bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Analysis of Fracture Propagation Behavior in Hard Rocks Subjected to Radial Borehole Fracturing Based on the Combined Finite-Discrete Element Method
Authors: Zou Wenchao , Huang Zhongwei , Wang Zikang , Wu Xiaoguang , Zhang Xu , Xie Zixiao , Li Kun , Huang Pengpeng , Tan Hui , Qin Xinyu 
Published: August 2024

ABSTRACT:
Hydraulic fracturing is an important stimulation technology to achieve high and stable production in deep and ultra-deep reservoirs. However, there are currently numerous complex technical problems, such as high breakdown pressure, single fracture and uncontrollable. To addressing those issues, a novel stimulation, radial borehole fracturing has been proposed. To have a clear understanding of the radial borehole fracturing performance, a 3D Finite-Discrete Element Method model of radial borehole fracturing is established in this paper. Then, the applicability of the HM coupled FDEM model was validated by laboratory experiments. The results indicate that when horizontal stress difference ratio is 0.4, radial borehole fracturing has a significant guiding effect on fracture propagation behavior. Radial borehole fracturing creates fractures with larger tortuosity and aperture. Compared to conventional fracturing, the breakdown pressure of hard rock in radial borehole fracturing is 9.1%∼14.1% lower. As Young's modulus increases, the guidance of radial borehole and the complexity of fracture network strengthen. The present study is expected to provide a theoretical foundation for applicability of radial borehole fracturing in deep and ultra-deep reservoirs.

1. INTRODUCTION
The deep and ultra-deep oil and gas resources are rich and widely distributed in China, accounting for 35% of the total oil and gas resources (She, 2024). In recent years, important breakthroughs have been made in exploration, which has rapidly attracted wide attention of scholars. These reservoirs possess distinctive geological features, characterized by high temperatures and pressures (Lei et al., 2021). The rocks exhibit traits such as high density, high hardness, strong heterogeneity, and high compressive strength. Consequently, there are currently numerous technical problems to be solved in the process of reservoir stimulation in deep and ultra-deep wells, such as high breakdown pressure, single fracture and uncontrollable (Zhang et al., 2023; Li et al., 2021). Therefore, an innovative stimulation method is proposed to address the above problems.
Radial borehole fracturing is a kind of reservoir stimulation technology that carries out hydraulic fracturing on the basis of drilling radial boreholes, which can significantly reduce the formation breakdown pressure and guide fracture directional propagation (Guo et al., 2022; Guo et al., 2016). Field tests conducted in geothermal and coal formations have demonstrated substantial enhancements in reservoir permeability with the application of this innovative technology (Chen et al., 2017; Nair et al., 2017; Ouadi et al., 2024).
Underground Space Design Using DFN-Based Tools: Comparisons of Static Kinematic Block Stability vs Distinct Element Modelling Assessments
Authors: Ng J. Wang , C. J. Button E , Ye J. Z. 
Published: August 2024

ABSTRACT:
Discrete fracture networks (DFN) are applied extensively in the design of underground spaces for both mining and civil infrastructure industries. DFN-based design tools enable discrete modelling of rock masses and kinematic stability assessments to be undertaken for design. When coupled with distinct element modelling, this approach significantly enhances the quality of designs by more precisely predicting the behavior of the ground. This combined approach can identify critical mechanisms, such as block interlocking and unravelling, which are pivotal in controlling the overall behavior of the ground.
The paper presents the design method undertaken for a large underground cavern employing DFN models through both static block kinematic assessment and DEM numerical analysis. A comparison of the two approaches highlights the importance of DEM in simulating ground behavior to ensure that critical mechanisms are incorporated into the design. This DFN-based method promotes safer and more efficient designs, leading to improved risk identification and cost savings for the project.

1. INTRODUCTION
Discrete fracture networks (DFN) are applied extensively in the design of underground spaces for both mining and civil infrastructure industries. DFN-based design tools are useful as they allow discrete modelling of a rock mass and kinematic stability assessment of individual blocks. When coupled with distinct element modelling (DEM) techniques, the design can be enhanced by more accurately predicting ground behavior, including identifying adverse failure mechanisms that may be critical for the design or interlocking mechanisms that maintain stability of the excavation.
The DFN-based design approach to underground space have been successfully applied by authors such as Haryono (2022) and Weir (2018) to predict the range of unstable block sizes for support design. This method enables a real realistic and more efficient designs that lead to better design risk identification as well as cost savings for the project.
Block kinematic assessments are a typical first step for rock excavation support design. There are, however, limitations with the method as the approach is usually focused on limit equilibrium and a static block boundary condition preventing the influence of dynamic block interactions (i.e. displacements) from being considered. Impacts of dynamic block interactions may result in interlocking and/or unravelling effects that have important controls on the overall ground behavior.
Numerical Simulation of Hydraulic Fracture Vertical Propagation in Bedded Shale by Phase-Field Method
Authors: Tian Ganghua , Wang Haizhu , Wang Bin , Shi Mingliang , Zheng Yong 
Published: August 2024

ABSTRACT:
Volumetric fracturing technology is an effective tool for shale oil exploration. The developed bedding planes and strong inhomogeneity of continental shale make them limited in fracture seam height propagation, which restricts the efficient extraction of shale oil. To better understand the law of hydraulic fracture propagation in the vertical direction, a coupled hydraulic-mechanic-damage model is established based on the phase field method to study the propagation of fractures in bedded shales. Based on this model, the effects of fracturing fluid viscosity and alternative injection methods were simulated. Following research results were obtained. The strong filtration loss of low-viscosity fracturing fluid leads to a shorter fracture height and tends to open the bedding planes. Increasing the viscosity can significantly enhance the penetration capacity of the hydraulic fracture and thus improve the stimulation efficiency. Additionally, the alternative injection method of injecting high-viscosity fracturing fluid before the low-viscosity one can breach the constraints of the laminae in the near-well zone and achieve sufficient reconstruction of the reservoir in the longitudinal direction. Therefore, in practical applications, reasonable fracturing fluid design and injection schemes need to be chosen according to different geological conditions and engineering needs to get better fracturing modification performance.

1. INTRODUCTION
Hydraulic fracturing is an important tool for the efficient exploitation of unconventional oil and gas resources (Yu et al., 2023). However, this also increases the risk of water contamination and geological instability. Therefore, numerical simulations are needed to accurately predict hydraulic fractures to guide fracturing scheme optimization while avoiding potential risks (Yang et al., 2022).
Current numerical methods for hydraulic fracture propagation investigations are categorized into two main types: discrete and continuous methods. The latter saves the work of dealing with displacement discontinuities of complex crack surfaces when simulating crack extension and is easier to implement numerically. Continuum methods such as the gradient damage model (Sun et al., 2021), screening Poisson method (Areias et al., 2016), peridynamic model (Nadimi et al., 2016, Ni et al., 2020, Qin et al., 2021), and phase field model (PFM) (Zhou & Zhuang, 2020, Liu et al., 2021, Liu et al., 2022, Zhuang et al., 2023) are widely used.
Lithology Identification of Deep Coal Seam Based on Machine Learning
Authors: Qi An , Li Yesong , Hai Liu , Feng Zhang , Qi Yang , Hao Liu , Ningbo Lv , Cheng Zhang , Hui Li , Zhou Fujian , Li Ben 
Published: August 2024

ABSTRACT:
Lithology identification is a crucial aspect of coalbed methane exploration and development. Given the intricate composition and lithology of deep coal seams, with frequent interbedding of coal seams, mudstone, and fine sandstone, accurate identification is challenging, particularly due to the similar logging responses of mudstone and fine sandstone. Conventional lithology interpretation algorithms based on crossplots often yield inaccurate results. This study focuses on the deep coal seam in Block SF on the east margin of the Ordos Basin, China. A dataset is compiled based on field logging and coring results. Through correlation analysis, seven key parameters—caliper, compensated neutron porosity, transit-time of compressional wave, gamma ray, deep resistivity log, spontaneous potential, formation bulk density—are selected from the logging data. The comparative analysis results of 16 machine learning algorithms including extra tree, random forest, and xgboost indicate that the extra tree algorithm provides superior fitting and generalization ability, with an F1 score of the classification model reaching 0.798. At the same time, it has high computational efficiency. The predictive outcomes of the model serve as a foundation and reference for determining fracturing intervals and identifying geological sweet spots in subsequent stages.

1. INTRODUCTION
Coalbed methane, also known as coal seam gas, is one of the typical clean energy sources. Its extraction holds significant importance for both coal mine safety and strategic energy reserves. China boasts abundant proven coalbed methane resources, with a gas-in-place resource volume reaching 30 trillion cubic meters (Tao et al., 2019). As exploration and development of coalbed methane continue to advance, a trend is emerging from single coal seams to coal series, from low-rank coal to high-rank coal, and from shallow to deep coalbed methane development (Guo et al., 2024). In the eastern SF block of the Ordos Basin in China, coal series formations are widely distributed, exhibiting a rich variety of lithologic combinations and distinct differences in reservoir formation modes (Cai et al., 2022). Particularly noteworthy is the development of thin interbeds of coal and sandstone-shale, posing challenges for reservoir identification and completion design for hydraulic fracturing. Therefore, conducting identification and prediction of lithology in geological formations is of vital significance for deep coalbed fracturing design and favorable area prediction for reservoir formation.
Experimental and Numerical Investigation on Fracture Propagation Sensitivity Parameters in Deep Coal Seams
Authors: Jian Wu , Libo Zhou , Yao Jiang , Yun Wang , Qi Yang , Chunjiang Qian , Cheng Zhang , Ningbo Lv , Hui Li , Zhou Fujian , Li Ben 
Published: August 2024

ABSTRACT:
Hydraulic fracturing is the primary method for increasing hydrocarbon production in the extraction of deep coal bed methane. Understanding the initiation and propagation mechanisms of hydraulic fractures in deep coal seams, as well as developing design principles for hydraulic fracturing operations, can improve the efficiency of such operations. This study aims to identify the key factors affecting hydraulic fracture initiation and propagation in deep coal seams through indoor experiments and numerical simulations of deep coal seam wells. The study conducted an indoor experiment on hydraulic fracturing, using CT three-dimensional reconstruction technology and a two-dimensional fractal dimension analysis method to analyze the fracture morphology of deep coal seams. The study assessed the impact of various parameters, including fracturing displacement, fracturing fluid viscosity, lithology, and well trajectory, on hydraulic fracture initiation and fracture propagation. Additionally, a numerical model of fracture propagation was established to simulate hydraulic fracture initiation and propagation in typical wells in deep coal seams. The study also employed a two-dimensional fractal dimension analysis method and weight analysis method to analyze sensitivity parameters affecting fracture complexity and identified the main controlling factors of fracture initiation and propagation in deep coal seams. This study explores the basic principles of complex fracture propagation mechanisms through small-scale indoor hydraulic fracturing experiments. It aims to identify the key operational parameters that can enhance the complexity of fracture networks in hydraulic fracturing. The study also uses numerical simulations to analyze the important factors that influence the complexity of fractures through well-scale numerical simulations of fracture propagation. This approach provides design tools and theoretical insights for optimizing hydraulic fracturing design in deep coal seams.

1. INTRODUCTION
Coalbed methane is an unconventional oil and gas resource. More than 47.6 trillion cubic meters of coalbed methane resources exist in coal reservoirs buried at a depth of more than 1500 meters (Zuo H.C, 2015). Coal seams have a unique bedding and cutting development system and usually require hydraulic fracturing methods to obtain a high yield. Deep coal seams have poor physical properties, high stress, low permeability, and strong adsorption capacity, so the effect of conventional fracturing transformation is not acceptable.
Modelling Faults as Fracture Swarms to Introduce Multi-Scale Heterogeneity
Authors: Libby S. A. 
Published: August 2024

ABSTRACT:
Faults modify the geomechanical and hydrogeological properties of their host rock. Consequently, proper characterization of faults is relevant to a wide range of sectors including energy, storage and sequestration, mining and geotechnical. Although faults may be conceptualized as simple surfaces when considered at their full scale, a detailed view reveals a heterogeneous structure with damage zones and anastomosing fault cores. Consequently, simulations of whole fault systems can achieve reasonable results by modelling the faults as simple surfaces, but where model applications require a higher resolution another approach is required to introduce out-of-plane heterogeneities. This paper discusses two methods that achieve this by simulating faults as swarms of fractures located around midplanes, including a novel method that can readily scale to very large networks. Crucially, both methods can use midplanes generated as large-scale discrete fracture networks (DFNs) to produce meter scale DFNs with aspects controlled by kilometer scale features. This offers two benefits: a single model of the fault system can be applied across a wider range of scales, and the intensity distribution of the DFNs better simulate naturally occurring fracture networks. Both geomechanical and hydrogeological models can benefit from this approach.

1. INTRODUCTION
The impact of faults on the geomechanical and hydrogeological properties of their host rock is a widely studied topic, with implications for a wide range of sectors including energy, storage and sequestration, mining and civil engineering (e.g. Fossen, 2010). As numerical modelling continues to become a more prevalent tool for understanding the subsurface, the numerical characterization of faults becomes increasingly important.
Although faults may be considered near planar features without a discrete thickness when conceptualized at their full scale (a concept subsequently referred to as a fault midplane), a view of a fault at a smaller scale reveals a heterogeneous internal structure, both in the local geometry of the features comprising the fault core and the geomechanical and hydrogeological properties that arise (Aaltonen et al., 2016; Caine et al., 1996; Choi et al., 2016; de Joussineau, 2023; Faulkner et al., 2008; Fossen, 2010; Gabrielsen & Braathen, 2014; Kim et al., 2004; Nordbäck & Mattila, 2018; Wang et al., 2023). Consequently, simulations of fault systems at a scale that encompasses whole faults can achieve reasonable results by modelling the faults as simple surfaces. However, if the model also needs to simulate faults at a meter scale, a single planar surface may not adequately represent observed geological features such as damage zones and anastomosing fault cores.
Field Experiences of Near-Wellbore Poroelastic Effects and Benefits of Pump-Out in Microfrac in Unconventional Reservoirs
Authors: Sen Souvik , Chakrabarti Prajit , Franquet Javier A. 
Published: August 2024

ABSTRACT:
This study discusses the challenges faced during the wireline straddle packer microfrac tests and the effective solutions, based on our field experiences from the recently concluded successful microfrac campaign targeting the unconventional reservoirs (tight sandstones and dolomites from Triassic-Cambrian) of north Africa. The main challenges were posed by the near wellbore poroelastic effects by mud filtrate that yields pore pressure and stress perturbations locally and artificially elevates formation breakdown pressure. We adopted the ‘pump-out’ technique as an effective solution where the removal certain volume of mud from the near wellbore region reduces the artificial strengthening effect of the mud filter cake and helps reduce the breakdown pressure. The majority of the microfrac tests exhibited the proven benefit of multiple rapid loading-unloading cycles by injection (hole pressurization) and pump-out (hole depressurization) in inducing near-wellbore fatigue to effectively weaken the formation before achieving successful breakdown. In some of the stations, increasing trend observed in fracture reopening and closure in the consecutive test cycles, contributed by the poroelastic effect. The pump-out technique was also effective in eliminating such effects. This study demonstrates the benefits of pump-out technique in achieving successful breakdown and at times conclusive closure in challenging environments.

1. INTRODUCTION
The application and importance of geomechanical modeling is well accepted and therefore extensively utilized for tackling mechanical wellbore instabilities, optimizing wellbore trajectories, hydraulic fracture designs and completion strategies, etc. (Almalikee and Sen, 2021, 2022; Farouk et al., 2022; Darjani et al., 2023). It is critically required in any fluid injection program including CO2 sequestration to ensure a long-term confinement of the injected fluid volume without compromising caprock integrity (Sen et al., 2023). Minimum horizontal stress (Shmin) is one of the most important parameters in geomechanical modeling. An over- or under-estimation of Shmin can significantly affect the inferences, therefore requires downhole calibration to reduce uncertainties. For example, lack of Shmin calibration can misinterpret the stress contrast between reservoir and caprock, thus affecting the fluid injection designs and hydraulic fracturing management etc.
A New Geomechanical Modeling Workflow for CCUS Near-Well Integrity Assessment in Layered Poroelastic Medium
Authors: Zhai Guang , Peters Elisabeth , Candela Thibault 
Published: August 2024

ABSTRACT:
The practice of cold CO2 injection into depleted oil/gas reservoirs addressing the increasing global emissions requires efficient and robust geomechanical assessment of near-well (caprock) damage risks. The geomechanical responses involve driving forces of small-footprint cooling zones from thermal effects, large-footprint pressure plumes from fluid diffusion, and possible continuing reservoir inelastic compaction. The workflow of coupling these processes to rock mechanics for geomechanical assessment is based on numerical or (semi-)analytical solutions. Among the latter, the recent development of MACRIS at TNO considers the fundamental point-source solution in homogeneous half-space which has been validated with FEM methods and is computationally efficient. Here, we extend the MACRIS framework and use the point-source solution in a layered, poroelastic half-space. Such improvement can provide several advantages of considering vertical heterogeneity of earth medium, solid-fluid coupling outside the reservoir, and undrained conditions in caprock. By incorporating the layered poroelastic point-source solution, we develop a workflow consisting of reservoir hydro-thermal simulation for temperature and fluid pressure distributions, calculating point-source mechanical influence functions in layered poroelastic medium, and integration for geomechanical assessment at targets. Finally, we demonstrate the workflow and show results from a case study using realistic model parameters provided by operators.

1. INTRODUCTION
Enabling large-scale CO2 capture, utilization and storage (CCUS) is crucial to ensure global emission reductions in line with the Paris agreement (Hennessy et al., 2022). Several previous large-scale projects for CO2 storage have been focused on deep aquifers, e.g., in the Salah CO2 storage site in Algeria (Ringrose et al., 2013). Recently, using depleted oil/gas reservoir for large-scale CCUS has been proposed to be promising for addressing the increasing global emissions, since they are well characterized from previous O&G activities with large pressure margins for safe storage (Wei et al., 2023).
During the practice of CCUS in the context of depleted oil/gas reservoirs, one of the major challenges is the timely and robust geomechanical assessment of near-well damage hazards, which can help mitigate potential damage-related risks and enhance the safe operations (Wei et al., 2023). The geomechanical assessment may require the consideration of both reservoir depletion (oil/gas production) and re-pressurization (CO2 injection) phases, since the reservoir deformation processes during the two phases can be physically linked. In reservoir leakage pathways. Such processes have not received much study to date (Fan et al., 2020; Liu et al., 2020).