Petroleum Research最新文献

{"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}

{"title":"Surface wettability of quartz and calcite: Impact of cleavage, exposure time, and scale of measurement","authors":"Mahmoud Aboushanab ,&nbsp;Abubakar Isah ,&nbsp;Mohamed Mahmoud ,&nbsp;Dalaver H. Anjum ,&nbsp;Muhammad Arif","doi":"10.1016/j.ptlrs.2025.04.001","DOIUrl":"10.1016/j.ptlrs.2025.04.001","url":null,"abstract":"<div><div>Accurately characterizing the wettability of solid surfaces is essential for various applications. Numerous factors, such as operating conditions and the features of the sample surface, affect wettability. In subsurface applications, precise wettability characterization of rock/fluid systems is particularly important because it determines fluid distribution and multiphase flow within porous media. Despite operating under similar conditions, significant variations are observed in the reported wettability of specific rock/fluid systems. Factors contributing to these inconsistencies include surface roughness and surface cleavage, which are often overlooked in contact angle measurements. Therefore, this study examines the impact of surface roughness and cleavage planes on freshly cleaved surfaces in comparison to surfaces exposed to the atmosphere. Pure calcite and clean quartz surfaces were selected in this study. For the surface cleavage effect, both macro and micro contact angles have been utilized, coupled with advanced image analysis to visualize the wettability changes as a function of scale. Furthermore, Fourier Transform Infrared (FTIR) spectroscopy is utilized to determine surface functional groups responsible for wettability variation due to atmospheric contaminants. Findings suggest that freshly cleaved surfaces exhibit greater hydrophilicity than their exposed counterparts, underscoring the necessity for caution when dealing with calcite and quartz due to the pivotal role of exposure time in determining wettability. Surface roughness measurements have been conducted to examine the impact of exposure time on surface topography and the results confirm that the change in surface roughness was negligible. The findings from this study enhance comprehension of the mechanisms at the nano-to milli-metre scale responsible for wettability variations. Also, a scientific understanding of the mechanisms responsible for wetting characteristics is established, which can be beneficial in addressing the discrepancies in the observed wetting behaviour.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 738-748"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760647","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Application of hybrid numerical reservoir simulation and artificial neural network for evaluating reservoir performance under waterflooding","authors":"Paul Theophily Nsulangi ,&nbsp;John Mbogo Kafuku ,&nbsp;Guan Zhen Liang","doi":"10.1016/j.ptlrs.2025.02.001","DOIUrl":"10.1016/j.ptlrs.2025.02.001","url":null,"abstract":"<div><div>In the current study, an artificial neural network (ANN) and a numerical reservoir simulation (NRS) technique are used to analyse reservoir performance under waterflooding in the ZH86 block of the Zhaozhouqiao oilfield, China. Using five input datasets extracted from the history-matched NRS model, an NRS-ANN hybrid is trained using a trial-and-error approach. NRS-ANN hybrid model #46 (which has 5, 10, 10, 6, 6, and 1 neurons in the input layer, four hidden layers, and output layer, respectively) is found to produce the minimal root mean square error on the test dataset. On the validation data, the prediction performance of the selected NRS-ANN hybrid model achieves a minimal root mean square error of 0.0274 m³/day and maximal coefficient of determination and coefficient of correlation values of about 0.9999. The correlation between the block liquid production rate (BLPR, m³/day), block water production rate (BWPR, m³/day), block water cut (BWCT, %), block water injection rate (BWIR, m³/day), and block reservoir pressure (BRP, bar) as input variables and the simulated oil production rate (SOPRH) as the output variable is investigated. There is a positive correlation between SOPRH and BLPR, BWIR, and BWCT, and a negative correlation between SOPRH and BRP and BWPR. Segment B of ZH86 block experiences a 3.8% increase in BLPR, while segments A and C show declines of 1.3% and 1.6%, respectively. These variations in the liquid production rate correspond to changes in SOPRH of 4.3%, 1.9%, and 9.7% for segments A, B, and C, respectively. The prediction performance of the NRS-ANN hybrid model is compared with that of a simple NRS model. The accuracy of the NRS-ANN hybrid model in predicting oil production is found to be 1125 times that of the NRS model. Based on these results, it is concluded that the proposed NRS-ANN hybrid provides an accurate and useful tool for analysing reservoir performance under the waterflooding oil recovery technique.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 3","pages":"Pages 564-576"},"PeriodicalIF":4.0,"publicationDate":"2025-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145120657","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":"Study on electrochemical corrosion of P110 tubing during air injection oil flooding","authors":"Lijuan Pan ,&nbsp;Xue Han ,&nbsp;Junwei Fang ,&nbsp;Haifu Yuan ,&nbsp;Zhongfu Cheng ,&nbsp;Miaopeng Zhou ,&nbsp;Xin Shi ,&nbsp;Dezhi Zeng","doi":"10.1016/j.ptlrs.2024.12.001","DOIUrl":"10.1016/j.ptlrs.2024.12.001","url":null,"abstract":"<div><div>This article addresses the corrosion problem of P110 tubing during the process of enhancing oil recovery by injecting air. The effects of changes in oxygen content and tensile stress on the corrosion of P110 tubing were studied using electrochemical testing methods. The results show that with an increase in oxygen content (0, 10000 ppm, 20000 ppm, 30000 ppm, 40000 ppm), the product film on the surface of P110 tubing is loose and porous, the film resistance and charge transfer resistance decrease, the self-corrosion current density increases, and the corrosion intensifies. With an increase in tensile stress (0, 20%Ϭs, 50%Ϭs, 70%Ϭs, 100%Ϭs), the corrosion tendency of P110 tubing increases,the stability and protection of the product film are destroyed, the film resistance and charge transfer resistance decrease, the electrochemical activity of the steel surface increases, the self-corrosion current density increases, and the corrosion intensifies.Based on this, considering the effects of oxygen content and tensile stress on the corrosion of P110 tubing, anti-corrosion suggestions are given to provide a reference basis for corrosion control of air-injected tubular columns.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 3","pages":"Pages 543-551"},"PeriodicalIF":4.0,"publicationDate":"2025-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145120659","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":"Performance evaluation of fracturing-huff-n-percolation-puff (FHnPP) processes in a hydrocarbon reservoir","authors":"Yanan Ding ,&nbsp;Haiwen Wang ,&nbsp;Maoxian Wang ,&nbsp;Chen Zhang ,&nbsp;Daoyong Yang","doi":"10.1016/j.ptlrs.2025.02.002","DOIUrl":"10.1016/j.ptlrs.2025.02.002","url":null,"abstract":"<div><div>Due to its superior performance on the efficient exploitation of a small fault-block reservoir, a novel technique of fracturing-huff-<em>n</em>-percolation-puff (FHnPP) has received increasing attentions in recent years. In order to clearly identify and understand the associated mechanisms, reservoir simulations have been conducted to evaluate performance of an FHnPP process in a hydrocarbon reservoir. A series of simulation scenarios are designed to evaluate and identify dominant factors based on both single-factor and orthogonal schemes. The FHnPP performance can be understood as follows, i.e., created (micro-)fractures are extended from the surrounding water-zone deeper into formation during water injection, this process rebuilds the pressure field, enabling more trapped oil to be subsequently driven backwards the well after such (micro-)fractures are closed or partially-closed. Surfactants effectively reduce the water/oil interfacial tension (IFT), but it only increases oil production at early times. The existence of secondary fractures slightly enhances oil recovery at early puff-period after which such a positive impact is gradually vanished. A higher matrix permeability yields a higher ultimate oil recovery, but such a yielded positive effect from fracturing is then degraded. Moreover, the residual permeability of fractures during production (i.e., the puff process) negatively affect oil recovery, while a longer length of fracture results in more produced oil. Also, both injection rate and soaking time positively affect the oil recovery though the latter is insignificant. The orthogonal analysis indicates that, sensitivity of the dominant factors affecting oil recovery varies from each other, while the sensitivity of FHnPP's advantages to those factors is found also unequal. In the target reservoir with the optimized FHnPP parameters, significant oil increment (i.e., a recovery factor (<em>RF</em>) of 3.59% (i.e., 609.1 m³ oil)) can be achieved compared with that of the traditional huff-<em>n</em>-puff (THnP) process. This numerical study not only proves the feasibility and advantages of the FHnPP technique, but also deepens our understanding of its performance and identifies the dominating factors.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 3","pages":"Pages 458-473"},"PeriodicalIF":4.0,"publicationDate":"2025-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145120705","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}