Pub Date : 2026-02-01Epub Date: 2025-12-13DOI: 10.1016/j.petsci.2025.12.017
Xiang-Yu Kong, Hong Li, Bang-Rui Wu
This paper investigates how sectoral implied energy intensity responds to energy technology progress, using the U.S. shale gas revolution—the most significant energy breakthrough of the 21st century—as a quasi-natural experiment. Using industry-level input-output and trade data, we implement a difference-in-differences (DID) strategy to identify the effects. We find that the shale revolution, on average, increases sectoral implied energy intensity in countries with higher natural gas import demand. The results are robust to alternative specifications, multiple fixed effects, parallel-trend checks, and placebo tests. Mechanism analysis suggests that the rise in implied energy intensity is driven by increased natural gas imports and intensified competition among gas-exporting countries. Heterogeneity analysis further reveals that skill-intensive sectors, transportation, public services, and environmental industries are more responsive to the shale gas technology shock. These findings underscore the spillover effects of the revolution not only on global trade patterns but also on sectoral energy use, highlighting the need for enhanced coordination in energy technology development and energy security strategies.
{"title":"The impact of fossil energy technological progress on sectoral implied energy intensity: Evidence from the U.S. shale gas revolution","authors":"Xiang-Yu Kong, Hong Li, Bang-Rui Wu","doi":"10.1016/j.petsci.2025.12.017","DOIUrl":"10.1016/j.petsci.2025.12.017","url":null,"abstract":"<div><div>This paper investigates how sectoral implied energy intensity responds to energy technology progress, using the U.S. shale gas revolution—the most significant energy breakthrough of the 21st century—as a quasi-natural experiment. Using industry-level input-output and trade data, we implement a difference-in-differences (DID) strategy to identify the effects. We find that the shale revolution, on average, increases sectoral implied energy intensity in countries with higher natural gas import demand. The results are robust to alternative specifications, multiple fixed effects, parallel-trend checks, and placebo tests. Mechanism analysis suggests that the rise in implied energy intensity is driven by increased natural gas imports and intensified competition among gas-exporting countries. Heterogeneity analysis further reveals that skill-intensive sectors, transportation, public services, and environmental industries are more responsive to the shale gas technology shock. These findings underscore the spillover effects of the revolution not only on global trade patterns but also on sectoral energy use, highlighting the need for enhanced coordination in energy technology development and energy security strategies.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 990-997"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417680","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 : 2026-02-01Epub Date: 2025-10-16DOI: 10.1016/j.petsci.2025.10.009
Hui-Long Ma , Xiu-Li Feng , Le-Le Liu , An Zhang , Dong Wang
The effective stress of marine sediments frequently shifts owing to natural or anthropogenic factors, and a broad spectrum of processes fundamentally require accounting for sediment responses to such changes. Marine sediments hosting natural gas hydrates have been regarded as a prospective energy reservoir, and depressurization-driven production efficiency hinges largely on the effective absolute permeability of hydrate-bearing strata. Yet, how this permeability evolves during depressurization remains unresolved, and whether pore-hosted hydrates impede or enhance it remains ambiguous. This study probes the permeability response of hydrate-bearing sands to cyclic loading through isotropic compression/swelling and water flow tests. Results reveal that methane hydrate presence curbs the void-ratio decline yet amplifies the effective-void-ratio reduction during isotropic loading. The effective absolute permeability of hydrate-bearing sands declines with rising hydrate saturation and increasing mean effective stress, and permeability stress sensitivity intensifies at higher hydrate saturations and lower mean effective stresses. The introduced model accurately predicts void-ratio changes during isotropic loading and unloading. Coefficients for strengthening, normal filling, and enhanced filling effects are introduced and quantified to disentangle the positive and negative influences of methane hydrate, with the negative filling effect exceeding the positive strengthening effect by one order of magnitude for quartz sands.
{"title":"Changes in the effective absolute permeability of hydrate-bearing sands during isotropic loading and unloading","authors":"Hui-Long Ma , Xiu-Li Feng , Le-Le Liu , An Zhang , Dong Wang","doi":"10.1016/j.petsci.2025.10.009","DOIUrl":"10.1016/j.petsci.2025.10.009","url":null,"abstract":"<div><div>The effective stress of marine sediments frequently shifts owing to natural or anthropogenic factors, and a broad spectrum of processes fundamentally require accounting for sediment responses to such changes. Marine sediments hosting natural gas hydrates have been regarded as a prospective energy reservoir, and depressurization-driven production efficiency hinges largely on the effective absolute permeability of hydrate-bearing strata. Yet, how this permeability evolves during depressurization remains unresolved, and whether pore-hosted hydrates impede or enhance it remains ambiguous. This study probes the permeability response of hydrate-bearing sands to cyclic loading through isotropic compression/swelling and water flow tests. Results reveal that methane hydrate presence curbs the void-ratio decline yet amplifies the effective-void-ratio reduction during isotropic loading. The effective absolute permeability of hydrate-bearing sands declines with rising hydrate saturation and increasing mean effective stress, and permeability stress sensitivity intensifies at higher hydrate saturations and lower mean effective stresses. The introduced model accurately predicts void-ratio changes during isotropic loading and unloading. Coefficients for strengthening, normal filling, and enhanced filling effects are introduced and quantified to disentangle the positive and negative influences of methane hydrate, with the negative filling effect exceeding the positive strengthening effect by one order of magnitude for quartz sands.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 998-1013"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417835","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 : 2026-02-01Epub Date: 2025-11-25DOI: 10.1016/j.petsci.2025.11.039
Ying Xiong , Peng-Fei Chen , Wan-Fen Pu , Rui Jiang , Qin Pang
CO2 injection is a significant enhanced oil recovery method in shale oil reservoirs and facilitates the mitigation of CO2 emissions. However, the phase behavior and miscibility process of light shale oil and CO2 system in shale reservoirs with widely distributed nanopores remain uncertain. Based on the thermodynamic equilibrium theory and the modified Peng-Robinson equation of state (PR-EOS), a confined fluid model considering the effect of nanoconfinement (critical property shift and adsorption) and capillarity was used to study the phase diagram and thermodynamic property of shale oil-CO2 mixtures. The validity of the fluid model in bulk and in nanopores was verified with the pressure-volume-temperature (PVT) experiments and literature data, respectively. The interfacial tension (IFT) and minimum miscible pressure (MMP) were determined by the Parachor model and IFT vanishing method (VIT), respectively. The effects of pore sizes, temperature and injected gas type and compositions on the IFT and MMP was comprehensively investigated. The result shows that the nanoconfinement effect causes the two-phase region in the phase diagram of reservoir fluids to contract and enhances the ability of CO2 and light components to enter smaller pores, thus reducing the bubble point pressure, oil density, oil viscosity and IFT of shale oil-CO2 mixtures in nanopores. The nanoconfinement effect is more pronounced in pore radius of less than 50 nm, with roughly 16% reduction in the MMP of shale oil-CO2 mixtures. Temperature has a negative effect on the IFT and MMP of shale oil-CO2 mixtures due to the decreased solubility of CO2 under high temperature. The miscibility of CO2 and shale oil is improved by propane (C3H8) and ethane (C2H6), while decreased by methane (CH4).
{"title":"Study on the phase behavior and minimum miscible pressure of CO2-shale oil in nanopores with confinement effect","authors":"Ying Xiong , Peng-Fei Chen , Wan-Fen Pu , Rui Jiang , Qin Pang","doi":"10.1016/j.petsci.2025.11.039","DOIUrl":"10.1016/j.petsci.2025.11.039","url":null,"abstract":"<div><div>CO<sub>2</sub> injection is a significant enhanced oil recovery method in shale oil reservoirs and facilitates the mitigation of CO<sub>2</sub> emissions. However, the phase behavior and miscibility process of light shale oil and CO<sub>2</sub> system in shale reservoirs with widely distributed nanopores remain uncertain. Based on the thermodynamic equilibrium theory and the modified Peng-Robinson equation of state (PR-EOS), a confined fluid model considering the effect of nanoconfinement (critical property shift and adsorption) and capillarity was used to study the phase diagram and thermodynamic property of shale oil-CO<sub>2</sub> mixtures. The validity of the fluid model in bulk and in nanopores was verified with the pressure-volume-temperature (PVT) experiments and literature data, respectively. The interfacial tension (IFT) and minimum miscible pressure (MMP) were determined by the Parachor model and IFT vanishing method (VIT), respectively. The effects of pore sizes, temperature and injected gas type and compositions on the IFT and MMP was comprehensively investigated. The result shows that the nanoconfinement effect causes the two-phase region in the phase diagram of reservoir fluids to contract and enhances the ability of CO<sub>2</sub> and light components to enter smaller pores, thus reducing the bubble point pressure, oil density, oil viscosity and IFT of shale oil-CO<sub>2</sub> mixtures in nanopores. The nanoconfinement effect is more pronounced in pore radius of less than 50 nm, with roughly 16% reduction in the MMP of shale oil-CO<sub>2</sub> mixtures. Temperature has a negative effect on the IFT and MMP of shale oil-CO<sub>2</sub> mixtures due to the decreased solubility of CO<sub>2</sub> under high temperature. The miscibility of CO<sub>2</sub> and shale oil is improved by propane (C<sub>3</sub>H<sub>8</sub>) and ethane (C<sub>2</sub>H<sub>6</sub>), while decreased by methane (CH<sub>4</sub>).</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 777-790"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417833","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 : 2026-02-01Epub Date: 2025-11-28DOI: 10.1016/j.petsci.2025.11.040
Liang-Yu Xia , Yao Wu , Yue-Mei Zhang
Although carbon dioxide enhanced oil recovery (CO2-EOR) is a technically and economically viable option within carbon capture, utilization, and storage (CCUS), its transition from demonstration to commercial application still requires subsidies. Existing research mainly focuses on carbon capture, overlooking the impact of stakeholder interest distribution and subsidy demand differences across the industrial chain. To address this issue, we first investigated the factors influencing subsidy requirements for CO2-EOR projects under a vertically integrated business model. Utilizing the dynamic feedback relationships among these factors, we developed a system dynamics model to assess subsidy demand. Considering CO2-EOR decision flexibility, we used real options analysis to evaluate the value of flexible decisions. Simulation identified three key factors for subsidy stratification: capture method, reservoir depth, and oil displacement efficiency. By calculating from the economic break-even point, we defined subsidy thresholds and developed a graded scheme linked to crude oil prices, considering their impact on policy effectiveness. Using the subsidy intensity of Section 45Q tax credit as a reference for simulation, the results indicate that when crude oil prices reach a certain level, the subsidy demand for projects can drop to zero. Differentiated subsidies reduced the amount required to achieve the same policy objectives by 25%, significantly enhancing policy efficiency.
{"title":"A more efficient subsidy policy for CO2 enhanced oil recovery: Insights from a vertically integrated business model","authors":"Liang-Yu Xia , Yao Wu , Yue-Mei Zhang","doi":"10.1016/j.petsci.2025.11.040","DOIUrl":"10.1016/j.petsci.2025.11.040","url":null,"abstract":"<div><div>Although carbon dioxide enhanced oil recovery (CO<sub>2</sub>-EOR) is a technically and economically viable option within carbon capture, utilization, and storage (CCUS), its transition from demonstration to commercial application still requires subsidies. Existing research mainly focuses on carbon capture, overlooking the impact of stakeholder interest distribution and subsidy demand differences across the industrial chain. To address this issue, we first investigated the factors influencing subsidy requirements for CO<sub>2</sub>-EOR projects under a vertically integrated business model. Utilizing the dynamic feedback relationships among these factors, we developed a system dynamics model to assess subsidy demand. Considering CO<sub>2</sub>-EOR decision flexibility, we used real options analysis to evaluate the value of flexible decisions. Simulation identified three key factors for subsidy stratification: capture method, reservoir depth, and oil displacement efficiency. By calculating from the economic break-even point, we defined subsidy thresholds and developed a graded scheme linked to crude oil prices, considering their impact on policy effectiveness. Using the subsidy intensity of Section 45Q tax credit as a reference for simulation, the results indicate that when crude oil prices reach a certain level, the subsidy demand for projects can drop to zero. Differentiated subsidies reduced the amount required to achieve the same policy objectives by 25%, significantly enhancing policy efficiency.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 979-989"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417681","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 : 2026-02-01Epub Date: 2025-11-08DOI: 10.1016/j.petsci.2025.11.009
Chen-Yu Xu , Ran-Hong Xie , Jiang-Feng Guo , Xiang-Yu Wang , Li-Zhi Xiao , Guo-Wen Jin , Bo-Chuan Jin , Xiao-Long Ju
Continental shale oil reservoirs in China, particularly those of low to medium maturity, contain a high proportion of untransformed solid organic matter (SOM). The SOM plays a critical role as a potential oil and gas resource. Nuclear magnetic resonance (NMR) is a powerful technique for the evaluation of shale oil reservoirs. However, it is challenging for conventional T1-T2 measurement methods to fully capture signals from ultra-short relaxation components such as SOM, due to the measurement deficiency caused by NMR instruments. To this end, the free induction decay (FID) and inversion recovery FID (IR-FID) pulse sequences are introduced, and two novel methods are proposed for quantitative characterization of SOM. The first method, Method I, employs the signal amplitude difference between T2∗ and T1-T2 spectra to obtain the SOM content. The second, Method II, directly quantifies the SOM signal from the T1-T2∗ spectrum. A novel parameter, the ratio of T1/T2∗ to T1/T2, is also proposed to refine the identification of SOM in the T1-T2 spectrum. The effectiveness of the proposed methods is validated by strong correlations with four geochemical parameters indicative of SOM content. The results from Method I show significantly improved correlations with all four geochemical parameters compared to the conventional T1-T2 method. The results from Method II show excellent correlations with parameters from step-by-step (SBS) Rock-Eval pyrolysis, reaching coefficients of determination (R2) as high as 0.8958 and 0.8828. This method also shows strong numerical consistency with the geochemical parameters, specifically with (S1–2b + S2-1+S2-2). Method II is therefore highly suitable for quantitatively evaluating the total solid hydrogen content, including solid petroleum hydrocarbons, bitumen, and kerogen. This work achieves, for the first time, the precise quantification of SOM at the core scale, providing a high-precision, large-scale, and non-destructive approach for evaluating the resource potential of shale oil reservoirs.
{"title":"A novel NMR methodology for the quantitative characterization of solid organic matter in shale oil","authors":"Chen-Yu Xu , Ran-Hong Xie , Jiang-Feng Guo , Xiang-Yu Wang , Li-Zhi Xiao , Guo-Wen Jin , Bo-Chuan Jin , Xiao-Long Ju","doi":"10.1016/j.petsci.2025.11.009","DOIUrl":"10.1016/j.petsci.2025.11.009","url":null,"abstract":"<div><div>Continental shale oil reservoirs in China, particularly those of low to medium maturity, contain a high proportion of untransformed solid organic matter (SOM). The SOM plays a critical role as a potential oil and gas resource. Nuclear magnetic resonance (NMR) is a powerful technique for the evaluation of shale oil reservoirs. However, it is challenging for conventional <em>T</em><sub>1</sub>-<em>T</em><sub>2</sub> measurement methods to fully capture signals from ultra-short relaxation components such as SOM, due to the measurement deficiency caused by NMR instruments. To this end, the free induction decay (FID) and inversion recovery FID (IR-FID) pulse sequences are introduced, and two novel methods are proposed for quantitative characterization of SOM. The first method, Method I, employs the signal amplitude difference between <em>T</em><sub>2</sub><sup>∗</sup> and <em>T</em><sub>1</sub>-<em>T</em><sub>2</sub> spectra to obtain the SOM content. The second, Method II, directly quantifies the SOM signal from the <em>T</em><sub>1</sub>-<em>T</em><sub>2</sub><sup>∗</sup> spectrum. A novel parameter, the ratio of <em>T</em><sub>1</sub>/<em>T</em><sub>2</sub><sup>∗</sup> to <em>T</em><sub>1</sub>/<em>T</em><sub>2</sub>, is also proposed to refine the identification of SOM in the <em>T</em><sub>1</sub>-<em>T</em><sub>2</sub> spectrum. The effectiveness of the proposed methods is validated by strong correlations with four geochemical parameters indicative of SOM content. The results from Method I show significantly improved correlations with all four geochemical parameters compared to the conventional <em>T</em><sub>1</sub>-<em>T</em><sub>2</sub> method. The results from Method II show excellent correlations with parameters from step-by-step (SBS) Rock-Eval pyrolysis, reaching coefficients of determination (<em>R</em><sup>2</sup>) as high as 0.8958 and 0.8828. This method also shows strong numerical consistency with the geochemical parameters, specifically with (<em>S</em><sub>1–2b</sub> + <em>S</em><sub>2-1</sub>+<em>S</em><sub>2-2</sub>). Method II is therefore highly suitable for quantitatively evaluating the total solid hydrogen content, including solid petroleum hydrocarbons, bitumen, and kerogen. This work achieves, for the first time, the precise quantification of SOM at the core scale, providing a high-precision, large-scale, and non-destructive approach for evaluating the resource potential of shale oil reservoirs.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 680-691"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147418367","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 : 2026-02-01Epub Date: 2025-10-25DOI: 10.1016/j.petsci.2025.10.021
Jun-Qing Guo , Peng-Hui Liu , De-Zhi Sun , Chun-Sheng Lu , Yu-Qing Wang , Wei Li
Soft coal seams with low porosity are prone to water-blocking during mid to late stages of coalbed methane production, reducing gas recovery. To address this, an electroosmosis-driven drainage strategy was proposed in this paper, based on the charged properties of soft coal in water. Three coal ranks (anthracite, coking coal, and long-flame coal) were tested using a custom electroosmotic drainage device. Electrical properties were characterized, and the effects of potential gradients on drainage were analyzed. Fluorescent particle tracing and Fourier-transform infrared spectroscopy were used to explore residual water migration. It is shown that electroosmosis can significantly enhance drainage across all coal ranks. For coking and long-flame coals, drainage increases with voltage before stabilizing; anthracite exhibits peaked at 4 V/cm. The fluorescent tracing reveals water coalescence and migration. Long-flame coal shows best, linked to optimal higher hydroxyl content and electronegativity. Electroosmotic force, governed by pH, hydroxyl content, and field strength, enables directional water transport. Finally, an engineering design is suggested to reduce water-blocking and enhance coalbed methane recovery.
{"title":"Mechanism and influencing factors of electroosmosis-driven residual water drainage in soft coal seams during coalbed methane recovery","authors":"Jun-Qing Guo , Peng-Hui Liu , De-Zhi Sun , Chun-Sheng Lu , Yu-Qing Wang , Wei Li","doi":"10.1016/j.petsci.2025.10.021","DOIUrl":"10.1016/j.petsci.2025.10.021","url":null,"abstract":"<div><div>Soft coal seams with low porosity are prone to water-blocking during mid to late stages of coalbed methane production, reducing gas recovery. To address this, an electroosmosis-driven drainage strategy was proposed in this paper, based on the charged properties of soft coal in water. Three coal ranks (anthracite, coking coal, and long-flame coal) were tested using a custom electroosmotic drainage device. Electrical properties were characterized, and the effects of potential gradients on drainage were analyzed. Fluorescent particle tracing and Fourier-transform infrared spectroscopy were used to explore residual water migration. It is shown that electroosmosis can significantly enhance drainage across all coal ranks. For coking and long-flame coals, drainage increases with voltage before stabilizing; anthracite exhibits peaked at 4 V/cm. The fluorescent tracing reveals water coalescence and migration. Long-flame coal shows best, linked to optimal higher hydroxyl content and electronegativity. Electroosmotic force, governed by pH, hydroxyl content, and field strength, enables directional water transport. Finally, an engineering design is suggested to reduce water-blocking and enhance coalbed methane recovery.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 791-803"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417834","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}
Since shale gas is a valuable energy resource, effective planning for its extraction and utilization depends on precise forecasting of gas well production. Conventional models need long computation time, a wide range of geological and fluid data, and suffer from unstable predictions. To develop a low-cost, intelligent, and reliable forecast system for shale gas production, a hybrid Temporal Convolutional Network-Policy Gradient Informer (TCN-PgInformer) model was constructed for multivariate production prediction research. This model is based on the Informer model of its own unique self-attention mechanism, which lowers the temporal complexity of conventional self-attention technique while increasing the model’s accuracy. Meanwhile, to completely avoid the gradient vanishing problem, the dilated convolutions of TCN structure are employed to extract the long-term dependency relationships. Ultimately, a policy gradient (Pg) algorithm is introduced to enhance the parameter training speed. The results indicate that the daily gas production may be accurately predicted by TCN-PgInformer model. A detailed performance comparison was carried out among TCN-PgInformer, CNN, GRU and CNN-LSTM models in the literature. The comparison demonstrates that the suggested TCN-PgInformer model outperforms existing techniques. For four different gas production stages, the MAPE/RMSE error of other models is 2–12 times higher than that of the TCN-PgInformer model, while the R2 accuracy of TCN-PgInformer model can be as high as 1 time higher than other models. Therefore, the designed model has excellent applicability, which offers reference and guidance for shale gas development.
{"title":"A machine learning method for evaluating shale gas production based on the TCN-PgInformer model","authors":"Hao-Yu Zhang , Wen-Sheng Wu , Zhang-Xin Chen , Benjieming Liu","doi":"10.1016/j.petsci.2025.11.022","DOIUrl":"10.1016/j.petsci.2025.11.022","url":null,"abstract":"<div><div>Since shale gas is a valuable energy resource, effective planning for its extraction and utilization depends on precise forecasting of gas well production. Conventional models need long computation time, a wide range of geological and fluid data, and suffer from unstable predictions. To develop a low-cost, intelligent, and reliable forecast system for shale gas production, a hybrid Temporal Convolutional Network-Policy Gradient Informer (TCN-PgInformer) model was constructed for multivariate production prediction research. This model is based on the Informer model of its own unique self-attention mechanism, which lowers the temporal complexity of conventional self-attention technique while increasing the model’s accuracy. Meanwhile, to completely avoid the gradient vanishing problem, the dilated convolutions of TCN structure are employed to extract the long-term dependency relationships. Ultimately, a policy gradient (Pg) algorithm is introduced to enhance the parameter training speed. The results indicate that the daily gas production may be accurately predicted by TCN-PgInformer model. A detailed performance comparison was carried out among TCN-PgInformer, CNN, GRU and CNN-LSTM models in the literature. The comparison demonstrates that the suggested TCN-PgInformer model outperforms existing techniques. For four different gas production stages, the MAPE/RMSE error of other models is 2–12 times higher than that of the TCN-PgInformer model, while the <em>R</em><sup>2</sup> accuracy of TCN-PgInformer model can be as high as 1 time higher than other models. Therefore, the designed model has excellent applicability, which offers reference and guidance for shale gas development.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 643-655"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147418371","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 : 2026-02-01Epub Date: 2025-09-17DOI: 10.1016/j.petsci.2025.09.021
Yu Du , Hu-Cheng Deng , Xiao-Fei Hu , Hao-Tian Zhang , Hong-Hui Wang , Cui-Li Wang , Mao-Xin Liu , Chen-Yang Zhao , Shang-Rong Guo , Zi-Yun Zheng
Natural fractures serve as the primary storage spaces and flow pathways in deep to ultra-deep tight sandstone reservoirs, directly influencing hydrocarbon accumulation, preservation, and production. Borehole images offer intuitive, continuous, and high-resolution identification of natural fractures along the entire borehole. However, relying solely on complete sinusoidal curves from borehole images for fracture identification may lead to omissions, as it overlooks cases where these curves are incomplete or truncated. To address the problems and deficiencies in fracture identification, this study systematically classifies borehole image feature patterns based on core-to-log spatial position restoring. A bidirectional comparison is conducted between natural fractures in cores and the fracture image features in borehole images. A quantitative relationship between fracture dip angle, thin layer thickness and borehole radius was established, accompanied by a mathematical expression describing the fracture curve morphology was proposed. These findings enabled the development of an imaging response pattern for natural fractures in deep and ultra-deep tight sandstone reservoirs, incorporating key parameters such as dip angle, through-layer connectivity, and spatial position within the borehole. In the Bashijiqike–Baxigai tight-sandstone reservoirs of the Bozi–Dabei area, we estimate that approximately 24% of core-observed fractures display distinct linear-pattern features on borehole images, whereas approximately 91% of borehole images features can be correlated with fractures observed in core. Fracture identification rates for natural fractures increased by 17% in water-based mud and by 3% in oil-based mud through the application of the natural fracture image response pattern. Moreover, this study analyzes the deviations in the matching between core fractures and image features. Finally, we further discuss the common sources of error in natural fracture identification using borehole images from multiple perspectives, including missing core responses, inconsistencies between core and borehole image features, distortion of fracture chord curve, inaccurate fracture count, misclassification of fractures, and variations in interpretation under different mud systems. The research addresses the blind spots of traditional methods in fracture identification within thin layers, not only enhancing the detection rate of natural fractures but also further improving the accuracy of fracture recognition. At the same time, it will contribute to the optimization of fracture characterization, reservoir evaluation, and production forecasting, providing a more reliable data foundation for exploration and development under complex geological conditions.
{"title":"Fracture response patterns in deep to ultra-deep tight sandstones: A comparison based on core and borehole images","authors":"Yu Du , Hu-Cheng Deng , Xiao-Fei Hu , Hao-Tian Zhang , Hong-Hui Wang , Cui-Li Wang , Mao-Xin Liu , Chen-Yang Zhao , Shang-Rong Guo , Zi-Yun Zheng","doi":"10.1016/j.petsci.2025.09.021","DOIUrl":"10.1016/j.petsci.2025.09.021","url":null,"abstract":"<div><div>Natural fractures serve as the primary storage spaces and flow pathways in deep to ultra-deep tight sandstone reservoirs, directly influencing hydrocarbon accumulation, preservation, and production. Borehole images offer intuitive, continuous, and high-resolution identification of natural fractures along the entire borehole. However, relying solely on complete sinusoidal curves from borehole images for fracture identification may lead to omissions, as it overlooks cases where these curves are incomplete or truncated. To address the problems and deficiencies in fracture identification, this study systematically classifies borehole image feature patterns based on core-to-log spatial position restoring. A bidirectional comparison is conducted between natural fractures in cores and the fracture image features in borehole images. A quantitative relationship between fracture dip angle, thin layer thickness and borehole radius was established, accompanied by a mathematical expression describing the fracture curve morphology was proposed. These findings enabled the development of an imaging response pattern for natural fractures in deep and ultra-deep tight sandstone reservoirs, incorporating key parameters such as dip angle, through-layer connectivity, and spatial position within the borehole. In the Bashijiqike–Baxigai tight-sandstone reservoirs of the Bozi–Dabei area, we estimate that approximately 24% of core-observed fractures display distinct linear-pattern features on borehole images, whereas approximately 91% of borehole images features can be correlated with fractures observed in core. Fracture identification rates for natural fractures increased by 17% in water-based mud and by 3% in oil-based mud through the application of the natural fracture image response pattern. Moreover, this study analyzes the deviations in the matching between core fractures and image features. Finally, we further discuss the common sources of error in natural fracture identification using borehole images from multiple perspectives, including missing core responses, inconsistencies between core and borehole image features, distortion of fracture chord curve, inaccurate fracture count, misclassification of fractures, and variations in interpretation under different mud systems. The research addresses the blind spots of traditional methods in fracture identification within thin layers, not only enhancing the detection rate of natural fractures but also further improving the accuracy of fracture recognition. At the same time, it will contribute to the optimization of fracture characterization, reservoir evaluation, and production forecasting, providing a more reliable data foundation for exploration and development under complex geological conditions.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 541-562"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417949","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 : 2026-02-01Epub Date: 2025-10-17DOI: 10.1016/j.petsci.2025.10.008
Wen Zhang , Qian-Ping Wang , Wen-Hui Liu , Ping-Ping Shi , Hou-Yong Luo , Peng Liu , Xiao-Yan Chen , Qian Zhang , Xiao-Feng Wang , Dong-Dong Zhang , Yi-Ran Wang , Fu-Qi Li
The discovery of high-yield industrial gas flows in the limestone layer of the Permian Taiyuan Formation in the Ordos Basin highlights promising prospects for natural gas exploration and has positioned this region as a key exploration area. However, research on the origin and distribution of natural gas in the Taiyuan Limestone Formation, especially its hydrocarbon generation potential and whether these organically enriched limestones can serve as effective source rocks, remains limited. In this study, we aimed to analyse the composition and carbon isotopes of the Upper Palaeozoic Taiyuan Limestone Formation natural gas, including propane-specific isotopes. The isotopic data were compared with coal-type gases from the corresponding strata and oil-type gases from the Lower Palaeozoic carbonate strata. Natural gas in the Upper Palaeozoic Taiyuan Limestone Formation was markedly distinct from the ‘self-generated and self-accumulated’ oil-type gas in the Lower Palaeozoic subsalt strata, indicating no obvious correlation between the two gases. The results did not support the notion that large-scale natural gas accumulations in the Lower Palaeozoic carbonate formations could be originated from Upper Palaeozoic limestone source rocks. The natural gas in the Upper Palaeozoic Taiyuan Limestone Formation was highly consistent with the typical coal-type gas from the Upper Paleozoic. The geochemical characteristics of the natural gas in the region were consistent with that of conventional natural gas, the position-specific isotopic composition of propane ΔC−T values had a narrow, positive. This showed that the gas in the Taiyuan Limestone Formation was derived from type III kerogen, and propane mainly generated through the n-C3H7 free radical pathway. Geochemical analyses of the Taiyuan Limestone source rocks, such as the determination of total organic carbon, kerogen carbon isotopes, organic macerals. Combined with the geochemical analysis of natural gas, it revealed low abundance of organic matter but good kerogen types, predominantly type II–III, at a late to high-maturity evolution stage. Although the formation had certain hydrocarbon generation potential, it falls short of the hydrocarbon generation capacity of the Carboniferous–Permian coal measure source rocks. At present, there is no large–scale hydrocarbon generation, and it is not enough to provide hydrocarbon for the Lower Paleozoic.
{"title":"Geochemical characteristics and sources of natural gas in the Upper Paleozoic limestone strata, Ordos Basin","authors":"Wen Zhang , Qian-Ping Wang , Wen-Hui Liu , Ping-Ping Shi , Hou-Yong Luo , Peng Liu , Xiao-Yan Chen , Qian Zhang , Xiao-Feng Wang , Dong-Dong Zhang , Yi-Ran Wang , Fu-Qi Li","doi":"10.1016/j.petsci.2025.10.008","DOIUrl":"10.1016/j.petsci.2025.10.008","url":null,"abstract":"<div><div>The discovery of high-yield industrial gas flows in the limestone layer of the Permian Taiyuan Formation in the Ordos Basin highlights promising prospects for natural gas exploration and has positioned this region as a key exploration area. However, research on the origin and distribution of natural gas in the Taiyuan Limestone Formation, especially its hydrocarbon generation potential and whether these organically enriched limestones can serve as effective source rocks, remains limited. In this study, we aimed to analyse the composition and carbon isotopes of the Upper Palaeozoic Taiyuan Limestone Formation natural gas, including propane-specific isotopes. The isotopic data were compared with coal-type gases from the corresponding strata and oil-type gases from the Lower Palaeozoic carbonate strata. Natural gas in the Upper Palaeozoic Taiyuan Limestone Formation was markedly distinct from the ‘self-generated and self-accumulated’ oil-type gas in the Lower Palaeozoic subsalt strata, indicating no obvious correlation between the two gases. The results did not support the notion that large-scale natural gas accumulations in the Lower Palaeozoic carbonate formations could be originated from Upper Palaeozoic limestone source rocks. The natural gas in the Upper Palaeozoic Taiyuan Limestone Formation was highly consistent with the typical coal-type gas from the Upper Paleozoic. The geochemical characteristics of the natural gas in the region were consistent with that of conventional natural gas, the position-specific isotopic composition of propane Δ<sub>C−T</sub> values had a narrow, positive. This showed that the gas in the Taiyuan Limestone Formation was derived from type III kerogen, and propane mainly generated through the <em>n</em>-C<sub>3</sub>H<sub>7</sub> free radical pathway. Geochemical analyses of the Taiyuan Limestone source rocks, such as the determination of total organic carbon, kerogen carbon isotopes, organic macerals. Combined with the geochemical analysis of natural gas, it revealed low abundance of organic matter but good kerogen types, predominantly type II–III, at a late to high-maturity evolution stage. Although the formation had certain hydrocarbon generation potential, it falls short of the hydrocarbon generation capacity of the Carboniferous–Permian coal measure source rocks. At present, there is no large–scale hydrocarbon generation, and it is not enough to provide hydrocarbon for the Lower Paleozoic.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 582-595"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417950","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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