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

Deadline for manuscript submissions: closed (28 February 2026) | Viewed by 16868

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Editors

Dr. Lei Li

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Guest Editor

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
Interests: gas flooding; CCUS; chemical flooding; shale oil/tight oil recovery
Special Issues, Collections and Topics in MDPI journals

Dr. Hailong Zhao

E-Mail Website
Guest Editor

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
Interests: EOR; CCUS; chemical flooding; heavy oil
Special Issues, Collections and Topics in MDPI journals

Dr. Long Xu

E-Mail Website
Guest Editor

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
Interests: gas flooding; chemical flooding; heavy oil/shale oil/tight oil recovery
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

Enhanced oil recovery (EOR) is a key focus in petroleum engineering and energy production as global demand for hydrocarbon resources grows. Understanding the fundamental mechanisms of oil and gas flow through porous media, combined with advanced techniques to optimize recovery, is essential for efficiently developing oil and gas reservoirs. The complexities of multiphase flow, reservoir heterogeneity, and the interaction between injected fluids and formation rocks require detailed investigation, modeling, and innovative approaches.

This Special Issue on "Flow Mechanisms and Enhanced Oil Recovery" aims to gather novel research contributions that delve into the physical mechanisms of oil and gas flow in reservoirs and new methods to increase hydrocarbon recovery. We encourage submissions that explore the influence of reservoir properties, fluid behavior under different conditions, and the development of advanced simulation tools to model these processes. Contributions addressing innovative EOR techniques, such as gas flooding, chemical injection, and water-alternating-gas (WAG), and their impact on recovery efficiency are highly welcomed.

The Special Issue will highlight experimental and numerical studies, focusing on optimizing recovery methods and understanding the intricate flow dynamics in complex reservoir environments. Authors are invited to share their work on the characterization of reservoir systems, designing and implementing EOR strategies, and integrating state-of-the-art technologies in field applications. Modeling and simulation of fluid dynamics and EOR processes will also play a central role in this issue, offering valuable insights into optimizing field operations.

Topics include, but are not limited to:

Multiphase flow mechanisms in porous media;
Enhanced oil recovery techniques (gas injection, chemical flooding, and thermal methods);
Reservoir heterogeneity and its influence on flow and recovery;
Simulation and modeling of oil and gas flow in complex reservoirs;
Water-alternating-gas (WAG) and its optimization;
Field applications and case studies of successful EOR implementation;
Interaction between fluids and formation rocks under EOR processes.

We invite researchers from academia and industry to contribute their original research articles, reviews, and short communications to this Special Issue. Your participation will provide valuable contributions to the global understanding of flow mechanisms and strategies to enhance oil recovery, fostering innovation in this critical area of energy production.

Dr. Lei Li
Dr. Hailong Zhao
Dr. Long Xu
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 250 words) can be sent to the Editorial Office for assessment.

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-anonymized 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 semimonthly 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

oil and gas flow mechanisms
enhanced oil recovery (EOR)
multiphase flow
reservoir simulation
water-alternating-gas (WAG)
gas injection
chemical flooding
porous media

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Published Papers (14 papers)

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Research

22 pages, 10784 KB

Open AccessArticle

Multi-Scale Investigation of Reservoir Property Variations During Multi-Cycle Steam Stimulation in Heavy Oil Reservoirs

by Yanxu Zhou, Changcheng Han, Ting Yang, Yatao Wei, Xin Jiang, Yuzhao Cao and Xinbian Lu

Processes 2026, 14(6), 935; https://doi.org/10.3390/pr14060935 - 16 Mar 2026

Viewed by 352

Abstract

The application of multi-cycle steam stimulation in heavy oil reservoirs frequently alters reservoir properties, influencing the effectiveness of the stimulation and subsequent development strategies. The inherent heterogeneity of strata, characterized by distinct sedimentary facies rhythms, leads to differential patterns of property evolution. Therefore, understanding facies-controlled property variations during steam stimulation is essential for optimizing recovery strategies. This study integrates 1D core experiments with 3D geological modeling to dynamically simulate the stimulation process, enabling a comprehensive multi-scale analysis. The results show the following: (1) Both sedimentary rhythms exhibit progressive increases in porosity and permeability with successive cycles until reaching stabilization plateaus, with the uniform rhythm stabilizing earlier than the coarsening-upward rhythm. (2) 3D simulations reveal a predominant increasing trend in porosity and permeability after multi-cycle stimulation, albeit with localized reduction zones. (3) Multi-scale analysis indicates that, during the early stage (cycles 1–9), the underwater distributary channel microfacies undergoes more rapid property changes and achieves a greater cumulative increase in porosity and permeability. Conversely, during the later stage (cycles 10–30), the mouth bar microfacies demonstrates faster property alterations and a larger cumulative enhancement. This facies-specific, time-dependent understanding provides critical insights for tailoring steam stimulation strategies in heterogeneous heavy oil reservoirs. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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11 pages, 1148 KB

Open AccessArticle

Molecular Dynamics Simulation Study on the Mechanism of CO₂-CH₄ Synergistic Enhanced Oil Recovery in Tight Oil Reservoirs

by Lifeng Liu, Chengwei Wang, Lei Li and Yuliang Su

Processes 2026, 14(4), 638; https://doi.org/10.3390/pr14040638 - 12 Feb 2026

Viewed by 500

Abstract

Tight oil reservoirs are currently a hot topic in petroleum exploration and development. However, due to the low porosity and low permeability of reservoirs and the lack of external energy supplementation, there is a significant mismatch between resources and production in tight oil. Mining and experimental studies have shown that CO₂ and gaseous hydrocarbons have a high injectivity and effective oil displacement effect in tight oil reservoirs. Currently, research is mostly focused on a single energy supplement medium, and whether CO₂ hydrocarbon mixtures can more effectively improve oil recovery needs to be further studied. The features of crude oil expansion capacity and interaction energy changes following various fluid interactions were investigated via molecular dynamics simulation techniques in response to the ambitious comprehension of the mechanistic changes underlying the CO₂–CH₄ synergistic effect during the development of tight oil reservoirs. The research results indicate that the expansion and diffusion abilities of crude oil are improved after being treated with pure CO₂, CO₂-CH₄ (9:1), CO₂-CH₄ (7:3), and CO₂-CH₄ (1:1), and enhanced with increasing CO₂ content in the injected fluid. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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49 pages, 13115 KB

Open AccessArticle

The Experimental and Numerical Studies on Optimizing Injection Strategies for Microspheres-Alternating-Nanoemulsion Flooding in Tight Reservoirs

by Jun Wang, Lijun Zheng, Changhao Yan, Baoqiang Lv, Pengzhen Zhao, Wensheng Wu, Xiukun Wang and Jun Yang

Processes 2025, 13(12), 4093; https://doi.org/10.3390/pr13124093 - 18 Dec 2025

Viewed by 598

Abstract

In recent years, the production of tight reservoirs with waterflooding in China has entered a progressively declining phase with unstable oil rate and higher water cut, rising challenges to any further enhancement of oil recovery. Targeting the high water cut and complex pore structure characteristics typical of these reservoirs, this work evaluates the reservoir compatibility of a microspheres-alternating-nanoemulsion flooding process and optimizes its injection strategy. Representative reservoir scenarios were first established; laser-particle-size analyzers and other laboratory instruments were then employed to quantify formulation-reservoir compatibility. A multiscale numerical study has been performed with CMG-STARS v.2022. The core-scale simulations systematically examined the influence of key factors on displacement efficiency improvement and water cut reduction, matched with the experimental results of core flooding tests. The combined experimental/numerical workflow furnishes a theoretical framework for optimizing the injection scheme. Beyond assessing formulation compatibility, the study delivers optimized injection parameters and strategies for microspheres-alternating-nanoemulsion flooding, providing both theoretical analysis and practical technology reference for improving oil recovery in tight reservoirs with higher water cut. Specifically, when the microsphere concentration increased from 0.1% to 0.3%, the minimum water cut was reduced by approximately 5%, while further concentration increases showed no significant additional impact on water content. Compared with water flooding, the relative permeability curve of the microspheres-alternating-nanoemulsion flooding system shifted entirely to the right. Numerical simulation of representative well groups revealed that a slug design with a microsphere-to-nanoemulsion ratio of 1:3 yielded the optimal enhanced oil recovery effect, and after ten years of production, the recovery factor increased by 0.46%. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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18 pages, 3111 KB

Open AccessArticle

Mechanism and Parameter Optimization of Surfactant-Assisted CO₂ Huff-n-Puff for Enhanced Oil Recovery in Tight Conglomerate Reservoirs

by Ming Li, Jigang Zhang, Meng Ning, Yong Zhao, Guoshan Zhang, Jiaxing Liu, Mingjian Wang and Lei Li

Processes 2025, 13(12), 3888; https://doi.org/10.3390/pr13123888 - 2 Dec 2025

Viewed by 807

Abstract

China possesses abundant tight conglomerate oil resources. However, these reservoirs are typically characterized by low porosity and permeability, high clay mineral content, and complex pore structures, resulting in poor performance of conventional waterflooding development. Challenges including insufficient energy replenishment and high flow resistance ultimately lead to low oil recovery factors. This study systematically investigates surfactant-assisted CO₂ huff-n-puff (SA-CO₂-HnP) for enhanced oil recovery in tight conglomerate reservoirs. For a tight conglomerate reservoir in a Xinjiang block, a fully implicit, multiphase, multicomponent dual-porosity numerical model was established. By integrating pore–throat distributions acquired through high-pressure mercury intrusion with a self-developed MATLAB PVT package, nanoconfinement-induced shifts in the phase envelope were rigorously embedded into the simulation framework. The calibrated model was subsequently employed to conduct a comprehensive sensitivity analysis, quantitatively delineating the influence of petrophysical, completion, and operational variables on production performance. Simulation results demonstrate that compared to conventional CO₂ huff-n-puff, the addition of surfactants increases the cumulative recovery factor by 3.5 percentage points over a 20-year production period. The enhancement mechanisms primarily include reducing CO₂–oil interfacial tension (IFT) and minimum miscibility pressure (MMP), improving reservoir wettability, and promoting CO₂ dissolution and diffusion in crude oil. Sensitivity analysis reveals that injection duration, injection pressure, and injection rate significantly influence recovery efficiency, while soaking time exhibits relatively limited impact. Moreover, an optimal surfactant concentration (0.0003 mole fraction) exists; excessive concentrations lead to diminished enhancement effects due to competitive adsorption and pore blockage. This study demonstrates that SA-CO₂-HnP technology offers favorable economic viability and operational feasibility, providing theoretical foundation and parameter optimization guidance for efficient tight conglomerate oil reservoir development. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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22 pages, 6608 KB

Open AccessArticle

Dynamic Response of Fracture Networks and the Evolution of Waterflood Fronts During Fracture-Flooding

by Bintao Zheng, Liaoyuan Zhang, Yunfan Liu, Yuan Li, Yuzhe Zhang, Xiaodan Li and Lei Li

Processes 2025, 13(11), 3592; https://doi.org/10.3390/pr13113592 - 6 Nov 2025

Cited by 2 | Viewed by 636

Abstract

This study investigates the dynamic response of fracture networks and the evolution of waterflood fronts during fracture-flooding in low-permeability and tight reservoirs. By establishing a discrete fracture model that incorporates geomechanical heterogeneity and natural fractures, and utilizing the Barton-Bandis criterion to describe fracture stress-sensitive behavior, the fracture-flooding process was simulated and analyzed under two scenarios: considering versus ignoring the time-varying stress effect. The results demonstrate that when the time-varying stress effect is considered, fracture conductivity gradually recovers with increasing injection pressure, as the elevated fluid pressure within the fractures reduces the effective normal stress, promoting elastic dilation of the fracture aperture. This is evidenced by the average conductivity coefficient increasing from 0.4 (near-closure) to 0.99 (fully open) during the injection period. This recovery mechanism promotes a “wall-imbibition-dominated” flow pattern. In contrast, neglecting this effect leads to a “fracture-tip-breakthrough-dominated” mode, causing poor front uniformity. Quantitative analysis of the front morphology confirms this improvement: the perimeter-to-area ratio decreased from 2.507 to 1.647, and the coefficient of variation dropped from 0.490 to 0.324. This research provides an important theoretical basis for optimizing fracture-flooding operations and enhancing oil recovery. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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20 pages, 4410 KB

Open AccessArticle

Fractal Analysis of Microstructural Effects on Gas-Water Relative Permeability in Fractured Reservoirs

by Linhao Qiu, Yuxi Yang, Xiang Luo, Yunxiu Sai and Youyou Cheng

Processes 2025, 13(11), 3435; https://doi.org/10.3390/pr13113435 - 26 Oct 2025

Viewed by 833

Abstract

During natural gas extraction, understanding multiphase flow in fractured reservoirs remains a critical challenge due to the heterogeneous distribution of pores and fractures and the multi-scale nature of seepage mechanisms. These complexities introduce randomness in fluid distribution and tortuosity in seepage channels, limiting accurate characterization of gas-water flow. To address this issue, a dual-medium gas-water two-phase relative permeability model is developed by incorporating the fractal dimension of fracture surfaces, the tortuosity of the rock matrix, and the stress sensitivity of fracture networks. The model integrates essential microstructural parameters to capture the nonlinear flow behavior in dual-porosity systems. A systematic sensitivity analysis is conducted to evaluate the effects of fracture and matrix properties on the relative permeability curve. Results indicate that the fracture surface fractal dimension exerts a dominant influence in the two-phase flow region (fracture fractal dimensions in the range of 1.6–2.8), while near single-phase flow, fracture fractal dimensions in the range of 2.4–2.8 strongly affect flow behavior. Overall, the findings demonstrate that fracture-related parameters play a greater role than matrix properties in governing permeability evolution. This study provides predictive capability for two-phase flow in stress-sensitive fractured carbonates. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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24 pages, 5484 KB

Open AccessArticle

Mechanistic Investigation of CO₂-Soluble Compound Foaming Systems for Flow Blocking and Enhanced Oil Recovery

by Junhong Jia, Wei Fan, Chengwei Yang, Danchen Li and Xiukun Wang

Processes 2025, 13(10), 3299; https://doi.org/10.3390/pr13103299 - 15 Oct 2025

Cited by 2 | Viewed by 682

Abstract

Carbon dioxide (CO₂) has been widely applied in gas flooding for reservoir development due to its remarkable oil recovery potential. However, because its viscosity is lower than that of water and most crude oils, severe channeling often occurs during the flooding process, resulting in a significant reduction in the sweep efficiency. To address this issue, foam flooding has attracted considerable attention as an effective method for controlling CO₂ mobility. In this study, a compound foam system was developed with alpha-olefin sulfonate (AOS) as the primary foaming agent, alcohol ethoxylate (AEO) and cetyltrimethylammonium bromide (CTAB) as co-surfactants, and partially hydrolyzed polyacrylamide (HPAM) as the stabilizer. The optimal system was screened through evaluations of comprehensive foam index, salt tolerance, oil resistance, and shear resistance. Results indicate that the AOS+AEO formulation exhibits superior foaming ability, salt tolerance, and foam stability compared with the AOS+CTAB system, with the best performance achieved at a mass ratio of 2:1 (AOS:AEO), balancing both adaptability and economic feasibility. A heterogeneous reservoir model was constructed using parallel core flooding to investigate the displacement performance and blocking capability of the system. Nuclear magnetic resonance (NMR) imaging was employed to monitor in situ oil phase migration and clarify the recovery mechanisms. Experimental results show that the compound foam system demonstrates excellent conformance control performance, achieving a blocking efficiency of 84.5% and improving the overall oil recovery by 4.6%. NMR imaging further reveals that the system effectively mobilizes low-permeability zones, with T₂ spectrum analysis indicating a 4.5% incremental recovery in low-permeability layers. Moreover, in reservoirs with larger permeability ratio, the system exhibits enhanced blocking efficiency (up to 86.5%), though the incremental recovery is not strictly proportional to the blocking effect. Compared with previous AOS-based CO₂ foam studies that primarily relied on pressure drop and effluent analyses, this work introduces NMR imaging and T₂ spectrum diagnostics to directly visualize pore-scale fluid redistribution and quantify sweep efficiency within heterogeneous cores. The NMR data provide mechanistic evidence that the enhanced recovery originates from selective foam propagation and the mobilization of residual oil in low-permeability channels, rather than merely from increased flow resistance. This integration of advanced pore-scale imaging with macroscopic displacement analysis represents a mechanistic advancement over conventional CO₂ foam evaluations, offering new insights into the conformance control behavior of AOS-based foam systems in heterogeneous reservoirs. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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18 pages, 3556 KB

Open AccessArticle

Development of Double Crosslinked Nano Microspheres and Study on CO₂ Drive Blocking Mechanism

by Ping Guo, Yong Li, Yanbao Liu and Yunlong Zou

Processes 2025, 13(9), 2903; https://doi.org/10.3390/pr13092903 - 11 Sep 2025

Viewed by 817

Abstract

In this study, a new type of double crosslinked nanospheres (DCNPM-A) was developed to solve the problem of gas channeling caused by fracture development in the process of CO₂ oil displacement, and the microsphere system with delayed swelling was successfully synthesized by inverse micro lotion polymerization. The microsphere adopts a dual crosslinking structure of stable crosslinking agent (MBA) and unstable crosslinking agent (UCA), achieving intelligent sealing function of shallow low expansion and deep high temperature triggered secondary expansion. The successful preparation of microspheres was verified by characterization methods such as Zeta potential and SEM, and the effects of reaction temperature, time, initiator and crosslinking agent dosage on microsphere properties were systematically studied. The experimental results show that DCNPM-A microspheres exhibit excellent expansion performance, thermal stability, and acid resistance in acidic, high-temperature, and high mineralization environments. Their expansion ratio can reach 13.5 times, and they can maintain stability for more than 60 days in supercritical CO₂ environments. Core displacement experiments have confirmed that the microspheres have the best sealing performance in matrices with a permeability of 10 × 10⁻³ μm² and fractures with a width of 0.03 mm. The combination of 0.8 PV injection volume, 0.5 mL·min⁻¹ injection rate, and continuous injection method significantly improved the plugging rate and recovery rate of CO₂ flooding. This study provides new technical support for the efficient development of low-permeability fractured reservoirs. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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24 pages, 13675 KB

Open AccessFeature PaperEditor’s ChoiceArticle

Microscopic Investigation of the Effect of Different Wormhole Configurations on CO₂-Based Cyclic Solvent Injection in Post-CHOPS Reservoirs

by Sepideh Palizdan, Farshid Torabi and Afsar Jaffar Ali

Processes 2025, 13(7), 2194; https://doi.org/10.3390/pr13072194 - 9 Jul 2025

Cited by 1 | Viewed by 874

Abstract

Cyclic Solvent Injection (CSI), one of the most promising solvent-based enhanced oil recovery (EOR) methods, has attracted the oil industry’s interest due to its energy efficiency, produced oil quality, and environmental suitability. Previous studies revealed that foamy oil flow is considered as one of the main mechanisms of the CSI process. However, due to the presence of complex high-permeable channels known as wormholes in Post-Cold Heavy Oil Production with Sands (Post-CHOPS) reservoirs, understanding the effect of each operational parameter on the performance of the CSI process in these reservoirs requires a pore-scale investigation of different wormhole configurations. Therefore, in this project, a comprehensive microfluidic experimental investigation into the effect of symmetrical and asymmetrical wormholes during the CSI process has been conducted. A total of 11 tests were designed, considering four different microfluidic systems with various wormhole configurations. Various operational parameters, including solvent type, pressure depletion rate, and the number of cycles, were considered to assess their effects on foamy oil behavior in post-CHOPS reservoirs in the presence of wormholes. The finding revealed that the wormhole configuration plays a crucial role in controlling the oil production behavior. While the presence of the wormhole in a symmetrical design could positively improve oil production, it would restrict oil production in an asymmetrical design. To address this challenge, we used the solvent mixture containing 30% propane that outperformed CO₂, overcame the impact of the asymmetrical wormhole, and increased the total recovery factor by 14% under a 12 kPa/min pressure depletion rate compared to utilizing pure CO₂. Moreover, the results showed that applying a lower pressure depletion rate at 4 kPa/min could recover a slightly higher amount of oil, approximately 2%, during the first cycle compared to tests conducted under higher pressure depletion rates. However, in later cycles, a higher pressure depletion rate at 12 kPa/min significantly improved foamy oil flow quality and, subsequently, heavy oil recovery. The interesting finding, as observed, is the gap difference between the total recovery factor at the end of the cycle and the recovery factor after the first cycle, which increases noticeably with higher pressure depletion rate, increasing from 9.5% under 4 kPa/min to 16% under 12 kPa/min. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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21 pages, 18767 KB

Open AccessArticle

Reservoir Architecture of Turbidite Lobes and Remaining Oil Distribution: A Study on the B Formation for Z Oilfield of the Illizi Basin, Algeria

by Changhai Li, Weiqiang Li, Huimin Ye, Qiang Zhu, Xuejun Shan, Shengli Wang, Deyong Wang, Ziyu Zhang, Hongping Wang, Xianjie Zhou and Zhaofeng Zhu

Processes 2025, 13(3), 805; https://doi.org/10.3390/pr13030805 - 10 Mar 2025

Cited by 5 | Viewed by 1911

Abstract

The turbidite lobe is a significant reservoir type formed by gravity flow. Analyzing the architecture of this reservoir holds great importance for deep-water oil and gas development. The main producing zone in Z Oilfield develops a set of turbidite lobes. After more than 60 years of development, the well spacing has become dense, providing favorable conditions for detailed research on reservoir architecture of this kind. Based on seismic data, core data, and logging data, combined with the results of reservoir numerical simulation, this paper studies the reservoir architecture of turbidite lobes, displays the distribution of remaining oil in the turbidite lobes, and proposes development policies suitable for turbidite lobe reservoirs. The results show that the turbidite lobes can be classified into four sedimentary microfacies: lobe off-axis, lobe fringe, interlobe facies, and feeder channel facies. The study area is mainly characterized by multiple sets of lobes. There are feeder channels running through the south to the north. Due to the imperfect well pattern, the remaining oil is concentrated near the lobe fringe facies and the gas–oil contact. It is recommended to tap the potential of the turbidite lobes by adopting the “production at the off-axis lobes facies and injection at the lobe fringe facies (POIF)”. The study on the reservoir architecture and remaining oil of turbidite lobes has crucial guiding significance for the efficient development of Z Oilfield and can also provide some reference for developing deep-water oilfields with similar sedimentary backgrounds. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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20 pages, 3150 KB

Open AccessArticle

Effect of Reservoir Transformation on Fracture Expansion in Deep Coalbed Methane Reservoirs and Mechanism Analysis

by Jun Liu, Qinghua Zhang and Yanyang Fan

Processes 2025, 13(2), 493; https://doi.org/10.3390/pr13020493 - 10 Feb 2025

Cited by 1 | Viewed by 1279

Abstract

This paper proposed a fracture propagation model of water-based fracturing based on seepage–stress–damage coupling, which was employed to analyse the effects of different water-based fracturing fluid properties and rock parameters on the propagation behaviour of reservoir fractures in low-permeability reservoirs. Concurrently, molecular dynamics theory and mechanical analysis of reservoir fractures were employed to elucidate the microscopic mechanism of water-based fracturing on fracture propagation. The results showed that the apparent viscosity of water-based fracturing fluid primarily contributed to elevated fracture internal pressures through the seepage reduction in water-based fracturing fluid at the coal fracture surface. A substantial impact on the minimum fracturing pressure of coal fractures that rapidly pierce the coal rock and an increasing crack extension was notably presented by the low filtration and high viscosity of water-based fracturing fluids. Furthermore, the reservoir pressure and the crack turning angle were not conducive to the effective expansion of coal seam fractures, whereas the reservoir temperature exhibited a positive proportional relationship with deep coal seam fractures. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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18 pages, 7669 KB

Open AccessArticle

The Crack Propagation Behaviour of CO₂ Fracturing Fluid in Unconventional Low Permeability Reservoirs: Factor Analysis and Mechanism Revelation

by Qiang Li, Qingchao Li, Hongqi Cao, Jingjuan Wu, Fuling Wang and Yanling Wang

Processes 2025, 13(1), 159; https://doi.org/10.3390/pr13010159 - 8 Jan 2025

Cited by 112 | Viewed by 3152

Abstract

To circumvent the numerous deficiencies inherent to water-based fracturing fluids and the associated greenhouse effect, CO₂ fracturing fluids are employed as a novel reservoir working fluid for reservoir reconstruction in unconventional oil fields. Herein, a mathematical model of CO₂ fracturing crack propagation based on seepage–stress–damage coupling was constructed for analysing the effects of different drilling fluid components and reservoir parameters on the crack propagation behaviour of low permeability reservoirs. Additionally, the fracture expansion mechanism of CO₂ fracturing fluid on low permeability reservoirs was elucidated through mechanical and chemical analysis. The findings demonstrated that CO₂ fracturing fluid can effectively facilitate the expansion of cracks in low-permeability reservoirs, and thickener content, reservoir pressure, and reservoir parameters were identified as influencing factors in the expansion of reservoir cracks and the evolution of rock damage. The 5% CO₂ thickener can increase the apparent viscosity and fracture length of CO₂ fracturing fluid to 5.12 mPa·s and 58 m, respectively, which are significantly higher than the fluid viscosity (0.04 mPa·s) and expansion capacity (13 m) of pure CO₂ fracturing fluid. Furthermore, various other factors significantly influence the fracture expansion capacity of CO₂ fracturing fluid, thereby offering technical support for fracture propagation in low-permeability reservoirs and enhancing oil recovery. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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20 pages, 6646 KB

Open AccessArticle

The Numerical Simulation Study on the Heat Transfer Mechanism in Heavy Oil Reservoirs During In-Situ Combustion

by Jiuzhi Sun, Bo Wang, Yunjie Shu, Yanchao Wang, Yi Pan and Chao Tian

Processes 2025, 13(1), 56; https://doi.org/10.3390/pr13010056 - 30 Dec 2024

Cited by 4 | Viewed by 1822

Abstract

The escalating energy demand has prompted nations to prioritize the development of high-viscosity and challenging-to-extract heavy and extra-heavy oil reserves. Consequently, the technique of in-situ combustion in oil reservoirs by injecting air to ignite heavy oil resources, leveraging the generated heat to enhance recovery rates, is a particularly critical extraction method. However, simulation studies of in-situ combustion techniques are still primarily conducted at a macroscopic level. Therefore, conducting more detailed numerical simulation studies holds significant importance. This paper establishes a mathematical model for heat transfer within reservoirs during in-situ combustion, thoroughly investigating the effects of inlet temperature, injection pressure, injection duration, and porosity on the heat transfer processes inside the reservoir. The research demonstrates that the reservoir’s internal temperature gradually rises as the injection duration increases. Additionally, porosity (an increase from 0.1 to 0.3 enhances the heat propagation rate by 15%) and injection pressure (an increase from 5 MPa to 8 MPa boosts the heat propagation rate by 25%) significantly affect the heat transfer rate. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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19 pages, 10067 KB

Open AccessArticle

Research on Composite 3D Well Pattern for Blocky Heavy Oil in Offshore Areas: Transition from Huff-and-Puff to Displacement-Drainage

by Zhigang Geng, Gongchang Wang, Wenqian Zheng, Chunxiao Du, Taotao Ge, Cong Tian and Dawei Wang

Processes 2024, 12(12), 2884; https://doi.org/10.3390/pr12122884 - 17 Dec 2024

Viewed by 1497

Abstract

In view of the deep burial depth, high formation pressure, and presence of top and bottom water in offshore extra-heavy-oil reservoirs, this paper conducts a study on the production performance and flow field variation law of steam huff-and-puff to steam flooding conversion in thick heavy-oil reservoirs based on physical simulation, and analyzes the development effect of the conversion from steam huff-and-puff to steam flooding. On this basis, by comprehensively considering the advantages of gravity-assisted steam flooding and a three-dimensional HHSD well pattern obtained from physical simulation experiments, this paper proposes a well pattern development mode of steam huff-and-puff to composite displacement and drainage, and analyzes the development effect of this well pattern mode using the reservoir numerical simulation method. The research results show that, compared with the planar well pattern of steam huff-and-puff to steam flooding conversion, the adoption of the three-dimensional well pattern can significantly improve the degree of reservoir production and the expansion dynamics of the steam chamber, and mitigate adverse effects such as the increase in water cut caused by top and bottom water on thermal recovery. The composite development of steam huff-and-puff to composite displacement and drainage can be divided into three stages: thermal communication, gravity drainage-assisted steam flooding, and thermal breakthrough erosion and oil washing. The steam chamber presents a development mode of “single-point development–rapid longitudinal expansion–rapid transverse expansion upon reaching the top–polymerization into a sheet”, and simultaneously possesses the oil displacement mechanisms of both steam displacement and gravity drainage. The proposed composite mode of steam huff-and-puff to composite displacement and drainage has guided the implementation of adjustment wells in the Bohai L Oilfield, and the recovery factor has been increased by about 20% compared with the steam huff-and-puff development of the basic well pattern. This study has reference and guiding significance for the efficient thermal recovery development of this oilfield. Full article

(This article belongs to the Special Issue Flow Mechanisms and Enhanced Oil Recovery)

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