Petroleum Research最新文献

{"title":"High-resolution sequence stratigraphic framework and target sand bodies correlation of tight oil reservoirs in the Upper Triassic Yanchang Formation, Ordos Basin","authors":"Xiulin Hou,&nbsp;Mingqiu Hou,&nbsp;Qingfu Feng,&nbsp;Yuxiang Xiao,&nbsp;Zhengdong Lei,&nbsp;Lingbin Lai,&nbsp;Siyang Li,&nbsp;Hongyu Tian","doi":"10.1016/j.ptlrs.2025.05.003","DOIUrl":"10.1016/j.ptlrs.2025.05.003","url":null,"abstract":"<div><div>In this study, we developed a high-resolution stratigraphic framework for the Yanchang Formation in the Huachi Block of the Qingyang Oilfield, located in the Ordos Basin, northwest China. Using well log and seismic data, we traced and correlated sweet-spot sand bodies in tight oil reservoirs. Three long-term base-level cycles were identified in the Yanchang Formation, and five medium-term base-level cycles were delineated from the Chang 72 sub-Member to the Chang 4 + 5 Members, corresponding to five distinct oil groups. The primary production layer, Oil Group 3, was further divided into short-term and very short-term base-level cycles to facilitate the prediction of hydrocarbon target zones. Sweet-spot sand bodies were traced and correlated within very short-term cycles. The sweet-spot sand bodies are mainly sublacustrine channel deposits in the delta front, which were mainly developed in the five single layers (3-1-2, 3-1-3, 3-1-4, 3-2-2, 3-2-3 and 3-2-5) of the small layers 3-1 and 3-2 during the regression periods of base-level cycles. The sweet spot sand bodies within the small layer 3-2 are derived from three sets of sources in the northeast, northwest, and south of the basin. The Class I sweet spot is distributed within the single layer 3-2-5, with an average thickness of about 6 m, covering about 25% of the study area. The Class II sweet spot is developed in all five single layers, with the thickest and largest sweet-spot sand body in the Single layer 3-2-3, covering about 90% of the study area. This study highlights the critical importance of establishing a high-resolution sequence stratigraphic framework for the refined delineation of sweet-spot sand bodies within a deltaic-lacustrine depositional system. Additionally, sublacustrine fan deposits formed during the regressive semi-cycle were identified as key sweet spots in the study area.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 749-763"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760648","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":"Starch nanoprecipitation with ethanol for the formulation of ultralow salinity formation water-tapioca starch nanoparticles potentially for enhanced oil recovery application","authors":"Suriatie Yusuf ,&nbsp;Akhmal Sidek ,&nbsp;Shaziera Omar ,&nbsp;Sairoz Norazlan Sharbini ,&nbsp;Hasanain Ali Al-Jaber","doi":"10.1016/j.ptlrs.2025.05.009","DOIUrl":"10.1016/j.ptlrs.2025.05.009","url":null,"abstract":"<div><div>The present study evaluated commercial starch behavior and tapioca starch nanoparticles (TSNP) with 100 ppm ultralow salinity formation water as a potential alternative for enhanced oil recovery (EOR). Generally, starch exhibits excellent properties as a conventional viscosifier substitute in the petroleum industry. This study proposed a conventional polymer substitute, which is typically hydrolyzed polyacrylamide (HPAM) or oxide nanoparticles, for chemical flooding EOR employment. The TSNP was successfully synthesized via nanoprecipitation with ethanol as the precipitant medium. Two TSNP of different sizes, 1% and 3%, are successfully synthesized, which demonstrated chemical and physical attributes almost identical to raw tapioca starch (TS), corroborating their composition similarities. The 1% TSNP was significantly smaller compared to the 3% TSNP, but both samples possessed distinct angular, polygonal, and truncated shapes with sharp edges. Although the structure of the TSNP synthesized was a C-type crystal, their crystallinity was slightly lower. Fourier-transform infrared (FTIR) and energy dispersive X-ray (EDX) analyses confirmed similar chemical compositions of the raw TS and TSNP assessed. The EOR formulations employed in the study were prepared with various TS and TSNP concentrations, ranging from 0 ppm to 2000 ppm. The formulations were assessed at various temperatures between 25 °C and 75 °C. Rheological results indicated that TS and TSNP formulations coupled with low salinity formation water yielded non-Newtonian shear thickening behavior with respect to starch types, concentrations, temperatures, and shear rates. The 1% TSNP formulation exhibited favorable solution viscosifying criteria than the 3% TSNP sample within evaluated parameters. Surface tension, IFT, and wettability alteration measurements revealed indirect and inconclusive trend regarding TSNP concentrations and temperatures. Nonetheless, adding 1% and 3% TSNP considerably influenced IFT reduction and wettability alteration in several favorable combinations, indicating feasibility for EOR applications.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 864-881"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760693","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":"Treatment of water disposal injection process by oilfield chemicals: Maintaining injectivity and environmental effects","authors":"Peyman Abbasi ,&nbsp;Mohammad Madani ,&nbsp;Shokoufah Abbasi","doi":"10.1016/j.ptlrs.2025.04.007","DOIUrl":"10.1016/j.ptlrs.2025.04.007","url":null,"abstract":"<div><div>Oil production from hydrocarbon reservoirs is invariably accompanied by water production, which poses significant challenges to both production and injection systems, particularly due to the formation of mineral scales. While scale formation in production wells has been extensively studied, its impact on water disposal wells which is critical for managing produced water and ensuring environmental compliance, remains underexplored. This research gap is especially important because disposal wells face unique challenges, such as injectivity loss, environmental risks from wastewater release, and the need for sustainable scale management practices. This study addresses these challenges by investigating mineral scale formation in a water disposal well in southern Iran. Unlike previous research focused on production wells, this work emphasizes the unique operational and environmental implications of scale precipitation in disposal wells. For this purpose, field information including well schematic, disposal injection system data and acidizing jobs processes performed in well A is investigated. Analyzing and simulation of the composition of the water disposal sample resulted that maximum amount of scale precipitation in surface pipeline is equal to 92 mg/l owing to CaSO₄ precipitation. Also, CaSO₄ and CaCO₃ are precipitated within near wellbore area. CaSO₄ is the dominate scale type and maximum amount of this scale is 656 mg/l and CaCO₃ is minor scale type with 54.42 mg/l in near wellbore condition. Furthermore, based on the injection pressure and injection rate data assessment in the time interval between two consecutive acidizing jobs, the formation of scales and the reduction of injectivity in well A are proved. Also, from operation point of view and according to ASTM-0374 method, scale inhibitor should be injected continuously at a concentration of 40 ppm from the surface to cover the entire injection system. The results show that scale inhibitor is an effective solution in prevention of scale precipitation, with 95.2% efficiency in scale formation inhibition. By focusing on disposal wells, this study provides novel insights into scale management strategies tailored to the unique requirements of water disposal operations. The findings highlight the effectiveness of chemical inhibitors in preventing scale formation and offer a sustainable alternative to conventional acidizing methods. This research contributes to advancing environmentally responsible practices in oilfield water disposal, addressing a critical gap in the field.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 894-901"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760696","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":"Clay mineral content and their impact on reservoir quality: Insight into the carbonate reservoirs oil fields, Central-Eastern Russia","authors":"Dmitriy A. Martyushev ,&nbsp;Shadfar Davoodi ,&nbsp;Anastasia D. Anickaeva ,&nbsp;Zhao Zhi","doi":"10.1016/j.ptlrs.2025.04.003","DOIUrl":"10.1016/j.ptlrs.2025.04.003","url":null,"abstract":"<div><div>Clay minerals are widespread in both sandstone and carbonate reservoirs. Previous studies have emphasized that clay minerals influence oil filtration in sandstones; however, very few studies to date have examined the influence of clay minerals in carbonates on oil production. To address this, scanning electron microscopy images, X-ray diffraction, nuclear magnetic resonance, and filtration experiments with low-salinity water flooding are used in this study to investigate the presence of clay minerals. Based on the XRD data, the mineralogy of cement in the carbonate reservoirs of the two fields (Perm Krai, Russia) is characterized by the presence of both non-clay minerals (quartz, feldspar, anhydrite, and halite) and clay minerals (illite/smectite, fibrous illite, and kaolinite). Illite/smectite flakes occur mainly as small platelets (&lt;0.2 μm), which are distributed over the surface of the calcite crystals. However, individual illite/smectite flakes were identified, reaching 50 μm in width and ∼5 μm in thickness. The NMR results indicate a significant amount of clay-bound water is present in core samples containing illite/smectite flakes and isolated examples of fibrous illite. Kaolinite and fibrous illite readily disperse when interacting with low-salinity water, allowing clay particles to migrate into small pores after dispersion. The dispersion and migration of kaolinite and fibrous illite contribute to a significant decrease in permeability compared to rocks containing only illite/smectite. Thus, studying the mineralogy and chemical composition of clay minerals is an urgent task for hydrocarbon production from carbonate reservoirs. The presence of clay minerals must be determined when selecting process fluids during operations and water for injection in reservoir pressure maintenance systems.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 791-802"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760651","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":"Numerical modeling validation of the sealability of bismuth alloy plugs","authors":"Marcelo Anunciação Jaculli,&nbsp;Lewaa Hmadeh,&nbsp;Sigbjørn Sangesland,&nbsp;Behzad Elahifar","doi":"10.1016/j.ptlrs.2025.05.004","DOIUrl":"10.1016/j.ptlrs.2025.05.004","url":null,"abstract":"<div><div>Due to the high demand for plugging and abandonment (P&amp;A) of wells, concerns have been raised regarding existing solutions in terms of their capability of long-term sealing - such as cement, which is the only qualified barrier material for downhole plugs. Therefore, alternative materials that can ensure better long-term sealability than cement are sought. Metal plugs have been actively researched and tested in the field, especially the ones made of bismuth alloys, due to their characteristics of impermeability and expansion upon solidification. This work focuses on the numerical modeling of bismuth-tin plugs for potential field applications. Bismuth is unique due to its expansion upon solidification, a beneficial characteristic that achieves better sealability. However, due to the low melting point of bismuth alloys, they can be susceptible to creep and aging effects if the plug is placed in high-temperature wells. In this work, the mechanical behavior of the eutectic bismuth-tin alloy is modeled using commercial finite element analysis software and then validate this model with available laboratory data. Such modeling includes expansion, creep, and aging effects of the alloy; expansion data is taken from manufacturers, while creep and aging use data found in the literature. The sealability is then checked by carrying out numerical push-out tests. The results obtained do not agree completely with laboratory data, especially at lower temperatures, highlighting the uncertainties in the input data used, especially on creep parameters. The conclusion from this validation procedure is that it is fundamental to acquire good input data for the model to match experimental results accurately. In particular, the creep parameters - for whichever fitting model is adopted - and the friction coefficient are the major sources of uncertainties, while being the main drivers of the sealability mechanism of metal plugs. This leads to a recommendation for thorough sample testing, under test conditions that replicate actual field conditions to obtain more accurate parameters. Further, this work contributes by providing a working numerical model that can be used to simulate different laboratory and field scenarios, thus assessing the sealing capabilities of any bismuth-based alloy.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 923-935"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760698","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":"Potential cleaner and greener method for ultra-tight shale oil development without hydraulic fracturing: Experimental validation for CO2 and hydrocarbon gas injection","authors":"Elena Mukhina ,&nbsp;Timur Yunusov ,&nbsp;Chengdong Yuan ,&nbsp;Denis Bakulin ,&nbsp;Artur Martirosov ,&nbsp;Alexandra Ushakova ,&nbsp;Renbao Zhao ,&nbsp;Alexey Cheremisin","doi":"10.1016/j.ptlrs.2025.05.007","DOIUrl":"10.1016/j.ptlrs.2025.05.007","url":null,"abstract":"<div><div>Currently, multistage hydraulic fracturing is the primary method for shale oil development. However, it has significant environmental drawbacks including large volumes of wastewater, greenhouse gas emissions, and toxic air pollutants, primarily due to high energy and water consumption as well as the use of chemical additives. In addition, the primary depletion method after multistage hydraulic fracturing can yield oil recovery factors of only a few percent. Therefore, there is an urgent need to develop cleaner and more sustainable methods for shale oil recovery. Currently, mainly some huff-and-puff enhanced oil recovery (EOR) methods without fracturing shale oil samples are being investigated. In this study, we managed to successfully investigate the feasibility of CO₂ and hydrocarbon gas (HCG) injection as a cleaner and greener method for ultra-tight shale oil development without fracturing through core flooding experiments combined with X-ray scanning in a continuous injection mode. The results show that continuous CO₂ and HCG gas injection yielded a maximum of 75% oil recovery without significant asphaltene precipitation or permeability reduction. A piston-like displacement front was observed during miscible HCG flooding. A two-stage displacement process was observed: the first stage is controlled by miscible gas displacement where pore filling is dominated by the occurrence of snap-off. The second stage is a diffusion-driven displacement where molecular diffusion plays a more important role with subsequent oil swelling and viscosity reduction after diffusive mixing. The findings not only prove the feasibility of gas injection (CO₂ and HCG) for developing ultra-tight shale oil without fracturing but also contribute to enriching the theory of gas flooding mechanisms.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 688-698"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760614","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":"Production forecasting in carbonate oil reservoirs through integration of deep learning and geological parameters","authors":"Jiuyu Zhao ,&nbsp;Fuyong Wang","doi":"10.1016/j.ptlrs.2025.06.007","DOIUrl":"10.1016/j.ptlrs.2025.06.007","url":null,"abstract":"<div><div>Deep learning has emerged as a groundbreaking proxy model for predicting well production, holding great promise for accelerating the advancement and management of the oil and gas industry. However, prior research on well production rate prediction often lacks the incorporation of geological models and comprehensive production data, resulting in limited transfer ability. This research introduces the application of Convolutional Neural Networks (CNN) and Long Short-Term Memory (LSTM) networks to forecast the production rate of new wells. By integrating multiple well production data, including factors such as time, choke size, pressure, temperature, water, and demulsifier injection volume, as well as geological parameters like permeability and porosity, the proposed models demonstrate the capability to accurately predict well production rates. Furthermore, the incorporation of one-hot encoding and convolution layers enhances prediction outcomes, leading to a significant 0.2 increase in the R² value. The feasibility of utilizing adjacent multi-well data for predicting new well production rates is affirmed, with all models achieving R² values exceeding 0.96 when employing encoded simulation data. Particularly, the integration of a CNN layer into the LSTM network showcases a significant improvement of 0.2 in the R² value, based on actual oilfield data. These findings suggest that additional performance improvements can be realized through the implementation of data coding techniques and the integration of CNN layers into the model architecture.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 699-709"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760644","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 inter-well interference and well spacing optimization for horizontal wells in Gulong terrestrial pure shale oil","authors":"Lifeng Liu ,&nbsp;Zhongbao Wu ,&nbsp;Yuxiang Xiao ,&nbsp;Zhenhua Xu ,&nbsp;Huizhu Xiang","doi":"10.1016/j.ptlrs.2025.05.005","DOIUrl":"10.1016/j.ptlrs.2025.05.005","url":null,"abstract":"<div><div>Gulong shale has abundant oil resources with low-porosity and low-permeability reservoir characteristics, and effective development has been achieved using horizontal well volume fracturing in single-well network deployment. Compared with tight oil, the terrestrial pure shale oil reservoir has more complex geological characteristics with developed shale joints and high clay content, which have a great impact on both hydraulic fracturing and production effects. Therefore, it is important for well spacing to be specifically designed for optimal single-well production and reservoir recovery rates. Taking the No. 1 Test Area of Gulong shale oil as an example, the inter-well interference intensity was evaluated by monitoring fracture construction pressure interference, tracer fugitive flow, and downhole microseismic phenomena at different well spacing. Using the unconventional reservoir production instability analysis method, the influence of well spacing on the length of effective fracture with proppant was examined, and the lower limit of 400 m well spacing was determined. Based on the geological and production evaluation parameters of the test area, a multi-well numerical model of the reservoir was established based on the differences in effective fracture length at different well spacing, and reasonable well spacing was demonstrated by considering the estimated ultimate recovery (EUR) of a single-well and block recovery rate. The simulation shows that the effect of well spacing on the development effect of Gulong terrestrial pure shale oil is different from that of tight oil and shale gas. By increasing the well spacing, the single-well EUR of shale oil increases significantly; the recovery first increases and then decreases, and the variation is small. Based on the current fracturing pattern and scale in the test area of Gulong shale oil, the well spacing of 300 m can be optimized to 500–550 m, the single-well EUR can be more than doubled, and the recovery can be increased by about 20%.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 782-790"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760650","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":"Quantifying the effect of mineral compositions on the brittleness of shale using the finite element method","authors":"Yunfei Zhang ,&nbsp;Yulong Yang ,&nbsp;Dmitriy A. Martyushev ,&nbsp;Zhaojie Song ,&nbsp;Yufan Meng","doi":"10.1016/j.ptlrs.2025.08.001","DOIUrl":"10.1016/j.ptlrs.2025.08.001","url":null,"abstract":"<div><div>The emergence of shale oil and gas has markedly boosted the global oil and gas storage and production growth, impacting the strategic energy patterns of numerous countries. However, exploring and exploiting shale reservoirs presents significant challenges, with production efficiency improvements largely reliant on hydraulic fracturing techniques. The mineral composition of shale and the brittleness index are critical parameters that influence the effectiveness of fracturing and production in shale reservoirs, but to date, no accurate calculation method that integrates the mineral composition and its mechanical properties for calculating the rock brittleness index. This study, based on modeling of shale SEM (Scanning Electron Microscope) images and finite element mechanical analysis, quantifies the impact of mineral compositions on the brittleness of shale. By fitting regression equations with different mineral compositions as variables, it classifies shales with different brittleness indexes and predicts the expansion patterns of fractures in shale reservoirs. The results show that each component distribution and anisotropy of shale rock has a minor effect on its brittleness index. The content of each component of shale has a greater effect on its mechanical properties, and the higher the brittle mineral content, the greater the brittleness index of shale, and also easier it is to form the complex fracture networks, which is beneficial to improve the production.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 679-687"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760593","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":"Rock typing and causality analysis in unconventional formation using Bayes nets","authors":"Evgeny Chekhonin ,&nbsp;Alexander Nikitin ,&nbsp;Dimitri Pissarenko ,&nbsp;Yuri Popov ,&nbsp;Raissa Romushkevich ,&nbsp;Dzhulia Zagranovskaya","doi":"10.1016/j.ptlrs.2025.04.009","DOIUrl":"10.1016/j.ptlrs.2025.04.009","url":null,"abstract":"<div><div>Unconventional formations are characterized by high heterogeneity and anisotropy, making it difficult to interpret logging data, perform core analysis, and create accurate petrophysical models. To address this challenge, a new methodology has been developed that uses Bayesian networks to perform rock-typing in unconventional reservoirs. The research combines, for the first time, logging data and thermal core profiling data to enhance classification accuracy based on Bayesian theory. The material used in this study is unique, encompassing extended logging and core data, a large number of full-size core samples, and various Bayesian networks. Constrained-based, score-based, and hybrid algorithms were applied to identify network structures. Comparing different Bayesian networks' performance was made possible by applying the methodology to rock-typing of 2923 full-size samples taken from three wells drilled in the central part of West Siberia through the Bazhenov Formation. Hybrid algorithms − K2-MPC and HC-MWST − gives the networks providing the most successful rock-typing (up to 84% of correctly classified samples). Naive Bayes' rock-typing quality is the worst, which indicates that the input data is not independent. Accounting for some thermal core profiling data improves (up to 6%) the quality of the rock-typing. Lessons we learned in obtaining an effective network structure are described. Bayesian networks and Random Forest provide similar rock typing results, but Bayesian networks give probabilities for samples belonging to each of the rock types studied and also allows specialists to grasp the causal relationships among input parameters. This research offers a new perspective for the analysis of unconventional reservoirs.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 710-724"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760645","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}