Petroleum Research最新文献

{"title":"Gas enhanced oil recovery methods for offshore oilfields: Features, implementation, operational status","authors":"Oleg V. Anikin,&nbsp;Vadim K. Derevyanko,&nbsp;Alexander V. Bolotov,&nbsp;Ilgiz F. Minkhanov,&nbsp;Mikhail A. Varfolomeev,&nbsp;Emilia A. Konstantinovich,&nbsp;Valeria A. Kadysheva","doi":"10.1016/j.ptlrs.2024.12.003","DOIUrl":"10.1016/j.ptlrs.2024.12.003","url":null,"abstract":"<div><div>Nowadays, enhanced oil recovery (EOR) methods have been evaluated both for onshore and offshore oilfields. However, the conditions for using EOR methods in offshore fields are more complex due to the unique features of the infrastructure, transportation facilities and geological conditions. The experience gained from offshore gas EOR (gEOR) pilot projects has shown effective methods for increasing oil production at a later stage of field development. The technical knowledge base gained has been analyzed in this paper, which includes an analysis of the advantages and disadvantages of offshore projects and operational experience with gas and water-gas flooding in offshore environments. A history of implemented EOR projects in offshore oil fields from 1970 to the present and an evaluation of the application of different injection methods with hydrocarbon gas, CO₂ and nitrogen is presented sequentially.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 404-415"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314515","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":"Early oil charging from Sinian shales in Ordovician carbonates of the Tabei Uplift, Tarim Basin: Evidence from biomarkers","authors":"Qingxiu Zeng ,&nbsp;Peng Sun ,&nbsp;Xingchao Jiang ,&nbsp;Heng Zhang ,&nbsp;Qifei Fang ,&nbsp;Lei Jiang","doi":"10.1016/j.ptlrs.2024.11.001","DOIUrl":"10.1016/j.ptlrs.2024.11.001","url":null,"abstract":"<div><div>Despite over 40 years of exploration focusing on the deep to ultra-deep Ordovician carbonates as major hydrocarbon targets in the Tarim Basin, the identification of their source rocks remains elusive. Based on biomarkers, carbon and sulfur isotopes of hydrocarbons, the primary source for the Ordovician petroleum system has been attributed mainly to the lower Cambrian shales, although some oils were likely contributed from the Lower Ordovician source rocks. However, the current understanding of the evolution of the Ordovician petroleum system remains rudimentary, largely due to the complex interplay of multi-source (i.e., the widespread Precambrian shales) hydrocarbon inputs, diagenetic alterations, and tectonic processes over geological time. This study systematically investigates the molecular geochemistry of reservoir bitumen within the Ordovician carbonates from Tabei uplift, coupled with bitumen from the Sinian units at the western edge of the Tarim Basin. Our results indicate that the ion chromatography-mass spectrometry spectra and the saturated to aromatic hydrocarbons ratio of Ordovician reservoir bitumen closely resemble those of Sinian bitumen, as well as the published data of Sinian shales. This coupling linkage is revealed by cross-plots and ternary phase diagrams of various biomarker parameters, which can effectively distinguish the Sinian sources from other sources, i.e., the Lower Cambrian and Ordovician, for the Ordovician reservoir bitumen. Specifically, the ∑n-C₂₁^-/∑n-C₂₂⁺, Pr/Ph, G/C₃₁H22S, C₂₃/C₂₁TT ratios are effective indexes to differentiate these source rocks. By compiling the published organic geochemistry data of oils, it appears to infer that approximately 8.1% of the present-day oils produced from the Ordovician carbonates likely contain some proportion of Sinian-sourced oils. The recognition of Sinian sourced oils contributing to the paleo- and present-day Ordovician petroleum system offers valuable insights for the exploration of deep-ultra deep carbonates in the Tarim Basin, emphasizing the need to consider Precambrian shales as a significant hydrocarbon source.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 234-246"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314627","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":"The role of hydrocyclone and induced gas flotation technologies in offshore produced water deoiling advancements","authors":"Sandro Duarte César ,&nbsp;Debbie De Jager ,&nbsp;Mahomet Njoya","doi":"10.1016/j.ptlrs.2024.10.002","DOIUrl":"10.1016/j.ptlrs.2024.10.002","url":null,"abstract":"<div><div>Produced water, a byproduct of oil and gas extraction, presents significant environmental challenges if not properly treated. This review focuses on advancements in two primary offshore deoiling technologies, namely: induced gas flotation and hydrocyclones, tracing their evolution from the 1940s to the present. The study provides a detailed comparison of these technologies in terms of efficiency, energy consumption, and waste generation, offering both qualitative and quantitative assessments. Particular attention is given to the integration of hydrocyclone-induced gas flotation (HIGF) systems, which enhance oil removal efficiency while reducing energy consumption, making them an important solution in offshore produced water management. Additionally, the review identifies specific design improvements in flotation units, such as multistage configurations, and explores the role of operational control in optimizing hydrocyclone performance. Global variations in produced water discharge standards are examined, emphasising the need for stricter environmental regulations. In addition, this study highlights the combined use of hydrocyclone and flotation technologies as a comprehensive approach for addressing both environmental and operational challenges in offshore produced water treatment.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 342-351"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314511","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":"Organic geochemical aspects of aliphatic hydrocarbon fractions for determining coal bed methane exploration strategies of Sawahlunto and Sangatta coals","authors":"Muhamad Nur Khozin,&nbsp;Yulfi Zetra,&nbsp;R.Y. Perry Burhan","doi":"10.1016/j.ptlrs.2025.01.002","DOIUrl":"10.1016/j.ptlrs.2025.01.002","url":null,"abstract":"<div><div>Sawahlunto (SL-02) and Sangatta (KD-04) coals were analyzed for the presence of aliphatic hydrocarbon fraction biomarkers to assess their organic geochemistry and its implications for selecting exploration strategies for coal bed methane (CBM). Structural identification using the gas chromatography–mass spectrometry (GC–MS) method revealed the distribution of n-alkanes, isoprenoids, sesquiterpenoids, and triterpenoids. The organic matter in both coal samples originated from higher terrigenous plants, as indicated by the dominance of long-chain n-alkanes, carbon preference index (CPI) values greater than 1, low vs. high carbon preference index (LHCPI) values less than 1, terrigenous/aquatic ratio (TAR) values over 5, and the dominance of 8β(H)-homodrimane over 8β(H)-drimane. An oxic depositional environment is suggested by a Pr/Ph ratio greater than 1, the presence of hopanes (C31 and C32), and the low abundance of 8β(H)-drimane in both samples. CPI values greater than 1, OEP values greater than 1, LHCPI values less than 1, the abundance of 17α(H),21β(H)-homohopane (22S) compared with that of 17α(H),21β(H)-homohopane (22R), and the presence of several unsaturated biomarkers in the KD-04 sample, such as olean-12-ene, olean-18-ene, and neohop-13(18)-ene, indicate that the coal is relatively immature. A cross plot of the Pr/n-C17 ratio against the Ph/n-C18 ratio in the Hunt diagram classifies the sample as humic coal derived from higher terrigenous plants, deposited in an oxic environment, and as a type III kerogen with gas-generating potential in both the SL-02 and KD-04 coals. These biomarker data and parameters are highly relevant for methane gas miners in SL-02 coal from the Sawahlunto coal mine, West Sumatra, and KD-04 coal from the Sangatta coal mine, East Kalimantan. The CBM is estimated to have a biogenic origin.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 320-330"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314642","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":"Innovative treatment of toxic oily petroleum wastewater with magnetic sludge under UVA light","authors":"Saeedeh Rastgar ,&nbsp;Habibollah Younesi ,&nbsp;Hassan Rezeai ,&nbsp;Hajar Abyar","doi":"10.1016/j.ptlrs.2024.11.005","DOIUrl":"10.1016/j.ptlrs.2024.11.005","url":null,"abstract":"&lt;div&gt;&lt;div&gt;The primary objective of the present study is to address the critical issue of managing the large volumes of toxic oil sludge and oil waste generated in various industrial processes. This environmental challenge poses significant risks to ecosystems and human health, necessitating effective remediation strategies. In this research, we make a pioneering attempt to synthesize a novel photocatalyst, specifically Char/Fe&lt;sub&gt;3&lt;/sub&gt;O&lt;sub&gt;4&lt;/sub&gt;/TiO&lt;sub&gt;2&lt;/sub&gt;-based magnetic waxy diesel sludge, aimed at reducing the complex and hazardous compounds present in toxic oily petroleum wastewater when exposed to ultraviolet light. The synthesis of the Char/Fe&lt;sub&gt;3&lt;/sub&gt;O&lt;sub&gt;4&lt;/sub&gt;/TiO&lt;sub&gt;2&lt;/sub&gt; photocatalyst involved an innovative approach where titanium dioxide (TiO&lt;sub&gt;2&lt;/sub&gt;) was meticulously coated onto specially prepared synthetic magnetic activated carbon. A comprehensive array of analytical techniques was employed to substantiate the successful synthesis of the photocatalyst. These analyses included Fourier-transform infrared spectroscopy, high-resolution transmission electron microscopy, energy-dispersive X-ray spectroscopy, X-ray diffraction, Brunauer–Emmett–Teller surface area analysis, thermogravimetric analysis combined with differential thermogravimetry, CHNOS analysis, X-ray fluorescence, Raman spectroscopy, diffuse reflectance spectroscopy, and vibrating sample magnetometer techniques. The utilization of these diverse analytical methods provides robust evidence of the structural and functional integrity of the synthesized photocatalyst. The experimental work was conducted in a controlled batch system to evaluate the effectiveness of the photocatalyst under varying conditions. The results obtained from the analyses confirmed the successful incorporation of iron and titanium dioxide within the synthesized magnetic char, thereby validating the synthesis of the photocatalyst. To further optimize the wastewater treatment process, Response Surface Methodology was employed to systematically investigate the influence of various operational parameters. The optimal conditions for the treatment of toxic oily petroleum wastewater were determined to be at a pH of 6.5, with a photocatalyst dosage of 300 mg, a temperature of 35 °C, and an exposure time of 35 min under UVA&lt;sub&gt;6W&lt;/sub&gt; irradiation. Under these ideal conditions, the photocatalytic system demonstrated remarkable efficacy in removing hazardous compounds, achieving removal rates of 98.136% for Chemical Oxygen Demand, 95.194% for Biochemical Oxygen Demand, 92.66% for Total Kjeldahl Nitrogen, 95.99% for Total Dissolved Solids, and 91.99% for Total Suspended Solids. Kinetic and isotherm studies further elucidated the behavior of the photocatalytic process, revealing that the removal of toxic oily wastewater with Char/Fe&lt;sub&gt;3&lt;/sub&gt;O&lt;sub&gt;4&lt;/sub&gt;/TiO&lt;sub&gt;2&lt;/sub&gt; adhered closely to pseudo-first-order kinetic models, as well as the Freundlich and Henderson isotherm models. The negative","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 383-403"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314514","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":"Integrated geological study for reservoir modeling and characterization of the Shurijeh gas bearing sandstones in one of the Northeast Iran gas fields","authors":"Milad Moradi ,&nbsp;Ali Kadkhodaie","doi":"10.1016/j.ptlrs.2024.11.003","DOIUrl":"10.1016/j.ptlrs.2024.11.003","url":null,"abstract":"<div><div>The sandstones deposited in the sequence of Shurijeh Formation comprise a giant gas reservoir in the Northeast of Iran. Five primary facies (petrofacies) were identified in the deposits of Shurijeh Formation such that the entire sedimentary sequence was divided into eight zones. Diagenetic processes have affected the pore properties of sandstone (zone D2). In this research, the petrophysical parameters (porosity and water saturation) and lithology were gamma-ray in the correlation with the petrofacies and core data. The areas with good reservoir properties for each zone and the total reservoir volume were simulated by exerting an appropriate threshold cutoff limit for the reservoir parameter (porosity and water saturation) and shale volume. For determine the economic hydrocarbon volume of the field, the uncertainty analysis in volumetric calculations was carried out utilizing the Monte Carlo method, with the production of Case50, gas-in-place was calculated as 28 × 10⁶ cubic meters. The sensitivity analysis was conducted to determine the impact of each parameter on gas-in-place. Based on the results of this study, the sedimentary facies and diagenesis processes directly affect the in gas-in-place the reservoir. According to the sensitivity analysis, the map of underground lines (UGC) and fluid contact were the most sensitive compared to porosity and water saturation. That the fluid contact is related to the sedimentary facies and diagenetic processes. In fine-grained sedimentary facies, due to the transition zone increase, it is difficult to accurately determine the fluid boundary of the reservoir, while in coarse-grained sediments, which have high permeability, due to the transition zone reduction, the fluid boundary is more accurately determined. Also, diagenetic processes such as cementation, dissolution, and dolomitic processes cause great complexity in determining fluid boundaries. Therefore, comprehensive geological and reservoir studies must be done before any field development work. In this study, the spread of the reservoir zones B and D1, which have the highest volume of in-situ hydrocarbons, with lithofacies that are associated with high-energy environments (mostly sandstone) and have excellent petrophysical parameters in terms of reservoir quality was demonstrated. In accordance with these results, initial depositional processes control the distribution of porosity, water saturation, thickness and extension of prolific areas at the field scale.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 279-294"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314629","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 fracturing parameters for horizontal wells in high-sulfur gas reservoirs considering the effect of sulfur deposition","authors":"Chang Sun ,&nbsp;Zhongjun Zhao ,&nbsp;Jinghong Hu ,&nbsp;Yuan Zhang ,&nbsp;Yidong Cai ,&nbsp;Jun Lu","doi":"10.1016/j.ptlrs.2024.10.001","DOIUrl":"10.1016/j.ptlrs.2024.10.001","url":null,"abstract":"<div><div>During the development of high-sulfur gas reservoirs, the precipitation and deposition of elemental sulfur can lead to a reduction in reservoir porosity and permeability. Previous studies focus on the well production with optimized operational parameters, but the effect of sulfur deposition is not included, which impacts fracturing parameters, well production, and economic evaluation. Therefore, this work proposes a reasonable approach for parameter optimization considering sulfur. The variation of porosity and permeability are first evaluated during sulfur deposition. After that, fracture half-length, fracture spacing, fracture conductivity, and fracture distribution are optimized with orthogonalization factor analysis, and the influence of sulfur deposition on different fracture parameters are detailed analyzed. The results shown that the fracture half-length and fracture conductivity are greatly affected by sulfur deposition. Finally, net profit value is applied to obtain the optimal fracture spacing interval. With economic evaluation, the optimal fracture spacing interval of 125 m–150 m is determined considering the net profit and the payback period. This work provides a useful economic method for fracture parameter optimization high-sulfur gas reservoirs, which benefits for the development and production of gas reservoirs.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 295-303"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314640","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":"A 3D printing approach to microfluidic devices for enhanced oil recovery research: An updated perspective","authors":"Chantal T. Tracey,&nbsp;Egor O. Ryabchenko,&nbsp;Mariia A. Moshkova,&nbsp;Pavel V. Krivoshapkin,&nbsp;Elena F. Krivoshapkina","doi":"10.1016/j.ptlrs.2024.11.004","DOIUrl":"10.1016/j.ptlrs.2024.11.004","url":null,"abstract":"<div><div>Reservoir simulation uses numerical models to study how reservoir properties impact oil recovery. However, numerical modelling is insufficient and is often paired with physical simulation, where physical models are used to verify and improve simulation results. Historically, physical simulation was conducted using difficult-to-extract reservoir rock samples; however, microfluidic devices (MFDs) have emerged as viable substitutes. Unfortunately, conventional approaches to MFD fabrication leads to devices with physical and chemical properties dissimilar to that of reservoir rock – which can decrease simulation accuracy. Thanks to significant advancements in three-dimensional printing, it can be used to fabricate MFDs with properties and dimensions close to those of reservoir rocks thanks to high resolution, good dimensional accuracy, and a wide range of printable substrates, resulting in more accurate simulation aimed at maximizing oil recovery.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 370-382"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314513","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":"Comparing the effect of nanofluids in capillary imbibition with traditional displacing fluids","authors":"V.A. Zhigarev ,&nbsp;M.I. Pryazhnikov ,&nbsp;A.D. Skorobogatova ,&nbsp;A.I. Pryazhnikov ,&nbsp;A.V. Minakov ,&nbsp;S.M. Zharkov","doi":"10.1016/j.ptlrs.2025.01.004","DOIUrl":"10.1016/j.ptlrs.2025.01.004","url":null,"abstract":"<div><div>The effectiveness of surfactant solutions, polymers and nanosuspensions in capillary imbibition was studied comparatively. Two series of experiments on capillary imbibition with displacing liquids from cores saturated with low-viscosity (4.2 mPa s) and high-viscosity (28.9 mPa s) oil were performed. Water, a polymer solution of polyacrylamide, surfactant solutions (AES and SDS), as well as suspensions of spherical nanoparticles were considered as displacing fluids. The mass concentration of the substances varied from 0.05 to 0.25%. The rate of change in the volume of the displaced oil for 0.1% AES solution and suspension 1030 over time was greater than for other displacing liquids. The smallest increase in the volume of displaced oil was observed for the polymer solution. The coefficient of low-viscosity oil displacement from sandstone by water as a result of capillary imbibition was found to be 58%. When using surfactant solutions and suspensions, an increase in the oil displacement coefficient was observed: the SDS solution increased the capillary imbibition rate by 4%, and the suspension of SiO₂ nanoparticles (10 nm) gave a 3% increase. The polyacrylamide solution reduced the capillary imbibition rate by 12%. In the series with higher oil viscosity, the effect of additives was more significant. The rate of capillary imbibition increased by 22% in the case of 0.1% SDS solution and by 24% for 0.1% SiO₂ suspension (10 nm). The analysis of the factors influencing the displacement coefficient during capillary imbibition with solutions of surfactants, polymers and nanosuspensions was carried out. It has been shown that nanosuspensions are not inferior to surfactant solutions and leave polymer solutions far behind in terms of their positive effect on the oil displacement coefficient.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 432-442"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314518","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":"Combined mechanistic and machine learning method for construction of oil reservoir permeability map consistent with well test measurements","authors":"Evgenii Kanin ,&nbsp;Alsu Garipova ,&nbsp;Sergei Boronin ,&nbsp;Vladimir Vanovskiy ,&nbsp;Albert Vainshtein ,&nbsp;Andrey Afanasyev ,&nbsp;Andrei Osiptsov ,&nbsp;Evgeny Burnaev","doi":"10.1016/j.ptlrs.2024.09.001","DOIUrl":"10.1016/j.ptlrs.2024.09.001","url":null,"abstract":"<div><div>We introduce a novel method for estimating the spatial distribution of absolute permeability in oil reservoirs, consistent with well logging and well test measurements. The primary objective is to create a permeability map, incorporating the well test interpretation results and achieving hydrodynamic similarity to the actual permeability distribution around each well. This enhancement aims to improve the accuracy of reservoir modeling outcomes in reproducing real data. We utilize Nadaraya-Watson kernel regression to parameterize the two-dimensional spatial distribution of rock permeability. The kernel regression parameters are optimized by minimizing the discrepancies between actual and predicted values of permeability at well locations, the integral permeability of the reservoir domain around each well, and skin factors. This inverse optimization problem is addressed by repeatedly solving forward problems, where an artificial neural network (ANN) predicts the integral permeability of the formation surrounding a well and skin factor. The ANN is trained on a physics-based dataset generated through a synthetic well test procedure, which includes the numerical modeling of the bottomhole pressure decline curve in a reservoir simulator and its interpretation using a semi-analytical reservoir model. The proposed method is tested on the “Egg Model”, a synthetic reservoir with significant heterogeneity due to highly permeable channels. The permeability map created by our approach demonstrates hydrodynamic similarity to the original map. Numerical reservoir simulations, corresponding to the constructed and original permeability maps, yield comparable pore pressure and water saturation distributions at the end of the simulation period. Additionally, we observe a notable match in flow rates and total volumes of produced oil, water, and injected water between simulations. The developed approach outperforms kriging in terms of numerical reservoir modeling outcomes. This research advances existing geostatistical interpolation techniques by fusing well logging and well test data to build the reservoir permeability map through an optimization framework coupled with machine learning. Unlike traditional variogram-based geostatistical simulation algorithms, our method provides a permeability distribution that is hydrodynamically similar to the actual one, enhancing initial guess in the history matching process. The novel incorporation of well test interpretation results into the permeability map represents a significant improvement over existing methods, offering an innovative approach that can benefit the petroleum industry. We also provide recommendations for further development of the proposed algorithm to account for geological realism.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 247-265"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314628","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}