bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rock-Discontinuity-Fragmentation (R-Dis-Frag): A Computer Package for the Characterization of Large-Scale Fractured Rock Masses in Real-Time
Authors: Hekmatnejad A. , Crespin B. 
Published: September 2022

ABSTRACT:
Rock block geometry (size, frequency, and shape) is an important characteristic in many rock engineering studies including rock mass classification, discrete element method, surface and underground stability analysis, drilling, blasting design and hydro-geological analyses. There are several polyhedral modelers available, but the limited computational capacity is one of the main issues when dealing with the characterization of real scale fractured rock mass up to millions of fractures at a real engineering time scale. This paper presents a novel approach for a voxel-based polyhedral modeler, optimized to exploit the computing parallelism of graphics processing units (GPUs). In this approach, there is no limitation for the complexity of rock blocks, fracture shapes, and excavation surfaces with complex morphologies. The computational time for the geometrical characterization of rock blocks for a 100-meters cubical domain with 2000,000 fractures is less than 3 minutes.

1. INTRODUCTION
One of the most important sources of uncertainty for the evaluation of fractured rock mass behavior is the "block geometric uncertainty" which plays a critical role in the design of underground and surface opening. According to the literature review, the most significant discrete fracture network parameters when analyzing block geometry uncertainties are orientation, size, topology, volumetric intensity, and 3D mechanical connectivity (Rodriguez and Sitar, 2008; Wang et al, 2013; Zheng et al., 2015; Li et al., 2018, Hekmatnejad et al., 2021). If fractures in the rock mass cannot be fully described in 3D, uncertainties appear in the block formation and block geometry (size, shape, location), which in turn create another kind of uncertainty – that of driving force and resistance force; it also affects the amount of required support in tunneling application and the probability of hanging up occurrences at draw points in cave mining. When considering a discrete fracture network model, the most fundamental and important step is the identification of complex formed blocks, their geometry, and even their stability states (block stability analysis) for instability analysis around the surface and underground excavations (see Figure 1).
Quantitative Evaluation Method and Application of Wellbore Stability Based on Geomechanics
Authors: Zhai Wenbao , Wang Qian , Chen Zhixue , Chen Xuefeng , Li Bo , Hao Weiwei , Jiang Jiwei , Li Mingyin , Liu Dezhi , Rao Jiafu 
Published: September 2022

ABSTRACT:
Wellbore instability is one of the difficult problems restricting safe drilling. The traditional theoretical model of wellbore stability is easy to cause the actual drilling fluid density to be high and aggravate the risk of drilling lost circulation. Therefore, firstly, the rock mechanics parameter profile is quantitatively obtained according to the field multi-source data, and the single well geomechanics model is established; Then, the Monte Carlo method is used to comprehensively consider the uncertainty of geomechanical parameters, and a quantitative evaluation method of wellbore stability based on geomechanics is established to reasonably evaluate the wellbore stability probability and optimize the safe density window of drilling fluid; Finally, taking well X of an oil field in Western China as an example, the new method is used to quantitatively evaluate the wellbore stable section and unstable section, and the evaluation results are compared with the actual complex situation to dynamically optimize the density window of drilling fluid. The results show that the calculation results of the new method are consistent with the actual situation, and the probability of wellbore stability is more than 80%. This method can effectively evaluate the wellbore stability, and provide a reasonable density window of drilling fluid, reducing the drilling complexity and cost, which is of great significance to meet the requirements of safe and efficient drilling.

1. INTRODUCTION
Drilling engineering is an indispensable and important link during oil and gas energy exploration and development, but wellbore instability causes frequent drilling complex problems, which seriously restricts the drilling cycle. Therefore, a reasonable evaluation of wellbore stability is conducive to broadening the safety density window of drilling fluid and effectively reducing drilling complexity, and shortening the drilling cycle(Darvishpour et al., 2019). In recent years, many scholars have made comprehensive analysis on the factors that may affect the wellbore stability(Germanovich and Dyskin, 2000; Germanovich et al., 1994; Li et al., 2022; Mokhel et al., 1996; Moos et al., 2003; Tran and Abousleiman, 2010; Zoback et al., 1985). Traditionally, it is considered that wellbore instability is caused by far-field stress conditions or by stress acting on a natural plane with too little or no cohesion(M. Zoback et al., 1985), which is related to shear and yield. For plastic rocks, the wellbore collapse can be described by using the plastic yield criterion(Germanovich and Dyskin, 2000), but for brittle rocks, the description of wellbore collapse can not only consider the shear failure hypothesis but also consider the shape of rock fragments, i.e. tensile failure and brittle failure (Germanovich et al., 1994).
Downhole Microseismic Monitoring of Injection Stimulations at the Utah FORGE EGS Site
Authors: Rutledge J. , Dyer B. , Bethmann F. , Meier P. , Pankow K. , Wannamaker P. , Moore J. 
Published: September 2022

ABSTRACT:
Downhole microseismic monitoring provides the best means of detecting, mapping and characterizing the fracture systems developed during the creation and evolution of Enhanced Geothermal System (EGS) reservoirs. EGS development requires at least two wells, one for injection and the second for production. During the initial stimulation of well 16A(78)-32, the injection well at the Utah Frontier Observatory for Research in Geothermal Energy, an array of three downhole, high-temperature, eight-level digital receiver strings will be deployed to monitor the fracture system. The well has a true vertical depth of 8540 ft, a measured depth of 10,987 ft, and a maximum temperature of 220°C. Below 7260 ft, the well plunges 25° through the granite basement rock. Three zones will be stimulated near the toe of the well. The configuration of the three monitor wells and the receiver depth placements are designed to resolve the isolation or the possible interference of the stimulated volumes and guide the placement of the production well. After the initial stimulations, the multilevel strings will be replaced with dual-level strings for long-term monitoring.

1. INTRODUCTION
The Utah Frontier Observatory for Research in Geothermal Energy (FORGE) project is a test site for demonstrating technologies for Engineered Geothermal Systems (EGS) (Moore et al., 2020). EGS involves the creation of sustainable rock permeability to extract heat for long periods of time. At Utah FORGE, hydraulic stimulation of favorably oriented fractures will be conducted to form the reservoir. Seismicity induced by these stimulations must be monitored to map the EGS reservoir growth and to mitigate possible seismic hazards (Majer et al., 2016). An overview of the guiding risk studies, as well as the history of seismicity at the site and the planning and network deployed for monitoring potential seismic hazards is presented in Pankow et al. (2017); Pankow et al. (2019a); and Pankow et al. (2019b).
Numerical Modeling of Thermo-Hydro-Mechanical Processes Related to Geothermal Heat Pump Operations in a Subarctic Climate
Authors: Norouzi E. , Li B. , Raymond J. 
Published: September 2022

ABSTRACT:
Ground Source Heat Pumps (GSHPs) are extensively used as a renewable energy technology worldwide. However, the use of GSHPs in cold regions remains challenging. Particularly, for a shallow GSHP system, the cyclic freezing and thawing conditions may cause considerable ground subsidence and have an impact on the stability of infrastructure. Very few studies were conducted to analyze the geo-risk of installation and operation of GSHPs in subarctic regions. In this paper, a fully coupled thermal-hydro-mechanical analysis is performed based on a finite element framework to investigate the geo-risk of ground subsidence due to the installation and operation of GSHPs. The modified Clausius-Clapeyron model is included in the modeling framework considering phase change of ice under freeze-thaw cycles. The nonlinear relations between ice saturation and hydro-mechanical properties of frozen soil have been implemented using experimental data from the literature. The numerical modeling tool is applied to the case study of a potential Canadian GSHP site in Umiujaq, northern Quebec, where the ground is composed of several meters of silt overlying the bedrock.

1. INRTODUCTION
Over last decades, stabilizing the permafrost regions has been an important concern for geotechnical engineers, specially in regions where cycling freezing and thawing are encountered because of the global warming affecting infrastructure. Therefore, applying different stabilizing methods may be necessary in these regions to reduce the predicable geohazards.
Recently, the development of Ground Source Heat Pump (GSHP) systems has increased. Such systems operate with a renewable source and allows for energy storage. As solar energy is insufficient during the northern winter, GSHP systems are a potential avenue in subarctic regions as an alternative to store energy during summer and provide it in winter. With 44,561 inhabitants of Nord-du-Québec in 2016 living in villages in subarctic regions, there is a good potential to utilize the GSHP systems for heating to reduce the consumption of fuel usually shipped by boat(Gunawan et al., 2020).
A Plasticity Mechanism for Hydraulic Fracture Height Containment
Authors: Papanastasiou P. , Konstantinou C. 
Published: September 2022

ABSTRACT:
In this paper we present a new mechanism that explains hydraulic fracture containment in the target zone. The study is based on the modelling of hydraulic fracture propagation in weak rocks and comparison of the results of propagation in the vertical direction with propagation in the horizontal direction. The modelling is based on both analytical modelling with a Mohr-Coulomb dislocation theory and on FEM modelling of hydraulic fracture propagation in weak formations described by Mohr-Coulomb elastoplastic material and a cohesive-type fracture propagation criterion. It was found that the resistance to fracturing, expressed in the dislocation model by the required force and in the FEM by an effective fracture toughness that increases with fracture extension tending to asymptotic value, depends strongly on the fracture propagation direction. A dominant parameter that quantifies these effects is a new brittleness index (BI) that depends both on rock strength and insitu stresses. This BI defines a) if a hydraulic fracture will be created and b) if the fracture will remain contained in the target zone and c) what deviation is expected from LEFM modelling of hydraulic fracturing.

1. INTRODUCTION
An important design objective in hydraulic fracturing is the fracture to remain vertically contained in order to achieve a long penetration in the pay zone. A contained fracture will eliminate the risk of mixing hydrocarbon fluids with water or natural gas with oil if the surrounding layers contain different fluids. The overarching objective is to maximize the flow of hydrocarbon in the wellbore through a long conductive path formed by a propped fracture. Clearly, the mechanical properties of reservoir and surrounding layers affect the fracture height. An obvious explanation for the often-observed fracture containment in the reservoir layer, is the higher horizontal stress, called closure stress, in the barrier layers, usually shales. In order to restrict fracture height growth, the commercial hydraulic fracturing simulators assume that the barrier shale layers are under higher closure stress or they have higher resistance to fracturing, expressed by the fracture toughness. However, though there were cases that such conditions do not exist in the barrier layer, the hydraulic fractures still remained contained. Often, hydraulic fractures do not even reach the shale-reservoir interface. Nevertheless, in practice a cased-cemented well is perforated in the lower part of the reservoir to minimize the risk of hydraulic fracturing reaching the upper barrier layer.
The Influence of Hydraulic Fluid Properties on Induced Seismicity During Underground Hydrogen Storage
Authors: Burtonshaw J. E. J. , Paluszny A. , Thomas R. N. , Zimmerman R. W. 
Published: September 2022

ABSTRACT:
Geological hydrogen storage is a promising technique to seasonally store surplus renewable energy at the large scale. Depleted gas reservoirs are currently being considered as potential storage sites for hydrogen. Induced seismicity is a key aspect of the sustainability and acceptance of both onshore and offshore gas storage and production. This study conducts a preliminary numerical assessesment of the deformation of a single three-dimensional fault that extends from the reservoir and into the caprock during the injection and storage of hydrogen over a period of weeks. Simulations are conducted with a three-dimensional finite element, fully coupled poroelastic code. Induced seismicity is quantified both in terms of tangential displacements on the fault surfaces, cumulative moment release, and maximum seism c event magnitudes. The reservoir is an anticlinal structure bound from above by a low permeability caprock, and below from a low permeability underburden. Mechanical properties are defined based on North Sea depleted gas reservoirs. The effect of injection fluid parameters such as density and viscosity are investigated. For hydrogen storage in depleted oil and gas reservoirs with proximate faults, some minor seismicity can be expected. According to these preliminary simulations, geological hydrogen storage appears to be operationally sustainable in terms of the magnitude of induced seismicity, at least for the injection volumes, rates and storage periods considered in this work. For the studied case, the maximal potential seismicity observed is of moment magnitude 2.1, with very few seismic events.

1. INTRODUCTION
In an energy future dominated by conventional renewable energies such as wind and solar power, periods of energy surplus and deficit will be commonplace due to seasonal and annual variations in climatic conditions (Heinemann et al., 2021). During periods of energy excess, wind and solar derived electricity can be diverted to electrolyzers for green hydrogen production (Elberry et al., 2021). This hydrogen must then be stored for production and subsequent utilization during the periods of energy deficit, reducing reliance on coal, natural gas, and oil as emergency seasonal fuels. Depleted reservoirs are a potential candidate for storage at the large scale.
Interference Analysis of Shale Gas Horizontal Wells Considering Magnetic Azimuth Correction
Authors: Yu Ruifeng , Diao Binbin , Gao Deli 
Published: September 2022

ABSTRACT:
In order to analyze the interference risk of shale gas horizontal wells, a model is established to analyze the interference domain in shale gas horizontal wells. With this model, the borehole uncertainty and the fracturing interference domain can be coupled reasonably. To reduce borehole uncertainty and further reduce the interference domain, the multi-station analysis (MSA) is employed to correct the magnetic azimuth of the shale gas horizontal wells. The interference domain of a shale gas horizontal well was studied. With magnetic azimuth correction, the semimajor axis of ellipse of borehole uncertainty (EOU) decreases from 23.10 m to 19.48 m (lateral) at the measure depth of 5671.60 m. And the edge length of the interference domain decreases from 206.20 m to 198.96 m. The results show that, magnetic azimuth correction based on MSA can reduce the interference domain and interference risk. And this analysis method can provide a theoretical reference for avoiding interference in shale gas horizontal wells.

1. INTRODUCTION
In order to achieve long-term stable production of shale gas fields, infill and adjustment wells are deployed to reduce the well spacing in shale gas fields. With the well spacing reduced, the overall benefit is improved. But it also leads to earlier well to well interference. Interference will result in many drillings technical problems, such as complex and frequent overflows and leakages. Therefore, interference analysis has always been the focus and hot issue in shale gas development.
The interference domain is determined by fracturing interference domain and the borehole uncertainty. Numerical simulation method is usually employed to calculate the fracturing interference distance. A discrete fracture model is proposed for multi-scale flow in large-scale fractured tight oil reservoirs (Fang et al., 2017). On the basis of this model, a method for analyzing the well spacing of shale gas horizontal wells based on the integration of geology, engineering and economy is established (Yong et al., 2020). Numerical simulation shows that the cross section of the fracturing interference field in the direction of wellbore extension can be approximated as an ellipse ( Liu et al., 2018; Zhou et al., 2021). Actual drilling data of Fuling shale gas field in the Sichuan shows that the semi-major axes of the ellipse can be approximated to 80m and 50m (Gu et al., 2020; Liu, 2020).
Study on Heat Extraction Performance of 3D Enhanced Geothermal System with Faults Connected
Authors: Tang Yijia , Ma Tianshou , Guo Jianhua , Hu Xihui , Liu Bo 
Published: September 2022

ABSTRACT:
Enhanced geothermal system (EGS) is the major way to extract heat from impermeable hot dry rocks. As heat mining process in EGS is complex, effective numerical simulation method is required. Lots of EGS simulation models are proposed with different kinds of fracture system using discrete fracture network method or equivalent porous media method. However, the situation that EGS with faults connected have seldom investigated. Thus, a 3D geothermal heat extraction model connected with faults is established, and solved by the finite element method. The proposed numerical model is validated with single fracture heat extraction analytical model. The largest error between two models is 5.63%, which shows the efficiency of the proposed model. The effect of faults on heat extraction in EGS is studied. The results demonstrate that compared with the EGS disconnected with the fault, the EGS with fault get higher production temperature and poor production flow rate. The more faults there are, the more injected fluid is lost, resulting in lowest heat extraction performance. Thus, in hot dry rock heat mining engineering practice, hydraulic fracturing operations should avoid connect with faults to ensure much more injection fluid can be extracted.

1. INTRODUCTION
With the energy crisis and environmental pollution problems more and more serious, increasing attention has been paid to the development of clean energy, especial for the hot dry rock (HDR) (Lund and Boyd, 2016). HDR is a kind of dense, high-thermal geothermal resource buried 3,000 meters underground. In China, the geothermal resource of HDR rock is about 7×1015 MWh, 2% of which can meet the requirement of energy consumption for 3,400 years (Zhu et al. 2015; Huang, 2014).
Enhanced geothermal system (EGS) is developed to extract HDR geothermal resources. Typical EGS is composed of injection well, production well, and fracture network. The wells are connected through fracture network (Olasolo, 2016; Tang et al. 2020). The injected fluid extracts the heat though the fracture network and produces high thermal fluid from production well. The Fenton Hill EGS project in the United States was the world’s first EGS site trial, proving the concept of EGS. France built the world’s first EGS site for commercial application, namely the Soultz EGS site. The generation power reached 1.5MWe. Australia built the world’s first EGS site from private company in Cooper Basin (Lu 2017). Other countries built EGS power stations after another. Unfortunately, most of them eventually shut down, because the fluid loss in the fracture network is dramatic, which is hard for commercial use (Kelkar et al. 2016). Therefore, it is very important to study the heat extraction mechanism of fluid in fracture network.
Effects of Partially Cemented Annulus on Casing Integrity in Salt Formations
Authors: Melo D. D. E. F. , Fontoura S. A. B. , Inoue N. , Zhou C. , Marcou S. R. , Soares C. R. W. , Carneiro G. 
Published: September 2022

ABSTRACT:
The time-dependent behavior of salt rocks poses challenges to well design. Salt mobility is associated with critical wellbore closure and excessive casing loads. In the presence of cement imperfections, non-uniform loads on casing strings can lead to failure. A parametric finite-element analysis considers an uncemented annulus, a fully cemented annulus, and a partially cemented annulus with a channel covering 20%, 50% and 80% of the pipe circumference. No pressure build-up was considered. Commonly applied to Brazilian salts, a double-mechanism creep law is adopted, and strain rate uncertainties are accounted for. The stress distribution is less severe when uniform loads act on the casing surface. A partially cemented annulus results in non-uniform loads and deformation of the casing cross-section. A small volume of cement channels leads to localized regions of critical stress within the casing. As the channel size increases, the higher moment arm results in higher casing stresses, especially when two-point bending occurs at the salt-casing contact. Analysis of casing yield and failure when cement channels are present along salt sections allows for more accurate evaluation of casing integrity.

1. INTRODUCTION
Well design in salt formations faces many challenges due to the time-dependent behavior of these rocks. Wellbore closure due to salt creep may lead to drill string sticking or aborted casing runs, and the correct drilling mud weight must be applied. After casing is set, salt creep can increase casing loads and compromise well integrity.
When submitted to a deviatoric stress, salt exhibits a time-dependent strain response according to Figure 1. During the first stage of loading (primary creep) salt undergoes a high rate of deformation, that gradually slows down until it reaches steady state (Secondary) creep. Finally, during tertiary creep the strain rate increases until rupture (Jaeger et al, 2007; Goodman, 1989). The strain rate is influenced by many factors, such as mineralogical composition, impurities, formation temperature and the imposed differential stress (Liu et al., 2013, Fjaer et al., 2008).