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21 pages, 4844 KB

Open AccessArticle

A Study on Characteristics of Oil–Water Relative Permeability Curves and Seepage Mechanisms in Low-Permeability Reservoirs

by Baolei Liu, Hongmin Yu, Youqi Wang, Zheng Yu and Lingfeng Zhao

Processes 2025, 13(11), 3460; https://doi.org/10.3390/pr13113460 - 28 Oct 2025

Viewed by 714

Abstract

Low-permeability reservoirs play a crucial role in global energy supply, yet their efficient development is hindered by complex seepage mechanisms and strong nonlinear flow behavior. This study systematically investigates the characteristics of oil–water relative permeability curves and the associated non-Darcy flow phenomena in [...] Read more.

Low-permeability reservoirs play a crucial role in global energy supply, yet their efficient development is hindered by complex seepage mechanisms and strong nonlinear flow behavior. This study systematically investigates the characteristics of oil–water relative permeability curves and the associated non-Darcy flow phenomena in low-permeability sandstone reservoirs. Through unsteady-state water flooding experiments on native cores with permeabilities ranging from 2.99 to 34.40 mD, we analyzed the influence of permeability on relative permeability curves and categorized the water-phase curves into concave-downward and linear types. A dynamic quasi-threshold pressure gradient model was established, incorporating the corrected permeability and water saturation. Furthermore, a novel relative permeability calculation model was derived by integrating the threshold pressure gradient into the non-Darcy flow framework. Validation against the traditional Johnson–Bossler–Naumann (JBN) method demonstrated that the proposed model more accurately captures the flow behavior in low-permeability media, showing lower oil-phase permeability and higher water-phase permeability. The findings provide a reliable theoretical basis for optimizing water flooding strategies and enhancing recovery in low-permeability reservoirs. Full article

(This article belongs to the Special Issue Advanced Strategies in Enhanced Oil Recovery: Theory and Technology)

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34 pages, 15906 KB

Open AccessArticle

Investigation of the Relationship Between Reservoir Sensitivity and Injectivity Impedance in Low-Permeability Reservoirs

by Baolei Liu, Youqi Wang, Hongmin Yu, Xiang Li and Lingfeng Zhao

Processes 2025, 13(10), 3283; https://doi.org/10.3390/pr13103283 - 14 Oct 2025

Viewed by 463

Abstract

In low-permeability reservoirs, studying reservoir sensitivity is crucial for optimizing water flooding, as it identifies detrimental mineral-fluid interactions that can cause formation damage and reduce injection efficiency. However, existing diagnostic methods for sensitivity-induced damage rely on post-facto pressure monitoring and lack a quantitative [...] Read more.

In low-permeability reservoirs, studying reservoir sensitivity is crucial for optimizing water flooding, as it identifies detrimental mineral-fluid interactions that can cause formation damage and reduce injection efficiency. However, existing diagnostic methods for sensitivity-induced damage rely on post-facto pressure monitoring and lack a quantitative relationship between sensitivity factors and water injectivity impairment. Furthermore, correlating microscale interactions with macroscopic injectivity parameters remains challenging, causing current models to inadequately represent actual injection behavior. This study combines microscopic techniques (e.g., SEM, XRD, NMR) with macroscopic core flooding experiments under various sensitivity-inducing conditions to analyze the influence of reservoir mineral composition on flow capacity, evaluate formation sensitivity, and assess the dynamic impact on water injectivity. The quantitative relationship between clay minerals and injectivity impairment in low-permeability reservoirs is also investigated. The results indicate that flow capacity is predominantly governed by the type and content of sensitive minerals. In water-sensitive reservoirs, water injection induces clay swelling and migration, leading to flow path reconfiguration and water-blocking effects. In salt-sensitive formations, high-salinity water promotes salt precipitation within pore throats, reducing permeability. In velocity-sensitive formations, fine particle migration causes flow resistance to initially increase slightly and then gradually decline with continued injection. Acidizing generally enhances pore connectivity but induces pore-throat plugging in chlorite-rich reservoirs. Alkaline fluids can exacerbate heterogeneity and generate precipitates, though appropriate concentrations may improve connectivity. Under low effective stress, rock dilation increases porosity and permeability, while elevated stress causes compaction, increasing flow impedance. Full article

(This article belongs to the Special Issue Advanced Strategies in Enhanced Oil Recovery: Theory and Technology)

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22 pages, 4270 KB

Open AccessArticle

Numerical Simulation of CO₂ Injection and Production in Shale Oil Reservoirs with Radial Borehole Fracturing

by Dongyan Zhou, Haihai Dong, Xiaohui Wang, Wen Zhang, Xiaotian Li, Yang Cao, Qun Wang and Jiacheng Dai

Processes 2025, 13(9), 2873; https://doi.org/10.3390/pr13092873 - 8 Sep 2025

Viewed by 1578

Abstract

Shale oil is a vital strategic resource in China. Developing shale oil using CO₂ not only enhances oil recovery but also contributes to achieving Chinese “dual carbon” goals. Given the challenges of insufficient number of fractures, inadequate vertical stimulation volume, and poor [...] Read more.

Shale oil is a vital strategic resource in China. Developing shale oil using CO₂ not only enhances oil recovery but also contributes to achieving Chinese “dual carbon” goals. Given the challenges of insufficient number of fractures, inadequate vertical stimulation volume, and poor reservoir mobility associated with horizontal well fracturing, this study proposes a method for CO₂ flooding based on radial borehole fracturing in a single well to achieve long-term carbon sequestration. To this end, a multi-component numerical model is built to analyze the production capacity of radial borehole fracturing. This study analyzed the impacts of non-Darcy flow, diffusion, and adsorption mechanisms on CO₂ migration and sequestration. It also compared the applicability of continuous CO₂ flooding and CO₂ huff-and-puff under different matrix permeabilities. The results indicate that (1) CO₂ flooding using radial borehole fracturing can achieve long-term oil production and carbon sequestration. (2) Under low permeability conditions, the liquid non-Darcy effect retards the flow of oil and CO₂, while diffusion and adsorption facilitate CO₂ sequestration in the reservoir. The impact on carbon sequestration is ranked as follows: non-Darcy effect > adsorption > diffusion. (3) High-permeability reservoirs are more suitable for carbon sequestration and should utilize continuous CO₂ flooding. For low-permeability reservoirs (<0.001 mD), huff-and-puff should be employed to mobilize the reservoir around fractures and achieve carbon sequestration. The findings of this study are expected to provide new methods and a theoretical basis for efficient and economical carbon sequestration in shale 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, 2180 KB

Open AccessArticle

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 588

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 KB

Open AccessArticle

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

Cited by 1 | Viewed by 563

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 KB

Open AccessArticle

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

Cited by 3 | Viewed by 783

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 KB

Open AccessArticle

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 636

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 KB

Open AccessArticle

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 6 | Viewed by 2730

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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