bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comprehensive Stress Modeling Approach for High Topography-Complex Geological Structure of XGS Field
Authors: Luo Yu , Zhou Yuan , Peng Xian , Zhao Yichao , Li Longxin , Li Limin , Younessi Ahmadreza , Zhou Yongsheng 
Published: October 2022

ABSTRACT:
The magnitude and orientation of the in-situ stresses are greatly impacted in areas where the ground elevation changes dramatically within the field boundaries. The stress model for XGS field, located in onshore China, is constrained using a comprehensive workflow starting from analyzing the wellbore scaled data to a full field finite element numerical model. The well data from 14 offset wells are used to constrain the magnitude and orientation of the principal stresses in the XGS field. Because of the significant difference in the ground elevation of the offset wells, the calculated in-situ stresses are associated with some level of errors in the 1D models. This is corrected to some extend by calculating the stresses using a 3D modeling approach. Subsequently, a 4D finite element numerical model is used to capture the impact of the complexities in geological structure and high topography changes in XGS field. The findings from the 4D model show that the state of stresses in the shallow sections within the high topography structure tend to be under normal stress regime which gradually changes to strike-slip stress regime in the deeper section.

1. INTRODUCTION
The XGS underground gas storage facility currently operates in a depleted gas reservoir located in the Sichuan province, Southwest China. The facilities are constructed during the second half of 2011 and cushion gas injection started in June 2013. Located in a high topography and high tectonic stress region, the geological setting of the XGS field is structurally complex and highly faulted (Li et al., 2021).
Because the field is located under a high topography structure (Fig 1), the magnitude and orientation of the in-situ stresses are greatly impacted. A comprehensive approach was used to capture the complexities in the stress model withing the XGS field. For this purpose, first the stress magnitudes and orientations are modeled using the wellbore scaled events from 14 main offset wells. These 1D well-centric models are then upscaled to the entire field using 3D static modeling approaches. Subsequently, a 4D numerical model is used to initialize the stresses to capture the impact of the complexities in geological structure and high topography changes in XGS field. Similar workflows were used to conduct 4D models by Fang et al. (2014) and Younessi et al. (2018).
Laboratory Evaluation of Micro-Proppants on Enhancement of Microfracture Conductivity
Authors: Yuan Shuai , Zhou Fujian , Tian Yakai , Liang Tianbo , Liang Xingyuan 
Published: October 2022

ABSTRACT:
The complex fracture network generated from hydraulic fracturing is of great importance for well productivity in unconventional reservoirs. However, numerous natural or induced microfractures are closed without proppant placement after hydraulic fracturing is completed. Micro-proppants have small enough particle sizes and longer transport distances, which can access microfractures and keep them open. The objective of this work is to investigate the particle size distribution, crushing rate as well as microfracture conductivity by micro-proppants from fly ash. Microproppants have a large range of particle size from 1 μm to 300 μm, and the average particle diameters are 22.84 μm and 51.13 μm. The crushing rates of micro-proppants are related to the particle size distributions and mineral contents. More concentrated distribution of particle sizes and higher contents of high-hardness minerals lead to a lower crushing rate of micro-proppants. The fracture conductivity is exponentially decreased with closure stress, and it is controlled by average particle sizes and crushing rates of micro-proppants. The results demonstrate micro-proppants from fly ash are sufficient to the requirements of hydraulic fracturing and improve hydrocarbon production of unconventional reservoirs.

1. INTRODUCTION
Hydraulic fracturing is considered the most effective stimulation method for unconventional reservoirs to improve well productivity. The complex fracture networks are created by pumping a large number of fracturing fluids during hydraulic fracturing, which consists of primary fractures, secondary fractures, and induced microfractures. The induced microfractures have small openness of less than 0.1 mm (Danso et al., 2021). For unconventional reservoirs with extremely low permeability like shales, induced microfractures have a large contribution to the conductivity of the fracture network (Sharma & Manchanda, 2015; Grieser et al., 2016; Keshavarz et al., 2016). The 20/40 mesh proppants are usually used to support the primary fracture for high fracture conductivity. The 100-mesh proppants in recent use cannot reach the induced microfractures. Therefore, micro-proppants with particle diameters less than 150 μm (100-mesh) are selected to reach the induced microfractures (Nguyen et al., 2013; Dahl, Calvin, et al., 2015; Calvin et al., 2017a; Tian et al., 2022). The micro-proppants are generally added to the pad fluid before placing the conventional proppant in primary fractures. Field trials have indicated that micro-proppants can improve well productivity up to 50% in unconventional reservoirs such as Wolfcamp, Woodford SCOOP, and Barnett Shale formations (Calvin et al., 2017b; Dahl, Nguyen, et al., 2015; Lau et al., 2019; Radu et al., 2020).
Heat Propagation Through Fractures During Hydraulic Stimulation in Crystalline Rock
Authors: Wenning Q. C. , Gholizadeh Doonechaly N. , Shakas A. , Hertrich M. , Maurer H. , Giardini D. , Team Bedretto , Serbeto F. , Bethmann F. , Dyer B. , Castilla R. , Meier P. , Wiemer S. 
Published: October 2022

ABSTRACT:
The Bedretto Underground Laboratory for Geosciences and Geoenergies (BULGG) is located in central Switzerland and serves as a test bed for geothermal energy research. Several boreholes were drilled from the laboratory section (ca. 1.1 km overburden) to serve as injection boreholes for stimulation and geophysical monitoring boreholes. During a hydraulic stimulation injection in winter 2020 into injection borehole ST2 interval ranging from 313 to 320 m, we observe a thermal perturbation using distributed fiber optic temperature sensing in a neighboring open borehole (MB1) at a depth of 275 m to 295 m. Prior to injection, there is a thermal anomaly in MB1 at about 289 m due to natural fracture fluid flow. Below this depth the temperature is approximately 1.5 °C higher than above. During injection there is a gradual upward movement of the thermal anomaly to ca. 278 m depth. After injection is stopped, the thermal signal gradually recovers to the original depth. The cause for such a temperature change is potentially due to increased warm water flow reaching the base of MB1 from deeper ST2 or poro-elastic fracture closure of the cold-water conducting fractures at 278 and 289 m depth in MB1 during stimulation.

1. INTRODUCTION
Geothermal energy is considered a sustainable form of power generation. While the earth generates over three times the total yearly human energy consumption (Pollack et al., 1993; Davies and Davies, 2010), the use of geothermal energy for power generation at the industrial scale has been limited, largely in part due to the need to engineer and stimulate reservoirs at significant depth to tap into the heat sources.
Such ‘enhanced’ or ‘engineered’ geothermal systems (EGS) require hydraulic stimulation or fracturing to achieve economic heat extraction, adding to economic impact of drilling and completing a well, as well as creating additional difficulties like induced seismicity. To date, there are just a few examples from across the world which have had success in producing heat from EGS reservoirs (Brown, 1995; Albright and Pearson, 1982; Moore et al., 2018; Link et al., 2020; Genter et al., 2010).
On Averaging of Toughness Heterogeneity When Modelling Hydraulic Fracture Evolution
Authors: Da Fies G. , Peck D. , Dutko M. , Mishuris G. 
Published: October 2022

ABSTRACT:
In this paper we describe various approaches used to capture heterogeneity within the reservoir undergoing hydraulic fracturing treatment and their implication on modelling of fracture propagation. In highly laminated reservoirs with soft and/or weak layers, capturing heterogeneity at an appropriate resolution is the key for successful prediction fracture growth and other crucial treatment parameters.
Our focus is on studying several strategies to average fracture toughness and assess their suitability for use in advanced computational methods such as FE/BEM. In practice the well log and petrophysical data deduced from various measurements and observations are upscaled and/or homogenized to the spatial approximation size. The fracture toughness is one of the most delicate physical parameters and application of the homogenization techniques are rather uncertain, hence any proposed averaging will depend on process conditions and the toughness distribution.
We propose and analyse a notion of an average toughness and show that it is a process dependent variable and provide some recommendations how to implement the defined measure into the numerical modelling. As an example, we use periodic distributions and consider model without leak off that allows us straightforward handling different regimes (toughness/viscosity).

1. INTRODUCTION
Typically, when using computational methods such as Finite Element Method, the well log and petrophysical data obtained from various measurements and observations are upscaled and/or "homogenized" to the element size. From all in-situ parameters, toughness is one of the most delicate physical parameters to handle, as application of the homogenization techniques are rather questionable here as commented on by Caiulo and Kachanov (2010) and Kachanos (1994). Compared to other types of fracture evolution, hydraulic fracturing is probably the most stable crack propagation process and thus, fortunately, some estimates can be provided here.
We estimate errors introduced by various strategies to incorporate heterogeneous fracture toughness into numerical modelling (Dontsov and Suarez-Rivera (2021), Da Fies et al. (2021)). We use periodic distributions and consider model without leak off that allows us straightforward handling different regimes (toughness/viscosity). For the simulations, we use an extremely effective in house-built time – space adaptive solver utilizing main ideas from those reported by Wrobel and Mishuris (2015). The solver is capable to compute rather arbitrary distribution of the toughness.
Numerical Simulation of Triaxial Experimental Results on Sandstone Using Critical State Mechanics
Authors: Reppas N. , Davie C. , Wetenhall B. , Gui Y. L. , Ma J 
Published: October 2022

ABSTRACT:
In carbon capture and storage schemes, the carbon dioxide (CO2) can be injected at high pressures and low temperatures for permanent storage in deep reservoirs. In the North Sea, the storage sites will be predominantly sandstone. Triaxial tests on sandstone were conducted until failure using representative in-situ stresses to estimate the mechanical properties of the rock. A theoretical constitutive model, using Finite Element Modelling (FEM), describing the stress-strain behavior and damage evolution of rock during triaxial testing, is presented alongside the results of the tests. The model reproduced the experimental outcomes satisfactorily and was used to estimate the critical state mechanic parameters. Lower temperature indicated higher strength on sandstone, a decrease in the Poisson’s ratio and, consequently, damage increase.

1. INTRODUCTION
Potential Carbon Capture and Storage (CCS) schemes include injecting liquid carbon dioxide (CO2) from ships into subsea formations for permanent storage. CO2 on a ship is stored at a temperature close to the triple point of CO2 at around -50°C~-57°C and exposed to almost 0.6~0.7 MPa pressure in order to keep the containment of the CO2 mixture in liquid form (Reppas et al., 2021, Wetenhall et al., 2014). The difference between the injected CO2 from a ship and the temperature of the wellbore wall, which is increasing by 30°C/km, is causing temperature fluctuations and external stresses. These loadings and their mechanical effects on the wellbore wall can be described by triaxial tests.
Laboratory tests were undertaken to determine how the mechanical properties of sandstone elastic modulus E, Poisson’s ratio n, the shear modulus G and bulk modulus K of rock— are influenced by the different confining pressures and temperatures. As sandstone is found in the sub-sea basins, it has high porosity and can be a likely storage medium for CCS, it was selected as the type of rock for the triaxial testing. Three different temperatures 15°C, -5°C and -10°C were experimentally examined. The three temperatures represent a different injection scenario of CO2. Confining pressures of 12.5 MPa and 24 MPa were used to represent rock conditions at 500m depth and 1000 m depth under the North Sea, respectively.
Coarse-Graining Methods for the Modified JKR Contact Model on a Triaxial Compression Test
Authors: Kazidenov Daniyar , Khamitov Furkhat , Amanbek Yerlan 
Published: October 2022

ABSTRACT:
The Discrete Element Method (DEM) modeled by coarse-graining approaches has been gaining importance in many applications including a triaxial compression test that represents the key micromechanical behaviors of deformable solids. In this work, the triaxial compression test has been investigated using a realistic particle-size distribution sample that replicates the weak cemented sandstone in Kazakhstan. The simulation was performed by the modified Johnson-Kendall-Roberts (JKR)-based DEM model with cohesive contact forces. According to the model, bonds between particles are broken at the maximum value of the normal contact force, and no new bonds are formed after the breakage. In this research, we implemented the coarse-graining methods for the modified JKR model. A scaling law was developed for each material parameter in the model such as density, surface energy density, Young’s modulus, Poisson’s ratio, friction and restitution coefficients . In addition, those approaches were combined with the same statistic weight (SSW) and same size parcel (SSP) scaling methods in order to scale the polydisperse particles. These combined methods are based on the conservation of mass and momentum by applying statistic weights to the particle diameters. First, the original particle simulation with the modified JKR settings was validated with the experimental data. Then, the stress-strain response and bonding behavior were compared between the original particle system and coarse-grained simulations. There is a good agreement between the results obtained from the original particle system and coarse-grained particle models. Moreover, the speedup of the coarse-grained simulations in parallel computing is achieved approximately 15 times faster than the original particle system with the same number of cores.

1. INTRODUCTION
Sand production negatively affects the operation in the oil and gas industry. It usually occurs with weak unconsolidated sandstone reservoirs where the stress on the formation exceeds the mechanical strength of the rock, which leads to its failure. The produced sand blocks the flow line, destroys the equipment by erosion, and prevents access to the wellbore. As a result, the operational cost increases due to production limitations. The prediction of sand production optimizes the best strategy for sand control management to minimize those limitations.
Effect of Disturbance Factor Distribution Function on Stability of an Open Pit Mine
Authors: Ma T. , Cami B. , Javankhoshdel S. , Yacoub T. , Corkum B. , Curran J. 
Published: October 2022

ABSTRACT:
The disturbance factor (D) is a parameter in the Generalized Hoek-Brown failure criterion for rock slopes in slope stability. It represents the subsurface damage to the rock material properties resulting from blasting and stress relaxation during excavations. Within the region of assumed damage, a number between zero (undisturbed) and unity (very disturbed) is prescribed as the value of the disturbance factor. Most commonly a uniform value of D is assumed within the entire region of damage, but little research has been done to study the impact of the variation in the D parameter on stability. Through use of an example, this paper examines the effect of various distribution functions of D through the damaged region, such namely, as constant, linearly varying, and exponentially varying. The failure surfaces and factors of safety for the slope as determined via limit equilibrium are also compared with finite element analyses. Varying the distribution of the damage function was found to significantly affect the failure surface and factor of safety. It is recommended that practitioners adopt care to select an appropriate distribution for slope stability analysis.

1. BACKGROUND
The Generalized Hoek-Brown method (Hoek and Brown 2018) is widely used for determining rock mass strength in rock mechanics. One application of this method is in the design of open pits in rock masses which requires the evaluation of factor of safety against overall sliding. During excavation, subsurface damage can occur to the surrounding rock masses and cause fracturing. The damage can be caused by two sources: (a) blasting and (b) stress relaxation (Hoek et al. 2002), and can be quantified in the form of a disturbance factor, D, which ranges from a zero (undisturbed) to unity (disturbed) within the rock masses. For slope stability, the shear strength of the rock activated along the slip surface can be obtained by solving Eq. (1) to Eq. (4) (Hoek et al. 2018).
Stratigraphic Analysis of Microseismic Signatures During Hydraulic Stimulation
Authors: Welch N. J. , Huang L. , Gross M. R. , Glubokovskikh S. 
Published: October 2022

ABSTRACT:
This paper presents a novel workflow to enhance the interpretation of microseismic events by comparing the temporal evolution of the microseismic cloud between adjacent stages from two different wells. The stratigraphic properties of identified rock layers along with changes within the local stress field distribution may determine the propagation path and aperture of the hydraulic fracture. Hydraulic fractures however are largely aseismic, and thus microseismic signatures surrounding the hydraulic fracture may indicate important damage-zone fracture formation. A comparison of each microseismic event with the local rock stratigraphy of the hypocenter determined regions where rock composition and larger formation layers influenced the microseismic signals of events. This analysis allowed for classification of microseismic events by formation layers and can elicit different in-situ stress states during hydraulic stimulation. Principal Component Analysis of each formation microseismic cloud can quickly show dominating stresses in the microseismic signals. The changes in the microseismic cloud between the first and second stimulated wells during a zipper fracture stimulation shows the significant changes in formation stress from one well to another in a multi-well system.

1. INTRODUCTION
The Hydraulic Fracture Test Site (HFTS-1) is a Public-Private partnership funded by the United States Department of Energy (DOE) with various industry and academic partners to expand our knowledge of the hydraulic stimulation of unconventional reservoirs. In the project 11 horizontal wells were drilled with over 400 stimulation stages completed with advanced monitoring deployed in multiple wells. The test site is located in the West Texas Permian (Midland) Basin targeting the upper and middle Wolfcamp formations. A total of 183 m (600 ft.) of core was recovered from a slanted investigation well drilled after stimulation to determine the extent of fracture propagation and proppant transport (Ciezobka et al., 2018; Courtier et al., 2017).
Simulation-Based Economical Modeling of Hydraulic Fracturing for Enhanced Geothermal System
Authors: Porlles J. W. , Jabbari H. 
Published: October 2022

ABSTRACT:
Hydraulic fracturing is applied to extract fluids (oil, gas, and water) from very low permeability rocks. This type of stimulation could develop hot and dry rock geothermal resources. Habitually, those reservoirs are located in the depth of 2.7 Km to 5.5 Km; and at more than 180 °C. This study designs a hydraulic fracturing model in horizontal wells to extract hot water economically, creating high permeable artificial fractures. We aim to investigate the effects of varying fracture-cluster lengths, proppant, and frac fluid types, on hydraulic fracturing treatments using 2D and 3D simulation models. Some parameters such as type of proppant, fracture fluids, number of stages, fracture length, and fracture width are evaluated considering the reservoir’s high temperature and high pressure. Finally, different scenarios are evaluated to know if the hydraulic model is economically feasible to generate electricity with the current price of electricity price, drilling, and completion cost.

1. INTRODUCTION
We perform an analysis to evaluate the feasibility of developing an enhanced geothermal system (EGS) project, considering the evaluation and modeling of a horizontal well stimulated by hydraulic fracturing, including fracture fluids and types of proppants that could be used in a frac job. The assessment covers a conceptual representation of a granitoid reservoir, considering a complete economic analysis including NPV, discount rate, reservoir temperature, number of horizontal wells, depth, and electricity sale price.
The Department of Energy (DOE) generated an important report called "Geovision, Harnessing the Heat Beneath our feet". This report explains some scenarios concerning the geothermal industry and how will be the forecast for the next 30 years (DOE, 2019). Figure 1 presents the three scenarios explained in the report. The business-as-usual scenario (BAU) explains current and anticipated future trends if the geothermal industry continues on the exact forecast of 2015 conditions. Next, the Improved Regulatory Timeline (IRT) scenario estimates the impacts of reduced geothermal project development timelines and increased discovery rate of geothermal resources due to streamlined regulatory and permitting processes. Finally, the Technology Improvement (TI) scenario assesses the impacts of advanced technology developed aggressivity and the reduction of the cost of some technologies such as drilling, stimulation, logging, and power plants.