bluuebunny/crossref_metadata_2025_split huggingface dataset:
Measuring Hydraulic Fracture Propagation and Closure in Sandstone
Authors: Talebkeikhah M. , Momeni S. , Lecampion B. 
Published: August 2024

ABSTRACT:
This study investigates experimentally hydraulic fracture propagation, arrest and closure in permeable rocks. Through a controlled laboratory experiment on a Molasse sandstone block under a true triaxial state of stress, hydraulic fracture propagation and closure was monitored via the measurements of fluid pressure, fracture opening at the wellbore and continuous recording of passive acoustic at sixteen sensors. The combination of acoustic data, fluid pressure, and fracture opening measurements offer an interesting dataset to better understand fracture closure. Both the width and pressure behavior upon closure are consistent with recent theoretical estimate. This notably justify the use of pressure derivatives with respect to the square-root of shut-in time to pick fracture closure. The scaled opening versus reverse time and scaled pressure over the square root of reverse time exhibits a linear behavior, in line with the expected theoretical behavior. As a result, the width evolution near closure can be used to estimate the leakoff coefficient. Interestingly, our measurements also reveal the existence of a irreversible/residual opening at the wellbore even after complete fracture closure, whose value is of the order of the Molasse sandstone grain size. This may be attributed to a small amount of shear slip/fracture mixed modality, potentially causing non-alignement of asperities of the fracture surfaces at closure.

1 INTRODUCTION
Hydraulic fracturing is a technique widely employed to enhance well productivity. It is also a reliable method to measure in-situ stresses at great depths from wellbores. The hydraulic fracturing process involves injecting a fluid at pressure sufficiently large to propagate a tensile fracture in the rock. Upon cessation of the injection, the fracture eventually closes due to the combined effects of the confining in-situ stress and the depressurization of the fluid associated with its permeation into the surrounding permeable rock matrix. The behavior of hydraulic fracture once the fluid injection has stopped depends on the dominant propagation regime. Indeed, in cases where toughness dominates, the fracture immediately arrests, and then close due to fluid leak-off. Conversely, if fluid viscous dissipation is dominating when the injection stops, the fracture continues to grow for a while driven by the energy elastically stored in the solid during the propagation phase (Möri and Lecampion (2021)). Following fracture arrest, fracture recession and closure starts. Its dynamic is mostly governed by fluid leak-off. Although a large number of numerical and theoretical models have been investigated (Nolte (1979a); Desroches and Thiercelin (1993); Papanastasiou (2000); Mohammadnejad and Andrade (2016); Peirce (2022); Peirce and Detournay (2022b,a)), experimental investigation with precise measurements of fracture arrest and closure are limited (De Pater et al. (1996)).
Poroelastic Stress Cycling and Microseismic Activity at the San Emidio Geothermal Field, NV (USA)
Authors: Wang H. F. , Sone H. , Cardiff M. , Guo H. , Thurber C. , Luo X. , Feigl K. L. , Sherman C. 
Published: August 2024

ABSTRACT:
Guo et al. (2023) presented a hypothetical scenario of Thermal-Hydrologic-Mechanical (THM) processes that included a microearthquake cycle associated with annual plant shutdowns at the San Emidio Geothermal Field in northwestern Nevada (USA). Their scenario focused on the relative magnitudes of fluid pressure, Pp, and critical pore fluid pressure, Pcrit, which is the magnitude of pore pressure above which Coulomb failure triggers seismicity. The scenario was based on three sets of observations and inferences associated with the 20-hour shutdown in December 2016 during which all pumping operations stopped: 1) Simulation of fluid-pressure changes, 2) Observation of microseismic events before, during, and after the shutdown, and 3) Stress inversion of focal mechanisms. We examine the THM coupling between stress, pore fluid pressure, and temperature in terms of the critical value Pcrit using first-order estimates for failure on small slip patches in a normal-fault zone.

1. INTRODUCTION
Extraction of heat from geothermal reservoirs requires a working fluid circulating in hot rock. Efficiently managing the resource must consider how fundamental physical variables of temperature and fluid pressure control reservoir stresses. Simulating thermal-hydrologic-mechanical (THM) processes in heterogeneous rock is typically approached using numerical models calibrated and validated from field observations. THM models are based on conceptual models and idealized physics. The WHOLESCALE (Water and Hole Observations Leverage Effective Stress Calculations and Lessen Expenses) project at the San Emidio Geothermal Field uses Lawrence Livermore's GEOS code to model the three-dimensional stress field through time (Feigl et al., 2024; Luo et al., 2024). The code allows for geometric flexibility, heterogeneity, and coupling between thermal (T), hydrologic (H), and mechanical (M) processes as well as limited chemical (C) but not biological (B) processes. Although THM codes are indispensable tools for understanding reservoir behavior for reservoir management, their complexity and detail can obscure the controlling processes. Another difficulty is choosing an appropriate mesh and time step that are numerically reasonable because observations may span many orders of magnitude in space and time, e.g., deformation over months and years associated with InSAR and rapid microseismic events too small to be captured by InSAR.
Evolution of Hydraulic Fracture Permeability in EGS Considering Natural Fracture Compressibility and Strength of the Surrounding Rock
Authors: McLean M. L. , Espinoza D. N. , Ahmmed B. 
Published: August 2024

ABSTRACT:
The long-term success of an Enhanced Geothermal System (EGS) project requires distributed fluid flow in created fractures, ideally each with uniform and moderate permeability to avoid early thermal breakthrough. Yet, thermal depletion causes fracture opening, increasing the likelihood of flow channeling in areas with high fracture permeability. Furthermore, the effective reservoir rock stiffness (including natural fracture compliance) has a first-order impact on thermally induced stress changes, and thus fracture permeability. The objective of this work is to explore the role of thermal depletion on hydraulic fracture permeability considering a non-linear elastoplastic geothermal reservoir response. We utilize three-dimensional numerical simulations based on effective medium theory of fractured rocks to implicitly account for natural fracture compressibility and strength. Results demonstrate that a portion of the thermal strain-induced by cooling- is absorbed by natural fracture compressibility, which reduces the overall stress change, and tends to attenuate hydraulic fracture opening. Critically stressed natural fractures can yield during operation and decrease the likelihood of flow channeling. Lastly, the modeling results indicate that linear elastic models tend to overpredict fracture opening compared to models that account for effective properties of fractured rock masses.

1 INTRODUCTION
Predictions of recoverable heat energy from Enhanced Geothermal Systems (EGS) reservoirs with models that neglect stress-dependent and non-linear fracture permeability are conservative estimates (Kohl et al., 1995). Flow channeling and thermal short-circuiting caused by thermo-poroelastic coupled feedback is often observed early on in field tests and would limit the installed capacity unless efforts were made to improve the flow distribution (MIT, 2006). Localized fracture opening increases injectivity and decreases the geothermal effective reservoir volume by localizing injected flow (Hicks et al., 1996). Hence, reservoir stresses (in-situ and any changes during operation) play a significant role in the distribution of EGS circulation fluid and evolution of fracture permeability (McLean and Espinoza, 2023). Spatial heterogeneity in the initial fracture aperture may further decrease reservoir performance from the beginning because preferential flow paths may exist prior to injection (Guo et al., 2016).
High-Precision Triple Multiscale Model Characterizes the Complex Pore-Fracture System of Continental Shale Reservoir
Authors: Li Haoyu , Wang Wendong , Su Yuliang , Deng Yuxuan , Li Dongxia , Li Lei , Hao Yongmao 
Published: August 2024

ABSTRACT:
Continental shale reservoirs display distinct features, including elevated organic-rich clay content, intricate migration mechanisms, and multiscale porosity. Traditional reservoir flow and transport theories are unsuitable for the porous structure of shale oil reservoirs. This study employs a dual-medium model to depict both organic and inorganic porosity within shale reservoirs. Furthermore, an embedded discrete fracture model characterizes hydraulic fractures, establishing a multi-medium model encompassing organic porosity, inorganic porosity, and fractures. Additionally, this investigation comprehensively addresses the micro-scale flow mechanisms of shale oil, precisely delineating the multiphase flow characteristics in the multiscale media of continental shale. This methodology significantly improves the accuracy of numerical simulations for continental shale oil reservoirs. The exploration of different flow mechanisms' impact on shale oil production reveals a consistent decline in cumulative oil production as the stress sensitivity coefficient increases. The analysis of shale oil reservoir production variation, considering adsorption, indicates that organic matter adsorption contributes approximately 10% to the total shale oil production.

1. INTRODUCTION
The progress in horizontal well drilling and hydraulic fracturing technology (Bowker et al., 2007) has positioned the development of shale oil reservoirs as a prospective solution to meet the growing global energy demand (Sun et al., 2021). This has, in turn, prompted the exploration and exploitation of shale oil in several nations. Advances in shale oil extraction have spurred the exploration and development of shale oil in multiple nations (Liu et al., 2022). In China, the potentially recoverable resources of low-maturity shale oil in continental shale are estimated to range from 700 to 900 million tons (Zhao et al., 2020), underscoring the considerable potential of shale oil resources. Therefore, the efficient extraction of shale oil is of paramount importance for national energy independence and security.
Continental shale oil reservoirs in China exhibit characteristics such as low porosity, low permeability, heterogeneity, and multiscale porosity media (Xu et al., 2022). The structural composition of shale includes organic matter, predominantly kerogen, along with minorganic minerals like quartz, clay minerals, and natural fractures (Liu et al., 2022). Under the action of hydraulic fracturing, a multi-scale pore-fracture network is formed in shale oil reservoirs (Deng et al., 2023). Nevertheless, current numerical simulation tools struggle to precisely depict the migration mechanism of shale oil within multi-scale media and calculate flow transitions between different media (Wang et al., 2023). This limitation has implications for the accuracy of flow simulations in shale oil reservoirs and the precise prediction of production outcomes.
Study on Fracture Propagation Law of Cement Sheath Interface During Fracturing Process
Authors: Lai Chenxi , Feng Yongcun , Su Feiyu , Gu Chenwang , Li Xiaorong 
Published: August 2024

ABSTRACT:
In the process of fracturing construction, the injection of high-pressure fluid will lead to the propagation of fractures at the first and second interfaces of the wellbore cement sheath, which seriously affects the integrity of the wellbore, and even cause the interlayer channeling of the fracturing fluid. In this paper, a three-dimensional finite element model of fracture propagation at cement sheath interface is established based on the Cohesive Element Method. The numerical model can quantitatively analyze the influencing factors of fracture propagation at cement sheath interface, including mechanical properties of cement sheath, horizontal in-situ stress difference, initial fracture shape, injection pressure and time of fracturing fluid. The results show that the wellbore integrity can be maintained and the interface cementation strength can be improved by optimizing the appropriate cement slurry system and the elastic modulus of cement sheath. Before fracturing, the selection of perforation location needs to fully consider the heterogeneity of the formation. Selecting the formation with relatively low horizontal in-situ stress difference will effectively slow down the fracture propagation at the cement sheath interface. When the injection pressure of the fracturing fluid exceeds the propagation pressure of the interface fracture, it will lead to the interlayer channeling of the fracturing fluid, and even fracturing failure. In summary, in order to improve the wellbore integrity in the fracturing production process, it is very important to optimize the appropriate cement slurry system and fracturing design scheme.

1. INTRODUCTION
Wellbore integrity is an important attribute of wellbore to resist structural damage and maintain wellbore function. It can ensure the safety of drilling engineering and is very important to the whole oil and gas production process (Tian et al., 2015; Song et al., 2016). The cement sheath is the core of wellbore integrity, providing interlayer isolation and support for the casing to ensure its integrity throughout the life of the wellbore (Gray et al., 2009; Feng, 2016).
At present, hydraulic fracturing technology is a major means of increasing production in the oil field. This technology is to inject the fracturing fluid (mainly water, sand or other proppants suspended with the help of thickeners) into the wellbore through a high-pressure pump to form artificial fractures in the deep strata, so that oil and gas can flow more freely in the reservoir. When the fluid pressure is removed from the well, the small particle hydraulic fracturing proppant (sand or alumina) maintains the fracture in an open state to increase the reservoir permeability (Xu et al., 2019; Biao, 2011). In the process of fracturing construction, the injection of high-pressure fluid will lead to the propagation of fractures at the first and second interfaces of the wellbore cement sheath, which seriously affects the integrity of the wellbore.
Quantitative Assessment of Anisotropic Elastic Properties of Rock Using Disk Specimens
Authors: Kim D. Y. , Kim S. S. , Seo S. M. , Diaz M. B. , Kim K. Y. , Kim H. , Park E. S. 
Published: August 2024

ABSTRACT:
Rocks exhibit anisotropy in various properties, including ultrasonic waves and diametrical deformation in the radial direction. While previous studies have attempted to analyze rock failure and anisotropy using several cores, the aim of this research is to evaluate the properties and anisotropic characteristics of rock materials through non-destructive experimental analysis of a single core. This analysis focuses on three physical properties: diametrical change, P-wave velocity, and compressive elastic modulus. The specimens were shaped into disks, with a diameter of 50 mm and thickness ranging from 26 to 29 mm. They were subjected to mechanical loading, ultrasonic waves, and diameter measurements in rotating radial directions to quantify anisotropic traits. These experiments revealed significant variations in diameter change, elastic modulus, and P-wave velocity across different orientations, indicating a substantial degree of anisotropy in the rock specimens. Consequently, this research performed non-destructive analysis of rock cores, characterizing physical properties, and analyzing anisotropy, confirming that the diameter and P-wave velocity maintain nearly perpendicular angles. Additionally, X-ray CT analysis has shown that rocks with lower homogeneity exhibit more pronounced anisotropy.

1. INTRODUCTION
Rock anisotropy is primarily influenced by structural features such as cleavage, foliation, bedding planes, schistosity, along with various joints and fissures ranging from micro to macro in size, and is also determined by two main mechanisms when subjected to structural loads: the alignment of minerals and particles, and the arrangement of pores and microcracks, which vary based on the rock's composition (Phillips and Phillips, 1980). Rocks possess hydraulic, mechanical, thermal, dynamic, and physical properties, and these anisotropy of structural properties causes these characteristics to vary depending on the direction (Johnston and Christensen, 1995; Amadei, 1996). Understanding the importance of rock anisotropy is essential, as it directly influences different applications such as seismic wave propagation in oil and gas exploration, fault stress distribution, which is critical to earthquake preparedness, impacts the structural integrity of dams, dictates the containment of radioactive materials, affects heat extraction rates in geothermal operations, and guides excavation strategies in tunnel construction.
Key Design Parameters for Enhanced Geothermal System (EGS)
Authors: Dehdouh Abdesselem , Mellal Ilyas , Bettir Nassima , Abdelhamid Cilia , Allam Lotfi , Rasouli Vamegh , Gyimah Emmanuel 
Published: August 2024

ABSTRACT:
Enhanced Geothermal Systems (EGS) offer significant potential for clean energy extraction from hot rock formations. However, maintaining high flow circulation, maximizing heat extraction, and minimizing thermal losses remain major challenges. This study presents a modeling investigation of key physical processes and design considerations for a multistage hydraulically stimulated EGS, utilizing a fully integrated reservoir model. We analyzed the influence of the key fracturing design parameters (injection rates, cluster spacing, well spacing, and fracture conductivity) alongside formation temperature. The findings demonstrate that multistage stimulation within a single cluster enhances well flow performance, delays thermal breakthrough, and enables higher circulating flow rates. Sensitivity analyses reveal a substantial impact of each parameter on EGS performance. Additionally, net present value (NPV) calculations are incorporated to evaluate the economic feasibility of each scenario. This comprehensive study offers valuable insights for appraising and selecting EGS candidates, paving the way for advancements in sustainable and efficient geothermal energy production.

1. INTRODUCTION
The increasing demand for clean and sustainable energy has intensified the search for alternative sources. Among these, geothermal energy stands out, harnessing the Earth's internal heat to generate electricity and provide direct heat with very low greenhouse gas emissions (Lu, 2018). Around 11000 MWe of electricity is being produced worldwide from geothermal sources, and the DOE goal is to reach 90.000 MWe by 2050 (Huttrer, 2021). High temperatures of more than 120 C and high flow rates are required for an economic project (Blackwell. D et al., 2011). Conventional geothermal sources are limited, often concentrated in regions with naturally fractured and permeable rock formations to maintain high flow rates (Gyimah et al., 2023). This is where Enhanced Geothermal Systems (EGS) emerge as a game-changer, unlocking the vast potential of hot, impermeable rock formations that were previously inaccessible(Okoroafor et al., 2022).
EGS technology creates an artificial flow path by stimulating the underlying rock through hydraulic fracturing (Gyimah. E et al., 2024). Multiple producer and injector wells were drilled with close spacing to circulate the continuously injected fluid. The injected fluid gets its thermal energy from the formation and then produced to the surface (Huenges, 2016). This enhances permeability, allowing fluid circulation and heat extraction. While still in its developmental stages, EGS holds immense promise for significantly expanding geothermal energy's reach and potential (Merzoug, Okoroafor, et al., 2023).
Experimental and Numerical Investigation on the Fracture Characteristics of Different PDC Cutters Penetrating Limestone
Authors: Fu Xinkang , Huang Zhongwei , Zhang Zhuangzhuang , Ji Guodong , Zhang Jiawei 
Published: August 2024

ABSTRACT:
Carbonate rocks are an important oil and gas reservoir rock. Conical PDC (Polycrystalline Diamond Compact) cutter, as a special shaped PDC cutter, can significantly improve the rate of penetration (ROP) in hard formations. However, the breakage characteristics and failure mode of the conical PDC cutter penetrating carbonate rock is unclear. A series of single cutter penetration tests were carried out with the conical and conventional PDC cutters. The surface morphology of broken pit and specific energy were analyzed. The conical cutter caused brittle damage on the rock around the broken pit at the rake angle of 10 and 20 degrees. The results of the numerical model based on the cohesive element method show that the conical cutter produce the significant tensile damage on the rock at the rake angle of 10 and 20 degrees. The tensile capacity of the conical cutter is stronger than that of the conventional cutter. The research findings of this work offer insights into the breakage process and failure mode of carbonate rock by the conical cutter.

1. INTRODUCTION
Carbonate rocks are an considerably important oil and gas reservoir rock (Wenzhi et al., 2014). The carbonate rocks store 70% of the oil and gas resources. Nearly 50% of proven recoverable oil and gas resources are stored in deep and ultra-deep carbonate formations worldwide (Al-Shargabi et al., 2022). Therefore, carbonate oil and gas resources have great exploration and development potential.
The carbonate formations in China are concentrated at depths ranging from 5000 to 7000 meters (Ma et al., 2017). These formations consist of challenging rocks that are hard, and poorly drillable, resulting in a low rate of penetration (ROP) (Zeng et al., 2023).
PDC bits dominate the global drilling market (Rostamsowlat et al., 2022). In recent years, a large number of special-shaped cutter, including conical cutter, have flooded into the drilling market (Izbinski et al., 2019). In 2010, Novatek Company invented conical PDC cutter (Durrand et al., 2010).