Geoenergy Science and Engineering最新文献

{"title":"Experimental study on deep CBM well CO2 fracturing scaling:From microscale SEM observation to macroscale scale Inhibition—Ion polarization, thermal activation, and EDTA formulation","authors":"Tao Xiujuan ,&nbsp;Li Yibo ,&nbsp;Zheng Zixuan ,&nbsp;Tao Jing ,&nbsp;Liu Jiajie ,&nbsp;Zhang Jing","doi":"10.1016/j.geoen.2025.214161","DOIUrl":"10.1016/j.geoen.2025.214161","url":null,"abstract":"<div><div>In the process of carbon dioxide dry fracturing of deep coalbed methane wells, serious scaling phenomenon occurred in the wellbore, but the wellbore scaling pattern are not clear, the scaling process was simulated indoors by adding saturated NaCO₃ and NaHCO₃ solutions into brines with different mineralisation levels and studied the chelating agent on the scaling process of the role of the law. The influence of formation water ion type, ion concentration, formation temperature, chelating agent EDTA on the amount of scaling and scale inhibition effect was investigated, and the change rule of scale crystals in the process of precipitation of carbonate ions with calcium and magnesium ions and the mode of action of scale inhibition were observed from the microscopic point of view. The results show that: ① the strength of cation polarity will change the scale crystal shape, Ca²⁺ polarization weak tend to form block CaCO₃, Mg²⁺ polarization strong easy to generate needle MgCO₃, both types of crystal deposits tend to aggregate.; ② the ion concentration in the formation is proportional to the amount of scaling. Mineralisation of 100000 mg/L, adding excess saturated Na₂CO₃ solution, the amount of scaling reached 1.084 g, mineralisation of 250000 mg/L, the amount of scaling reached 1.549 g, compared with the former increased by 42.90 %, the mineralisation increases through the solubility product breakthroughs and ionic strength effect significantly increases the amount of scaling, formation water mineralisation increased by 1 %, the amount of scaling increased by 0.286 % on average; ③ Temperature increases alter the state of ions by changing the activation energy. When the temperature reaches 80 °C, the shape of scale crystals changes from irregular spherical (calcium bicarbonate) to regular blocky (calcium carbonate). Compared with magnesium ions, calcium ions preferentially combine with anions to form scale. Under higher temperature conditions, the scale formed at the bottom of the well is mainly calcium carbonate. ④ Chelating agent EDTA can significantly reduce the scale formation by complexing Ca²⁺. In a system with a calcium ion concentration of 15,000 mg/L, the minimum scale inhibition rate is achieved by adding 20 mL of 0.1 mol/L EDTA. However, further increasing the dosage of the chelating agent will cause colloid flocculation and increase precipitation, leading to an increase in the scale formation.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214161"},"PeriodicalIF":4.6,"publicationDate":"2025-08-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144860712","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":"Sophisticated distributed acoustic sensing (DAS) for real-time monitoring and analysis of wellbore integrity","authors":"Feiyu Su ,&nbsp;Xiaorong Li ,&nbsp;Yongcun Feng ,&nbsp;Saxing Li ,&nbsp;Yangang Wang ,&nbsp;Chenwang Gu ,&nbsp;Xiaoyu Si","doi":"10.1016/j.geoen.2025.214162","DOIUrl":"10.1016/j.geoen.2025.214162","url":null,"abstract":"<div><div>Underground gas storage wells have higher sealing integrity requirements for the casing-cement sheath-formation system due to the characteristics of alternate strong injection-production mode and high gas leakage risk. The cement sheath is crucial to the zonal isolation and production safety as a core component of the wellbore. However, the conventional monitoring methods only assess cement conditions at a specific moment and lack the capability for full-cycle dynamic monitoring. Therefore, the article proposes a new method using Distributed Acoustic Sensors (DAS) to monitor the Top of Cement (TOC) and fluid leakage location. A series of DAS monitoring experiments are conducted to evaluate wellbore integrity, including a 24-h cement slurry hydration process and fluid leakage process within cement. Then the Continuous Wavelet Transform-Convolutional Neural Network-Bidirectional Long Short-Term Memory (CWT-CNN-BiLSTM) network is established to capture the sealing failure characteristics of the cement sheath. The results indicate that the hydration strain change of cement slurry and the position of TOC are accurately determined by the DAS system. The location and flow rate of fluid leakage in cement sheath cracks are determined by analyzing the strain rate profile and acoustic energy. The CWT-CNN-BiLSTM network adaptively extracts the time-frequency information of non-stationary signals and reveals the mapping relationship between signal features and cement sheath failure conditions. Compared with the conventional model, the model demonstrates greater robustness and reliability, achieving a classification accuracy of 99.31 %. In conclusion, the novel monitoring method can determine whether remedial measures are needed by providing information on the cement sheath integrity.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214162"},"PeriodicalIF":4.6,"publicationDate":"2025-08-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144860711","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":"Adaptation thresholds and mechanistic insights into dispersed particle gel strengthened alkali for enhanced oil recovery in heterogeneous reservoirs","authors":"Dongfang Lv ,&nbsp;Guang Zhao ,&nbsp;Teng Wang ,&nbsp;Jinzhong Zhao ,&nbsp;Zhe Li ,&nbsp;Caili Dai","doi":"10.1016/j.geoen.2025.214142","DOIUrl":"10.1016/j.geoen.2025.214142","url":null,"abstract":"<div><div>After developing dispersed particle gel strengthened alkali (DPGSA) as a heterogeneous combination flooding, the research focused on adaptation thresholds and mechanisms of action of DPGSA. The adaptation thresholds of DPGSA have been verified, including temperatures (25–100 °C), salinities (0–200,000 mg/L for NaCl and up to 0–2200 mg/L for CaCl₂), oil viscosities (10–200 mPa s), acid value (0.04–0.44), and permeabilities (0.25–1.89 μm²). The study investigated the mechanism of DPGSA on the oil-water interface. The interfacial tension (IFT) of 0.7 wt% DPG + 1.6 wt% Na₂CO₃ is initially 0.071 mN/m, decreasing to 0.045 mN/m after 60 days of aging. Na₂CO₃ is conducive to low IFT and stable the interfacial membrane. The interfacial membrane strength was reduced by 6.64 %–7.49 % with an increase in DPG concentration, and by 27.01 %–27.98 % with an increase in aging time. At 0.03–0.1 Hz, the elastic modulus (21–35 mN/m) &gt; viscous modulus (13–17 mN/m), enhancing the dynamic stability of the interfacial membrane. The normalized breakthrough time are 0.39 for DPG and 0.65 for Na₂CO₃, facilitating Na₂CO₃ entry into low-permeability zones. The recovery rate in low-porosity layers (0.01–1 μm) increased from 6.91 % to 54.59 % with the application of DPGSA. The coalescence of residual oil, stripping oil film, and oil emulsification are due to the low IFT and high-strength interfacial membrane of DPGSA. This study elucidated DPGSA's adaptability and mechanism, facilitating its widespread use in oilfield.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214142"},"PeriodicalIF":4.6,"publicationDate":"2025-08-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144840900","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":"Impact of intrinsic layered heterogeneity on CO2 convective-reactive dissolution in saline aquifers","authors":"Qigui Tan ,&nbsp;Ruichao Tian ,&nbsp;Jian Tian ,&nbsp;Haoping Peng","doi":"10.1016/j.geoen.2025.214160","DOIUrl":"10.1016/j.geoen.2025.214160","url":null,"abstract":"<div><div>The heterogeneity of saline aquifers significantly influences CO₂ dissolution efficiency and convective-reactive transport dynamics, which still remains insufficiently understood. To address this knowledge gap, this study systematically evaluates the effects of three intrinsic layered heterogeneities (i.e., porosity, permeability, and reactant content) in saline aquifers on both the convective mixing behavior of CO₂ plumes and the chemical dissolution of CaCO₃. These investigations are conducted using a newly developed convective-reactive transport model. The results demonstrate that, compared to homogeneous aquifers, layered heterogeneity with decreasing porosity or reactant content significantly enhances CO₂ convective-reactive transport, leading to faster CO₂ full mixing with brine and complete CaCO₃ dissolution. In contrast, increasing porosity or reactant content with depth exhibits a negative effect on CO₂ dissolution efficiency. Permeability layered heterogeneity in aquifers inhibits CO₂ convective-reactive dissolution compared to homogeneous aquifers. Distinct CO₂-plume migration patterns emerge in different layered heterogeneous saline aquifers, primarily characterized by fingering, channeling, and compaction flow regimes. Additionally, the results also suggest that the evolution of Da number during CO₂ dissolution process can be adopted to evaluate the CO₂ dissolution efficiency. The findings of this work can provide a reference for screening the heterogeneous saline aquifers suitable for efficient CO₂ dissolution.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214160"},"PeriodicalIF":4.6,"publicationDate":"2025-08-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144831634","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":"Proppant consolidation and hysteresis in hydraulic fractures: Insights from the application of a strain transfer model for interpreting fracture width changes from distributed fiber optic strain sensing","authors":"Queendarlyn A. Nwabueze,&nbsp;Smith Leggett","doi":"10.1016/j.geoen.2025.214159","DOIUrl":"10.1016/j.geoen.2025.214159","url":null,"abstract":"<div><div>Monitoring unconventional reservoirs using fiber optics distributed strain sensing (DSS) has become crucial for assessing the efficiency of stimulation operations. DSS improves our understanding of far-field fracture geometries induced by hydraulic fracturing. Intermediate layers between the reservoir and fiber core affect the quality of the strain measurement. This study aims to improve the interpretation of strain-based measurements from hydraulic fracture stimulation by proposing an analytical model. We adopted an existing strain transfer model used in the study of concrete structures to address variations in elastic properties and interfacial slip within multilayer systems. The strain transfer model is integrated with a mechanical model incorporating proppant deformation and fracture width hysteresis during production and pressure build-up. This approach accounts for strain transfer from fractured reservoir rock to optical fibers in a multilayer well completion system. We conducted a sensitivity analysis to investigate the influence of the mechanical behavior of proppant packs on fracture width and DSS measurements. Two different soil samples were considered for this sensitivity. After the first unloading cycle, a permanent fracture width reduction of approximately 20 % is observed. The rate of fracture width reduction decreased with successive cycles. The developed model was validated using Rayleigh frequency shift distributed strain sensing (RFS-DSS) field data from the Hydraulic Fracture Test Site 2 (HFTS2) project in the Permian-Delaware Basin. The modeled strain response captures the hysteresis behavior along the unloading and reloading paths of the proppant pack during the production and pressure buildup stages. We propose that the observed extensional strain rates are not solely due to changes in fracture aperture but also strain transfer between the intermediate layers of the well completion system. The observed semi-log plot behavior of peak strain change from the field data aligns with our model's prediction. This study presents a novel application of a strain transfer model to improve RFS-DSS strain-based measurements in unconventional stimulation operations. The developed strain transfer model significantly enhances the understanding of near-wellbore hydraulic fracture characteristics and the interrelationship between stimulation and production in unconventional reservoirs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214159"},"PeriodicalIF":4.6,"publicationDate":"2025-08-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144893791","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":"Foam stability and acidizing effect evaluation of a foam acid fluid system for low-temperature dolomite geothermal reservoir stimulation","authors":"Ou Jiang ,&nbsp;Xiuhua Zheng ,&nbsp;Pei Wu ,&nbsp;Luyao Ma ,&nbsp;Xu Liu ,&nbsp;Pengfei Jin ,&nbsp;Pengxiang Zhang ,&nbsp;Yang Yang ,&nbsp;Haoyu Yu","doi":"10.1016/j.geoen.2025.214158","DOIUrl":"10.1016/j.geoen.2025.214158","url":null,"abstract":"<div><div>Acidizing improves reservoir productivity, and foam acid fluid systems achieve both effective acidizing and reservoir protection compared to conventionally utilized acid fluids. Nevertheless, the current application of foam acid fluids is restricted to oil-gas reservoir stimulation, owing to the differences in development conditions between oil-gas and geothermal reservoirs. The transformative application of foam acid fluids from oil-gas to geothermal reservoirs can address the problems induced by conventional acid fluids in geothermal reservoirs, such as limited effective acidizing distance and difficulties in flowing back residual fluids. Here, a foam acid fluid system with typical foaming agents, including sodium dodecyl sulfate (SDS), cocoamidopropyl betaine (CAPB), dodecyl trimethyl ammonium bromide (DTAB) and decaethylene glycol monododecyl ether (DGME), with various foam stabilizer xanthan (XC) contents (0.3 %–1.2 %) is proposed. Its feasibility in low-temperature (25 °C−90 °C) geothermal reservoir stimulation is verified through foam stability and acidizing effects, containing dissolution and corrosion inhibition performances. The results shows that the foam acid fluids with DTAB and DGME at 1.2 % XC have a required foam stability. A network micro-structure of foam stabilizers, the stronger intermolecular forces in the foaming system, and the chemical reaction stability of foaming agents, mutually contribute to the foam stability. Compared to non-foam acid fluids, foam acid fluids significantly retards acid-rock reaction, with a more uniform dissolution of the cuttings microscopically. The existence of bromide ion (Br⁻) in DTAB enhances the corrosion of N80 steel, which is above an accepted corrosion speed. This study highlights the great application potential of foam acid fluid system in an efficient stimulation of low-temperature dolomite geothermal reservoirs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214158"},"PeriodicalIF":4.6,"publicationDate":"2025-08-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144851920","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":"Oil quality assessment and evolution process in insoluble sediment voids for underground salt cavern oil storage (SCOS): An experimental perspective","authors":"Xinxing Wei ,&nbsp;Xilin Shi ,&nbsp;Yinping Li ,&nbsp;Yashuai Huang ,&nbsp;Yang Hong","doi":"10.1016/j.geoen.2025.214145","DOIUrl":"10.1016/j.geoen.2025.214145","url":null,"abstract":"<div><div>Underground salt cavern refined oil storage is a well-established method for large-scale of deep energy storage. Utilizing the salt cavern insoluble sediment void to store the refined oil in salt mines with plenty of insoluble interlayers and impurities can enhance the oil storage capacity. Assessing the refined oil quality in these salt cavern sediment voids is essential for efficient use. A suite of specialized testing equipment was developed to evaluate refined oil quality in salt cavern storage environments, including an oil storage environment simulation device, a water content tester, an oil demulsification time tester, a kinematic viscosity tester, and a sediment content tester. These integrated devices were developed based on a novel salt cavern sediment void oil storage conditions design to explore the oil quality evolution rule. The analysis focused on oil quality changes due to physical, chemical, and microbial factors and the evolution process of oil quality in salt cavern sediment voids. The 30 days of oil storage results indicate that refined oil quality remains generally stable in these salt cavern storage environments. Most refined oils, including diesel, gasoline, kerosene, and mineral oil, meet water content requirements, except for partially refined oil near the oil-brine interface. The oil's emulsification characteristics deteriorate over time, but significant emulsification zones do not form quickly in salt caverns. High-viscosity oils interact more with sediment than low-viscosity oils. The oil viscosity coefficient remains unchanged for about 30 days. High-viscosity oils exert greater extraction forces on sediment particles. These findings provide a foundation for optimizing storage design and operational strategies for SCOS.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214145"},"PeriodicalIF":4.6,"publicationDate":"2025-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144831632","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":"Optimizing cementing displacement efficiency using a machine learning ensemble Models: Application of fluent simulation and optimization algorithms","authors":"Mou Yang ,&nbsp;Shuangmiao Che ,&nbsp;Pengchao Zhao ,&nbsp;ShiYao Wang ,&nbsp;Mulei Zhu ,&nbsp;Jingpeng Wang","doi":"10.1016/j.geoen.2025.214149","DOIUrl":"10.1016/j.geoen.2025.214149","url":null,"abstract":"<div><div>Increasing displacement efficiency during cementing has been identified as a crucial measure for enhancing cementing quality. To evaluate displacement efficiency, the correctness of using the Fluent simulation method was verified based on field logging data. On this basis, Fluent numerical simulation results were utilized as the dataset, which formed the foundation for developing prediction models for displacement efficiency. Prediction models were developed using machine learning techniques, employing Random Forest, Extremely Randomized Trees, Artificial Neural Network, and Support Vector Machine algorithms. To ensure seamless integration of these techniques, the Stacking method was applied as a meta-model to combine the most accurate individual models, effectively leveraging their strengths. The prediction accuracy of the ensemble model was analyzed along with the influence weights of various cementing parameters on displacement efficiency. The research further optimized cementing parameters using the Stacking prediction model in conjunction with advanced optimization algorithms, including the L-BFGS, simulated annealing, and gradient descent methods, to achieve optimal displacement efficiency. High computational accuracy was demonstrated by the Random Forest and Extremely Randomized Trees algorithms, with further improvements achieved through the ensemble model combining these two algorithms. The L-BFGS algorithm performed excellently in predicting displacement efficiency in both wide and narrow annular gaps, resulting in improvements of 3.74 % and 5.46 %, respectively, compared to the original method. Furthermore, the deviation between the predicted results and the actual simulated values was controlled within 3.5 %, indicating a high degree of accuracy and reliability. This research not only validates Fluent simulations with field data but also demonstrates the value of machine learning in overcoming measurement challenges. By integrating simulations with prediction and optimization models, it introduces a practical framework that enhances cementing optimization and sets a benchmark for future studies.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214149"},"PeriodicalIF":4.6,"publicationDate":"2025-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144827557","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":"Enhanced oil recovery mechanisms of pre-fracturing CO2 injection in high-maturity shale oil reservoirs: Integrated phase behavior experiments and field-scale numerical simulations","authors":"Xiao Han ,&nbsp;Zhaojie Song ,&nbsp;Jiaqi Wang ,&nbsp;Ning Qi ,&nbsp;Peiyu Li ,&nbsp;Jiatong Jiang ,&nbsp;Yilei Song ,&nbsp;Kaixing Zhang ,&nbsp;Minchen Chen ,&nbsp;Yanrong Lv","doi":"10.1016/j.geoen.2025.214146","DOIUrl":"10.1016/j.geoen.2025.214146","url":null,"abstract":"<div><div>CO₂-EOR in shale oil reservoirs serves as an effective method for enhancing oil recovery while facilitating geological carbon sequestration. This study proposes a novel pre-fracturing CO₂ injection (PFCI) technique, where controlled-volume CO₂ injetion is systematically implemented prior to hydraulic fracturing in high-maturity shale oil reservoirs, aiming to modulate fluid phase behavior and replenish reservoir elastic energy. Through experimental and numerical investigations of PFCI in high-maturity shale oil reservoirs and field-scale simulations, it was revealed that the PFCI method demonstrates substantial advantages over CO₂ huff and puff (HnP) in enhancing oil recovery and carbon sequestration. PFCI significantly promotes interphase mass transfer, reinforces elastic energy, and enhances crude oil mobility. Furthermore, PFCI improves CO₂ sweep efficiency and suppresses fracturing fluid flowback. Phase behavior analysis indicates that CO₂ injection into high-maturity shale oil reservoirs induces dramatic phase transformations. The reservoir fluid undergoes sequential phase state transitions during CO₂ injection: the transformation progresses from light volatile oil reservoirs to near-critical light volatile oil reservoirs, then to near-critical gas reservoirs, and ultimately to gas reservoirs. PFCI exhibits exceptional energy replenishment capability, reducing reservoir oil bubble-point pressure during this process and facilitating the dissolution of free gas into formation crude oil. During production stage, the oil drainage radius expands by 1.55 times with more balanced recovery of hydrocarbon components. Cumulative oil production from PFCI can be further increased by 18–25 % compared to CO₂ HnP, and achieving 47.67 % CO₂ sequestration efficiency within one-year production. The integration of enhanced oil recovery mechanisms and carbon sequestration effects establishes PFCI as an efficient development strategy for high-maturity shale oil reservoirs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214146"},"PeriodicalIF":4.6,"publicationDate":"2025-08-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144921599","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":"Biogeochemistry during hydraulic fracturing: A critical review of reservoirs, fluids, processes, and implications","authors":"Xiaodong He ,&nbsp;Peiyue Li ,&nbsp;Hui Qian ,&nbsp;Hua Shi ,&nbsp;Zhanguo Ma","doi":"10.1016/j.geoen.2025.214143","DOIUrl":"10.1016/j.geoen.2025.214143","url":null,"abstract":"<div><div>The hydraulic fracturing process disrupts the pre-existing equilibrium among water, rock, gas, and microbe in deep subsurface environments. This process shapes a novel microbial ecosystem and triggers a series of complex biogeochemical interactions, thereby influencing natural gas recovery efficiency and flowback water quality. This review critically examines biogeochemical processes during hydraulic fracturing in three prevalent low-permeability reservoirs: tight sandstone, shale, and coal reservoirs, aiming to generate biogeochemical insights into environmentally sustainable unconventional energy exploitation. Building on the examination of low-permeability reservoirs and fracturing fluid characteristics, the discussion delved into biogeochemical processes, encompassing fluids mixing, mineral dissolution and precipitation, clay swelling, ion exchange and adsorption, and biochemical reactions. These interactions involve intricate and coupled physical, chemical, and biological processes, further complicated by the heterogeneity of reservoirs and the complexity of fracturing fluid compositions. Biogeochemistry persists throughout the lifecycle of unconventional hydrocarbon extraction, impacting energy recovery, flowback fluids water quality, and environmental outcomes. Optimizing fracturing fluids additives based on biogeochemical insights can minimize contaminants and enhance production efficiency. This study offers in-depth insights into water-rock interactions and microbial activities in deep formation, highlighting the nuanced effects of biogeochemical processes on hydraulic fracturing and its environmental impact. It underscores the importance of refining hydraulic fracturing designs to enhance unconventional gas production while reducing environmental risks.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214143"},"PeriodicalIF":4.6,"publicationDate":"2025-08-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144827558","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}