bluuebunny/crossref_metadata_2025_split huggingface dataset:
Thermal Damage in Crystalline Rocks: The Role of Heterogeneity in Mechanical Performance and Fracture Mechanisms
Authors: Dang Yike , Yang Zheng , Yang Shangtong , Shang Junlong 
Published: August 2024

ABSTRACT:
Investigating thermally treated rocks' mechanical properties and failure processes is crucial for advancing geothermal energy storage and extraction technologies. Naturally occurring rocks typically exhibit inherent flaws and fractures. Nevertheless, existing studies on the impact of thermal treatment on rock damage predominantly utilize intact rock specimens, either through numerical simulations or experimental approaches. This research introduces the Grain-Based model (GBM) to represent the complex shapes of mineral grains accurately and incorporates the heterogeneity of grain sizes. By employing the Weibull distribution, the model captures the variability in rock internal strength due to microcracks, porosity, mineral composition, and other factors. Furthermore, it integrates the temperature dependency of rocks' physical and mechanical properties when subjected to elevated temperatures, the numerical simulation reproduced the phenomenon that the compaction stage of the stress-strain curve caused by thermal damage extends as the temperature rises. Overall, this study provides a complete understanding of the thermal effects on rock integrity.

1. INTRODUCTION
Rocks in nature commonly contain defects such as joints, fissures, and structural planes, which have a decisive impact on the mechanical behavior and stability of the rocks. Particularly under conditions of high temperature, the mechanical properties and failure mechanisms of rocks with such defects can vary significantly from those observed at room temperatures, thus impacting the safety and reliability of rock engineering projects. In geological engineering, nuclear waste storage, and geothermal energy development, rocks are routinely subjected to high-temperature environments. Temperature variations can intensify the expansion of internal defects in rocks, modify their mechanical attributes, and trigger new failure modes.
As a quintessential crystalline rock, granite possesses a markedly heterogeneous internal structure. This heterogeneity leads to unique thermal stress responses and failure mechanisms under high temperature and stress conditions, which are significantly different from those observed in homogeneous materials. The non-uniform thermal expansion can result in substantial stress concentration within the rock, facilitating the initiation and propagation of cracks. This process, in turn, impacts engineering structures' long-term performance and reliability.
The Energy Budget in Fluid-Driven Fracturing: A Continuum Damage Approach
Authors: Mobasher Mostafa E. , Waisman Haim 
Published: August 2024

ABSTRACT:
We present a numerical approach for the quantification of the energy transfer, storage, and dissipation mechanisms in fluid-driven fracturing. The analysis approach is motivated and originated in the energy statement describing continuum damage, poroelasticity, and the non-local effects in both of damage and transport. The thermodynamically consistent derivation leads to the definition of the state laws, as well the as analytical expressions of energy storage and dissipation in the porous media. The derivation leads to the identification of three major energy loss mechanisms: 1) viscous fluid-flow, 2) solid-damage effect due to the growth of voids and cracks in the solid skeleton, and 3) fluid-damage effect due to the accompanying changes in compressibility and permeability. The analysis model is implemented following the framework of mixed non-linear finite element; and the energy dissipation functions are calculated numerically within this framework. Several benchmark fluid-driven fracturing problems are modeled, and the results agree with the available data from experimental models in the literature. The model is then used to perform several parametric investigations to provide an engineering value of the proposed approach; for example, the analysis of different fluid-injection rates shows most of the additional energy input in higher injection rates is dissipated in viscous fluid flow rather than the sought solid damage. Moreover, the model is used in the analysis of the interaction between fluid-driven fracturing and pre-existing weak zones featuring combinations of reduced stiffness and permeability to represent natural and man-made fractures.

1 INTRODUCTION
Hydraulic fracturing is a process in which a fracturing fluid is pumped at high rates in order to increase the permeability in a fracture zone, ultimately leading to more economical oil production. Energy used in the process is transferred into the porous domain in the form of: (a) elastic energy stored in a deformed domain; (b) energy used to generate new fracture surfaces, resulting in the dissipation of energy through solid skeleton decay (damage); and (c) energy used to transport the fluid through pores, resulting in dissipation via fluid viscosity. The goal of an optimized hydraulic fracturing approach would be to maximize the dissipation due to solid damage, as this would result in the stimulation of a larger reservoir volumeBunger and Lecampion (2017); Shlyapobersky (1985). This paper provides a quantitative evaluation of energy stored and dispersed throughout the process of hydraulic fracturing, based on an non-local damage and transport (NLDT) model modelMobasher et al. (2017); Mobasher (2017); Mobasher et al. (2018); Mobasher and Waisman (2021a,b).
Simulating Coupled THM Problem and Wellbore Integrity Analyses with Two-Phase Fluid Flow in Naturally Fractured Reservoirs
Authors: Wang Yarlong 
Published: August 2024

ABSTRACT:
Multi-phase fluid flow in naturally fractured reservoirs (NFR) is a complex and important process to be studied in energy and environmental industries. Either during CH4/H2/CO2 injection/sequestration or thermal EOR process, both fluid pressure and temperature changes may take place which will lead to significant thermal-hydraulic-mechanical (THM) responses that will impact both safety and efficiency of the project. Simulating THM responses in NFR, Formulation for an implicit pressure and explicit saturation (IMPES+T) finite element approach with an explicit thermal coupling is developed. Different shape functions, i.e. Petrov-Galerkin method, are applied to the saturation, displacement, fluid pressures, and temperature with convective energy transport calculation. In addition, a simplified coupled hydraulic-mechanical (HM) algorithm is proposed for displacement-pressures calculations, which is also coupled to an independently calculated convective-conductive thermal process. The induced pore pressure and critical stresses are highlighted in a dual-porosity medium, evaluating the wellbore integrity during injection and production in naturally fractured formations. A thermally induced tangential stress increase of 1 MPa on the wellbore wall is equivalent to a formation strength reduction of the same magnitude and yet more than 50% increase of the effective tangential stress, the key stress affecting wellbore integrity, at the wellbore wall in the fracture system may be achievable in the naturally fractured media (NFM).

1. INTRODUCTION
To simulate multiphase fluid flow, heat transport and skeleton deformation processes in NFR [Bai et al., 1993; Khalili, and Valliappan, 1996; Khalili, 2008], numerical method such finite element method has been applied to approximate solutions of the Thermal-Hydraulic-Mechanical (THM) responses. Isothermal multi-phase fluid flow and non-isothermal single-phase cases are extensively dealt with, respectively [Lewis and Ghafouri, 1997; Nair et al., 2005; Pao and Lewis, 2002; Gelet et al., 2012; Khoei et al., 2016; Arzanfudi and Al-Khoury, 2017]. Simulating CO2 injection, energy enhanced production and geothermal energy extraction processes in a NFR, a fully coupled THM model with multi-phase fluid flow is required and thus developed in this paper.
A Simplified Finite Element Algorithm and Coupled THM Problems in Stress-Sensitive Naturally Fractured Reservoirs During Injection/Production
Authors: Wang Yarlong 
Published: August 2024

ABSTRACT:
Stress concentration in vicinity of a wellbore may suppress fracture network and restrict the fluid flux in naturally fractured reservoirs (NFR). Primarily reducing the absolute permeability in the fracture network, such an impact may be reach a significant level when productivity may not increase after a drawdown increase. To cope with such a possible reversal incremental fluid flow, a critical drawdown is identified, for the case when the permeability reduction effect may surpass those inremental contributions of a drawdown increase to the flow flux. A different strategy by increasing the external fluid pressure and maintaining a constant bottom hole pressure (BHP) should be applied, so that the near-wellbore permeability may remain unchanged. Both simulation and field applications are performed and more than 30% production rate increase can be expected depending on the in-situ stresses level against permeability changes for each well. Finite element method is used for a coupled THM problem and simplified finite element algorithm is applied with a dual-porosity mode in NFR

1. INTRODUCTION
Then the permeability perpendicular to a confining stress (Principal stress direction or fluid flow directions) is conventionally defined as a function of the effective stress. Practically speaking the principal directions of fluid flow and stresses seldom coincide and in what follows, we propose to define changes of the principal permeability as a function of the normal stress to the principal flow direction, the former may be calculated by the principal stress tensor and the latter is characterized of the natural fractures and the geological bedding. Furthermore, if plasticity, sliding along a fracture or joint, and dilatancy occur, the shear component of the stress tensor should be also used. Thirdly we can determine if a production decline can be reversed by controlling the wellbore drawdown, i.e. if the drawdown and stress concentrations fall into the aforementioned sensitive range. Fourthly we may diagnose if a production decline in a specific field is caused by these stress sensitive permeability change. Finally we may find alternative ways to increase drawdown without bringing down the permeability at the wellbore at the same time. In other words, once we can correlate producing well drawdown to the induced stress changes, which are in the stress-permeability sensitive range, then we can adjust the producing drawdown to serve the purpose for production enhancement. Once these factors are identified, a dual-porosity model is built and finite element method is utilized for production calculations. It should be realized that without considering these factors, any attempt to increase production by lifting drawdown will be neutralized by the consequence of permeability reduction. Production declines in a carbonated reservoir northwestern China are observed and enhancing strategies are proposed.
Application of a Modified Warpinski Method for In-Situ Horizontal Stress Prediction Coupled with Thermal Effects
Authors: Duarte M. C. , Fernandes F. B. , Gildin E. , Braga A. M. B. 
Published: August 2024

ABSTRACT:
Understanding the effect of in-situ stresses on geological formations has been modeled over the years aiming to evaluate their behavior in zones of interest. The relationship between horizontal stress, pore pressure, and fracture gradient significantly predicts the safe range of drilling fluid weight, avoiding kick, wellbore instability, and loss of circulation material. The challenges in estimating horizontal stress include the lack of information on rock properties, which entails the need for open-hole well tests and/or coring analysis. These techniques collaborate to estimate the stresses in a specific area well but are not applicable to all scenarios. The Warpinski method proposes an approach for elastic and viscoelastic rock behavior, introducing the relationship between stress and strain when deriving horizontal stress. This research presents a case study in which the Warpinski method is applied, assuming temperature variation and its effect compared to a second scenario when the temperature is assumed to be constant. The preliminary data were derived from a prior study referenced throughout the paper, and the results were compared to previous methods that were well-known in the oil industry. The data obtained from the Warpinski method shows a good approach related to the other methods mentioned, showing results that are in accordance with what is expected.

1 INTRODUCTION
Over the years, researchers have developed models to understand how in-situ stresses affect geological formations, intending to assess their behavior in specific zones of interest. Furthermore, as the pursuit of sustainable energy solutions intensifies, it requires intricate comprehension of the in-situ stress-strain dynamics, which makes it a paramount consideration in diverse subsurface engineering applications, playing a pivotal role in the realms of oil field development, geothermal energy extraction, and Carbon Capture and Storage (CCS) initiatives.
In the oil field, accurate estimations of in-situ stress are imperative for addressing challenges associated with bore-hole stability, hydraulic fracturing optimization, and reservoir management. The interaction between rock formations and the stress conditions is integral to mitigating risks such as wellbore collapse, induced seismicity, and fluid migration. The correlation among horizontal stress, pore pressure, and fracture gradient is a crucial predictor for determining a safe range of drilling fluid weight, preventing kicks, and the loss of circulation material (Lesage et al., 1991).
Evaluating a Practical Method for Rockfall Magnitude-Cumulative Frequency Estimation
Authors: Werley K. , Sala Z. , Hille M. , Vessely M. , Walton G. 
Published: August 2024

ABSTRACT:
Rockfall magnitude-cumulative frequency (MCF) distributions are useful for hazard analysis in slope asset management, including evaluating risk and the potential need for mitigation measures. MCF distributions can be produced from rockfall inventories; recently, remote sensing methods such as terrestrial lidar scanning (TLS) or structure from motion (SfM) photogrammetry have become popular tools for the generation of such inventories. However, it is not feasible to monitor every cut slope in mountainous regions such as Colorado, and for slopes that are monitored, it can take multiple years to develop an inventory that provides a reliable MCF distribution. This study evaluates the performance of an alternative rapid MCF curve estimation method relative to MCF curves generated from TLS- and SfM-based rockfall inventories. The estimation method involves a field or desktop inspection, wherein the inspector assesses the annual rockfall frequency and proportions of different rockfall volumes on the slope. The resulting frequencies are then averaged with literature values for the corresponding rockmass type to adjust the generic literature MCF curve to reflect credible rockfall from the slope. This method was applied to six cut slopes in Colorado that have at least two years of remote sensing-based rockfall inventories. We find that for many (but not all) of the slopes, the method provides a reasonable approximation of the MCF curve obtained using remote sensing data, and we discuss potential reasons for observed discrepancies.

1. INTRODUCTION
Monitoring rockfall along transportation corridors is imperative for understanding rockfall frequency and estimating risk associated with cut slopes (Hungr et al., 1999). A risk value communicates both the hazard of the slope and the potential consequences to roadway users. Rockfall hazard is represented by rockfall magnitude-cumulative frequency (MCF) distributions, which describes how often a certain rockfall volume or larger will occur. Thus, the MCF curve can be used as a key input for estimating cut slope risk.
A Statistical Review of Rock Mass Classification with Some Surprising Results
Authors: Wellman E. C. , Kemeny J. 
Published: August 2024

ABSTRACT:
The main classification systems that estimate rock mass properties include variants of the Rock Mass Rating (RMR) System, Rock Quality Designation (RQD), the Norwegian Tunneling Index (Q) (Barton), and the Geological Strength Index (GSI). The RMR system is based on intact strength, Rock quality designation, fracture frequency, and discontinuity condition. Typical distributions for these parameters may be approximated by normal, lognormal, or Weibull distributions and discrete distributions for fracture conditions. Water and pore pressure are sometimes included but should generally be treated as a boundary condition. RQD is a single-parameter system describing the percentage of sound rock core with a length greater than 10 cm. The Barton system has three main terms to describe a relative measure of the block size, an indicator of the inter-block shear strength, and a third quotient to describe "active stresses."
One of the primary findings of the statistical study is that two parameter systems, such as blockiness and joint condition, are better differentiators between rock mass classes; however, these systems still smear parameters. For example, a GSI range of 25-55 each indicates anything from blocky to disintegrated rock mass conditions. As a result, strength estimators based on GSI are not reliable for estimating rock mass strength and, in turn, the factor of safety. RMR and GSI results result in values on a normal distribution scaled from 0-100, typically centered on 50. The models are insufficient to describe the tail end of the distribution where rock mass failure typically occurs. The Q system significantly improves when the terms are derived independently but suffers from the same normalization issue when calculated from an RMR value.
The surprising finding is that single-parameter systems, including Fracture Frequency and Volumetric joint count, are better estimators (and differentiators) or properties across the range of rock mass conditions when looked at individually. Always understand the range of the rock mass parameters used and how that can impact the design. The paper will evaluate the need to develop strength estimators based on fracture frequency and volumetric joint count. Rock mass strength estimates should be developed from the underlying input data for classification rather than from normalized sums of multiple parameters.
Study on Post-Fracturing Inter-Well Interference in Deep Shale Gas
Authors: Wang Chen , Zhu Haiyan , Tang Xuanhe , He Mingyan , Kong Fansheng , Li Danlong , He Xiao , She Chaoyi , Zheng Majia , Wu Jianfa , Zeng Bo , Huang Haoyong , Li Junfeng , Xu Ersi , Gui Junchuan 
Published: August 2024

ABSTRACT:
Field practices have demonstrated that inter-well interference can lead to increased annular pressure in adjacent wells, increasing the risk of casing deformation and ultimately affecting production. Inter-well interference has become a "bottleneck" issue limiting the development of shale gas, necessitating urgent research on its mechanisms. Taking the L well area in the southern region of Sichuan Basin as the research object, this article establishes a numerical simulation model for the fracturing and exploitation of deep shale gas horizontal wells. The study analyzed the mechanisms and influencing factors of inter-well interference during the post-fracturing exploitation process. Key findings include that The higher conductivity of the hydraulic fractures, the larger fracturing scale, and the smaller well spacing, the more likely it is for inter-well interference phenomena to occur. It was also found that when there is no interference from natural fracture zone, batch exploitation can lead to more pronounced inter-well interference phenomena. Natural fracture zones between wells enhance this interference, but their impact is reduced during batch exploitation due to pressure recovery in the first exploited well. The study also highlights that the flow conductivity of natural fractures significantly affects inter-well interference during batch exploitation. Overall, this research provides insights into optimizing shale gas exploitation strategies in complex geological environments.

1 INTRODUCTION
The Sichuan Basin boasts the largest shale gas resources in China, with its annual shale gas production exceeding 90% of the country's total output. It is the main battleground of shale gas development in China. Based on extensive theoretical research and field practice, the multi-cluster fracturing process of shale gas horizontal wells has made a technical breakthrough. At present, the number of wells with interference between wells accounts for 50% in W area, which directly affects the production of old and new wells with interference (Guo et al., 2022). A large number of field practices show that inter-well interference will lead to the increase of annulus pressure in adjacent wells, increase the risk of casing variation, and eventually affect production. Interference between wells has become a "stuck neck" problem restricting shale gas development, and an effective method to evaluate interference is urgently needed.
Geothermal Resource Evaluation Based on Geological Modeling in Fushan Sag, Beibuwan Basin
Authors: Yun Xiaorui , Feng Jianyun , Zhang Ying , Zeng Yan 
Published: August 2024

ABSTRACT:
Fushan Sag is in the south of Beibuwan Basin, with rich geothermal resources and large development potential. Based on the regional geological background, geothermal geological conditions, this paper systematically analyzes the characteristics of thermal reservoir and evaluates the amount of geothermal resources based on geological modeling. The results show that The geothermal gradient in Fushan sag ranges from 2.48 to 4.68 °C/100m, with an average value of 3.35 °C/100m, the terrestrial heat flow values is 56.05-82.54 mW/m2 and the amount of deep geothermal resources within a range of 3-6 km is 1.4⁎1013J.

1. INTRODUCTION
Deep geothermal resources, including hydrothermal resources and hot dry rock (HDR), geothermal resources are usually buried at a depth greater than 3 km, (Dai and Chen, 2008; Younger et al., 2012; Muffler and Cataldi, 1978; Pang et al., 2020; Tester et al., 2006; Wang et al., 2017, 2002; Wang et al., 2012; Williams et al., 2008; Zhang Y et al., 2020).
Beibuwan Basin located in the northern part of South China Sea has been a key area for oil and gas exploration and development in recent years, and a large number of researches have been carried out on the basin structure, rocks, sedimentation, oil and gas reservoirs, etc. It is found in the process of oil and gas exploration that the overall geothermal temperature gradient in Beibuwan Basin is relatively high, and the geothermal temperature gradient of the Cenozoic stratum of the Sag area is generally in the range of 3.1-3.8°C/100m, and that the uplift area can reach 4-7°C/100m, indicating that the basin has the potential for geothermal resource development. Fushan Sag is in the south of Beibuwan Basin, with rich geothermal resources and large development potential, but the research degree is low and has not yet been exploited on a large scale (Zhu and Jiang, 1998; Li et al., 2012; Huang et al., 2012; Liu et al., 2008; Meng et al., 2009; Ma et al., 2012; Wu and Liu, 2021; Zheng et al., 2022; Gao et al., 2020; Dai et al., 2009; Li et al., 2007; Xu et al., 2021). Strengthening the research on the structure of the geothermal field, geothermal geologic conditions, amount of geothermal resources, and exploitation potential of the region is of great strategic significance to improve the energy structure of Hainan Island.