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Theoretical Studies and Simulations of Complex Fracture Propagation in Shale Oil and Gas

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A special issue of Processes (ISSN 2227-9717). This special issue belongs to the section "Petroleum and Low-Carbon Energy Process Engineering".

Deadline for manuscript submissions: 28 February 2027 | Viewed by 2293

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Editors

Dr. Xuanhe Tang

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Guest Editor

College of Energy, Chengdu University of Technology, Chengdu 610059, China
Interests: hydraulic fracturing; geomechanics; complex fracture propagation; multi-physics coupling; numerical modelling

Dr. Peng Zhao

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Guest Editor

State Key Laboratory of Geohazard Prevention and Geoenvironment Protection, Chengdu University of Technology, Chengdu 610059, China
Interests: deep rock mechanics; deep unconventional energy mining; dynamic response of disaster environment protection structure
Special Issues, Collections and Topics in MDPI journals

Dr. Liuke Huang

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Guest Editor

School of Civil Engineering and Geomatics, Southwest Petroleum University, Chengdu 610500, China
Interests: rock mechanics; geomechanics; reservoir reformation; hydraulic fracturing; unconventional reservoir development
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

Shale oil and gas have emerged as pivotal energy sources globally, playing a critical role in safeguarding energy security and stabilizing energy supplies amid the transition to low-carbon energy systems. Hydraulic fracturing, the most indispensable core technology for shale oil and gas development, has evolved into the 4.0 era, characterized by precise control, multi-field coupling optimization, and efficient fracture network construction. However, recent post-fracturing coring tests in major shale plays of the United States and China have revealed significant discrepancies between field-observed fracture formation mechanisms and existing theories. For instance, core analysis suggests that high-displacement fracturing may induce hydraulic fracture self-bifurcation during propagation—enabling fracture network construction independent of natural fractures—yet conventional numerical simulation methods struggle to accurately characterize this phenomenon. These inconsistencies highlight the urgent need for systematic research and discussion. This Special Issue focuses on the theoretical advancements and numerical simulation methods of fracture propagation in shale oil and gas fracturing.

This Special Issue entitled “Theoretical Studies and Simulations of Complex Fracture Propagation in Shale Oil and Gas” aims to integrate cutting-edge research from scholars worldwide, promoting progress in theories related to shale fracture formation mechanisms and optimizing numerical simulation techniques to address practical challenges in shale energy development. Topics include, but are not limited to, methods and/or applications in the following areas:

Initiation and propagation mechanisms;
Flow in fractures and inter-fracture flow competition;
Multi-scale fracture mechanics characteristics;
Stress response during fracturing processes;
Post-fracturing geomechanical characteristics;
Problems and challenges of existing fracturing technologies;
Next-generation fracturing technologies and supporting tools.

Dr. Xuanhe Tang
Dr. Peng Zhao
Dr. Liuke Huang
Guest Editors

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Keywords

shale oil and gas
hydraulic fracturing
initiation and propagation
geomechanics

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Published Papers (5 papers)

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Research

22 pages, 5549 KB

Open AccessArticle

Mechanisms of Cross-Layer Fracturing in Thin Interbedded Formations: Roles of Stress Shadow, Interlayer Stress Difference, and Interface Failure

by Zhi Chang, Runsen Li, Mingfang He, Linjun Zou and Xinjia Liu

Processes 2026, 14(12), 1966; https://doi.org/10.3390/pr14121966 - 17 Jun 2026

Viewed by 263

Abstract

Hydraulic fracture height growth in thin sandstone–mudstone interbeds is often limited by bedding interface failure and multi-cluster stress interference. In this study, a coupled fracture–matrix interface finite element model was developed for the He-8 sandstone–mudstone interbeds in the Sulige Gas Field and validated against previously published true triaxial hydraulic fracturing experiments. The simulations indicate that vertical–horizontal stress difference (VSD; the difference between overburden stress and minimum horizontal stress within a layer) promotes fracture-height growth, whereas interlayer stress difference (ISD; the minimum horizontal stress contrast between adjacent layers) acts as a stress barrier that promotes bedding interface shear failure and arrests vertical growth. For the investigated reservoir configuration, each 4 MPa increase in VSD increased fracture height by approximately 1.5 m in the three-cluster case and 1.8 m in the four-cluster case, whereas each 2 MPa increase in ISD reduced the average fracture height by approximately 4.0 m in the three-cluster case and 3.5 m in the four-cluster case. Under moderate ISD, increasing the fluid viscosity was more effective than increasing the injection rate alone, although the benefit depended on cluster number and interface failure state. These results clarify how stress contrast, interface strength, and multi-cluster stress shadows jointly control cross-layer fracture propagation in thin interbedded reservoirs. Full article

(This article belongs to the Special Issue Theoretical Studies and Simulations of Complex Fracture Propagation in Shale Oil and Gas)

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25 pages, 4977 KB

Open AccessArticle

Transient Pressure Behavior and Interference Mechanisms of Multi-Well Pads in Rectangular Bounded Shale Gas Reservoirs

by Yuping Sun, Hao Wang, Hang Yuan, Mingqiang Wei and Qiaojing Li

Processes 2026, 14(10), 1534; https://doi.org/10.3390/pr14101534 - 9 May 2026

Viewed by 276

Abstract

Inter-well interference in multi-well pad development is a critical factor influencing the recovery efficiency of shale gas reservoirs. This study presents a comprehensive semi-analytical model to characterize the transient pressure behavior and interference mechanisms of multi-well multi-stage fractured horizontal wells (MFHWs). Utilizing point source functions and the principle of superposition, the model accounts for complex shale gas transport mechanisms, including gas desorption, diffusion, and real-gas compressibility via pseudo-pressure transformation. The proposed model is validated against the industrial standard numerical simulator KAPPA-Saphir, showing an excellent match across most flow regimes, with a maximum relative error of 3.2% and an average relative error of less than 1% across the entire production period. The results identify five distinct flow stages: fracture linear flow, fracture radial flow, compound linear flow, compound radial flow, and boundary-dominated flow. Sensitivity analysis reveals that decreasing the inter-well spacing significantly shortens the fracture radial flow duration, while longitudinal staggering of wellbore centers effectively mitigates early-time interference and promotes more uniform reservoir drainage. Furthermore, it is observed that in multi-well systems, inner wells suffer from more severe energy competition and faster pressure depletion than peripheral wells. Based on these findings, it is proposed that the inter-well spacing should exceed four times the fracture half-length, and a staggered fracture arrangement (the relative positions in the x-direction of the fractures between the wells are not the same) should be prioritized. This work provides a robust theoretical framework and practical guidelines for optimizing well spacing and infill drilling strategies in shale gas reservoirs. Full article

(This article belongs to the Special Issue Theoretical Studies and Simulations of Complex Fracture Propagation in Shale Oil and Gas)

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32 pages, 8873 KB

Open AccessArticle

Super-Resolution Enhancement of Fiber-Optic LF-DAS for Closely Spaced Fracture Monitoring During Hydraulic Fracturing

by Yu Mao, Mian Chen, Weibo Sui, Jiaxin Li, Su Wang and Yalong Hao

Processes 2026, 14(9), 1380; https://doi.org/10.3390/pr14091380 - 25 Apr 2026

Viewed by 433

Abstract

Hydraulic fracturing of unconventional reservoirs requires accurate fracture monitoring for treatment optimization. Low-frequency distributed acoustic sensing (LF-DAS) in neighbor wells provides dense strain-rate observations, but gauge-length averaging limits spatial resolution and merges closely spaced fracture features. This study formulates gauge-length averaging as an explicit convolution operator and develops a regularized inversion method combining Tikhonov smoothing, a recursive prior, and L-curve parameter selection, supported by a semi-analytical multi-fracture forward model. On a synthetic benchmark, the method advances the effective resolution from the 10 m gauge-length scale to the 1 m sample-spacing scale, recovering fracture count in all hit-window time slices (versus 32% for raw data), achieving Pearson correlation of 0.80 versus 0.29, with peak-position error reduced by 47%. Noise-sensitivity analysis indicates a practical SNR floor near 20 dB, and Wiener-filter comparison confirms 1.5–2.7× correlation and 1.5–2.3× peak-count advantages across tested noise levels. Field application to HFTS-2 B1H stages 22 and 23 reveals previously hidden tensile features consistent with higher local fracture density. With per-stage processing in seconds and no extra sensing hardware, the method is well suited for near-real-time deployment. Full article

(This article belongs to the Special Issue Theoretical Studies and Simulations of Complex Fracture Propagation in Shale Oil and Gas)

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24 pages, 4627 KB

Open AccessArticle

Experimental Investigation of Proppant Transport in Multi-Level Complex Fracture Networks of Deep Shale Formations

by Zhenwei Bai, Wenjun Xu, Junjie Liu, Feng Jiang, Lei Wang, Chunting Liu, Xiaozhi Zhu and Juhui Zhu

Processes 2026, 14(7), 1170; https://doi.org/10.3390/pr14071170 - 4 Apr 2026

Viewed by 599

Abstract

Proppant transport in complex fracture networks strongly influences the effectiveness of volumetric hydraulic fracturing in deep shale reservoirs; however, experimental investigations remain limited by the scale and structural complexity of existing laboratory models. In this study, large-scale physical experiments were conducted using a self-designed fracture system consisting of a main fracture and multi-level tertiary branch fractures to investigate proppant transport and placement behavior under different operational conditions. Twelve experimental cases were performed by varying injection rate, fracturing fluid viscosity, proppant concentration, proppant type, and particle-size pumping sequence. The results show that increasing the injection rate and fluid viscosity improves the proppant transport capacity and promotes proppant migration into tertiary branch fractures, increasing the proppant distribution ratio by 6.58%, while the placement proportion in the main fracture decreases by 15.92%. Increasing the proppant concentration enhances proppant placement in all fracture levels, with the placement ratio of quartz sand increasing by 10–15%, but excessive concentration causes accumulation and bridging near the fracture entrance. Under identical conditions, ceramic proppant exhibits better overall placement performance than quartz sand, with a 22.81% higher placement ratio in the main fracture. In addition, the pumping sequence significantly affects proppant distribution; the large–small–large particle-size sequence achieves the highest placement ratio of 74.52%. These results provide quantitative experimental evidence for optimizing proppant injection strategies and fracturing parameters in deep shale reservoirs. Full article

(This article belongs to the Special Issue Theoretical Studies and Simulations of Complex Fracture Propagation in Shale Oil and Gas)

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25 pages, 14746 KB

Open AccessArticle

Dynamic In Situ Stress Evolution and Cross-Layer Fracture Propagation Mechanisms in Superimposed Shale Oil Reservoirs Under Long-Term Injection-Production Perturbations

by Deyu Wang, Wenbin Chen, Chuangchao Xu, Yangyang Zhang, Tongwu Zhang, Chao Hu, Wei Cao, Yushi Zou and Ziwen Zhao

Processes 2026, 14(7), 1135; https://doi.org/10.3390/pr14071135 - 31 Mar 2026

Viewed by 456

Abstract

Addressing the severe risk of artificial fractures causing vertical pressure channeling and subsequent water flooding during shale oil development in the Ordos Basin, this study investigates the overlapping development zone in Block Shun 269. Through laboratory rock mechanics experiments, the mechanical anisotropy of the overlapping layers was characterized. Utilizing actual production data, a 4D dynamic geomechanical model incorporating 21 years of injection-production history was established to reconstruct the pre-fracturing 3D in situ stress field. Based on this stress field model, a quantitative analysis was conducted on the evolution of injection-production stresses, the vertical superposition distance, the distribution of natural fractures, and the propagation patterns of hydraulic fractures across layers under various fracturing engineering parameters (including pumping rate, fluid viscosity, and perforation cluster, etc.). Research indicates that long-term injection-production disturbances caused the average minimum horizontal principal stress in the Chang 6 layer to decrease by 1.6 MPa, with partial “stress deficit zones” experiencing reductions as high as 3.5 MPa. This significantly weakened the stress shading capability between layers, resulting in the probability of fracturing cracks through the Chang 7 layer in the lower section increasing from 12% to 49%. The propagation of fracture height is jointly governed by geological and engineering factors, the weighting order is as follows: superposition distance > pumping rate > interlayer stress difference. A fracturing cross-layer risk assessment chart based on the coupling of geological and engineering factors has been established, proposing different anti-leakage and fracture control technical models for fracturing sections with different risk levels. Using this model to simulate fracturing in B horizontal wells, the simulation results were consistent with microseismic measurement data. Full article

(This article belongs to the Special Issue Theoretical Studies and Simulations of Complex Fracture Propagation in Shale Oil and Gas)

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