bluuebunny/crossref_metadata_2025_split huggingface dataset:
Creep and Lateral Stress Behavior of Gulf of Guinea Miocene Mudrock Specimens
Authors: Bhandari A. R. , Flemings P. B. , Ewy R. T. , Germaine J. T. 
Published: September 2023

ABSTRACT
We measured axial creep and lateral stress behavior in drained uniaxial strain experiments on intact and resedimented Gulf of Guinea Miocene kaolinite-rich mudrock specimens. At axial effective stress of ∼10 MPa (close to the in situ vertical effective stress of 7.9 MPa), the uniaxial lateral stress ratio (K0) is 0.75 for the resedimented material and 0.62 for the intact material. The intact material behaves over-consolidated because its in situ state (7.9 MPa) is less than the yield stress (∼20 MPa). The compressibility of the resedimented specimen is an order of magnitude higher than that of the intact specimen. The in situ void ratio is ∼0.15 void ratio units less than the void ratio of the resedimented specimen at the in situ vertical effective stress; this suggests that creep deformation has occurred over geological time. In addition, the creep rate of the resedimented material is an order of magnitude higher than the intact material. Overall, this paper illuminates the role of creep in the compression process.

INTRODUCTION
Intact specimens of in-situ clay deposits are usually impacted by sample disturbance (Lunne et al., 2006), especially for deep or offshore samples. The resedimentation technique has been used to prepare uniform test specimens that do not have sampling disturbance, and thereby study sediments for over half a century. It allows for control over stress history and produces specimens of desired porosity with complete saturation. It is commonly assumed that the laboratory resedimented material closely reproduces the mechanical behavior of intact specimens (Casey et al., 2016; Casey et al., 2019). However, recent studies have found that the resedimented specimens are usually less dense than the intact specimen at the in-situ vertical stress level (Finnegan, 2020), and the intact material (with no apparent geological unloading) shows measured yield stress markedly greater than the maximum past stress (Ewy et al., 2020; Finnegan, 2020). Such behaviors suggest that creep may have played a role in-situ. We systematically study intact and resedimented specimens to explore their behavior and understand mudrocks’ in-situ properties.
Using Low-Field Nuclear Magnetic Resonance and X-Ray Computed Microtomography Imaging to Explore Potential of Microbially-Induced Calcium Carbonate Precipitation Treatment to Seal Shale Fractures
Authors: Willett M. R. , Seymour J. D. , Bedey K. , Kirkland C. M. , Phillips A. J. , Cunningham A. B. , Dobeck L. , Crandall D. , Rutqvist J. 
Published: September 2023

ABSTRACT
Microbially-induced calcium carbonate precipitation (MICP) is a biological process in which microbially produced urease enzymes convert urea and calcium into solid calcium carbonate (CaCO3) deposits. Studies have shown that MICP can be used to seal fractures in shale, raising the possibility of applying this technology to restimulate fracking wells by plugging underperforming fractures. For this and other applications to become a reality, non-invasive tools are needed to determine how effectively MICP seals shale fractures under subsurface conditions. In this study, a 2.54 cm wide and 5.08 cm long Marcellus shale core with a single, ∼1 mm wide fracture held open by sand "proppant" underwent MICP-treatment at 60°C until reaching three orders of magnitude permeability reduction. Low-field nuclear magnetic resonance (LF-NMR) and X-Ray computed microtomography (μ-CT) techniques were used to assess the extent of biomineralization within the fracture. These tools revealed that while CaCO3 precipitation occurred throughout the fracture, there was preferential precipitation around proppant, and the core sealed at the effluent end before filling most of the fracture. Both tools were able to independently calculate of the amount of solid biomineral formed inside the fracture. This study found that the distribution of proppant within the shale fracture was an important parameter controlling the degree of biomineralization.

INTRODUCTION

Background
Shale is a fine-grained, sedimentary rock often found adjacent to layers of sandstone and limestone up to thousands of feet below ground surface (bgs). The unique characteristics of this formation have led it to play multiple roles in the ever-changing energy landscape of the 21st century. Possessing relatively high porosity but extremely low permeability, shale has been targeted for geologic carbon sequestration and nuclear waste disposal (Washburn, 2014). Many shale deposits also contain rich quantities of hydrocarbon fuels, which can be extracted from very tight pore spaces with hydraulic fracturing, also known as fracking. All of these applications highlight a need for methods to control permeability to ensure the long-term safety and utility of these reservoirs. For example, there may be a need for a method to plug fractures that arise in shale used for storage purposes to mitigate leakage. There is also motivation to seal fractures created in fracking wells to prevent contamination of aquifers by fracking fluids or potentially restimulate the well to enhance natural gas recovery (i.e. "frack/re-frack").
Quantifying the Variability in Interpretation of Shear Testing of a Natural Fracture
Authors: Franco M. A. , Potter J. , Ross B. J. 
Published: September 2023

ABSTRACT
The shear strength of discontinuities (e.g., joints, bedding planes, faults) plays an important role in the mechanical behavior of a rock mass and is crucial to the analysis and design of rock slopes. The shear strength of natural discontinuities is typically determined by performing a series of direct shear tests. Several sources of variability in direct shear test results are recognized by the geotechnical community (e.g., the inherent variability of shear strength in a rock mass, joint roughness), but the effect of variations in testing equipment, testing methods, and in the interpretation and application of test results has been little studied. The focus of this paper is the potential variance introduced by the interpretation of direct shear test results. The authors explore potential variation in a single direct shear test by examining test results from a natural joint with four different approaches. Potential future research paths are also discussed.

BACKGROUND
The direct shear test (DST) is widely used to determine the shear strength of natural discontinuities in rock and soil. This determination is of particular importance when designing rock-based engineering structures and assessing failures. Direct shear tests are performed using a shear box apparatus that maintains a constant force normal to the discontinuity while applying an increasing shear force parallel to the discontinuity (ASTM, 2016). The information recorded includes the applied normal force, displacement of the top of the specimen in relation to the bottom, the shear force applied to achieve that displacement, and fracture roughness. The test is generally performed three to four times with increasing applied normal loads, resulting in a set of traces corresponding to the applied normal forces. Figure 1 illustrates an idealized trace resulting from a direct shear test. Recorded forces are then converted to stresses by dividing by the surface contact area measured at the time of the test.
Two parameters are calculated based on the trace data described above (ASTM, 2016):
• Peak shear strength is associated with the maximum shear stress value along a sheared surface attained during a test.
• Residual shear strength is associated with the point at which the shear stress remains essentially constant with increasing shear displacement.
Similarity Solutions for Shallow Hydraulic Fracture in Impermeable Rock
Authors: Wang Z. Q. , Detournay E. 
Published: September 2023

ABSTRACT
The paper deals with the plane strain problem ofa shallow fluid-driven fracture propagating parallel to a free surface in an impermeable elastic rock. For a shallow fracture, the aperture corresponds essentially to the deflection of the layer defined by the free-surface and the crack. This problem is thus governed by the Euler-Bernoulli beam equation and by the lubrication theory. We show that the solution generally depends on two independent time scales and that there exist 4 similarity solutions denoted as (Equation), (Equation), (Equation) and (Equation). Furthermore, we demonstrate that the parametric space of solution is a rectangle with the vertices corresponding to the similarity solutions. The (Equation) and (Equation)-solutions are two different early time solutions characterized by a small length of the fluid-infiltrated region compared to the fracture length (i.e., the fluid lag occupies nearly the whole fracture), while the (Equation) and (Equation) solutions are two large-time solutions characterized by a vanishingly small lag. The (Equation) and the (Equation) vertices are similarity solutions for the particular case when Gc = 0, while (Equation) and (Equation) are similarity solutions for the case σo = 0. Thus the (Equation)-edge and the (Equation)-edge represent two particular fracture evolutions, the first one when Gc = 0 and the second one when σo = 0. However, the large time solution for the general case Gc &gt; 0 and σo &gt; 0 has not yet been identified, as the numerical solutions conflict with the large time matched asymptotic solution.

INTRODUCTION
Various instances of fluid-driven fracture near a free surface can be found in nature and in geo-engineering. They include excavation of hard rocks (Young, 1999), cave in-ducement in mining (Jeffrey et al., 2000), contaminant spill remediation (Murdoch, 2002), and the formation of sills by magma rising from deep underground chambers (Bunger and Cruden, 2011; Michaut, 2011).
Models of hydraulic fractures propagating near the surface of a homogeneous elastic semi-infinite domain can be formulated mathematically using elastic integral equations that relate the displacement discontinuity across the fracture to the net traction acting on the fracture faces, in combination with the nonlinear lubrication equation that governs the flow of viscous fluid inside the fracture (Zhang et al., 2002, 2005; Gordeliy and Detournay, 2011). The resulting system of integro-differential equations together with the boundary conditions at the injection point (typically a constant injection rate) and at the fracture tip (including the propagation criterion) is closed in regard to predicting the evolution of fracture geometry, fluid pressure, and aperture from given initial conditions.
Modeling Frac-Hits Using Reservoir Geomechanics and Phase Field Finite Element
Authors: Almetwally A. G. , Wheeler M. 
Published: September 2023

ABSTRACT
Frac-hits can have a significant negative impact on hydrocarbon production by reducing mobility efficiency and modifying pressure profiles around wells, particularly with increased infill drilling. However, the relationship between operational fracturing parameters and frac-hit events is still not well defined. To address this issue, this study presents an integrated simulation model that combines reservoir geomechanics and phase field finite element methods to simulate frac-hits events. This model considers reservoir and fracturing parameters for multiple horizontal wells in a drilling spacing unit. It was cross-validated with Molina's (2019) analytical model and Morales’ (2020) mechanical testing apparatus, enabling the evaluation of hydraulic and mechanical interactions, such as pressure communication, fracture merging while propagation, and stress shadowing (Molina, 2019; Morales, 2020). This approach provides valuable insights into optimal well and fracture placement, fracture behavior in relation to pre-existing fractures, and the impact of operational parameters on frac-hits. Ultimately, this research represents an effective tool for improving fracture designs and mitigating frac-hits, thereby enhancing field performance.

INTRODUCTION
Infill well development has become a widely used strategy for hydrocarbon production in unconventional reservoirs, with an increasing number of "infill" wells being drilled offset to one or more existing producers. However, the proximity of these new wells ("child" wells) to existing producers ("parent" wells) often leads to negative impacts on production due to "fracture driven interactions" (FDI's) or "frac-hits" (Daneshy et al., 2019; King, 2012). The severity of the impact depends on factors such as well spacing and the age of the parent well (Gupta et al., 2020; Lindsay et al., 2018; McDowell et al., 2019), and impacts are highly variable between different shale plays (Esquivel et al., 2017; Gupta et al., 2020; Miller et al., 2016). Various techniques have been applied to mitigate impacts from parent/child well interaction, such as preloading the parent well by injecting into it prior to the offset frac, varying well spacing, varying fracture sequencing, cube (or tank) development, chemical treatments, refracturing, and far-field diverter (Bommer et al., 2018; Haustveit et al., 2020; McDowell et al., 2019; Miller et al., 2016; Nieto et al., 2018; Patel et al., 2016; Sani et al., 2015; Swanson et al., 2018; Vidma et al., 2018; Whitfield et al., 2018; Zhang et al., 2019). Although these strategies have been successful, there is no universal solution, as each technique comes with different costs and benefits.
Investigations on Cement Thermal Properties with Direct Application to Underground Energy Storage
Authors: Abid Khizar , Velazco Alberto Toledo , Teodoriu Catalin , Amani Mahmood 
Published: September 2023

ABSTRACT
The current energy storage wave that looks at low temperature and heat storage in shallow reservoirs as well as the intensification of Hydrogen storage (especially as by product to methane) have reopened the quest for accurate and precise well temperature prediction and modeling. This prediction plays a critical role in the determination of wellbore storage capabilities, well integrity and overall energy storage efficiency. This paper shows experimental results on measuring thermal properties of various cement properties as well as selected rock which are used as comparison. Our data will show that small amount of additive products in cement may dramatically change cement thermal properties that could become important for the overall well heat transfer and thus will enhance the energy storage efficiency.

INTRODUCTION
With the focus of the world going toward the net zero goal with respect to carbon emission, the storage of hydrogen in the subsurface will play an important role to achieve that target. It is reported by Tarowskia and Uliasz-Misiak, (2022) that due to the ease of hydrogen availability around the world and increasing global acceptance, hydrogen has the potential to replace fossil fuel by 2050. At the moment the main source of hydrogen storage at the surface consists of the cryogenic and high-pressure tank. However, with further expansion of hydrogen gas as a source of renewable energy the storage capacity has to be increased. In this respect, underground hydrogen storage (UHS) gives an alternate solution in which hydrogen is injected into a suitable geological formation such as a depleted oil and gas reservoir, aquafer, and salt cavern, and can be reproduced when needed (Sambo, et al., 2022). As the only connection to the UHS is the well so it is of utmost importance that the integrity of the well is maintained. Hence, well cement plays an important role in the well integrity as it provides zonal isolation, give support to the casing, and seals of the problem some subsurface formation (Rincon, et al., 2022). Like any other subsurface gas storage, well cement will be exposed to different temperature cycles due to the process of injection and reproduction that can lead to thermal loading and degradation of the cement matrix. Therefore, it is necessary to know the thermal properties of the cement placed in the UHS so that the integrity of the well can be assured.
Characterization of a Tight Gas Reservoir Using the Integration of Electrofacies and Fracture Aperture, Ahnet, Algeria
Authors: Irofti Doina , Ifrene Ghoulem E. H. , Aihar Aimene , Bouabdallah Nassim , Khouissat Abdelhakim , Djemai Safouane 
Published: September 2023

ABSTRACT
The integration of this heterogeneity analysis with the interpreted fractures of the four wells in the area shows that the lithology has a major influence on the number and type of fractures. The well logs that are most impacted by composition were used to perform cluster analysis in four wells. Cluster analysis generates more representative scaled input parameters for reservoir characterization, which may be compared to the fractures obtained from borehole imaging result. On the basis of their measurable features, these approaches group like things and identify them from dissimilar objects. Because the procedure is neither driven by an external model or specified by a reference training set of previously known items, this clustering is known as unsupervised classification. We employed cluster analysis to classify rocks based on their core compositional characteristics. We utilized well logs that were impacted by composition in this investigation (NPOR, RHOB, GR and PEF). The cluster analysis was carried out using the Techlog software module Heterogeneous Rock Analysis (HRA).

INTRODUCTION
Serra & Abbott, 1980 coined the word "electro facies," which they define as "the set of log responses that distinguishes a bed and allows it to be recognized from others" (Kumar et al.,2006). Because log responses are measures of the physical qualities of rocks, electro facies may typically be ascribed to one or more lithofacies. Petroleum prospecting and reservoir characterization require the identification of facies. Facies were previously determined manually using graphical approaches such as cross-plotting from wire-line recordings and linking their behavior to cores. Several mathematical methods have recently been devised to automate the job of identifying facies.
The quality of the distribution of petrophysical characteristics is driven by reservoir rock type, which is critical for reservoir characterization (Cherana et al., 2022; Doghmane et al., 2022). It improves knowledge of fluid flow, rock storage capacity, and pore size distribution. Many different criteria may be used to classify rock types. Rock typing divides reservoir rocks into discrete units that were formed under comparable geological settings and have undergone similar diagenetic changes (Guo et al., 2005). Fracture aperture characteristics in a reservoir rock are the crucial parameters that control the quality of tight reservoir rock (Mahmood & Guo, 2019) and need to be considered in reservoir rock typing. This research combines rock classification with knowledge of fracture parameters such as aperture.
Thermal Effect on Long-Term Shale Behavior in Nuclear Waste Storage
Authors: Makhnenko R. Y. , Kim H. , Kim K. 
Published: September 2023

ABSTRACT
Shale-like formations can serve as barriers for geologic disposal of high-level nuclear waste. Adopting these tight materials has an advantage that any radionuclides emitted from the canisters would stay with hardly mobile pore water within the rock. However, there are a few issues associated with the sealing capacity of shales as high temperatures experienced in nuclear waste disposal can strongly affect their geomechanical and flow properties. In this study, we investigate how the continuous heating and hydromechanical loading are affecting the flow properties of a shale with the clay content above 50% and the dominant pore size on the order of tens of nanometers. Both intact and fractured specimens are considered, and parameters associated with a coupled hydromechanical model are measured in high-pressure laboratory experiments, including the time-dependent deformation introduced to the model through bulk viscosity. It appears that even a small increase in temperature from 24°C to 40°C significantly impacts long-term (viscoelastic) response of shale, while the effect on the short-term (poroelastic) behavior is less pronounced. At the same time, the thermal effect on the fluid flow is ambiguous: the permeability increases with temperature but is predicted to eventually decrease due to the accelerated rock compaction at elevated temperatures.

INTRODUCTION
Argillite geological formations have been considered worldwide as potential host rocks for geological disposal of high-level radioactive waste (HLW) because of their low permeability, high retention capacity for radionuclides, and capability to self-seal fractures (Sassani et al., 2021). Other favorable characteristics of argillites (often times represented by shales) are the strong sorptive behavior for many radionuclides reducing conditions because of the lack of oxygen transport from the surface, and chemical buffering of the effects caused by materials introduced during repository construction and operation (Tournassat et al., 2015; Urpi et al., 2019). One unfavorable feature of argillites compared to other potential host rock types is a relatively low thermal conductivity that would lead to higher host rock temperatures (potentially above 100 °C). This means that it will be crucial to gain reliable data for being able to confidently predict long-term, high-temperature responses of shaly host rock. This is exacerbated by the recent interest of disposal in large-sized canister of high decay heat that may lead to higher host rock temperature (Rutqvist, 2020). Moreover, with almost a hundred nuclear power plants across the US waiting for the permanent storage solutions, it is necessary to establish a procedure for obtaining properties of a wider range of typical argillites, from the more ductile materials with high clay content to more brittle rock that could respond vastly different when exposed to high temperature.