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Processes
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Advanced Strategies in Enhanced Oil Recovery: Theory and Technology
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Advanced Strategies in Enhanced Oil Recovery: Theory and Technology

A special issue of Processes (ISSN 2227-9717). This special issue belongs to the section "Energy Systems".

Deadline for manuscript submissions: 30 October 2025 | Viewed by 3013

Special Issue Editors

Prof. Dr. Hong He

E-Mail Website
Guest Editor
College of Petroleum Engineering, Yangtze University, Wuhan 430100, China
Interests: enhanced oil recovery; heavy oil; thermal recovery
Special Issues, Collections and Topics in MDPI journals
Dr. Mingchen Ding

E-Mail Website
Guest Editor
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
Interests: low permeability; tight oil CO2 injection development; profile control and water plugging; chemical flooding
Special Issues, Collections and Topics in MDPI journals
Prof. Dr. Long Yu

E-Mail Website
Guest Editor
Department of Petroleum Engineering, China University of Geosciences (Wuhan), Wuhan 430079, China
Interests: chemical flooding; CO2 storage in oil and gas reservoirs
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

Water flooding is recognized as one of the most common secondary oil recovery techniques, after the primary production period, which has been widely applied for different reservoirs. However, as reservoirs enter the late development stage, reservoir heterogeneity becomes serious and the distribution of the remaining oil becomes more scattered, and traditional water flooding recovery methods have been unable to satisfy the demand for enhanced oil recovery. In view of different reservoir types, including mature water flooding reservoirs, low-permeability reservoirs, heavy oil reservoirs, and so on, different strategies in enhanced oil recovery have been developed.

This Special Issue focuses on all aspects the above challenges, particularly the following:

  • Improve oil recovery strategies for water flooding reservoirs, including water shutoff, conformance control, and so on;
  • Chemical-enhanced oil recovery strategies, including polymer flooding, surfactant flooding, combined flooding, and so on;
  • CO2 flooding and storage strategies for different reservoirs;
  • Heavy oil recovery strategies.

Prof. Dr. Hong He
Dr. Mingchen Ding
Prof. Dr. Long Yu
Guest Editors

Manuscript Submission Information

Manuscripts should be submitted online at www.mdpi.com by registering and logging in to this website. Once you are registered, click here to go to the submission form. Manuscripts can be submitted until the deadline. All submissions that pass pre-check are peer-reviewed. Accepted papers will be published continuously in the journal (as soon as accepted) and will be listed together on the special issue website. Research articles, review articles as well as short communications are invited. For planned papers, a title and short abstract (about 100 words) can be sent to the Editorial Office for announcement on this website.

Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Processes is an international peer-reviewed open access monthly journal published by MDPI.

Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2400 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

  • enhanced oil recovery
  • water flooding
  • CO2 flooding
  • heavy oil reservoir
  • low-permeability reservoir
  • water shutoff
  • conformance control

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Published Papers (5 papers)

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Research

15 pages, 2180 KiB  
Article
Microfluidic Investigation on the Diffusion Law of Nano Displacement Agent in Porous Media
by Jiahui Liu, Shixun Bai, Weixiong Xiao and Shengwu Gao
Processes 2025, 13(8), 2546; https://doi.org/10.3390/pr13082546 - 12 Aug 2025
Viewed by 133
Abstract
Unconventional oil reservoirs are tight and often host micro-nano pores, and huff and puff is usually adopted for such reservoirs, mainly utilizing the mechanism of spontaneous imbibition. The penetration depth into the matrix during imbibition is one of the key influencing factors of [...] Read more.
Unconventional oil reservoirs are tight and often host micro-nano pores, and huff and puff is usually adopted for such reservoirs, mainly utilizing the mechanism of spontaneous imbibition. The penetration depth into the matrix during imbibition is one of the key influencing factors of oil recovery. In circumstances where a water phase is present in the reservoir, the injected oil displacement agent may not directly contact the oil phase, but instead needs to diffuse and migrate to the oil–water interface to adjust the capillary force, thereby affecting the imbibition depth. Therefore, the diffusion law of the oil displacement agent can indirectly affect the oil recovery by imbibition. In this study, microfluidic experiments were conducted to investigate the diffusion of nano oil displacement agents at different pore sizes (100 μm). The results show that the concentration distribution of nano oil displacement agents near the injection end was uniform during the diffusion process, and the concentration showed a decreasing trend with increasing depth. As the pore size decreased, the diffusion coefficient also decreased, and the diffusion effect deteriorated. There was a lower limit of pore size that allowed diffusion at approximately 15.66 μm. The diffusion law of the nano oil displacement agent in porous media obtained in this study is of great significance for improving the recovery rate of unconventional oil and gas resources. Full article
(This article belongs to the Special Issue Advanced Strategies in Enhanced Oil Recovery: Theory and Technology)
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17 pages, 4141 KiB  
Article
TPG Conversion and Residual Oil Simulation in Heavy Oil Reservoirs
by Wenli Ke, Zonglun Li and Qian Liu
Processes 2025, 13(8), 2403; https://doi.org/10.3390/pr13082403 - 29 Jul 2025
Viewed by 333
Abstract
The Threshold Pressure Gradient (TPG) phenomenon exerts a profound influence on fluid flow dynamics in heavy oil reservoirs. However, the discrepancies between the True Threshold Pressure Gradient (TTPG) and Pseudo-Threshold Pressure Gradient (PTPG) significantly impede accurate residual oil evaluation and rational field development [...] Read more.
The Threshold Pressure Gradient (TPG) phenomenon exerts a profound influence on fluid flow dynamics in heavy oil reservoirs. However, the discrepancies between the True Threshold Pressure Gradient (TTPG) and Pseudo-Threshold Pressure Gradient (PTPG) significantly impede accurate residual oil evaluation and rational field development planning. This study proposes a dual-exponential conversion model that effectively bridges the discrepancy between TTPG and PTPG, achieving an average deviation of 12.77–17.89% between calculated and measured TTPG values. Nonlinear seepage simulations demonstrate that TTPG induces distinct flow barrier effects, driving residual oil accumulation within low-permeability interlayers and the formation of well-defined “dead oil zones.” In contrast, the linear approximation inherent in PTPG overestimates flow initiation resistance, resulting in a 47% reduction in recovery efficiency and widespread residual oil enrichment. By developing a TTPG–PTPG conversion model and incorporating genuine nonlinear seepage characteristics into simulations, this study effectively mitigates the systematic errors arising from the linear PTPG assumption, thereby providing a scientific basis for accurately predicting residual oil distribution and enhancing oil recovery efficiency. Full article
(This article belongs to the Special Issue Advanced Strategies in Enhanced Oil Recovery: Theory and Technology)
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15 pages, 5067 KiB  
Article
Integrated Modeling of Time-Varying Permeability and Non-Darcy Flow in Heavy Oil Reservoirs: Numerical Simulator Development and Case Study
by Yongzheng Cui, Wensheng Zhou and Chen Liu
Processes 2025, 13(6), 1683; https://doi.org/10.3390/pr13061683 - 27 May 2025
Viewed by 412
Abstract
Studies have demonstrated that heavy oil flow exhibits threshold pressure gradient (TPG) which is closely related to the permeability and viscosity of the crude oil. Also, long-term water flooding continuously alters unconsolidated sandstone reservoir permeability through water flushing. These combined effects significantly influence [...] Read more.
Studies have demonstrated that heavy oil flow exhibits threshold pressure gradient (TPG) which is closely related to the permeability and viscosity of the crude oil. Also, long-term water flooding continuously alters unconsolidated sandstone reservoir permeability through water flushing. These combined effects significantly influence water flooding performance. Therefore, in this paper, a comprehensive oil–water two phase mathematical model is developed for waterflooded heavy oil unconsolidated sandstone reservoirs based on the traditional black oil model, incorporating both time-varying permeability and threshold pressure gradient. The water-flooding-dependent threshold pressure gradient is firstly proposed, accounting for time-varying permeability. Subsequently, a simulator is developed with finite volume and Newton iteration method. Good agreement is obtained with the commercial simulator based on traditional black oil model. Afterward, the influence of permeability time variation and threshold pressure gradient is analyzed in detail. Results demonstrate that the threshold pressure gradient and time-varying permeability both decrease the oil recovery. The threshold pressure gradient (TPG) reduces the oil flow region and displacement efficiency since production. The increases in permeability after long term water flooding exacerbate reservoir heterogeneity and reduce sweep efficiency. The lowest oil recovery is observed when non-Darcy flow and permeability time variation are considered simultaneously. Furthermore, the time-varying threshold pressure gradient is observed with permeability time variation. Finally, a field data history matching was successfully performed, demonstrating the practical applicability of the proposed model. This new model better aligns with reservoir development characteristics. It can provide a theoretical guide for the development of heavy oil reservoirs. Full article
(This article belongs to the Special Issue Advanced Strategies in Enhanced Oil Recovery: Theory and Technology)
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15 pages, 17211 KiB  
Article
Impact of Heterogeneity in Low-Permeability Reservoirs on Self-Diverting Acid Wormhole Formation and Acidizing Parameter Optimization
by Jun Luo, Chunlin Liu, An Liu, Xuchen Zhang and Fajian Nie
Processes 2025, 13(4), 1029; https://doi.org/10.3390/pr13041029 - 30 Mar 2025
Viewed by 435
Abstract
Carbonate rocks typically exhibit strong heterogeneity, which can have a significant impact on the effectiveness of acidification processes, and different types of acids are needed in the field to achieve various acidizing goals. This article develops a self-diverting acidizing program based on the [...] Read more.
Carbonate rocks typically exhibit strong heterogeneity, which can have a significant impact on the effectiveness of acidification processes, and different types of acids are needed in the field to achieve various acidizing goals. This article develops a self-diverting acidizing program based on the two-scale continuum model and open-source software FMOT, and investigates the influence of heterogeneity intensity on wormhole morphology and acidizing process parameters. The results indicate that different heterogeneity intensities significantly affected the morphology of the wormhole. At low intensity, the shape of the wormhole is close to a straight line, while at high intensity, it becomes tree-like. The reason for the significant impact is that the higher the heterogeneity intensity, the more obvious the dominant path within the rock, the more uneven the high viscosity zone formed, and the more obvious the turning of spent acid flow. The optimal injection rate of self-diverting acid increases with the increase in temperature. At lower injection rates, the self-diverting acid can produce more branching wormholes, and low temperatures enhance this effect, especially at high heterogeneity. Whether at a higher or lower acid injection rate, increasing the acid injection temperature appropriately is helpful to improve the acidizing efficiency. The acid injection rate and temperature should be adjusted to adapt to the pore heterogeneity of different intensities. Full article
(This article belongs to the Special Issue Advanced Strategies in Enhanced Oil Recovery: Theory and Technology)
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21 pages, 5536 KiB  
Article
Insights into Enhanced Oil Recovery by Viscosity Reduction Combination Flooding System for Conventional Heavy Oil Reservoir
by Hong He, Wenhui Ning, Haihua Pei, Ruping Chen, Yuhang Tian, Yibo Liu and Qingying Zuo
Processes 2025, 13(3), 618; https://doi.org/10.3390/pr13030618 - 21 Feb 2025
Cited by 3 | Viewed by 1365
Abstract
To settle the problems of high energy consumption and carbon emissions in the thermal recovery of heavy oil, the viscosity reduction combination flooding (V-RCF) method is proposed to enhance oil recovery for conventional heavy oil reservoirs. The performance of the viscosity reduction combination [...] Read more.
To settle the problems of high energy consumption and carbon emissions in the thermal recovery of heavy oil, the viscosity reduction combination flooding (V-RCF) method is proposed to enhance oil recovery for conventional heavy oil reservoirs. The performance of the viscosity reduction combination flooding (V-RCF) system composed of polymer, emulsifying surfactant, and ultra-low interfacial tension surfactant was evaluated. The interfacial tension between oil and water continues to be maintained at 10−3 mN/m as the concentration of ultra-low interfacial tension surfactant(L) increases. The viscosity reduction rate of the V-RCF system reaches over 95%. A series of parallel sand pack flooding experiments were carried out to investigate enhanced oil recovery. The enhanced oil recovery (EOR) efficiency of the V-RCF under various injection modes was compared, and the best injection mode was suggested. The incremental oil recovery of the V-RCF system under multiple slug injection modes is higher than that under single slug injection mode. The optimum slug injection sequence of the V-RCF system is injecting a polymer-emulsifying surfactant(P+R) slug firstly, and then, injecting a polymer-ultra-low interfacial tension surfactant(P+L) slug. The optimum slug size ratio of polymer-emulsifying surfactant(P+R) slug and polymer-ultra-low interfacial tension surfactant(P+L) slug is 2:1. The microfluidic flooding results have further confirmed that the best recovery rate is achieved when the slug ratio is 2:1 from a microscopic perspective. Full article
(This article belongs to the Special Issue Advanced Strategies in Enhanced Oil Recovery: Theory and Technology)
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