Geoenergy Science and Engineering最新文献

{"title":"High-Fidelity saturation prediction using physics-informed attention neural network","authors":"Yinhong Tian ,&nbsp;Guiwen Wang ,&nbsp;Hongbin Li ,&nbsp;Jin Lai","doi":"10.1016/j.geoen.2025.214246","DOIUrl":"10.1016/j.geoen.2025.214246","url":null,"abstract":"<div><div>Accurate estimation of water saturation is critical for reservoir characterization and optimal production strategies in ultra-deep tight sandstone gas reservoirs. However, traditional empirical models often fail to provide reliable predictions due to the inherent heterogeneity and nonlinear interactions within these reservoirs. To address these challenges, this paper proposes the Saturation Neural Network (SatuNN), a novel deep learning framework that combines CNNs, window attention, axial attention and BiLSTM to capture multi-scale spatiotemporal features from logging data. Specifically, the CNNs and window attention layers capture local spatial features, while the BiLSTM and axial attention layers address global temporal dependencies. The proposed model leverages a physics-informed neural network strategy to embed petrophysical constraints directly into the training process, ensuring physically consistent and geologically meaningful predictions. Comprehensive evaluations using core and logging data from ultradeep tight sandstone reservoirs in the Tuha Basin demonstrate that SatuNN achieves superior predictive accuracy and significantly lower errors (R² = 0.92, MAE = 3.27 %) compared to both the optimal ablation baseline model (Without WA: R² = 0.86, MAE = 4.51 %) and traditional petrophysical model (Archie: R² = 0.84, MAE = 4.83 %). Moreover, successful field applications in two blind-test wells further validate the robustness and practical applicability of the proposed model. The presented SatuNN framework provides an accurate approach for saturation prediction in ultradeep tight sandstone gas reservoirs, effectively offering potential to improve reservoir evaluation and field development strategies.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214246"},"PeriodicalIF":4.6,"publicationDate":"2025-10-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145267889","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Frictional properties of proppant-filled fractures/faults under a shear-flow condition and the implication for fracture/fault stability during geoenergy extraction","authors":"Liuke Huang ,&nbsp;Lingjun Pei ,&nbsp;Yuhong Lin ,&nbsp;Mengke An ,&nbsp;Xiaoyong Wen ,&nbsp;Junqing Lu ,&nbsp;Fengyuan Zhang ,&nbsp;Jinshuo Yan ,&nbsp;Zhen Zhong","doi":"10.1016/j.geoen.2025.214251","DOIUrl":"10.1016/j.geoen.2025.214251","url":null,"abstract":"<div><div>With the global expansion of geoenergy extraction, the fault stability associated with the industry exploitation have drawn extensive attention. During the hydraulic fracturing process, proppants are usually injected into the fractures together with the fracturing fluid to maintain the permeability of the reservoir. However, the mechanism by which proppants affect the shear behavior of fractures during the injection process has not been clearly explored, and this may change the shear motion state of faults. In this study, granite was used as the experimental material to simulate fractures, and ceramic sand (&lt;106 μm) were used as the fracture filling medium. The evolution of the frictional strength and frictional stability of fractures containing proppants under double direct shear conditions was investigated, and the effects of changes in normal stress, fluid flow rate of water, and shear velocity were studied. The results show that as the normal stress increases, the friction coefficient continuously decreases. When the normal stress is relatively high, the friction coefficient shows a decreasing trend with the increase in the fluid flow rate of water. At a lower fluid flow rate, the value of frictional stability (<em>a</em> – <em>b</em>) also increases with the increase in normal stress. The value of (<em>a</em> – <em>b</em>) is only negative when the normal stress is 1 MPa, and when the normal stress is increased to 2 MPa, all values of (<em>a</em> – <em>b</em>) are positive. The transient changes in frictional strength follow the same trend as the step changes in shear rate. Under the same normal stress, The fluid flow rate has a non-linear effect on the value of (<em>a</em> – <em>b</em>). These findings enable a deeper understanding of the possible impacts of granular proppant on fault frictional stability during the geoenergy extraction.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214251"},"PeriodicalIF":4.6,"publicationDate":"2025-10-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145267890","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"How industrial agglomeration and technological innovation affect carbon emission efficiency: Evidence from China","authors":"Qinghua Pang ,&nbsp;Huilin Zhai ,&nbsp;Tianxin Zhao ,&nbsp;Lina Zhang ,&nbsp;Yung-ho Chiu","doi":"10.1016/j.geoen.2025.214256","DOIUrl":"10.1016/j.geoen.2025.214256","url":null,"abstract":"<div><div>Despite growing attention to the nonlinear effect of industrial agglomeration on carbon emission efficiency, the critical role of technological innovation as a threshold variable in shaping the nonlinear dynamic remains underexplored. Herein, revealing the influence of industrial agglomeration on carbon emission efficiency in 30 provinces spanning 2006 to 2019 using a spatial Durbin model (SDM). Regional and industrial heterogeneities are also further discussed. Subsequently, the threshold role of technological innovation in the relationship between carbon emission efficiency and industrial agglomeration was tested by adopting a threshold panel model. The results showed: (1) A significant inverted “U-shaped” relationship was found to exist between industrial agglomeration and carbon emission efficiency. (2) The eastern region had a greater industrial agglomeration inflection point than the central and western regions. Capital and technology-intensive industries had more sustainable agglomeration advantages than resource-intensive and labor-intensive industries. (3) With the further development of technological innovation (TEC&gt;0.067), the positive influence of industrial agglomeration on carbon emission efficiency shifted from strong to weak. This study enables policymakers to leverage the technological innovation threshold as an actionable benchmark, strategically timing industrial agglomeration interventions to maximize decarbonization returns while avoiding scale-driven efficiency traps.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214256"},"PeriodicalIF":4.6,"publicationDate":"2025-10-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145267892","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Review of key technologies for ultra-deep carbonate reservoir development: Acid fracturing and challenges","authors":"Xiang Chen ,&nbsp;Qisheng Huang ,&nbsp;Pingli Liu ,&nbsp;Juan Du ,&nbsp;Haitai Hu ,&nbsp;Fei Liu ,&nbsp;Yucheng Jia ,&nbsp;Mingxin Lei","doi":"10.1016/j.geoen.2025.214247","DOIUrl":"10.1016/j.geoen.2025.214247","url":null,"abstract":"<div><div>As oil and gas exploration moves into deeper and ultra-deep carbonate reservoirs, ultra-high temperature and high pressure (UHTHP) conditions pose serious challenges for acid fracturing. However, a comprehensive review framework covering the full acid fracturing process under UHTHP conditions is still lacking. This review summarizes recent progress in acid fracturing under UHTHP environments. First, it examines acid-rock reaction kinetics, focusing on acid rheology under UHTHP and its impact on reaction rates, while comparing retardation mechanisms across different acid systems. Second, it reviews the effects of acid etching on the mechanical weakening of carbonate rocks and discusses constitutive models based on damage mechanics. Fracture conductivity prediction methods are also evaluated, with emphasis on their current limitations. Third, the review highlights the role of multi-stage alternating acid fracturing in enhancing non-uniform etching and improving fracture conductivity, especially under high closure stress. Finally, it outlines key research gaps in reaction modeling, mechanical degradation, and acid fracturing optimization under UHTHP conditions. The findings indicate that current kinetic models and conductivity prediction methods are poorly applicable to UHTHP environments, and that acid-induced weakening mechanisms require further investigation. This work provides theoretical insight and practical guidance for the design and optimization of acid fracturing in ultra-deep carbonate reservoirs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214247"},"PeriodicalIF":4.6,"publicationDate":"2025-10-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145267893","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Application of multiscale technology to oil and gas field development: A review of the state of the art in chemical modification of rock wettability","authors":"Haoxuan Zheng ,&nbsp;Yongmin Shi ,&nbsp;Yu Tian ,&nbsp;Xiaolong Yan ,&nbsp;Lin Yang ,&nbsp;Junyao Chen ,&nbsp;Xun Tian ,&nbsp;Weiyu Bi","doi":"10.1016/j.geoen.2025.214239","DOIUrl":"10.1016/j.geoen.2025.214239","url":null,"abstract":"<div><div>With the gradual depletion of global petroleum resources, an in-depth understanding and precise control of reservoir wettability has become key to enhancing oil recovery. This review systematically examines the research progress and application prospects of various chemical agents—including surfactants, chelating agents, nanomaterials, modified brines and alkali solutions, and polymers—in controlling reservoir wettability. Current studies are primarily based on crude oil characteristics and natural core samples, and are constrained by the complexity of mineral composition and crude oil chemistry. Future experiments should systematically investigate the interactions between active crude oil components and rock minerals, and employ advanced characterization techniques to deepen understanding of wettability-control mechanisms. Although most surfactants are cost-effective, their stability in complex reservoir environments is poor, which limits their application. Emerging gemini and composite surfactants have demonstrated good potential for wettability alteration; future research should develop highly adaptable surfactants through multi-ion synergistic effects. The selection of chelating agents and operational parameters requires further optimization, and their wettability-control mechanisms and synergistic effects with surfactants should be elucidated. The application of nanomaterials in wettability modification is still in its early stage, with issues such as colloidal stability and adsorption kinetics requiring further investigation. Despite the risk of pore-throat blockage in high-salinity, low-permeability reservoirs, optimizing nanomaterial formulations remains an effective solution. Low-mineralization water injection shows application potential, but its water-source compatibility and production-enhancement mechanisms remain controversial. Future efforts should focus on developing efficient, alkali-free composite flooding systems to overcome current technological bottlenecks. Field deployment still faces multiple challenges, including adsorption loss, precipitation plugging, formation damage, and cost-environmental concerns; it is recommended to optimize formulations and injection strategies through refined pilot tests, while developing green, biodegradable multi-component chemicals to achieve large-scale application of chemical EOR. This study also explores multiscale techniques for chemical-induced wettability alteration, providing novel insights and integrated strategies for advancing wettability-control research, ultimately aiming to bridge theoretical knowledge and field application in oil and gas extraction.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214239"},"PeriodicalIF":4.6,"publicationDate":"2025-10-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145267127","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Thermo-hydro-chemical coupling model of acid treatment in complex carbonate geothermal reservoirs","authors":"Xiang Chen ,&nbsp;Qisheng Huang ,&nbsp;Pingli Liu ,&nbsp;Juan Du ,&nbsp;Fei Liu ,&nbsp;Yucheng Jia ,&nbsp;Haohang Liu","doi":"10.1016/j.geoen.2025.214242","DOIUrl":"10.1016/j.geoen.2025.214242","url":null,"abstract":"<div><div>Permeability reduction due to mineral scaling, particle migration, and geochemical interactions is a critical challenge in carbonate geothermal reservoirs, significantly affecting the efficiency of Enhanced Geothermal Systems. Acid treatment is widely used to restore permeability by dissolving blockages and creating wormholes, thereby improving reservoir flow and heat transfer. However, existing acidizing models often neglect the effects of fracture blockage and reaction heat. To address these gaps, this study develops a thermo-hydro-chemical coupled model that integrates fluid dynamics, acid transport, thermal effects, and acid-rock reactions in a two-dimensional representation of a fractured carbonate geothermal reservoir. The model is formulated using the Stokes-Brinkman equation, the first and second laws of thermodynamics, Fick's law, the Arrhenius equation, and the Kozeny-Carman relationship to accurately capture wormhole propagation. A grid independence study ensures numerical stability, and the model is validated against published experimental results, confirming its reliability in predicting acid-rock interactions. Simulation results reveal that fracture blockage significantly alters acid flow paths, and if permeability within blocked fractures falls below that of the surrounding matrix, acid bypasses the fractures, increasing acid treatment costs. Furthermore, reaction heat plays a crucial role in wormhole propagation, with elevated temperatures accelerating acid consumption and altering dissolution patterns. The study also emphasizes the necessity of real-time monitoring of fracture conditions, as sudden changes in injection pressure or production flow rate may indicate blockage formation requiring intervention. This study provides theoretical guidance for efficient acid treatment in carbonate geothermal reservoirs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214242"},"PeriodicalIF":4.6,"publicationDate":"2025-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145267133","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Wellbore thermo-mechanical response during CO2 mixture geological sequestration in depleted reservoirs","authors":"Hui Li ,&nbsp;Jun Li ,&nbsp;Wei Lian ,&nbsp;Hui Zhang ,&nbsp;Jinlu Liu","doi":"10.1016/j.geoen.2025.214244","DOIUrl":"10.1016/j.geoen.2025.214244","url":null,"abstract":"<div><div>The wellbore serves as a critical channel for fluid injection during CO₂ geological sequestration. Accurate prediction of wellbore injection fluid properties, temperature-pressure evolution, and tubing mechanical responses is essential for safe CO₂ storage in depleted wells. This study established a comprehensive model incorporating real-time variations in mixed gas physical and thermodynamic properties with corrections for high-pressure conditions. The model accounts for intermolecular forces, Joule-Thomson effects, and viscous heat sources, while coupling these with tubing mechanical changes to simulate wellbore evolution during CO₂ mixture injection. Model validation against field measurements demonstrated high reliability and accuracy. Using this model, we analyzed wellbore temperature-pressure and tubing mechanical evolution under various injection parameters for different gas mixtures (CO₂, N₂, O₂, CH₄) and examined tubing loads' impact on sealing performance. Results indicate that mixture compositions minimally affect wellbore temperature but significantly influence pressure and density. Higher CO₂ concentrations increase bottomhole pressures and fluid densities. Injection temperature substantially affects shallow sections, with high-temperature injection exhibiting temperature inversion. Injection pressure and rate significantly influence wellbore conditions and tubing forces. Early injection periods show pronounced effects that gradually stabilize. Analysis of sealing loads revealed that low-temperature injection compromises wellhead hanger performance, while high-temperature injection affects bottomhole packer integrity. These findings provide valuable guidance for optimizing CO2 mixture injection parameters and wellbore sealing performance.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214244"},"PeriodicalIF":4.6,"publicationDate":"2025-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145267888","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Predicting CO2 solubility in water and brines using advanced machine learning models","authors":"Kun Liu ,&nbsp;Xiao-Qiang Bian ,&nbsp;Jing Chen ,&nbsp;Jian Li ,&nbsp;Yu-Peng Wang","doi":"10.1016/j.geoen.2025.214234","DOIUrl":"10.1016/j.geoen.2025.214234","url":null,"abstract":"<div><div>Carbon capture and storage (CCS) is a crucial technology for reducing industrial emissions, and its effectiveness is related to the prediction of CO₂ solubility. However, existing studies are typically limited to modeling specific water/brine systems and lack practical engineering validation. Therefore, this study proposes a CO₂ solubility model applicable to pure water, single-salt solutions, and mixed-salt solutions. A database containing 3383 experimental data entries was constructed from the published literature. Input variables include temperature, pressure, and salt concentrations of NaCl, KCl, Na₂SO₄, MgCl₂, and CaCl₂, and the output variable is CO₂ solubility. To improve the accuracy of CO₂ solubility prediction, we apply three optimization algorithms—Artificial Lemming Algorithm (ALA), Black-winged Kite Algorithm (BKA), and IVY Algorithm (IVYA)—to fine-tune two machine learning (ML) models: Light Gradient Boosting Machine (LightGBM) and eXtreme Gradient Boosting (XGBoost). The results were compared with the Cubic-Plus-Association (CPA) equation of state (EoS) combined with the MHV1 mixing rule (CPA-MHV1). Findings indicate that among all the models considered in this paper, BKA-LightGBM stands out for its high accuracy and low computational cost, with R² = 0.9930, RMSE = 0.0007 and AARD = 7.41 %, outperforming the CPA-MHV1 model in prediction accuracy. In addition, SHapley Additive exPlanations (SHAP) indicated that pressure is the most influential input parameter for model output. The leverage approach based on the Williams plot verified the reliability of the data, with 90.63 % of the samples distributed within a leverage threshold of 0.3, effectively minimizing the influence of outliers. Cross-validation and external validation demonstrated that the BKA-LightGBM model can be effectively applied to CCS engineering, for applications such as CO₂ capture via dissolution. These results suggest that the BKA-LightGBM model has strong potential to support the development of efficient and practical <span>CCS</span> technologies.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214234"},"PeriodicalIF":4.6,"publicationDate":"2025-10-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145267126","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Analysis of oil recovery efficiency based on nuclear magnetic resonance in porous media under the action of electric field: insights from microstructure and pore scale analysis","authors":"Qiang Li ,&nbsp;Zhengfu Ning ,&nbsp;Yuheng Yang ,&nbsp;Xiqian Zheng ,&nbsp;Jun Li ,&nbsp;Zejiang Jia","doi":"10.1016/j.geoen.2025.214241","DOIUrl":"10.1016/j.geoen.2025.214241","url":null,"abstract":"<div><div>Carbonate reservoirs, critical to global hydrocarbon resources, face development challenges due to heterogeneous multi-scale pore structures, resulting in severe water channeling and low recovery rates (&lt;30 %) during conventional waterflooding. While direct current (DC) electric field-assisted oil displacement offers efficient, cost-effective, and eco-friendly potential, its microscopic mechanisms remain underexplored. This study combines multi-scale pore characterization and core flooding experiments to systematically evaluate electric field effects on multiphase flow in heterogeneous reservoirs, emphasizing pore-scale electro-osmosis–electrophoresis synergy. Analyses of a calcite-dominated carbonate formation (95 % calcite, inter/intragranular porosity, poor connectivity) using scanning electron microscope (SEM), thin-section petrography, mercury intrusion, and nuclear magnetic resonance spectroscopy (NMR) revealed limited conventional waterflooding performance (25 %–28 % recovery), primarily mobilizing macropores (&gt;100 μm). Applying a 20V DC electric field increased recovery by 10.6 %, with an optimized “post-water-free electric drive” strategy adding 7.57 % incremental recovery. Even in long heterogeneous cores, a sustained 4.7 % recovery gain demonstrated field applicability. NMR confirmed enhanced oil mobilization in mesopores (10–100 μm), expanding accessible pore networks. Kinetic analysis identified dual mechanisms: Optimal displacement pressure gradients (0.5–0.6 MPa/cm) stabilized injection pressure, suppressed water channeling, and delayed water breakthrough; Intensified electro-osmosis promoted ion-directed migration, dynamically stabilizing pressure fields while reducing water consumption by ∼10 %. These processes synergistically improved displacement efficiency across pore scales. The study demonstrates DC electric fields effectively regulate multi-scale pore utilization and optimize seepage field distribution, providing mechanistic insights and engineering guidelines for carbonate reservoir development. By enhancing recovery efficiency while reducing water use and injection energy requirements, this approach demonstrates potential for low-carbon hydrocarbon recovery, supporting sustainable energy transitions.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214241"},"PeriodicalIF":4.6,"publicationDate":"2025-10-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145267132","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Cooperative operation optimization of natural gas pipeline network and underground gas storage: economic scheduling and low-carbon control","authors":"Jinghong Peng,&nbsp;Longyu Chen,&nbsp;Guangchuan Liang,&nbsp;Jun Zhou,&nbsp;Zichen Li,&nbsp;Can Qin,&nbsp;Shitao Liu","doi":"10.1016/j.geoen.2025.214243","DOIUrl":"10.1016/j.geoen.2025.214243","url":null,"abstract":"<div><div>With the growth in natural gas consumption and the implementation of the “Dual Carbon” policy, supply-demand balance and low-carbon management of natural gas pipeline network (NGPN) system are facing important challenges. This paper established a comprehensive economic and environmental optimization model of NGPN system integrating the structural and hydraulic characteristics of underground gas storage (UGS) to respond the multi-period changes of user demand by deciding the NGPN scheduling and UGS injection-withdrawal schemes. To promote low-carbon management, the model considers the carbon emission targets of the NGPN compressor stations and the UGS compressor groups, and innovatively couples the differential pressure power generation (DPPG) optimization of the UGS expander groups. A high-dimensional linearized relaxation method combining piecewise linear approximation and spatial grid approximation is designed to overcome the complex nonlinear properties of the model. The results show that the optimized NGPN scheduling scheme reduces the carbon emissions of compressor stations by 16.34 %. Through the rational decision of UGS injection-withdrawal scheme, the carbon emissions of compressor groups were reduced by 23.35 %, and the green electricity generated from the DPPG of expander groups further reduced the carbon emission of 6745.3 tons. Moreover, the influence of pipeline flow rate allocation and flow direction decision on system operation is analyzed, and the advantages of UGS in balancing supply and demand are verified. This study can provide decision support for low-carbon operation management of NGPN system with UGS.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214243"},"PeriodicalIF":4.6,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145267131","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}