Petroleum Science最新文献

{"title":"Performance evaluation of multilateral horizontal wells on flow characteristics and recovery efficiency based on coupled model","authors":"Chun-Xue Cui ,&nbsp;Xiao-Long Chai ,&nbsp;Yue-Wu Liu ,&nbsp;Zhi-Jun Zhou ,&nbsp;Guo-Qing Zhang ,&nbsp;Leng Tian","doi":"10.1016/j.petsci.2025.10.025","DOIUrl":"10.1016/j.petsci.2025.10.025","url":null,"abstract":"<div><div>The multi-branch horizontal wells can improve the reservoir dynamic flow profile, restrain water coning, enhance production and recovery efficiency due to large drainage area and low cost, and it is significant importance for academic research and industrial applications. However, the effects of branches interference and wellbore variable mass flow on transient dynamics of water breakthrough, production characteristics and recovery efficiency have long been ignored. To dynamically simulate and evaluate the fluid flow behavior of multilateral horizontal wells, first, the branches interference and coupled relationship between reservoir fluid seepage and wellbore variable mass flow has been investigated in this paper, a coupled model for predicting multilateral horizontal wells dynamic production and water breakthrough time is proposed with arbitrary three-dimensional spatial distribution. Subsequently, the model is validated by comparing the production and breakthrough time between actual production data and simulated software. Last, the performance characteristics including inflow dynamics, production, wellbore pressure drop and water breakthrough dynamic distribution are analyzed. The results indicate that the unstable flow time is shorten and it is about 0.6 h, and the wellbore inflow profile represents a characteristic of “low in the middle and high at both ends” on account of branches interference. The pressure drop of wellbore is mainly affected by friction, and other pressure drop types are acceleration pressure drop, convergence pressure drop and mixed pressure drop in order of influence, respectively. The breakthrough time is prior at junction of main wellbore and branch wellbores, then the bottom water spreads to the middle position of main wellbore and trailing position of each branch wellbore. The branch length has a critical impact on breakthrough time, and the branch numbers also affect it as well as the branch angle. The proposed theoretical model can be used to calculate and predict the production, breakthrough time and recovery efficiency of multilateral horizontal wells, and it supplies strong technical support for further development and enhance oil recovery of bottom water reservoir and actual oil field production.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 818-835"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417837","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Competition between viscous and capillary forces triggers diversity of fluid distribution and imbibition modes","authors":"Jin-Xin Cao ,&nbsp;Yi-Qiang Li ,&nbsp;Yu-Ling Zhang ,&nbsp;Ya-Qian Zhang ,&nbsp;Zhe-Yu Liu ,&nbsp;Qi-Hang Li ,&nbsp;Xue-Chen Tang ,&nbsp;Tao Song","doi":"10.1016/j.petsci.2025.09.043","DOIUrl":"10.1016/j.petsci.2025.09.043","url":null,"abstract":"<div><div>Spontaneous imbibition is the process in which the wetting phase displaces a non-wetting phase under the action of capillary forces. However, variations in interfacial properties, imbibition directions, and fractures result in different imbibition modes, posing challenges to a comprehensive understanding of the process. In this study, microfluidic chips representing matrix and fracture–matrix systems were designed. Imbibition agents with varied interfacial properties were selected to conduct experiments under counter-current and co-current conditions. A flow factor (<em>γ</em>), related to fracture geometry and imbibition direction, was defined and used together with the microscopic capillary number (<em>Ca</em>_micro) to characterize the imbibition process. Three distinct imbibition modes were observed for different <em>Ca</em>_micro and <em>γ</em>, clearly separated by <em>γ</em>–<em>Ca</em>_micro boundaries. During co-current imbibition, an unusual capillary-driven displacement process was observed, leading to fingering in the fracture–matrix model and leaving a large area of macroscale remaining oil. Smaller <em>Ca</em>_micro and fracture development will facilitate this process. In addition, various forms of microscale remaining oil, caused by bypass flow snap-off and Saffman–Taylor instability/Rayleigh–Taylor instability, were also observed across different imbibition processes. This study elucidates the imbibition mechanisms under the combined influence of capillary and viscous forces, providing deeper insights into the imbibition process in porous media.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 928-938"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147332460","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Stability mechanism and steady-state flow characteristics of oil-resistant foam in high-salinity reservoirs","authors":"Lin Sun ,&nbsp;Jia-Qi Yin ,&nbsp;Hong-Ying Sun ,&nbsp;Yan-Ping Wu ,&nbsp;Wan-Fen Pu ,&nbsp;Bing Wei","doi":"10.1016/j.petsci.2025.11.014","DOIUrl":"10.1016/j.petsci.2025.11.014","url":null,"abstract":"<div><div>High salinity and high oil content present major challenges to the effectiveness of foam in enhanced oil recovery (EOR). This study introduces RCS, a novel oil-resistant foam system designed for reservoirs with salinity levels reaching 2.1 × 10⁵ mg/L. RCS forms stable foams at oil–water ratios up to 60% and is effective across a wide crude oil viscosity range (10.8–7890 mPa·s). We investigated the film properties of oil-containing foam and the co-permeation behavior of the crude oil–N₂–foam system to elucidate the mechanisms underlying foam stability and steady-state flow. RCS emulsified high-viscosity crude oil into stable, large droplets that accumulated within the plateau borders, reducing drainage. Even at concentrations as low as 0.01 wt%, RCS formed stable pseudoemulsion films that prevented intrusion into the gas–water interface, allowing the foam half-life to be mainly controlled by the dilatational viscoelasticity of the interface. With increasing oil–water ratios, both drainage resistance and dilatational modulus increased, extending the drainage and foam half-lives. Coreflood experiments showed that co-injection of RCS with N₂ and crude oil produced stable foams and in-situ emulsions. At 5% oil fractional flow, the critical foam quality (<span><math><mrow><msubsup><mi>f</mi><mi>g</mi><mo>∗</mo></msubsup></mrow></math></span>) remained unchanged compared to oil-free conditions, although the maximum apparent viscosity decreased by 29.8%. At 10% oil fractional flow, <span><math><mrow><msubsup><mi>f</mi><mi>g</mi><mo>∗</mo></msubsup></mrow></math></span> shifted to a lower value, while the apparent viscosity in the low-quality regime increased markedly—exceeding that of the oil-free condition. These findings highlight that while crude oil more strongly impairs foam stability in porous media than in bulk, the formation of in-situ emulsions can partially offset or even enhance mobility control through a synergistic Jamin effect. Therefore, in-situ emulsification should be emphasized in foam applications within oil-containing environments.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 913-927"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417679","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Joint geostatistical seismic inversion of elastic and petrophysical properties using stochastic co-simulation models based on parametric copulas","authors":"Daniel Vázquez-Ramírez ,&nbsp;Martín A. Díaz-Viera ,&nbsp;Raúl del Valle-García","doi":"10.1016/j.petsci.2025.10.029","DOIUrl":"10.1016/j.petsci.2025.10.029","url":null,"abstract":"<div><div>Seismic properties play a fundamental role in the geological and petrophysical modeling of reservoirs due to their dependence on petrophysical properties. Most existing stochastic seismic inversion methods are based on Gaussian probability distribution functions and assume linear dependence. Examples include sequential Gaussian co-simulation (SGCS) and direct sequential simulation (DSS). In contrast, spatial stochastic co-simulation methods based on Bernstein copulas (BCCS) have recently been developed. These methods do not require a specific distribution type or linear dependence, thereby overcoming the limitations of traditional approaches.</div><div>In this context, we propose a novel approach for the joint seismic inversion of elastic and petrophysical properties using parametric copulas within a Bayesian inference framework. A joint probability distribution is constructed using well-scale petrophysical and elastic property data, fitted to parametric copula functions and treated as prior information. The model parameters are then updated <em>a posteriori</em> using petrophysical properties scaled by a moving window averaging method and seismic properties upscaled using the Backus averaging method. The resulting posterior model is used within the inversion process to generate elastic property realizations at the seismic scale.</div><div>The inverse problem is solved using a simulated annealing algorithm that minimizes a global objective function combining the root-mean-square (RMS) error between synthetic and observed seismic traces, and the semivariogram error between the simulated and target variogram models. For each elastic realization, a reflectivity series is computed and convolved with a seismic wavelet to generate a synthetic seismic trace. The best-fitting elastic realization is then used to simulate the corresponding petrophysical property using the same joint probability distribution.</div><div>The proposed method was applied to a deepwater reservoir case study to estimate total porosity and acoustic impedance at the seismic scale. Results demonstrate that the use of parametric copulas reduces computational cost and execution time while enabling effective integration of nonlinear dependencies. The synthetic traces exhibit RMS errors below 8%, validating the accuracy and robustness of the copula-based inversion framework.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 608-625"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417948","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Application of acrylic-based wellbore strengthening material in water-based drilling fluid to stabilize the fractured formation","authors":"Kai-He Lv ,&nbsp;Juan He ,&nbsp;Xian-Bin Huang ,&nbsp;Jin-Sheng Sun","doi":"10.1016/j.petsci.2025.11.037","DOIUrl":"10.1016/j.petsci.2025.11.037","url":null,"abstract":"<div><div>Wellbore instability is the main challenge encountered during borehole construction, particularly when employing water-based drilling fluid (WBDF) under complex geological conditions. A novel wellbore strengthening material of acrylic resin enhanced by hydrophobically modified calcium carbonate particles (ARH) is synthesized by emulsion polymerization. Transmission electron microscope and particle size analysis reveal that ARH exhibits a spherical structure with a <em>Z</em>-average diameter of 277.6 nm. The lap shear strength test shows ARH effectively adheres to two rock slices with a stress of 0.4838 MPa. Uniaxial compressive strength experiments of simulated rock cores verify that ARH can greatly enhance the compressive strength of the simulated core column to 7.1567 MPa. The incorporation of ARH significantly enhances the compressive strength of shale cores, with increases of 18.0620 and 18.9147 MPa compared to those immersed in water and base fluid, respectively. Further microporous membrane plugging experiments show that the filtration losses of 2% ARH in 4% base fluid through 0.1, 0.2, and 0.45 μm microporous membranes are 13.5, 13.2, and 27 mL, respectively, demonstrating excellent plugging capabilities for enhancing wellbore stability. This work generates important theoretical foundations and practical recommendations for wellbore strengthening applications utilizing ARH in complex drilling environments.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 730-741"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147332489","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Genesis of Late Carboniferous volcanic rocks in the Kebai Fault Zone, Western Junggar, Xinjiang: Constraints from zircon U-Pb age, whole rock geochemistry, and Sr-Nd-Pb isotopes","authors":"Wei Wang ,&nbsp;Chuan-Yi Tang ,&nbsp;Zong-Quan Yao ,&nbsp;Yan Gao ,&nbsp;Feng-Bin Han ,&nbsp;Zong-Rui Xie ,&nbsp;Jian Chen ,&nbsp;Yuan-Feng Yang ,&nbsp;Ya-Fang Zhang","doi":"10.1016/j.petsci.2025.10.030","DOIUrl":"10.1016/j.petsci.2025.10.030","url":null,"abstract":"<div><div>The Late Paleozoic tectonic evolution of the Junggar Basin played a critical role in the formation of its oil and gas resources; however, as most of the basin is covered by desert, the evolutionary process remains controversial. In this study, we present a comprehensive analysis of the rock associations, petrography, ages, and systematic elemental and isotopic compositions of Carboniferous volcanic rocks obtained from drilling holes along the western margin of the basin, aiming to better constrain the late Paleozoic tectonic evolution of this region. Two zircon samples, from tuff and andesite layers, yielded concordant ages of 316.8 ± 1.7 and 321.7 ± 1.8 Ma, respectively, indicating intense volcanic eruptions during the Late Carboniferous. The analyzed volcanic rocks exhibited sodic calc-alkaline affinities, with SiO₂ content ranging from 53.46 to 61.57 wt%, TiO₂ content from 0.75 to 1.20 wt%, and a significantly higher Na₂O content than that of K₂O. In terms of trace elements, they showed variable enrichment in light rare earth elements ((La/Yb)_N = 2.72 to 7.89) and large ion lithophile elements such as Ba, Th, U, and Sr. Low Cr (0.67–65.72) and Ni (0.86–34.90) contents, together with significant negative Eu anomalies (<em>δ</em>Eu = 0.17 to 0.35), suggest variable fractionation of the primitive magma prior to eruption. All these features, combined with prominent Nb-Ta depletions in PM-normalized incompatible element spider diagrams, unambiguously indicate their genetic relationship with a subduction environment. However, the volcanic rocks showed low initial (⁸⁷Sr/⁸⁶Sr)_i values (0.7039–0.7057) and positive <em>ε</em>_Nd(<em>t</em>) values (7.5–8.0). Moreover, the combined (²⁰⁸Pb/²⁰⁴Pb)_i ranged from 37.7295 to 37.7851, (²⁰⁷Pb/²⁰⁴Pb)_i ranged from 15.4935 to 15.5037, and (²⁰⁶Pb/²⁰⁴Pb)_i ranged from 17.8910 to 17.9254, indicating that their primitive magma originated from an extremely depleted mantle source with crustal contamination. Integrating this study with regional geology, we propose that the volcanic rocks in the Kebai Fault Zone were most likely formed in a back-arc basin setting induced by ridge subduction.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 712-729"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147418373","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A novel approach to evaluating remaining oil potential using dynamic connectivity and bivariate mapping in large-scale reservoirs","authors":"Jun-Da Wu,&nbsp;Tao Chang,&nbsp;Yi-Fan He,&nbsp;Quan-Lin Wang,&nbsp;Di Wang","doi":"10.1016/j.petsci.2025.12.018","DOIUrl":"10.1016/j.petsci.2025.12.018","url":null,"abstract":"<div><div>In the development of water flooding reservoirs, enhancing oil recovery often requires implementing measures tailored to the reservoir's specific characteristics. A critical step in this process is evaluating the remaining oil potential, which directly influences the effectiveness of recovery strategies. However, evaluating the remaining oil potential in large reservoirs is challenging due to reservoir heterogeneity and complex well patterns. Existing evaluation methods are often cumbersome and lack intuitiveness. To address these issues, this study proposes a novel method for evaluating remaining oil potential by utilizing reservoir dynamic connectivity and remaining oil abundance. This method draws upon the advantages of the Eikonal equation in accurately describing the pressure wavefront and its propagation speed. By replacing traditional analytical methods with bivariate mapping, this approach effectively visualizes and correlates dynamic and static attributes. On this basis, the reservoir is classified into four regions: uneconomic/awaiting measures, low-efficiency waterflooding, major potential, and primary production. The potential of each region is intuitively analyzed and evaluated, offering clear insights into development status, untapped potential, and optimal strategies for reservoirs within each region. The application of this method to the M oilfield in the Bohai Sea yielded promising results across three distinct scenarios aimed at enhancing recovery: horizontal well water control, injection–production system optimization, and infill horizontal well deployment. These successful outcomes highlight the applicability of this method to complex, large-scale reservoirs and highlight its potential as a valuable tool for guiding recovery strategies in other challenging reservoir environments.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 836-850"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417839","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Seismic simulation for distributed acoustic sensing data using a novel stress and strain-rate elastic wave equation","authors":"Chong Zhao ,&nbsp;Ji-Dong Yang ,&nbsp;Jian-Ping Huang ,&nbsp;Ning Qin ,&nbsp;Kun Tian ,&nbsp;Fei-Long Yang","doi":"10.1016/j.petsci.2025.09.015","DOIUrl":"10.1016/j.petsci.2025.09.015","url":null,"abstract":"<div><div>Distributed acoustic sensing (DAS) is an advanced seismic acquisition technology with many advantages, such as low cost, wide frequency band, dense spatial sampling, and continuous recording. The straight optical fiber is restricted to single-component data and exhibits the lack of broadside sensitivity. To address the limitations of straight optical fiber and investigate the seismic response of multi-component DAS system, we proposed a novel first-order stress and strain-rate elastic wave equation to simulate the propagation of strain-rate wavefields. Compared to conventional particle-velocity wavefields, the simulations of three numerical examples demonstrate that the proposed equation can correctly generate elastic normal strain-rate wavefields and produce multi-component DAS data. Additionally, the simulations indicate that increasing the gauge length reduces the measurement accuracy of DAS, and a helical-wound optical fiber at a winding angle of 35.3° remains insensitive to S-wave, whereas it can clearly record S-wave at 54.7°. Furthermore, this equation can be directly implemented for multi-component DAS revers time migration (RTM) or FWI, thereby eliminating the need for traditional data conversion.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 626-642"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147418372","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Long-term sustained release of small molecular surfactants using microcapsules","authors":"Shuang Liu ,&nbsp;Ling-Ling Ren ,&nbsp;Zheng Wang ,&nbsp;Jia-Wei Shi ,&nbsp;Chen-Guang Wang ,&nbsp;Jia-Hui Guo ,&nbsp;Lu Zhang ,&nbsp;Hao-Ran Cheng ,&nbsp;Li-Yuan Zhang","doi":"10.1016/j.petsci.2025.11.019","DOIUrl":"10.1016/j.petsci.2025.11.019","url":null,"abstract":"<div><div>The controlled manipulation of surfactant concentration is essential for optimizing performance in numerous industrial applications, such as enhanced oil recovery in oil industry. However, encapsulating surfactants has proven challenging due to their propensity to localize at interfaces. In this study, we use microfluidic technology to fabricate poly (ethylene glycol) diacrylate-based microcapsules for encapsulating small molecular cargoes through finely tuning the relationships among the interfacial tensions of inner, middle and outer phases. These microcapsules show excellent retention by regulating the shell thickness and monomer content, releasing less than 47.2% over 49 d at 20 °C. Upon oil contact, surfactant release is indicated by a contact angle decrease of 7.2° at 20 °C and 21.8° at 50 °C within 48 h. The releases of nonionic Tween 80 and zwitterionic Betaine 1 calculated via surface tension in saline solutions at 80 °C are reduced to as low as 8.2% within 48 h and 1.1% within 8 h. The pressure-induced release reaches 22.7% within 24 h under 15 MPa, significantly exceeding the impacts of temperature and salinity. Notably, even microcapsules with reduced eccentricity still demonstrate sustained-release behavior. Mechanical and degradation tests show that the sustained release is driven by the increase in pore size of the shell due to its gradual degradation. This tunable system offers a versatile platform for encapsulating and controlling the release of surfactants or other sensitive agents, ideal for harsh environmental applications requiring sustained functionality.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 954-965"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147330855","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Study of the effect of nanoemulsion on the EOR in low-permeability, highly waxy oil reservoirs based on NMR displacement experiments","authors":"Rui-Jie Fei ,&nbsp;Ming-Hui Li ,&nbsp;Shuai Yuan ,&nbsp;Chen Cao ,&nbsp;Fu-Jian Zhou ,&nbsp;Er-Dong Yao ,&nbsp;Hao Bai ,&nbsp;Diu-Wei Ding","doi":"10.1016/j.petsci.2025.11.013","DOIUrl":"10.1016/j.petsci.2025.11.013","url":null,"abstract":"<div><div>Wax precipitation damage caused by cold water injection or temperature reduction is very commonly seen in the development of waxy crude oil reservoirs. Various methods for eliminating wax precipitation damage have been studied by many scholars, such as injecting hot water, artificial fracture, and using chemical dewaxing agents. However, the effects of nanoemulsion on wax crystals and enhanced oil recovery (EOR) have not yet been systematically studied. This study used core displacement system based on nuclear magnetic resonance (NMR) to investigate the effect of nanoemulsion on the EOR in low-permeability, waxy oil reservoirs. Some influencing factors such as injection water temperatures, core permeability, fractured/unfractured core, and nanoemulsion concentration conditions have been investigated. Meanwhile, the wax crystal morphology and quantity have been studied before and after using nanoemulsion using a polarizing microscope. The main conclusions are as follows: (1) After injecting 60 °C hot water, the recovery can be increased from 19.36% to 32.82%, which can alleviate wax deposition damage to a certain extent. (2) Enhancing core permeability or using fractured cores can increase the flow capacity of displacement fluid within the core and enhance waxy crude oil recovery. The EOR after improving core permeability is 10.22%, while the EOR of the fractured core is 26.24%. (3) Nanoemulsions can dissolve wax crystals in waxy crude oil and inhibit their formation to achieve EOR. The crude oil recovery at nanoemulsion concentrations of 0.1, 0.5, and 1.0 wt% were 34.84%, 38.24%, and 42.85%, respectively. (4) The use of nanoemulsion can reduce the number, area ratio, and fractal dimension of wax crystals, thereby mitigating wax deposition damage. Using a 1 wt% of nanoemulsion, the area ratio of wax crystals decreased from 47.25% to 16.67%, and the number of wax crystals decreased from 1309 to 496.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"23 2","pages":"Pages 897-912"},"PeriodicalIF":6.1,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147417678","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}