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Advanced Studies of Oil and Gas Flow in Unconventional Oil and Gas Reservoir

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

Deadline for manuscript submissions: 25 April 2026 | Viewed by 7677

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Special Issue Editors

Dr. Adebayo Abdulrauf

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Guest Editor

Center for Integrative Petroleum Research (CIPR), College of Petroleum Engineering and Geosciences, King Fahd Univesity of Petroleum & Minerals, Dhahran 31261, Saudi Arabia
Interests: experimental petrophysics; CCUS; hydrogen storage; foam flow in porous media; unconventional reservoirs

Dr. Liwu Jiang

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Guest Editor

1. Unconventional Petroleum Research Institute, China University of Petroleum-Beijing at Karamay, Karamay 834000, China
2. Petroleum Systems Engineering, University of Regina, Regina, SK S4S 0A2, Canada
Interests: seepage flow in porous media; reservoir numerical simulation; CCUS; transient pressure/rate analysis

Dr. Ahmed Al-Yaseri

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Guest Editor

Center for Integrative Petroleum Research, Dhahran, Saudi Arabia
Interests: energy storage

Special Issue Information

Dear Colleagues,

Hydrocarbons have been explored and produced for many decades, with a particular focus on conventional reservoirs. Increased energy demands coupled with a decline in new conventional resources necessitate the exploration of non-conventional reservoirs such as shale, tight gas sands, coalbed methane, gas hydrates, and tar sands. Because the fluids in these reservoir rocks are bounded by strong capillary forces, with a reduced pathway available for flow, a new set of challenges ranging from characterization to production must be addressed. In recent years, significant technological advances have been witnessed in this field, but futher research is still needed. This Special Issue, entitled “Advanced Studies of Oil and Gas Flow in Unconventional Oil and Gas Reservoir”, aims to collect high-quality articles that present new findings, enhance our understanding of the field, and propose novel technologies related to all aspects of unconventional reservoirs. The scope of this Special Issue includes, but is not limited to, the following topics:

Reaservoir-scale and laboratory-scale characterization of unconventional reservoir rocks (geomechancs, petropjysics, petrography, geochemistry, etc.);
Simulation of oil and gas flow in unconventional rocks;
Unconventional rocks with respect to the United Nations sustainable development goals, such as CO₂ storage and water management;
Systematic review papers on unconventional rocks.

Dr. Adebayo Abdulrauf
Dr. Liwu Jiang
Dr. Ahmed Al-Yaseri
Guest Editors

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Keywords

unconventionals
petrophysics
geomechanics
oil
gas
carbondioxide
hydrogen storage

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Published Papers (8 papers)

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Research

20 pages, 16575 KB

Open AccessArticle

Controlling Factors and Genetic Mechanism of Tight Sandstone Reservoir Development: A Case Study of the He 8 Member in the Central Linxing Area, Eastern Ordos Basin

by Dawei Ren, Jingong Zhang, Feng Zhang and Tao Zhang

Processes 2025, 13(12), 3975; https://doi.org/10.3390/pr13123975 - 9 Dec 2025

Abstract

The Linxing area on the eastern margin of the Ordos Basin is a key area for tight-gas exploration. Here, the He 8 Member is the principal target for reserve growth and gas production. However, accurate prediction of sweet spots remains challenging due to poorly constrained primary controlling factors affecting high-quality reservoirs and their diagenetic densification mechanisms. To address these issues, we integrated data from cores, petrographic thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), and log-facies analysis to conduct refined sedimentary microfacies identification, diagenetic analysis, and quantitative porosity evolution analysis. Results indicate that high-quality reservoirs in the He 8 Member are predominantly controlled by distributary-channel microfacies of a braided-river delta plain. Reservoir densification resulted from destructive diagenesis, primarily intense compaction and multi-phase cementation. Compaction reduced porosity by 18.7% on average (accounting for 60% of the total loss), whereas cementation led to a 11.4% loss (36.5%). Dissolution locally enhanced reservoir quality but was insufficient to reverse the pre-existing tight background, providing a limited porosity increase of approximately 5.6%. This study reveals a depositional-diagenetic coupling control on reservoir quality and establishes a genetic model for tight sandstones, thereby providing a critical theoretical framework for sweet-spot prediction in the Linxing area and analogous geological settings. Full article

(This article belongs to the Special Issue Advanced Studies of Oil and Gas Flow in Unconventional Oil and Gas Reservoir)

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14 pages, 2295 KB

Open AccessArticle

Investigation of Microscopic Oil Flow Characteristics During Fracturing Fluid Invasion and Flowback in Shale Oil Reservoirs

by Yongqiang Zhang, Wei Fan, Chengwei Yang, Yao Lu, Yuanyuan Gao, Xiuyu Wang and Mei Li

Processes 2025, 13(12), 3780; https://doi.org/10.3390/pr13123780 - 23 Nov 2025

Viewed by 259

Abstract

After hydraulic fracturing of C shale formation, it is difficult to get stable production, and the flowback efficiency of fracturing fluid is low. In order to reveal the law of fracturing fluid invasion and flowback behavior and to investigate the microscopic characteristics of its effect in improving the oil recovery factor, the experiments were innovatively carried out by using online Nuclear Magnetic Resonance (NMR) technology combined with huff-n-puff experiments using formulated fracturing fluid on two shale rocks, with the core inlet end representing the fractured surface in the reservoir. The dominant pores, Minimum Pore-Producing Radius (MPPR), and invasion depth for upper sweet-spot core (with smaller K and Φ) and lower sweet-spot core (with larger K and Φ) during fracturing fluid invasion and flowback were compared. The results show that small pores in upper sweet-spot core are the dominant pores, while mesopores are dominant in the lower sweet-spot core. The MPPR is 0.0087 μm and 0.024 μm, respectively, for the upper and lower sweet spot. As invasion pressure difference increases from 10 MPa to 20 MPa, the invasion depth of fracturing fluid into the upper sweet-spot core increases from 0.15 cm to 0.29 cm, and for the lower sweet-spot core it increases from 0.23 cm to 0.36 cm, about 1.2 times that of the upper core. Based on the similarity criterion, the formula for calculating on-site effective invasion depth of fracturing fluid L_f is derived, and it is approximately 0.46 m and 0.70 m in the upper and lower sweet spot after a 30-day well soaking. Based on experiments, the flowback efficiency of fracturing fluid is obtained, which is 23.6% in the upper sweet spot and 17.66% in the lower sweet spot. Imbibition tests were also performed for two shale core samples, and it is found that the imbibition recovery degree of the upper sweet-spot core is higher than that of the lower sweet-spot core. Dimensionless time calculated by using Ma’s model yields good fitting results for imbibition, and the soaking time is upscaled to reservoir conditions. The research results provide important reference for hydraulic fracturing practice and thus to improve the oil recovery factor in shale oil reservoirs. Full article

(This article belongs to the Special Issue Advanced Studies of Oil and Gas Flow in Unconventional Oil and Gas Reservoir)

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15 pages, 3792 KB

Open AccessArticle

Enhancing CO₂ Sweep Efficiency in Tight Reservoir Horizontal Wells: A Segmented Huff-and-Puff Strategy to Mitigate Heterogeneity Effects

by Songchao Qi, Jiuzheng Yu, Jianshan Li, Xiaochun Liu, Shichun Yu, Qianyi Chen and Manwen Wu

Processes 2025, 13(11), 3706; https://doi.org/10.3390/pr13113706 - 17 Nov 2025

Viewed by 273

Abstract

CO₂ huff-and-puff in horizontal wells is a key technique for enhancing oil production and improving recovery in tight oil reservoirs. It offers dual benefits: supplementing reservoir energy and promoting carbon sequestration, aligning with the green, low-carbon direction of energy development. However, the overall development performance of such reservoirs is often unsatisfactory. The fundamental reason lies in the strong heterogeneity of tight formations, which leads to uneven fluid intake along horizontal sections. CO₂ tends to preferentially channel into high-permeability zones, severely limiting its sweep volume and resulting in the poor recovery of remaining oil in low-permeability areas. This study innovatively proposes a segmented CO₂ huff-and-puff approach for horizontal wells. Using two real wells (H1 and H2), numerical simulations were conducted to compare the performance of conventional uniform injection and segmented injection. This study also examined how different segmental injection sequences (heel–middle–toe vs. toe–middle–heel) and injection rates affect CO₂ huff-and-puff efficiency. Results show that, compared to uniform huff-and-puff, segmented huff-and-puff improved the oil recovery factor by an absolute value of more than 3.58% in both wells and reduced the average water cut by 4.67%. Among sequencing strategies, the toe–middle–heel injection sequence yielded the best performance, with oil production at the toe increasing by up to 53.64%. Additionally, high injection rates (6 m³/min) significantly expanded the CO₂ diffusion range and enhanced its interaction with crude oil. This work proposes a new technique to expand the sweep range and improve production in long horizontal wells within highly heterogeneous tight reservoirs, contributing significantly to more uniform reservoir utilization and enhanced recovery. Full article

(This article belongs to the Special Issue Advanced Studies of Oil and Gas Flow in Unconventional Oil and Gas Reservoir)

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15 pages, 3374 KB

Open AccessArticle

Modeling Production Decline for Fractured Wells with Non-Uniform Fracture Properties: A Semi-Analytical Approach Based on Double-Segment Fracture Model

by Liwu Jiang, Yinyin Ma, Jingting Wu, Jinju Liu and Tongjing Liu

Processes 2025, 13(11), 3627; https://doi.org/10.3390/pr13113627 - 9 Nov 2025

Viewed by 307

Abstract

Hydraulic fracturing operations can create complex fractures with spatiotemporal variations that significantly affect the transient rate performance of fractured wells. To address such heterogeneous fracture characteristics, the double-segment fracture model was adopted, allowing for distinct fracture conductivity and permeability modulus assignments to each fracture segment. A novel semi-analytical model was developed, validated, and applied to investigate the influence of non-uniform fracture properties on transient rate behavior for fractured wells. More specifically, the slab source function method and finite difference method were applied to solve the fluid flow problems in the matrix and fracture subsystems, respectively. The nonlinearity caused by the pressure-dependent fracture conductivity was tackled by the iteration method. Additionally, production type curves were constructed to assess the impact of non-uniform fracture properties on transient rate behavior. It is found that the fracture conductivity and stress-sensitivity of the fracture segment near the wellbore (FSNW) have a more significant impact on the well production rate than those of the fracture segment near the fracture tip (FSNT). As the fracture conductivity near the wellbore decreases, the production rate decreases correspondingly, whereas the fracture conductivity near the fracture tip has a negligible influence on the transient rate when fracture conductivity exceeds 10. The length of the fracture segment similarly affects the transient rate behavior, where longer high-conductivity fracture segments are associated with higher production rates. The stress-sensitivity of the FSNW greatly affects the transient rate, where higher stress-sensitivity levels result in a lower production rate. In contrast, the effect of stress-sensitivity of the FSNT on the transient rate can be neglected. The results and findings obtained in this work can help us analyze the practical production rate curves with more accurate approaches, thereby obtaining more reasonable and reliable estimation results of the fracture properties. Full article

(This article belongs to the Special Issue Advanced Studies of Oil and Gas Flow in Unconventional Oil and Gas Reservoir)

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17 pages, 9993 KB

Open AccessArticle

Evaluation of Tight Gas Reservoirs and Characteristics of Fracture Development: A Case Study of the He 8 Member in the Western Sulige Area, Ordos Basin

by Zhaoyu Zhang, Jingong Zhang, Zhiqiang Chen and Wanting Wang

Processes 2025, 13(9), 2838; https://doi.org/10.3390/pr13092838 - 4 Sep 2025

Viewed by 3473

Abstract

This study focuses on the tight sandstone reservoirs of the He 8 Member (Lower Permian Shihezi Formation) in the western Sulige area, Ordos Basin. Multiple analytical methods were integrated, including core observation, thin-section analysis, X-ray diffraction (XRD), and rock mechanics experiments, to systematically evaluate the reservoir’s petrology, pore microstructure, physical properties, and fracture formation mechanisms. Results indicate that the reservoir is primarily composed of quartz arenite (78%), characterized by low porosity (avg. 5.5%) and permeability (avg. 0.15 mD). The pore system comprises dissolution pores, lithic dissolution pores, intergranular pores, and intercrystalline pores. Depositional microfacies significantly influence reservoir quality. Subaqueous distributary channel sands exhibit the best properties (porosity > 5%), followed by mouth bar deposits. The reservoir experienced intense compaction and siliceous cementation, which considerably reduced primary porosity. In contrast, dissolution and tectonic fracturing processes significantly enhanced reservoir quality. Rock mechanics tests reveal that highly heterogeneous rocks are more prone to fracturing under differential stress (σ₁–σ₃). These fractures considerably improve the flow capacity of tight reservoirs. Full article

(This article belongs to the Special Issue Advanced Studies of Oil and Gas Flow in Unconventional Oil and Gas Reservoir)

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12 pages, 1987 KB

Open AccessArticle

Study on the Microscopic Mechanism of Supercritical CO₂ and Active Water Alternating Flooding in a Tight Oil Reservoir

by Bin Wang, Jingfeng Dong, Peiyao Zhou and Kaixin Liu

Processes 2025, 13(8), 2535; https://doi.org/10.3390/pr13082535 - 12 Aug 2025

Viewed by 582

Abstract

Tight oil reservoirs are characterized by low porosity, low permeability, and low saturation, making it difficult to achieve economic development through conventional water injection. This study experimentally evaluated different injection media and oil displacement methods and used nuclear magnetic resonance methods to explain the micro mechanisms of oil displacement during different oil displacement processes. The experiments showed that supercritical CO₂ flooding and supercritical CO₂ and active water alternating flooding were much more useful for low-permeability reservoirs compared with conventional water flooding. This technology can increase the recovery rate by more than 12.0%, which is 33.24% higher than the rate achieved with conventional water injection. In addition, it can effectively improve the rapid increase in water content caused by the rapid advance in the water front during the water injection process. The NMR results indicated good consistency for the recovery efficiency of pores under different oil displacement conditions. When the aperture varied between 0.1 µm and 1 µm (type III), the utilization rate was highest, followed by type IV (1–10 µm), type II (0.01–0.1 µm), and type I (0.001–0.01 µm). By comparison, conventional water and CO₂ alternating flooding was more effective for type III pores, increasing oil recovery by 12.58%, while active water + CO₂ alternating flooding can further drive oil, increasing oil recovery by 33.24% and greatly displacing oil in micro-pores and macro-pores. Full article

(This article belongs to the Special Issue Advanced Studies of Oil and Gas Flow in Unconventional Oil and Gas Reservoir)

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33 pages, 8851 KB

Open AccessArticle

Advanced Research on Stimulating Ultra-Tight Reservoirs: Combining Nanoscale Wettability, High-Performance Acidizing, and Field Validation

by Charbel Ramy, Razvan George Ripeanu, Salim Nassreddine, Maria Tănase, Elias Youssef Zouein, Alin Diniță, Constantin Cristian Muresan and Ayham Mhanna

Processes 2025, 13(7), 2153; https://doi.org/10.3390/pr13072153 - 7 Jul 2025

Cited by 1 | Viewed by 977

Abstract

Unconventional hydrocarbon reservoirs with low matrix permeability (<0.3 mD), high temperatures, and sour conditions present significant challenges for stimulation and production enhancement. This study examines field trials for a large oil and gas operator in the UAE, focusing on tight carbonate deposits with reservoir temperatures above 93 °C and high sour gas content. A novel multi-stage chemical stimulation workflow was created, beginning with a pre-flush phase that alters rock wettability and reduces interfacial tension at the micro-scale. This was followed by a second phase that increased near-wellbore permeability and ensured proper acid placement. The treatment’s core used a thermally stable, corrosion-resistant retarded acid system designed to slow reaction rates, allow deeper acid penetration, and build prolonged conductive wormholes. Simulations revealed considerable acid penetration of the formation beyond the near-wellbore zone. The post-treatment field data showed a tenfold improvement in injectivity, which corresponded closely to the acid penetration profiles predicted by modeling. Furthermore, oil production demonstrated sustained, high oil production of 515 bpd on average for several months after the treatment, in contrast to the previously unstable and low-rate production. Finally, the findings support a reproducible and technologically advanced stimulation technique for boosting recovery in ultra-tight carbonate reservoirs using the acid retardation effect where traditional stimulation fails. Full article

(This article belongs to the Special Issue Advanced Studies of Oil and Gas Flow in Unconventional Oil and Gas Reservoir)

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16 pages, 30990 KB

Open AccessArticle

Reservoir Characterization of Tight Sandstone Gas Reservoirs: A Case Study from the He 8 Member of the Shihezi Formation, Tianhuan Depression, Ordos Basin

by Zihao Dong, Xinzhi Yan, Jingong Zhang, Zhiqiang Chen and Hongxing Ma

Processes 2025, 13(5), 1355; https://doi.org/10.3390/pr13051355 - 29 Apr 2025

Viewed by 819

Abstract

Tight sandstone gas reservoirs, characterized by low porosity (typically < 10%) and ultra-low permeability (commonly < 0.1 × 10⁻³ μm²), represent a critical transitional resource in global energy transition, accounting for over 60% of total natural gas production in regions such as North America and Canada. In the northern Tianhuan Depression of the Ordos Basin, the Permian He 8 Member (He is the abbreviation of Shihezi) of the Shihezi Formation serves as one of the primary gas-bearing intervals within such reservoirs. Dominated by quartz sandstones (82%) with subordinate lithic quartz sandstones (15%), these reservoirs exhibit pore systems primarily supported by high-purity quartz and rigid lithic fragments. Diagenetic processes reveal sequential cementation: early-stage quartz cementation provides a framework for subsequent lithic fragment cementation, collectively resisting compaction. Depositionally, these sandstones are associated with fluvial-channel environments, evidenced by a sand-to-mud ratio of ~5.2:1. Pore structures are dominated by intergranular pores (65%), followed by dissolution pores (25%) formed via selective leaching of unstable minerals by acidic fluids in hydrothermal settings, and minor intragranular pores (10%). Authigenic clay minerals, predominantly kaolinite (>70% of total clays), act as the main interstitial material. Reservoir properties average 7.01% porosity and 0.5 × 10⁻³ μm² permeability, defining a typical low-porosity, ultra-low-permeability system. Vertically stacked sand bodies in the He 8 Member display large single-layer thicknesses (5–12 m) and moderate sealing capacity (caprock breakthrough pressure > 8 MPa), hosting gas–water mixed-phase occurrences. Rock mechanics experiments demonstrate that fractures enhance permeability by >60%, significantly controlling reservoir heterogeneity. Full article

(This article belongs to the Special Issue Advanced Studies of Oil and Gas Flow in Unconventional Oil and Gas Reservoir)

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