Geoenergy Science and Engineering最新文献

{"title":"Molecular dynamics insights into interfacial tension and solubility of hydrogen-cushion gas-water systems for underground hydrogen storage","authors":"Zhenxiao Shang ,&nbsp;Yongfei Yang ,&nbsp;Jiawei Li ,&nbsp;Qi Zhang ,&nbsp;Lei Zhang ,&nbsp;Hai Sun ,&nbsp;Junjie Zhong ,&nbsp;Kai Zhang ,&nbsp;Jun Yao","doi":"10.1016/j.geoen.2025.214215","DOIUrl":"10.1016/j.geoen.2025.214215","url":null,"abstract":"<div><div>Underground hydrogen storage (UHS) has been a promising option for large-scale hydrogen storage. Gas-water interfacial tension (IFT) and gas solubility are important parameters affecting the flow and distribution of hydrogen in underground porous media. The IFT and solubility of hydrogen-water systems at temperatures ranging from 298.15 K to 373.15 K, pressures ranging from 2.76 MPa to 46.88 MPa, and salinities up to 4.95 mol/kg were investigated using molecular simulation methods. The IFT of hydrogen-water systems exhibits a negative correlation with temperature and pressure but a positive correlation with salinity. Hydrogen solubility exhibits a positive correlation with pressure while showing a negative correlation with temperature and salinity. Hence, the high salinity caprock has a higher hydrogen-water IFT and lower hydrogen solubility, which is favorable for UHS projects. Cushion gas is used to maintain formation pressure and meanwhile mixed with hydrogen gas and diffused with each other. The effects of three different cushion gas types, including N₂, CO₂ and CH₄, and various cushion gas contents on the IFT and solubility of hydrogen-cushion gas-water systems were also investigated. Contrasting these three cushion gases, N₂ and CH₄ affect the IFT and solubility of hydrogen-cushion gas-water systems to a similar extent. In particular, CO₂ exhibits a propensity for interfacial accumulation, and can greatly reduce the gas-water IFT and has a high solubility. CO₂ is an excellent cushion gas, which is not only conducive to the solubility trapping of CO₂, but also forms a barrier at the gas-water interface and reduces the hydrogen loss by dissolution. This study focuses on revealing the influence of cushion gas on the two-phase system of UHS and clarifying the underlying mechanisms. Thus, it contributes to the selection of target formations and cushion gas types for UHS.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214215"},"PeriodicalIF":4.6,"publicationDate":"2025-09-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145158377","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":"Effect of the concentration of commercial partially CO2-soluble surfactants on foam strength","authors":"Albert Barrabino ,&nbsp;Helene Berntsen Auflem ,&nbsp;Mohammad Masoudi ,&nbsp;Torleif Holt ,&nbsp;Bård Bjørkvik ,&nbsp;Alv-Arne Grimstad","doi":"10.1016/j.geoen.2025.214223","DOIUrl":"10.1016/j.geoen.2025.214223","url":null,"abstract":"<div><div>Injection of CO₂ foam is an emerging technology for CO₂ mobility control. When searching for suitable surfactant system for maximum effect of the foam application it is necessary to consider deployment methods (dissolved in brine or in CO₂) and ways to avoid loss of foam strength away from the injection well. Loss of strength is partially related to concentration depletion caused by surfactant adsorption and partitioning into formation brine.</div><div>Here, two non-ionic surfactants with different CO₂ solubilities were studied in steady-state core flooding experiments with co-injection of CO₂ and surfactant solution with varying concentrations. For each surfactant concentration apparent viscosities were calculated from the measured differential pressures.</div><div>The surfactant Brij L23 had a low partition coefficient at the experimental conditions used, meaning that little surfactant was found in the CO₂. With this surfactant, foam was formed for low concentrations. The other surfactant, Tergitol TMN 10, was more CO₂ soluble, and the partition coefficient increased when the pressure was increased. As a result of the pressure increase more surfactant partitioned into the CO₂ and a higher concentration of surfactant was needed to form strong foam.</div><div>The experimental observations are explained as a result of the surfactant partitioning and are related to the critical micelle concentration of surfactant in brine. Additional measurements were made to characterise the rheology of the CO₂-brine interface for the different surfactant systems. It was shown that the interface was more flexible for the systems and conditions where strong foam was observed in the core flooding tests.</div><div>The observation that surfactant systems with stronger partitioning into CO₂ required higher concentrations to form strong foam, and also collapsed more rapidly for decreasing surfactant concentrations, seems to reject a proposition that high CO₂ solubility is favourable for expanding the reservoir zone where foam is generated. This indicates that the search for methods for effective CO₂ mobility control should concentrate on surfactants that are mainly water soluble.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214223"},"PeriodicalIF":4.6,"publicationDate":"2025-09-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145158378","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":"Optimization of microcrack control and performance in deepwater well cementing with microencapsulated phase change materials","authors":"Mingming Zheng ,&nbsp;Zurui Wu ,&nbsp;Tianle Liu ,&nbsp;Shichun Yan ,&nbsp;Xiaoke Li ,&nbsp;Guosheng Jiang ,&nbsp;Guokun Yang ,&nbsp;Yichen Du ,&nbsp;Yawei Zhang","doi":"10.1016/j.geoen.2025.214220","DOIUrl":"10.1016/j.geoen.2025.214220","url":null,"abstract":"<div><div>As deep-sea resource exploration progresses, maintaining wellbore stability and preventing natural gas hydrate (NGH) decomposition during cementing pose persistent challenges. This study clarifies the mechanisms of microencapsulated phase change materials (mPCM) in cement slurry by optimizing mPCM particle size and dosage. An efficient synthesis method was developed to produce mPCM with a polymethyl methacrylate (PMMA) shell and a hexadecane-octadecane core, followed by detailed physicochemical characterization. The impact of mPCM particle size (unscreened and 5–50, 50–75, 75–100 μm) and dosage (0–12 wt%) on Class G oilwell cement performance was assessed under simulated deep-sea conditions (15 °C, 3.5 % NaCl solution) using calorimetry, micro-CT, scanning electron microscopy, and compressive strength tests. Findings reveal that mPCM reduces hydration heat by up to 15.56 %, accelerates hydration, and shortens the induction period. Adding 4 wt% mPCM with particles smaller than 50 μm enhances cement compressive strength by 12.55 % while maintaining slurry fluidity. Smaller mPCM particles improve pore structure uniformity, decreasing porosity by 46.33 %, whereas larger particles increase pore complexity, reducing mechanical integrity. Thermal regulation efficiency diminishes when ambient temperature exceeds the mPCM phase transition onset, though minimal heat control persists. These results provide a novel approach to designing low-heat cement slurries, offering theoretical and technical insights for safe, sustainable deep-sea oil and gas extraction with reduced ecological impact.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214220"},"PeriodicalIF":4.6,"publicationDate":"2025-09-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106207","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":"Evaluating rock wettability in CO2-water systems using relative permeability data: Implications for geologic CO2 sequestration in saline aquifers","authors":"Abouzar Mirzaei-Paiaman,&nbsp;Jerry L. Jensen,&nbsp;Sheng Peng","doi":"10.1016/j.geoen.2025.214228","DOIUrl":"10.1016/j.geoen.2025.214228","url":null,"abstract":"<div><div>Wettability of the reservoir rock plays a crucial role in CO₂ sequestration in saline aquifers, affecting trapping mechanisms, migration dynamics, spatial distribution, and injection performance. We present two methods to determine rock wettability in CO₂-water systems by analyzing water-displacing-CO₂ relative permeability data. The first method assesses whether the water saturation at the crossover point of relative permeability curves is above or below a reference value —defined as a function of endpoint saturations— to indicate water-wet, CO₂-wet, or neutral-wet conditions. The second method compares the areas under the CO₂ and water relative permeability curves, based on the principle that the wetting fluid's area should be smaller. We developed two indices for each method, ranging from −1 (strongly CO₂-wet) to 1 (strongly water-wet). Wettability was evaluated from 33 tests across sandstones, carbonates, and shales, showing a range of CO₂-wet to water-wet states that generally align with reported contact angle measurements. A key observation is that simpler water–oil systems used as proxies may not reliably represent CO₂–brine behavior, as they often remain water-wet due to cleaning procedures and the use of fluids that do not alter wettability during the experiment, even when viscosity ratios and interfacial tensions are matched. While uncertainties remain due to sampling origin (e.g., outcrop versus subsurface) and laboratory cleaning procedures, the ability to derive wettability directly from relative permeability data offers a practical advantage, as such measurements are more accessible than reliable contact angle data. This enables more robust interpretation of multiphase flow behavior, supporting improved assessments of CO₂ storage capacity, injectivity, and long-term containment. The approach presented in this research for inferring wettability from relative permeability data is not limited to CO₂–brine systems. It can also be applied to other systems, such as water displacing hydrogen sulfide (H₂S) in acid gas storage or water displacing hydrogen in underground hydrogen storage (UHS).</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214228"},"PeriodicalIF":4.6,"publicationDate":"2025-09-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106206","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":"New transient identification methods for automated pre-processing of pressure measurements with permanent well gauges","authors":"Boyu Cui ,&nbsp;Anton Shchipanov ,&nbsp;Vasily Demyanov ,&nbsp;Nan Zhang ,&nbsp;Chunming Rong","doi":"10.1016/j.geoen.2025.214203","DOIUrl":"10.1016/j.geoen.2025.214203","url":null,"abstract":"<div><div>Well monitoring with pressure and temperature gauges is a part of well and reservoir surveillance systems across various industries, including petroleum and geothermal energy production as well as carbon capture and storage. Installing permanent downhole gauges (PDG) becomes a standard in the industry, which in combination with flow rates, provides measurements for well and reservoir monitoring by using pressure transient analysis (PTA). The feasibility and accuracy of PTA are governed by proper identification of pressure transients. Transient identification is traditionally a heavy manual trial-and-error process. It often involves pre-processing PDG data by resampling, denoising or outlier removal. However, any pre-processing may have a risk of overlooking important information. In addition, lack of pressure-rate synchronization in raw data complicates further PTA applications.</div><div>This paper introduces a novel methodology for automated transient identification from raw gauge data. The methodology enables identification of both shut-in and multi-rate flowing transients by using pressure data only. Moreover, the new transient identification runs on the raw data without resampling, denoising or outlier removal, which ensures keeping all the information from the measurements. The methodology is a combination of two new independent methods: Topographic Prominence Max Rotation (TPMR) and Local Minimum in Rotation (LMIR). The TPMR method utilizes the concept of prominence to identify significant shut-in transients. The LMIR method detects multi-rate flowing transients by identifying local minima in transformed pressure data via proper rotation matrix. Together, these methods provide an automated solution for dividing a pressure history into sequential flowing and shut-in transients. The new methodology has been tested and verified using real PDG datasets from the Norwegian Continental Shelf. The testing confirmed stability and accuracy of the methods, providing fast results with minimal human intervention. Then, an automated data pre-processing framework is described integrating the transient identification methodology with pressure and rate synchronization, rate reconstruction, superposition time and Bourdet derivative calculations. Finally, an integration of the framework within an automated time-lapse PTA well monitoring workflow is demonstrated.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214203"},"PeriodicalIF":4.6,"publicationDate":"2025-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106679","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":"Supramolecular reinforced gel fracturing fluid applied in ultra-deep reservoirs: Mechanism research of sand-carrying under fracturing fluid lubrication","authors":"Xiang Yan ,&nbsp;Caili Dai ,&nbsp;Yongping Huang ,&nbsp;Siwei Meng ,&nbsp;Xu Jin ,&nbsp;He Liu ,&nbsp;Bin Yuan ,&nbsp;Ming Chen ,&nbsp;Yining Wu","doi":"10.1016/j.geoen.2025.214209","DOIUrl":"10.1016/j.geoen.2025.214209","url":null,"abstract":"<div><div>Hydraulic fracturing plays a pivotal role in developing deep/ultra-deep oil and gas reservoirs. The high in-situ stress in deep/ultra-deep reservoirs results in narrow fracture apertures, which increases frictional resistance between proppants and fracture walls. This hinders proppant migration to the deeper regions of fractures for effective support, necessitating fracturing fluids with enhanced sand-carrying capabilities. In this study, two types of polymers capable of forming physically crosslinked networks through supramolecular interactions were synthesized. When crosslinked with organic zirconium, they form a supramolecular reinforced gel fracturing fluid. The fracturing fluid exhibits high strength, excellent shear recovery, and strong water-binding capacity, which allows the lubricating liquid film formed by the fracturing fluid on the fracture surface to maintain stability under ultra-high temperature conditions in ultra-deep reservoirs, thereby effectively reducing the frictional resistance between the proppant and the fracture walls. Data from the tribological experiment show that under the lubrication of the supramolecular reinforced gel fracturing fluid, the coefficient of friction (COF) of the proppant-fracture wall contacts is 0.48, which is 15.23 % lower than that of partially hydrolyzed polyacrylamide (HPAM) gel fracturing fluid. The relationship between the lubricating performance of the fracturing fluid and its sand-carrying ability was studied using the computational fluid dynamics-discrete element method (CFD-DEM) simulation approach. Under the lubrication effect of the fracturing fluid, the deep migration rate of the proppant (defined as the ratio of the number of proppants flowing out of the fracture to the total number of proppants) significantly increased from 7.16 % at a COF of 0.8–69.02 % at a COF of 0.05. This indicates that improved lubricating performance of the fracturing fluid enhances the proppant's ability to migrate into the deeper regions of the fracture.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214209"},"PeriodicalIF":4.6,"publicationDate":"2025-09-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106180","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":"Pore pressure prediction using machine learning methods and logging data considering Gaussian mixture clustering model","authors":"Jiajia Gao ,&nbsp;Weidong Yang ,&nbsp;Fuzhi Chen ,&nbsp;Long Chang ,&nbsp;Hai Lin ,&nbsp;Yutian Feng ,&nbsp;Gengchen Bian ,&nbsp;Hengyi Jiang","doi":"10.1016/j.geoen.2025.214188","DOIUrl":"10.1016/j.geoen.2025.214188","url":null,"abstract":"<div><div>This work proposes an innovative framework that combines intelligent clustering and machine learning methods to address the limitations of insufficient accuracy and complex operation in traditional pore pressure prediction methods. Firstly, the Gaussian mixture clustering model (GMCM) automatically identifies normal compaction clusters and eliminates the subjective error associated with manual division. Secondly, based on the clustering results and the CPO algorithm, the empirical coefficient of the Eaton method is dynamically optimized to generate high-precision pore pressure samples. Finally, the training set is constructed by integrating the preferred samples and logging data. The performances of the four machine learning models, including LSTM, XGBoost, SVR, and CNN-BiLSTM, are systematically evaluated using the ReliefF feature analysis. The empirical study demonstrates that the GMCM-CPO-Eaton method significantly enhances prediction accuracy in formations with abnormally high pressures. The errors of the AC-Eaton method and the RT-Eaton method are reduced by 11.7 % and 89.8 %, respectively. The predicted pore pressure curve highly matches the measured point height. The comprehensive performance of the models is in descending order: XGBoost, CNN-BiLSTM, LSTM, and SVR. The XGBoost model is susceptible to overfitting, which decreases its generalization ability, as evidenced by the MSE of the verification wells being above 0.12. The CNN-BiLSTM exhibits excellent stability, with its performance least affected by variations in data quantity and characteristic fluctuations. The determination coefficient R² remains stable above 0.95 in large samples and above 0.8 in small samples, performing well in adjacent well prediction with MSE values of 0.1005 and 0.0971 for the two studied wells. This further indicates that the CNN-BiSLTM model exhibits high generalization in predicting pore pressure.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214188"},"PeriodicalIF":4.6,"publicationDate":"2025-09-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145109588","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":"Advancing underground hydrogen storage: Geological insights from natural hydrogen occurrences in porous media","authors":"Lokesh Kumar Sekar,&nbsp;Axel Perwira Indro,&nbsp;Vida Gyaubea Matey-Korley,&nbsp;Chinaza Collins Ikeokwu,&nbsp;Esuru Rita Okoroafor","doi":"10.1016/j.geoen.2025.214208","DOIUrl":"10.1016/j.geoen.2025.214208","url":null,"abstract":"<div><div>Hydrogen storage in porous media is still in the research phase, especially as the literature has no proof of retrieving hydrogen stored in aquifers with high purity. A key challenge with hydrogen storage in porous media is the anticipated losses through processes like geochemical reactions, solubility, diffusion, adsorption, and microbial interactions. Thus, site selection is essential for efficient and secure hydrogen storage in the subsurface. The occurrence of natural hydrogen storage sites suggests that some geological conditions might enable hydrogen storage in the subsurface. Hence, this study investigates the properties of these sites to determine what lessons can be used for artificial geological hydrogen storage in porous media. Lessons learned from natural hydrogen sites address what kind of reservoir rocks are suitable for storage, what kind of rocks are good as seals, what reservoir and geological conditions of the reservoir minimize losses, and what additional data needs to be acquired before selecting a site for potential storage. Natural hydrogen was found occurring in both carbonate and sandstone formations. Findings from these sites show that carbonate reservoirs are associated with hydrogen concentrations exceeding 80 %, while sandstone reservoirs typically have concentrations of 70 % or lower. Shales and dolerites have acted as seal rocks. Most sites have average temperatures ranging from 20 to 50°. Larger H₂ concentrations are seen at depths shallower than 1300 m, and smaller hydrogen concentrations were seen at pressures greater than 400 bar. These findings provide some guidance for screening and selecting depleted reservoirs and saline aquifers for underground hydrogen storage.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214208"},"PeriodicalIF":4.6,"publicationDate":"2025-09-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106178","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":"Adsorption mechanism of polymers at the oil-water interfacial film and its effect on interfacial stability","authors":"Zhongchen Yu ,&nbsp;Zeqing Li ,&nbsp;Song Wang ,&nbsp;Qiushi Zhao ,&nbsp;Xigui Dong ,&nbsp;Ke Li ,&nbsp;Zhongzhong Yao","doi":"10.1016/j.geoen.2025.214189","DOIUrl":"10.1016/j.geoen.2025.214189","url":null,"abstract":"<div><div>The efficient treatment of oilfield produced water is a key link to realize the green and sustainable development of oilfields, so it is of great significance to study the stability mechanism of oilfield produced water to realize the efficient treatment of oilfield produced water. In this paper, the stability of “fracturing return fluids”(i.e., multi-polymer emulsion systems) is used as a background for the study. Molecular dynamics simulation by constructing a sandwich model of oil/intermediate/aqueous phases with different components by varying the concentration ratio between polymers. Study on the effect of changing the concentration ratio between polymers on the stability of oil-water interfaces under polymerization system and the principle of its effect. The results showed that a clear oil-water interface was formed after the system was stabilized, and the thickness, structure, strength and hydrophilic adsorption layer fullness of the interfacial film were related to the concentration ratio between the polymers. The adsorption of Hydroxypropyl guar gum (HPG) and partially hydrolyzed polyacrylamide (HPAM) at the oil-water interface would form a double-layer membrane structure. The interfacial stability was the strongest when the ratio of the concentration of HPG and HPAM reached 2:1.The different polymer concentrations altered the thickness, structure, strength, and hydrophilic adsorbent layer fullness of the interfacial, which in turn affected the stability of the system.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214189"},"PeriodicalIF":4.6,"publicationDate":"2025-09-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106277","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":"Evaluation of automated pressure transient detection methods for efficient oil well management","authors":"Daniel Folador Rossi ,&nbsp;Mateus Conrad Barcellos da Costa ,&nbsp;Karin Satie Komati","doi":"10.1016/j.geoen.2025.214202","DOIUrl":"10.1016/j.geoen.2025.214202","url":null,"abstract":"<div><div>One of the main causes of production decline in oil wells is the occurrence of formation damage. A major tool for monitoring such phenomena is Pressure Transient Analysis (PTA), applied when the well is closed (shut-in periods). With the advent of Permanent Down-hole Gauges (PDGs), this analysis can now be conducted at any time during oil production; however, the substantial volume of available data makes this task challenging and time-consuming. Therefore, several studies have focused on automating steps of PTA. This paper addresses the automation of the first step, transient detection, and presents a comparative study of six methods proposed in the literature based on signal processing techniques. The main contribution of this paper is an exploratory study intended to identify relevant aspects and patterns concerning the practical application of the methods on extensive and real-life datasets. The experimental evaluation of the methods was conducted using four real-world datasets provided by Petrobras S.A. for this research. Additionally, two synthetic datasets were introduced to facilitate a better interpretation of the findings. According to the experiments conducted, the method that achieved the best results was the convolution filter, proving to be a promising tool for transient and shut-in detection.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214202"},"PeriodicalIF":4.6,"publicationDate":"2025-09-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145060619","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}