime risk; resources endowment has the largest weight, followed by maritime risk. We provide suggestions of acquiring upstream helium-rich gas fields and purchase & sale agreement of bundled liquified natural gas (LNG) etc.
{"title":"Multi-attribute risk assessment on helium investment environment in host countries","authors":"Xu Zhao , Qing Wang , Zi-Yi Zhang","doi":"10.1016/j.petsci.2025.07.024","DOIUrl":"10.1016/j.petsci.2025.07.024","url":null,"abstract":"<div><div>Helium is a critical raw material, but its distribution is extremely uneven. To better mitigate trade risks and get a steady and safe supply of helium, it is of the upmost importance to assess the risk associated with the investment environment in helium-rich countries. This paper establishes an indicator system including 22 indicators from five dimensions, which consist of: helium resource endowment, macro environment, operation risk, maritime risk and, bilateral relationships. The game theory model combined with variance coefficient theory and expert survey are presented to determine the combined weights. The results show that Kazakhstan, Russia and Qatar present the best comprehensive performance; Australia has the highest operation risk and, Poland and Algeria have higher maritime risk; resources endowment has the largest weight, followed by maritime risk. We provide suggestions of acquiring upstream helium-rich gas fields and purchase & sale agreement of bundled liquified natural gas (LNG) etc.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 9","pages":"Pages 3854-3865"},"PeriodicalIF":6.1,"publicationDate":"2025-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145223558","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}
Pub Date : 2025-09-01DOI: 10.1016/j.petsci.2025.06.006
Xiao-Dong Wang , Qian-Ting Hu , Yong-Jiang Luo , Bao-Cai Wang , Sheng-Xian Zhao , Shao-Jun Liu , Yue Lei
Hydraulic fracturing (HF) has achieved significant commercial success in unconventional oil and gas development. However, it has the potential to induce fault slip. This study investigates the physical mechanisms underlying potential fault slip triggered by HF operations under varying geological and operational constraints. First, we elucidate the relationship between the critical stress state and the elastic modulus of the fault, and refine a formula for the maximum crustal stress difference on critically stressed faults, including stress concentration, friction, and dip. Second, we compare the role of injected fluid in permeable faults with that in impermeable faults, and demonstrate that fault slips can be triggered by a combination of friction decrease and pore pressure increase, even after ceasing injection. Specifically, we reveal that friction decline dominates induced fault slip on high permeable and hydraulically connected fault. Third, based on experimental results and theoretical analysis, we quantify the influence region of stress transfer under different conditions of well location and injection pressure. The results reveal that the elastic modulus of the fault controls the stress concentration on the fault plane. The dip of the fault and the stress concentration jointly determine the maximum crustal stress difference required for failure in critically stressed reverse faults. Thus, our study is more accurate in estimating the proximity of the in-situ stress to the critical state, compared with traditional methods. For critical reverse faults, the risk of induced slip is positively correlated with both injection pressure and friction of fault plane. When the injection pressure (PI) is 100 MPa and the friction (μ) is 0.8, the safe distance from injection point to critically stressed faults along the direction of maximum principal stress and maximum principal stress (dH and dv) should exceed 25 and 18 times as the hydraulic fracture half-length. When PI is 100 MPa and μ is 0.6, dH and dv are 23 and 17 times as the hydraulic fracture half-length, respectively. When PI is 60 MPa and μ is 0.6, dH and dv are 18 and 13 times as the hydraulic fracture half-length, respectively. The works enhance our understanding of HF-induced fault slip and potentially guide designs of the shale gas well location and trajectory for safer production.
{"title":"Experimental study of the characteristics of reverse fault slip induced by hydraulic fracturing","authors":"Xiao-Dong Wang , Qian-Ting Hu , Yong-Jiang Luo , Bao-Cai Wang , Sheng-Xian Zhao , Shao-Jun Liu , Yue Lei","doi":"10.1016/j.petsci.2025.06.006","DOIUrl":"10.1016/j.petsci.2025.06.006","url":null,"abstract":"<div><div>Hydraulic fracturing (HF) has achieved significant commercial success in unconventional oil and gas development. However, it has the potential to induce fault slip. This study investigates the physical mechanisms underlying potential fault slip triggered by HF operations under varying geological and operational constraints. First, we elucidate the relationship between the critical stress state and the elastic modulus of the fault, and refine a formula for the maximum crustal stress difference on critically stressed faults, including stress concentration, friction, and dip. Second, we compare the role of injected fluid in permeable faults with that in impermeable faults, and demonstrate that fault slips can be triggered by a combination of friction decrease and pore pressure increase, even after ceasing injection. Specifically, we reveal that friction decline dominates induced fault slip on high permeable and hydraulically connected fault. Third, based on experimental results and theoretical analysis, we quantify the influence region of stress transfer under different conditions of well location and injection pressure. The results reveal that the elastic modulus of the fault controls the stress concentration on the fault plane. The dip of the fault and the stress concentration jointly determine the maximum crustal stress difference required for failure in critically stressed reverse faults. Thus, our study is more accurate in estimating the proximity of the in-situ stress to the critical state, compared with traditional methods. For critical reverse faults, the risk of induced slip is positively correlated with both injection pressure and friction of fault plane. When the injection pressure (<em>P</em><sub>I</sub>) is 100 MPa and the friction (<em>μ</em>) is 0.8, the safe distance from injection point to critically stressed faults along the direction of maximum principal stress and maximum principal stress (<em>d</em><sub>H</sub> and <em>d</em><sub>v</sub>) should exceed 25 and 18 times as the hydraulic fracture half-length. When <em>P</em><sub>I</sub> is 100 MPa and <em>μ</em> is 0.6, <em>d</em><sub>H</sub> and <em>d</em><sub>v</sub> are 23 and 17 times as the hydraulic fracture half-length, respectively. When <em>P</em><sub>I</sub> is 60 MPa and <em>μ</em> is 0.6, <em>d</em><sub>H</sub> and <em>d</em><sub>v</sub> are 18 and 13 times as the hydraulic fracture half-length, respectively. The works enhance our understanding of HF-induced fault slip and potentially guide designs of the shale gas well location and trajectory for safer production.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 9","pages":"Pages 3729-3744"},"PeriodicalIF":6.1,"publicationDate":"2025-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145223570","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}
Pub Date : 2025-09-01DOI: 10.1016/j.petsci.2025.05.015
Jia-Hong Gao, Zhi-Jun Jin, Xin-Ping Liang
The Ordos Basin was recognized as the earliest terrestrial aquatic ecosystem to recover following Permian–Triassic mass extinction, significantly contributing to organic carbon sequestration during the early Mesozoic era. Volcanic activity has increased the organic carbon burial capacity of the third submember of Ch7 (Ch73) within this basin, although it has both positive and negative effects on organic carbon burial. In this study, we quantitatively characterized the organic carbon burial process by calculating the organic carbon accumulation rate (OCAR) and proposed an optimal sedimentary model influenced by volcanic activity. We conducted time series analysis on gamma ray (GR) data from Ch73 to determine sedimentation rates (SRs) while measuring the density of each sample via hydrostatic methods. By integrating these measurements with the total organic carbon (TOC) content, we established a dynamic OCAR for Ch73 ( = 0.68 g/(cm2·kyr)) and estimated that it sequestered 0.27 Tt of organic carbon. Our findings indicate that the OCAR under eunixic conditions ( = 1.02 g/(cm2·kyr)) is 2.49 times greater than that under ferruginous conditions ( = 0.41 g/(cm2·kyr)). The geochemical identification fingerprints of volcanism suggest that the top of Ch73 is influenced by volcanoes of appropriate intensity. In this sedimentary model, the dilution of organic matter (OM) by rapidly deposited volcanic ash is relatively low. Additionally, the cumulative effect of chemical weathering intensity due to volcanic activity leads to the input of nutrients from continental sources into the lake basin. This process promotes increased productivity, resulting in a significant increase in the OCAR ( = 0.76 g/(cm2·kyr)). This study provides new insights for dynamically assessing the impact of geological events on the OCAR.
{"title":"Lacustrine organic carbon sequestration driven by volcanism: A case study of the third submember of the Chang 7 Member of the Yanchang Formation in the Ordos Basin","authors":"Jia-Hong Gao, Zhi-Jun Jin, Xin-Ping Liang","doi":"10.1016/j.petsci.2025.05.015","DOIUrl":"10.1016/j.petsci.2025.05.015","url":null,"abstract":"<div><div>The Ordos Basin was recognized as the earliest terrestrial aquatic ecosystem to recover following Permian–Triassic mass extinction, significantly contributing to organic carbon sequestration during the early Mesozoic era. Volcanic activity has increased the organic carbon burial capacity of the third submember of Ch7 (Ch7<sub>3</sub>) within this basin, although it has both positive and negative effects on organic carbon burial. In this study, we quantitatively characterized the organic carbon burial process by calculating the organic carbon accumulation rate (OCAR) and proposed an optimal sedimentary model influenced by volcanic activity. We conducted time series analysis on gamma ray (GR) data from Ch7<sub>3</sub> to determine sedimentation rates (SRs) while measuring the density of each sample via hydrostatic methods. By integrating these measurements with the total organic carbon (TOC) content, we established a dynamic OCAR for Ch7<sub>3</sub> (<span><math><mrow><mover><mi>x</mi><mo>¯</mo></mover></mrow></math></span> = 0.68 g/(cm<sup>2</sup>·kyr)) and estimated that it sequestered 0.27 Tt of organic carbon. Our findings indicate that the OCAR under eunixic conditions (<span><math><mrow><mover><mi>x</mi><mo>¯</mo></mover></mrow></math></span> = 1.02 g/(cm<sup>2</sup>·kyr)) is 2.49 times greater than that under ferruginous conditions (<span><math><mrow><mover><mi>x</mi><mo>¯</mo></mover></mrow></math></span> = 0.41 g/(cm<sup>2</sup>·kyr)). The geochemical identification fingerprints of volcanism suggest that the top of Ch7<sub>3</sub> is influenced by volcanoes of appropriate intensity. In this sedimentary model, the dilution of organic matter (OM) by rapidly deposited volcanic ash is relatively low. Additionally, the cumulative effect of chemical weathering intensity due to volcanic activity leads to the input of nutrients from continental sources into the lake basin. This process promotes increased productivity, resulting in a significant increase in the OCAR (<span><math><mrow><mover><mi>x</mi><mo>¯</mo></mover></mrow></math></span> = 0.76 g/(cm<sup>2</sup>·kyr)). This study provides new insights for dynamically assessing the impact of geological events on the OCAR.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 9","pages":"Pages 3497-3511"},"PeriodicalIF":6.1,"publicationDate":"2025-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145223571","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}
Pub Date : 2025-09-01DOI: 10.1016/j.petsci.2025.05.017
Yu-Shi Zou , Dian-Yu Li , Can Yang , Yan-Chao Li , Shi-Cheng Zhang , Long-Qing Zou , Xin-Fang Ma
Temporary plugging and diversion fracturing (TPDF) is widely used to promote the uniform and complex distribution of multi-clustered hydraulic fractures (HFs) in a horizontal well of the unconventional formations. However, the migration behavior of temporary plugging agent (TPA), as a function of the concentration and particle size of TPA and cluster-perforation numbers, etc., determining the effectiveness of this technique, remains unclear. Therefore, this study conducted innovatively a series of TPDF simulation experiments on transparent polymethyl methacrylate (PMMA) specimens (cubic block of 30 cm × 30 cm × 30 cm) to explore visually the migration behavior of TPA in multi-clustered HFs in a horizontal well. A laboratory hydraulic sandblasting perforation completion technique was implemented to simulate the multi-cluster perforations. All the distributions of wellbore, perforations, HFs, and TPA can be seen clearly inside the PMMA specimen post the experiment. The results show that there are four characteristic plugging positions for the TPA: mouth of HF, middle of HF, tip of HF, and the intersection of HFs. Small particle size TPA tends to migrate to the fracture tip for plugging, while large particle size TPA tends to plug at the fracture mouth. The migration of the TPA is influenced obviously by the morphology of the fracture wall. A smooth fracture wall is conducive to the migration of the TPA to the far end of HFs, but not conducive to generating the plugging zone and HF diversion. In contrast, a "leaf vein" fracture of rough wall is conducive to generating the plugging layer and the diversion of HFs, but not conducive to the migration of the TPA to the far end of HFs. The migration ability of TPA in a "shell" pattern is intermediate between the two above cases. Increasing TPA concentration can encourage TPA to migrate more quickly to the characteristic plugging position, and thereby to promote the creation of effective plugging and subsequently the multi-stage diversion of the HFs. Nevertheless, excessive concentration may cause the TPA to settle prematurely, affecting the propagation of the HFs to the far end. Increasing the number of clusters to a certain extent can encourage TPA to migrate into the HFs and form plugging, and promote the diversion. An evaluation system for the migration ability of granular TPA has been established, and it was calculated that when there is no plugging expectation target, the comprehensive migration ability of small particle size TPA is stronger than that of large particle size TPA. This research provides theoretical foundation for the optimization of temporary plugging parameters.
临时封堵导流压裂（TPDF）被广泛应用于非常规地层水平井中，以促进多簇水力裂缝（HFs）的均匀复杂分布。然而，暂堵剂（TPA）的运移行为，作为TPA浓度、粒径和簇射孔数等因素的函数，决定了该技术的有效性，目前尚不清楚。因此，本研究创新性地对透明聚甲基丙烯酸甲酯（PMMA）样品（30 cm × 30 cm × 30 cm的立方块）进行了一系列的TPDF模拟实验，以直观地探索TPA在水平井多簇hf中的迁移行为。采用实验室水力喷砂射孔完井技术对多簇射孔进行了模拟。实验结束后，在PMMA试样内可以清楚地看到井筒、射孔、hf和TPA的所有分布。结果表明，TPA有四个特征堵塞位置：HF口、HF中部、HF尖端和HF交点。小粒径TPA倾向于向裂缝尖端迁移封堵，大粒径TPA倾向于在裂缝口处封堵。断裂壁形态对TPA的运移有明显影响。光滑的裂缝壁有利于TPA向HF远端运移，但不利于堵带和HF分流的产生。粗壁“叶脉”断裂有利于堵层的形成和高频流的导流，但不利于TPA向高频流远端运移。“壳”型TPA的迁移能力介于上述两种情况之间。增加TPA浓度可以促使TPA更快地迁移到特征堵漏位置，从而促进有效堵漏的产生，进而促进高通量的多级导流。然而，浓度过高可能导致TPA过早沉淀，影响高频蛋白向远端传播。在一定程度上增加集群数量，可以促进TPA向高通量区迁移，形成堵塞，促进引水。建立了粒状TPA运移能力评价体系，计算得出在不存在封堵预期目标时，小粒径TPA的综合运移能力强于大粒径TPA。该研究为暂堵参数的优化提供了理论依据。
{"title":"Temporary plugging agent transport behavior within visualized multi-fracture created during TPDF in a horizontal well: An experimental study","authors":"Yu-Shi Zou , Dian-Yu Li , Can Yang , Yan-Chao Li , Shi-Cheng Zhang , Long-Qing Zou , Xin-Fang Ma","doi":"10.1016/j.petsci.2025.05.017","DOIUrl":"10.1016/j.petsci.2025.05.017","url":null,"abstract":"<div><div>Temporary plugging and diversion fracturing (TPDF) is widely used to promote the uniform and complex distribution of multi-clustered hydraulic fractures (HFs) in a horizontal well of the unconventional formations. However, the migration behavior of temporary plugging agent (TPA), as a function of the concentration and particle size of TPA and cluster-perforation numbers, etc., determining the effectiveness of this technique, remains unclear. Therefore, this study conducted innovatively a series of TPDF simulation experiments on transparent polymethyl methacrylate (PMMA) specimens (cubic block of 30 cm × 30 cm × 30 cm) to explore visually the migration behavior of TPA in multi-clustered HFs in a horizontal well. A laboratory hydraulic sandblasting perforation completion technique was implemented to simulate the multi-cluster perforations. All the distributions of wellbore, perforations, HFs, and TPA can be seen clearly inside the PMMA specimen post the experiment. The results show that there are four characteristic plugging positions for the TPA: mouth of HF, middle of HF, tip of HF, and the intersection of HFs. Small particle size TPA tends to migrate to the fracture tip for plugging, while large particle size TPA tends to plug at the fracture mouth. The migration of the TPA is influenced obviously by the morphology of the fracture wall. A smooth fracture wall is conducive to the migration of the TPA to the far end of HFs, but not conducive to generating the plugging zone and HF diversion. In contrast, a \"leaf vein\" fracture of rough wall is conducive to generating the plugging layer and the diversion of HFs, but not conducive to the migration of the TPA to the far end of HFs. The migration ability of TPA in a \"shell\" pattern is intermediate between the two above cases. Increasing TPA concentration can encourage TPA to migrate more quickly to the characteristic plugging position, and thereby to promote the creation of effective plugging and subsequently the multi-stage diversion of the HFs. Nevertheless, excessive concentration may cause the TPA to settle prematurely, affecting the propagation of the HFs to the far end. Increasing the number of clusters to a certain extent can encourage TPA to migrate into the HFs and form plugging, and promote the diversion. An evaluation system for the migration ability of granular TPA has been established, and it was calculated that when there is no plugging expectation target, the comprehensive migration ability of small particle size TPA is stronger than that of large particle size TPA. This research provides theoretical foundation for the optimization of temporary plugging parameters.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 9","pages":"Pages 3671-3687"},"PeriodicalIF":6.1,"publicationDate":"2025-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145223161","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}
Pub Date : 2025-09-01DOI: 10.1016/j.petsci.2025.08.022
Dong-Dong Guo , Wen-Jia Ou , Yun-Hong Zhang , Heng-Yin Zhu , Shahab Ud Din , Ren Wang , Fu-Long Ning
The stability of oil-dominated emulsions, including oil-based drilling fluids and crude oils, is crucial for mitigating gas hydrate risks in the petroleum and natural gas industries. Nanoparticles can stabilize oil-water systems (Pickering emulsions) by residing at the oil-water interface. However, their effects on the kinetics of hydrate formation in these systems remain unclear. To address this, we experimentally investigated how hydrophilic and hydrophobic nano-CaCO3 influence CH4 hydrate formation within dynamic oil-water systems. A series of hydrate formation experiments were conducted with varying water cuts and different concentrations of nano-CaCO3 at a particle size of 20 nm, under 3 °C and 6 MPa. The induction time, hydrate formation volume, and hydrate growth rate were measured and calculated. The results indicate that hydrophilic nano-CaCO3 generally inhibits hydrate formation, particularly at high water cuts, while hydrophobic nano-CaCO3 can significantly inhibit or even prevent hydrate formation at low water cuts. Water cut strongly influences the kinetics of hydrate formation, and nanoparticle concentration also impacts the results, likely due to changes in oil-water interface stability caused by nanoparticle distribution. This study will offer valuable insights for designing deepwater oil-based drilling fluids using nanoparticles and ensuring safe multiphase flow in deepwater oil and gas operations.
{"title":"Hydrate formation and agglomeration in Pickering emulsions stabilized by hydrophilic and hydrophobic nano-CaCO3 particles","authors":"Dong-Dong Guo , Wen-Jia Ou , Yun-Hong Zhang , Heng-Yin Zhu , Shahab Ud Din , Ren Wang , Fu-Long Ning","doi":"10.1016/j.petsci.2025.08.022","DOIUrl":"10.1016/j.petsci.2025.08.022","url":null,"abstract":"<div><div>The stability of oil-dominated emulsions, including oil-based drilling fluids and crude oils, is crucial for mitigating gas hydrate risks in the petroleum and natural gas industries. Nanoparticles can stabilize oil-water systems (Pickering emulsions) by residing at the oil-water interface. However, their effects on the kinetics of hydrate formation in these systems remain unclear. To address this, we experimentally investigated how hydrophilic and hydrophobic nano-CaCO<sub>3</sub> influence CH<sub>4</sub> hydrate formation within dynamic oil-water systems. A series of hydrate formation experiments were conducted with varying water cuts and different concentrations of nano-CaCO<sub>3</sub> at a particle size of 20 nm, under 3 °C and 6 MPa. The induction time, hydrate formation volume, and hydrate growth rate were measured and calculated. The results indicate that hydrophilic nano-CaCO<sub>3</sub> generally inhibits hydrate formation, particularly at high water cuts, while hydrophobic nano-CaCO<sub>3</sub> can significantly inhibit or even prevent hydrate formation at low water cuts. Water cut strongly influences the kinetics of hydrate formation, and nanoparticle concentration also impacts the results, likely due to changes in oil-water interface stability caused by nanoparticle distribution. This study will offer valuable insights for designing deepwater oil-based drilling fluids using nanoparticles and ensuring safe multiphase flow in deepwater oil and gas operations.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 9","pages":"Pages 3817-3829"},"PeriodicalIF":6.1,"publicationDate":"2025-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145223555","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}
Pub Date : 2025-09-01DOI: 10.1016/j.petsci.2025.06.001
Qin-Yang Dai , Li-Ming Zhang , Kai Zhang , Hao Hao , Guo-Dong Chen , Xia Yan , Pi-Yang Liu , Bao-Bin Zhang , Chen-Yang Wang
This study introduces a novel approach to addressing the challenges of high-dimensional variables and strong nonlinearity in reservoir production and layer configuration optimization. For the first time, relational machine learning models are applied in reservoir development optimization. Traditional regression-based models often struggle in complex scenarios, but the proposed relational and regression-based composite differential evolution (RRCODE) method combines a Gaussian naive Bayes relational model with a radial basis function network regression model. This integration effectively captures complex relationships in the optimization process, improving both accuracy and convergence speed. Experimental tests on a multi-layer multi-channel reservoir model, the Egg reservoir model, and a real-field reservoir model (the S reservoir) demonstrate that RRCODE significantly reduces water injection and production volumes while increasing economic returns and cumulative oil recovery. Moreover, the surrogate models employed in RRCODE exhibit lightweight characteristics with low computational overhead. These results highlight RRCODE's superior performance in the integrated optimization of reservoir production and layer configurations, offering more efficient and economically viable solutions for oilfield development.
{"title":"Integrated optimization of reservoir production and layer configurations using relational and regression machine learning models","authors":"Qin-Yang Dai , Li-Ming Zhang , Kai Zhang , Hao Hao , Guo-Dong Chen , Xia Yan , Pi-Yang Liu , Bao-Bin Zhang , Chen-Yang Wang","doi":"10.1016/j.petsci.2025.06.001","DOIUrl":"10.1016/j.petsci.2025.06.001","url":null,"abstract":"<div><div>This study introduces a novel approach to addressing the challenges of high-dimensional variables and strong nonlinearity in reservoir production and layer configuration optimization. For the first time, relational machine learning models are applied in reservoir development optimization. Traditional regression-based models often struggle in complex scenarios, but the proposed relational and regression-based composite differential evolution (RRCODE) method combines a Gaussian naive Bayes relational model with a radial basis function network regression model. This integration effectively captures complex relationships in the optimization process, improving both accuracy and convergence speed. Experimental tests on a multi-layer multi-channel reservoir model, the Egg reservoir model, and a real-field reservoir model (the S reservoir) demonstrate that RRCODE significantly reduces water injection and production volumes while increasing economic returns and cumulative oil recovery. Moreover, the surrogate models employed in RRCODE exhibit lightweight characteristics with low computational overhead. These results highlight RRCODE's superior performance in the integrated optimization of reservoir production and layer configurations, offering more efficient and economically viable solutions for oilfield development.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 9","pages":"Pages 3745-3759"},"PeriodicalIF":6.1,"publicationDate":"2025-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145223569","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}
Pub Date : 2025-09-01DOI: 10.1016/j.petsci.2025.05.018
Meng-Bo Zhang , Hao-Jie Pan , Yong-Gang Wang , Miao Du , Sheng-Juan Cai , Feng Liu , Mei-Xin Ju
Carbonate reservoirs are known for their complex pore structures, which lead to variable elastic behaviors and seismic responses. These variations pose significant challenges for seismic interpretation of carbonate reservoirs. Therefore, quantitative characterization of pore structure is crucial for accurate fluid detection and reservoir property estimation. To address the complexity of pore geometry and the uneven fluid distribution in tight carbonate reservoirs, we develop a triple-pore effective medium model by integrating the extended Keys-Xu model with the Gassmann-Hill equation. Comparison between the theoretical modeling results and an available laboratory data set verifies the effectiveness of this model in pore type quantification. Based on this calibrated model, we propose a novel two-step triple pore-type inversion strategy with varying pore aspect ratio via a grid-searching algorithm. We apply this method to well logs and 3D seismic data from the tight carbonate reservoirs of the Ordovician Majiagou formation in the Ordos Basin. The good agreement between pore-type estimates and logging interpretation results suggests that our method significantly improves the accuracy of porosity estimates for different pore types, outperforming the pore-type inversion method with fixed pore aspect ratios. The successful application to seismic data also demonstrates that the proposed method provides a reliable distribution of pore types in tight carbonate reservoirs, confirming its applicability and feasibility in seismic pore-type estimation. This method not only facilitates the recognition of complex pore geometries but also provides valuable insights for accurate detection of high-quality reservoirs.
{"title":"Seismic pore-type characterization in tight carbonate reservoirs: A case study of the fourth member of Ordovician Majiagou Formation in Ordos Basin, China","authors":"Meng-Bo Zhang , Hao-Jie Pan , Yong-Gang Wang , Miao Du , Sheng-Juan Cai , Feng Liu , Mei-Xin Ju","doi":"10.1016/j.petsci.2025.05.018","DOIUrl":"10.1016/j.petsci.2025.05.018","url":null,"abstract":"<div><div>Carbonate reservoirs are known for their complex pore structures, which lead to variable elastic behaviors and seismic responses. These variations pose significant challenges for seismic interpretation of carbonate reservoirs. Therefore, quantitative characterization of pore structure is crucial for accurate fluid detection and reservoir property estimation. To address the complexity of pore geometry and the uneven fluid distribution in tight carbonate reservoirs, we develop a triple-pore effective medium model by integrating the extended Keys-Xu model with the Gassmann-Hill equation. Comparison between the theoretical modeling results and an available laboratory data set verifies the effectiveness of this model in pore type quantification. Based on this calibrated model, we propose a novel two-step triple pore-type inversion strategy with varying pore aspect ratio via a grid-searching algorithm. We apply this method to well logs and 3D seismic data from the tight carbonate reservoirs of the Ordovician Majiagou formation in the Ordos Basin. The good agreement between pore-type estimates and logging interpretation results suggests that our method significantly improves the accuracy of porosity estimates for different pore types, outperforming the pore-type inversion method with fixed pore aspect ratios. The successful application to seismic data also demonstrates that the proposed method provides a reliable distribution of pore types in tight carbonate reservoirs, confirming its applicability and feasibility in seismic pore-type estimation. This method not only facilitates the recognition of complex pore geometries but also provides valuable insights for accurate detection of high-quality reservoirs.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 9","pages":"Pages 3583-3598"},"PeriodicalIF":6.1,"publicationDate":"2025-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145223553","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}
Pub Date : 2025-08-01DOI: 10.1016/j.petsci.2025.05.019
Yi Zhao , Dan-Dan Zhu , Fei Wang , Xin-Ping Dai , Hui-Shen Jiao , Zi-Jie Zhou
Measurement-while-drilling (MWD) and guidance technologies have been extensively deployed in the exploitation of oil, natural gas, and other energy resources. Conventional control approaches are plagued by challenges, including limited anti-interference capabilities and the insufficient generalization of decision-making experience. To address the intricate problem of directional well trajectory control, an intelligent algorithm design framework grounded in the high-level interaction mechanism between geology and engineering is put forward. This framework aims to facilitate the rapid batch migration and update of drilling strategies. The proposed directional well trajectory control method comprehensively considers the multi-source heterogeneous attributes of drilling experience data, leverages the generative simulation of the geological drilling environment, and promptly constructs a directional well trajectory control model with self-adaptive capabilities to environmental variations. This construction is carried out based on three hierarchical levels: “offline pre-drilling learning, online during-drilling interaction, and post-drilling model transfer”. Simulation results indicate that the guidance model derived from this method demonstrates remarkable generalization performance and accuracy. It can significantly boost the adaptability of the control algorithm to diverse environments and enhance the penetration rate of the target reservoir during drilling operations.
{"title":"An intelligent drilling guide algorithm design framework based on highly interactive learning mechanism","authors":"Yi Zhao , Dan-Dan Zhu , Fei Wang , Xin-Ping Dai , Hui-Shen Jiao , Zi-Jie Zhou","doi":"10.1016/j.petsci.2025.05.019","DOIUrl":"10.1016/j.petsci.2025.05.019","url":null,"abstract":"<div><div>Measurement-while-drilling (MWD) and guidance technologies have been extensively deployed in the exploitation of oil, natural gas, and other energy resources. Conventional control approaches are plagued by challenges, including limited anti-interference capabilities and the insufficient generalization of decision-making experience. To address the intricate problem of directional well trajectory control, an intelligent algorithm design framework grounded in the high-level interaction mechanism between geology and engineering is put forward. This framework aims to facilitate the rapid batch migration and update of drilling strategies. The proposed directional well trajectory control method comprehensively considers the multi-source heterogeneous attributes of drilling experience data, leverages the generative simulation of the geological drilling environment, and promptly constructs a directional well trajectory control model with self-adaptive capabilities to environmental variations. This construction is carried out based on three hierarchical levels: “offline pre-drilling learning, online during-drilling interaction, and post-drilling model transfer”. Simulation results indicate that the guidance model derived from this method demonstrates remarkable generalization performance and accuracy. It can significantly boost the adaptability of the control algorithm to diverse environments and enhance the penetration rate of the target reservoir during drilling operations.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 8","pages":"Pages 3333-3343"},"PeriodicalIF":6.1,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145048254","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}
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