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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: 20 January 2027 | Viewed by 5136

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Editors

Dr. Xiujuan Tao

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Guest Editor

College of Chemistry and Chemical Engineering, Shanxi University of Science and Technology, Xi’an 710021, China
Interests: fractured reservoirs; wellbore stability; lost circulation control；reservoir protection; big data technology
Special Issues, Collections and Topics in MDPI journals

Dr. Yanjun Zhang

E-Mail Website
Guest Editor

College of Petroleum Engineering, Xi'an Shiyou University, Xi'an 710065, China
Interests: fracture driven interaction; fracturing and EOR integration; fracturing fluid retention; production strategy optimization; fracture propagation
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

As oil and gas development moves toward higher efficiency, lower carbon emissions and greater intelligence, stimulation technologies are evolving toward diversification and precision. This Special Issue aims to bring together recent advances and engineering practices in enhanced unconventional oil and gas recovery, with a focus on hydraulic fracturing, temporary plugging and diversion, CO₂-based fracturing and multi-physics coupling simulations.

The issue also considers the supportive role of artificial intelligence in areas such as fracture propagation prediction, optimization of fracturing parameters and monitoring data analysis. We encourage contributions that integrate fundamental research with field applications, including experimental studies, numerical modeling and case analyses. Through this Special Issue, we seek to deepen the understanding of stimulation mechanisms and promote the integration of new materials, advanced technologies and intelligent methods to support efficient development of unconventional reservoir.

Dr. Xiujuan Tao
Dr. Yanjun Zhang
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

reservoir stimulation reservoir protection
refracturing
temporary plugging
CO₂-based fracturing
artificial intelligence
multi-physical field coupling

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Published Papers (7 papers)

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Research

24 pages, 2605 KB

Open AccessArticle

Inversion and Dynamic Control of Local Heating Temperature Fields in Wellhead-Produced Fluids

by Xinwei Wang, Huiqin Wu, Dong Sun, Lihui Ma, Pan Zhang, Chenyu Fan, Haorong Wang and Riyi Lin

Processes 2026, 14(12), 1891; https://doi.org/10.3390/pr14121891 - 10 Jun 2026

Viewed by 336

Abstract

During heavy oil development, the gathering and transportation of low-temperature wellhead-produced fluids are often accompanied by high viscosity, pipe-wall deposition, and high flow resistance, threatening the continuous and stable operation of gathering systems. Existing studies on wellhead heating mainly focus on overall steady-state heating performance, while variable-flow heat transfer and start–stop control in local heating systems remain insufficiently explored. This study aims to evaluate the steady-state heating capacity, transient thermal response, and start–stop control performance of a localized electric heating section under variable-flow conditions. A 3D fluid–solid-coupled heat-transfer model of the heating element, pipe wall, and internal fluid was developed using COMSOL Multiphysics. The steady-state temperature field, transient heating and cooling behavior, and start–stop control characteristics were analyzed under different flow rates. The results show that, at a heating power of 15 kW and a flow rate of 20 m³/d, the maximum outer-wall temperature reached 564 K, and the average outlet fluid temperature reached 308.83 K, indicating effective heating performance. As the flow rate increased from 10 m³/d to 30 m³/d, the maximum pipe-wall temperature and fluid temperature rise both decreased, whereas the average fluid-side heat-transfer coefficient increased from approximately 700 W/(m²·K) to 1800 W/(m²·K), demonstrating enhanced convective heat transfer. Under a dual-threshold control strategy of 463.15–483.15 K, the system maintained the target temperature near 473.15 K under all tested conditions, while the load factor increased from 37.83% to 86.15%. These findings provide theoretical references and engineering support for optimizing power configuration and improving temperature control strategies in local heating systems for wellhead-produced fluids. Full article

(This article belongs to the Special Issue New Technology of Unconventional Reservoir Stimulation and Protection)

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19 pages, 2799 KB

Open AccessArticle

Study on the Influence Law of Hydrate Formation Ratio in Simulated Porous Media on Liquid Phase Permeability

by Kai Yang, Hanhong Yu, Shanshan Fu, Hualei Xu, Jie Wang and Houshun Jiang

Processes 2026, 14(8), 1285; https://doi.org/10.3390/pr14081285 - 17 Apr 2026

Viewed by 382

Abstract

Permeability evolution in hydrate-bearing porous media is a key factor controlling gas production efficiency during natural gas hydrate exploitation. In this study, laboratory experiments were conducted using sand-packed tubes filled with quartz sand and glass beads to systematically investigate the variation of liquid-phase permeability with hydrate saturation. The effects of pore structure, particle size, and initial gas injection pressure on hydrate formation and permeability reduction were analyzed. Furthermore, experimental results were compared with four commonly used permeability models, including the Kozeny model, the Dai model, the Masuda model, and the parallel capillary model. The results show that permeability decreases continuously with increasing hydrate saturation in both porous media, and the most rapid decline occurs at low saturation levels between 0 and 9%. Under the same conditions of 20–40 mesh and an initial pressure of 6.0 MPa, the pressure drop rate in the quartz-sand-packed tube reaches 1.062 kPa per minute, which is about 2.35 times higher than the 0.451 kPa per minute observed in the glass-bead-packed tube, indicating a faster hydrate formation rate and stronger permeability reduction in quartz sand. In addition, both increasing particle mesh size and raising the initial gas injection pressure significantly promote methane consumption and hydrate formation. Model comparison results demonstrate that permeability reduction is strongly dependent on pore structure. The Kozeny pore-filling model, the Dai model (M = 3), and the Masuda model (N = 8) show good agreement with the glass-bead data, whereas the Dai model (M = 8), the Masuda model (N = 15), and the pore-center form of the parallel capillary model better describe the quartz-sand system. In contrast, models based on particle-surface coating show poor agreement in both media. These findings indicate that permeability reduction is primarily controlled by pore-space occupation and flow-path restriction rather than uniform surface coverage. The results suggest that hydrate growth is more likely to occur in pore centers and critical pore-throat regions, although this conclusion is based on macroscopic model comparison and requires further validation by pore-scale observations. This study provides a quantitative basis for model selection and improves the understanding of permeability evolution in hydrate-bearing porous media. Full article

(This article belongs to the Special Issue New Technology of Unconventional Reservoir Stimulation and Protection)

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20 pages, 1983 KB

Open AccessArticle

Experimental Investigation of Surfactant-Assisted Low-Salinity Brine Flooding in Oil-Wet Carbonate Reservoirs for Enhanced Oil Recovery

by Amir Hossein Javadi, Ahmed Fatih Belhaj, Shasanowar Hussain Fakir and Hemanta Kumar Sarma

Processes 2026, 14(7), 1054; https://doi.org/10.3390/pr14071054 - 25 Mar 2026

Cited by 1 | Viewed by 824

Abstract

Low-salinity water flooding (LSWF) has been widely investigated as an enhanced oil recovery (EOR) method for carbonate reservoirs; however, the relative contributions of wettability alteration and oil–brine interfacial tension (IFT) reduction remain poorly understood, particularly under strongly oil-wet conditions. This study systematically investigates the physicochemical mechanisms governing oil recovery during hybrid LSWF–surfactant flooding in oil-wet carbonate systems. Oil-wet Indiana limestone cores were used as representative carbonate reservoir rocks. Seawater and its diluted analogs were employed as base brines and combined with anionic and cationic surfactants at varying concentrations. Zeta potential and pH measurements were conducted to characterize electrostatic interactions at the rock–brine and oil–brine interfaces, while dynamic contact angle and pendant-drop IFT measurements were used to quantify wettability evolution and fluid–fluid interactions. Core flooding experiments were subsequently performed to link interfacial phenomena to macroscopic oil recovery behavior. The results demonstrate that brine dilution induces more negative surface charges at both interfaces, promoting double-layer expansion and electrostatic repulsion, which stabilizes the aqueous film and drives wettability alteration toward a water-wet state. The addition of anionic surfactants further amplifies this effect by increasing surface charge negativity, whereas cationic surfactants preferentially adsorb onto the negatively charged rock surface, limiting wettability alteration despite producing greater IFT reduction. Sulfate ions enhance wettability alteration by facilitating divalent cation interactions with adsorbed oil components; however, excessive sulfate concentrations lead to precipitation-induced flow impairment. Core flooding results reveal that diluted seawater combined with an anionic surfactant yields the highest incremental oil recovery. Our findings conclusively demonstrate that wettability alteration—rather than IFT reduction—is the more dominant recovery mechanism in oil-wet carbonate reservoirs under the investigated conditions. These results provide mechanistic guidance for optimized brine and surfactant design in hybrid LSWF–chemical EOR applications. Full article

(This article belongs to the Special Issue New Technology of Unconventional Reservoir Stimulation and Protection)

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16 pages, 3952 KB

Open AccessArticle

Modeling Multi-Fracture Propagation in Fractured Reservoirs: Impacts of Limited-Entry and Temporary Plugging

by Wenjie Li, Hongjian Li, Tianbin Liao, Chao Duan, Tianyu Nie, Pan Hou, Minghao Hu and Bo Wang

Processes 2026, 14(3), 450; https://doi.org/10.3390/pr14030450 - 27 Jan 2026

Viewed by 563

Abstract

Staged multi-cluster fracturing in horizontal wells is a key technology for efficiently developing unconventional oil and gas reservoirs. Extreme Limited-Entry Fracturing (ELF) and Temporary Plugging Fracturing (TPF) are effective techniques to enhance the uniformity of fracture stimulation within a stage. However, in fractured reservoirs, the propagation morphology of multiple intra-stage fractures and fluid distribution patterns becomes significantly more complex under the influence of ELF and TPF. This complexity results in a lack of theoretical guidance for optimizing field operational parameters. This study establishes a competitive propagation model for multiple hydraulic fractures (HFs) within a stage under ELF and TPF conditions in fractured reservoirs based on the Displacement Discontinuity Method (DDM) and fluid mechanics theory. The accuracy of the model was verified by comparing it with laboratory experimental results and existing numerical simulation results. Using this model, the influence of ELF and TPF on intra-stage fracture propagation morphology and fluid partitioning was investigated. Results demonstrate that extremely limited-entry perforation and ball-sealer diversion effectively mitigate the additional flow resistance induced by both the stress shadow effect and the connection of natural fractures (NFs), thereby mitigating uneven fluid distribution and imbalanced fracture propagation among clusters. ELF artificially creates extremely high perforation friction by drastically reducing the number of perforations or the perforation diameter, thereby forcing the fracturing fluid to enter multiple perforation clusters relatively uniformly. Compared to the unlimited-entry scheme (16 perforations/cluster), the limited-entry scheme (5 perforations/cluster) yielded a 37.84% improvement in fluid distribution uniformity and reduced the coefficient of variation (CV) for fracture length and fluid intake by 54.28% and 44.16%, respectively. The essence of the TPF is non-uniform perforation distribution, which enables the perforation clusters with large fluid intake to obtain more temporary plugging balls (TPBs), so that their perforation friction can be increased and their fluid intake can be reduced, thereby diverting the fluid to the perforation clusters with small fluid intake. Deploying TPBs (50% of total perforations) at the mid-stage of fracturing (50% time) increased fluid distribution uniformity by 37.86% and reduced the CV of fracture length and fluid intake by 72.54% and 58.39%, respectively. This study provides methodological and modeling foundations for systematic optimization of balanced stimulation parameters in fractured reservoirs. Full article

(This article belongs to the Special Issue New Technology of Unconventional Reservoir Stimulation and Protection)

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18 pages, 5733 KB

Open AccessArticle

Research on the Calculation Method of Dynamic Effective Stress Coefficient Based on P-Wave Velocity

by Zhuochao Wang, Keke Huang, Daoli Liu, Qinpei Ren, Man Jiang, Zhaoming Chen, Kato Rutatina and Xiaoqiong Wang

Processes 2026, 14(1), 127; https://doi.org/10.3390/pr14010127 - 30 Dec 2025

Viewed by 731

Abstract

The Zhu I Depression in the Pearl River Estuary Basin is a major oil and gas enrichment area, with complex lithology, mainly mudstone, fine sandstone and siltstone, strong heterogeneity, and extensive development of abnormal high pressure, making it difficult to predict formation pressure. The effective stress coefficient (ESC) is an important parameter in formation pressure prediction and formation stress estimation, which is usually obtained by experiments and by the empirical function formulas of ESC and porosity. However, the calculation accuracy of these empirical formulas is often affected by lithology and critical porosity, and their application in the whole area or multi-lithology formations is limited. In addition, shear wave velocity data are limited by cost and technical conditions in practical logging applications. Therefore, based on the Gassmann equation and the approximation of P-wave modulus and volume modulus, this study realizes a multi-lithology ESC estimation method using P-wave velocity, density, and porosity, and applies it to the logging of the study block. The dynamic ESC along the wellbore direction is obtained and the logging dynamic ESC estimation model is corrected to verify the reliability of the method. The results show that the logging-derived ESC is mainly distributed in the range of 0.3~0.8, while the average ESC measured in the laboratory is between 0.5 and 0.6. The ESC of the sandstone layers with high porosity is relatively large and that of the mudstone layers with low porosity is small. In the absence of shear wave velocity, this method can effectively estimate the ESC and further predict formation pressure, which plays an important role in oil exploration and development. Full article

(This article belongs to the Special Issue New Technology of Unconventional Reservoir Stimulation and Protection)

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15 pages, 14100 KB

Open AccessArticle

Numerical Simulation of Bottom-Water Coning Suppression by Artificial Barriers and Water Drainage

by Yuankai Zhang, Liu Yang, Ning Xu, Junke Zhang and Xinhong Song

Processes 2026, 14(1), 116; https://doi.org/10.3390/pr14010116 - 29 Dec 2025

Cited by 1 | Viewed by 1126

Abstract

Bottom-water coning is a core challenge in the development of high-temperature, high-pressure, high-permeability, and fractured bottom water reservoirs. Taking the Carboniferous reservoir in Xinjiang as the research object, this work uses numerical simulation to optimize key parameters of artificial barriers, water drainage, and nitrogen injection technologies. The results show that an artificial barrier with a 30-m radius and intervention at 60% water cut placed at the reservoir top reduces water coning height by over 40%; water drainage starting after the third production year delays water cut rise by more than 2000 days; and nitrogen injection in the eighth production year at 65 MPa cuts water coning height by 30% to 40%. This work proposes a full-life-cycle phased synergy strategy, integrating early artificial barrier water blocking, mid-term intelligent water drainage pressure reduction, and late nitrogen injection oil stabilization. This work provides a direct and feasible technical paradigm for the efficient development of similar high-temperature, high-pressure, and fractured bottom water reservoirs worldwide. Full article

(This article belongs to the Special Issue New Technology of Unconventional Reservoir Stimulation and Protection)

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19 pages, 2921 KB

Open AccessArticle

A Study of the Reservoir Protection Mechanism of Fuzzy-Ball Workover Fluid for Temporary Plugging in Low-Pressure Oil Well Workover Operations

by Fanghui Zhu, Lihui Zheng, Yibo Li, Mengdi Zhang, Shuai Li, Hongwei Shi, Jingyi Yang, Xiaowei Huang and Xiujuan Tao

Processes 2026, 14(1), 59; https://doi.org/10.3390/pr14010059 - 23 Dec 2025

Cited by 1 | Viewed by 598

Abstract

This study addresses the challenges of low-pressure oil well workover operations, namely, severe loss of water-based workover fluid, significant reservoir damage from conventional temporary plugging agents, and slow production recovery, by focusing on the yet-mechanistically unclear “fuzzy-ball workover fluid.” Laboratory experiments combined with field data were used to evaluate its plugging performance and reservoir-protective mechanisms. In sand-filled tubes (diameter 25 mm, length 20–100 cm) sealed with the fuzzy-ball fluid, the formation’s bearing capacity increased by 3.25–18.59 MPa, showing a positive correlation with the plugging radius. Compatibility tests demonstrated that mixtures of crude oil and workover fluid (1:1) or crude oil, workover fluid, and water (1:1:1) held at 60 °C for 80 h exhibited only minor apparent viscosity reductions of 4 mPa·s and 2 mPa·s, respectively, indicating good stability. After successful plugging, a 1% ammonium persulfate solution was injected for 2 h to break the gel; permeability recovery rates reached 112–127%, confirming low reservoir damage and effective gel-break de-blocking. Field data from five wells (formation pressure coefficients 0.49–0.64) showed per-well fluid consumption of 33–83 m³ and post-workover liquid production index recoveries of 5.90–53.30%. Multivariate regression established mathematical relationships among bearing capacity, production index recovery, and fourteen geological engineering parameters, identifying the plugging radius as a key factor. Larger radii enhance both temporary plugging strength and production recovery without harming the reservoir, and they promote production by expanding the cleaning zone. In summary, the fuzzy-ball workover fluid achieves an integrated “high-efficiency plugging–low-damage gel-break–synergistic cleaning” mechanism, resolving the trade-off between temporary-plugging strength and production recovery in low-pressure wells and offering an innovative, environmentally friendly solution for the sustainable and efficient exploitation of oil–gas resources. Full article

(This article belongs to the Special Issue New Technology of Unconventional Reservoir Stimulation and Protection)

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