bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study on Fracturing and Proppant Setting in Unconsolidated Sand Formation
Authors: Zhang R. , Ito T. , Tenma N. 
Published: September 2022

ABSTRACT:
In the development of methane hydrates, the improvement to produce gas at commercial requirements is a current challenge. Hydraulic fracturing technology is a feasible way to increase permeability by forming artificial fractures. During the fracturing process, proppants are usually injected into induced fractures. These proppants keep the fractures open, thereby maintaining fractures permeability. However, the MH formation is unconsolidated and soft, unlike rock formation for which proppants are suitable. Currently, the understanding on the effectiveness of proppant is absent. In this study, we evaluated the effect of proppant and experimentally reproduced the process of hydraulic fracturing to create fractures and inject proppant . The experimental results of proppant stability evaluation showed that in the unconsolidated sand layer, proppant can play a certain role in maintaining the fracture opening, and it is difficult for the sand to invade the proppant layer. The proppant injection experiment showed that increasing the flow rate allowed the proppant to be injected more smoothly.

1. INTRODUCTION
As a potential unconventional natural gas resource, methane hydrate has received a lot of attention. Currently, producing natural gas from methane hydrate is technically possible. Japan has conducted two offshore production trials in 2013 and 2017. In the second production trial, the two production wells produced at average rates of 3400 m3/day and 9200 m3/day, respectively (Yamamoto, 2019), below the minimum commercialization requirement of 50,000 m3/day estimated by MH21 (The Research Consortium for Methane Hydrate Resources in Japan).
To produce methane gas from the methane hydrate (MH) reservoir, it is necessary to dissociate MH into methane gas and water. The depressurization method is an effective way for MH dissociation. This method will increase the pressure difference between the wellbore and the formation, resulting in consolidation of formation. Then, the permeability of these areas will decrease, which is not favorable for efficient methane gas production. Hydraulic fracturing is a feasible way to increase permeability by forming artificial fractures. The fracture extending from the production well to the surrounding ensures a flow path through the low permeability section. This significantly increases the drainage area, thereby increasing productivity. Fracturing usually was used in the hard and consolidated rock formations. MH-bearing formations are soft and unconsolidated sand and the properties of the formation are completely different from those of hard and consolidated rock. Therefore, the feasibility of fracturing in MH formation still needs further research.
Effects of Anisotropic Poroelasticity on Stress and Pore Pressure Changes Around Subsurface Reservoirs and Storage Sites
Authors: Holt R. M. , Bakk A. , Duda M.I. , Yan H. 
Published: September 2022

ABSTRACT:
Stresses and pore pressures change around depleting hydrocarbon reservoirs or fluid injection sites as result of reservoir pore pressure change. Such changes influence the stability of new wells drilled and may lead to fault activation, resulting in induced seismicity and possibly to casing damage in existing wells. Forecasting requires reliable geomechanical modeling of the reservoir and its surroundings. Classical analytical solutions are too simple, so numerical models are required. The rocks surrounding reservoirs are often anisotropic (like overburden shale), but their anisotropic elasticity is normally neglected, either because of model limitations, or in lack of input data. Here, however, the impact of anisotropy along with the elastic contrast between undrained surroundings and drained (isotropic) reservoir rock is addressed through a series of numerical scenarios. It is shown that isotropic models are unable to reproduce the stress changes predicted by the anisotropic models. Pore pressure changes may be underestimated by neglecting the anisotropic nature of the poroelastic Skempton parameters.

1. INTRODUCTION
Stress evolution around hydrocarbon reservoirs caused by depletion and around storage sites caused by injection of, e.g., wastewater or CO2, can be handled by analytical methods, such as the classical theory of Geertsma (1973). Although more sophisticated analytical, as well as numerical geomechanical models exist, the role of anisotropy in such computations has not been addressed in a systematic manner in the literature. We use a finite element method (FEM) to simulate stress changes in anisotropic surroundings (shales) around an isotropic reservoir. Because of its low permeability as a cap rock, the shale response will remain undrained within reservoir lifetime, unless leakage occurs through faults or other permeable conduits. Such pore-pressure changes are often ignored; however, they may have a crucial impact on drilling efficiency and borehole stability during infill drilling. In the reservoir rock, pore pressure will change in accord with fluid flow out of or into the reservoir, and the rock behavior will be described by drained moduli.
Research on the Influence of Hydration on the Evolution Law of Shale Pore Structure
Authors: Yang C. , Jia K. K. , Zhang X. R. , Wang L. L. 
Published: September 2022

ABSTRACT:
In this paper, shale is used as the research rock sample and sandstone is used as the control rock sample. Different types of supersaturated solutions are used to form a special humidity environment to complete the control of the water saturation of the rock samples. The T2 distribution curves of the two rock samples under different relative humidity were obtained by nuclear magnetic resonance (NMR) technology. Comparing the T2 distribution curves of different relative humidity, it is found that the pores of shale are dominated by small pores, while the pores of sandstone are dominated by large pores. The quality analysis of water-saturated samples shows that the porosity of sandstone is about 12%, and the porosity of shale is about 4%. The relationship between relative humidity and water saturation is plotted, and it is found that the adsorption capacity of shale to water is much stronger than that of sandstone. By drawing the capillary force curve of the sample and fitting the Van-Genuchten (VG) model, the VG model parameters of the sample are obtained, the m of sandstone is 0.28, the α of sandstone is 34.5, and the m of shale is 0.38, the α of shale is 0.12. The above research on the evolution law of shale pore structure is of great significance to the further study of the law of its physical parameters.

1. INTRODUCTION
Since 2000, the United States took the lead in launching the shale gas revolution due to major breakthroughs in horizontal drilling, hydraulic fracturing and other extraction technologies (Ciardo and Lecampion, 2021). According to prediction (Zhang et al., 2008), the global shale gas resource is 456 × 1012 m3, which is equivalent to the sum of the conventional natural gas, coalbed methane and tight gas in the world (471 × 1012 m3). Therefore, the commercial exploitation of shale gas is considered to be the most exciting and major achievement in the field of petroleum engineering in the past 100 years, which will change the global energy pattern greatly (Mi et al., 2010). In the Shale Gas Development Plan (2016-2020), the National Energy Administration of China pointed out that during the "Thirteenth Five-Year Plan" period, the production of shale gas will be 30 billion cubic meters by 2020, and the annual production volume will be 80-100 billion cubic meters by 2030. It can be seen that the development of shale gas exploitation also plays an important role in our country’s energy development.
The First Pressuremeter Testing Campaign on Wireline Formation Testers in Deep Boreholes
Authors: Elkhoury Jean E. , Elias Quincy K. , Prioul Romain , Peyret Emilie , Wilcox Ailsa , di Giovanni Mauro , van der Hulst Tim , Bérard Thomas , Desroches Jean , Garrard Rodney , Giger Silvio B. 
Published: September 2022

ABSTRACT:
Pressuremeter testing (PMT) is a formation test that consists of inflating a packer downhole, while measuring packer pressure exerted on the borehole wall as a function of injected fluid volume. Provided the stiffness of the packer is known and large enough compared to that of the formation, changes in packer pressure associated with changes in injected fluid volume provide a direct measurement of formation stiffness and, along with the relevant length-scales, produces an in situ static formation shear modulus, a very important parameter for Mechanical Earth Model calibration. Here, we report on the first field-scale campaign of PMTs in deep boreholes performed using a wireline formation tester (WFT) tool. These PMT measurements were carried out alongside a stress measurement campaign, to fully characterize potential sites for a deep geological repository for radioactive waste in Switzerland. The initial field trials highlighted challenges in calibrating packer stiffness, key in inferring formation stiffness. We overcame the challenges in packer characterization by adopting a true single packer configuration and by performing reference PMT measurements in casing and formations of known stiffness. Then, we performed PMT inflation and deflation cycles to infer in situ static shear moduli at every station tested. PMT-derived static shear moduli results are consistent with static shear moduli derived from sonic logs using independent dynamic-to-static elastic moduli transformations. The precision of the in situ PMT static shear moduli increases as the stiffness of the measuring system, WFT, increases with respect to formation stiffness. These first results show the viability of in situ PMT in deep boreholes with a wireline formation tester tool as it can be performed at multiple depths in a single run, in a time-efficient manner, and in combination with micro-hydraulic and sleeve fracturing stress tests for an integral approach to in situ geomechanical assessment.
Sensitivity Analysis of the Dry Density Distribution of a Bentonite Buffer in a Deep Geological Repository for Spent Nuclear Fuel
Authors: Gharbieh H. , Pulkkanen V.-M. , Navarro V. , Asensio L. 
Published: September 2022

ABSTRACT:
Bentonite buffers consisting of compacted blocks and pellet fills with different installation densities are used as engineered barriers in the KBS-3 deep geological final disposal concept for spent nuclear fuel. In this work, a sensitivity analysis was performed to identify the most influential parameters for the density homogenization of the bentonite buffer. In total, 16 input parameters related to 1) the THM models developed for compacted blocks and pellet fills, 2) the buffer design and 3) the thermal and hydraulic boundary conditions were studied. The output variable was the heterogeneity degree that was defined to quantify the remaining density differences in the buffer. For the analysis, 34 numerical full-scale simulations were performed with varying input parameter value combinations prescribed by a definitive screening design (DSD), which allows for the statistically reliable estimation of the effects of the different parameters. The results indicate that three parameters are most relevant for the homogenization in the buffer: the elastic stiffness of the inter-pellet pores related to the triple porosity model developed for pellet fills, the width of the outer pellet-filled gap and the microstructural swelling capacity of the bentonite. On this basis, recommendations for control of the homogenization in the buffer are given.

1. INTRODUCTION
In the KBS-3 final disposal concept, planned for example in Finland, a bentonite buffer is emplaced between a spent nuclear fuel containing canister and the crystalline host rock in a deep geological disposal facility. The installation gaps surrounding the highly compacted bentonite blocks are filled with pellets and the block densities vary by location, which leads to an uneven dry density distribution of the buffer at initial state. The wetting of the installed buffer induces swelling, which in turn leads to a complicated mechanical evolution of the buffer. After the wetting phase, a desired feature of the buffer is a sufficiently even dry density distribution, which is important for evaluating the fulfillment of the safety functions assigned to it, such as limiting the advective mass transport and protecting the canister from detrimental mechanical loads (Posiva & SKB, 2017).
Insights into Triaxial Testing Using Coupled Acoustic Emission and Distributed Optical Fiber Strain Measurements
Authors: Salazar A. V. , Selvadurai P. A. , Niu Z. , Bianchi P. , Rabaiotti C. , Madonna C. , Wiemer S. , Germanovich L. N. 
Published: September 2022

ABSTRACT:
During the failure of geomaterials, quasi-static (aseismic) and dynamic (seismic) deformation have been observed in laboratory and field experiences. The measurement of both is required for in-depth understanding into the progressive failure of rocks, and to reduce the risk associated with induced seismicity. The study of acoustic emission (AE) in the laboratory is commonly used to study how localized events can coalesce into a larger dynamic fracture nucleation. How energy is partitioned into driving the seismicity versus larger aseismic dissipative processes is not fully understood but by simultaneous measurement of seismic and distributed quasi-static deformation, we can investigate these phenomena.
This paper presents the results of a triaxial test on a dry, intact Rotondo granite sample implemented with both optical fibers to measure the distributed strain and calibrated AE sensors to derive a physical representation of the seismic sources. We show that quasi-static deformation can be measured using distributed measurement methods that show evidence of strain localization. Fiber optics show complex spatial distribution in strain near failure due to shear fracture forming in the later stages. The spatial expression of seismicity and a post-test X-Ray computed tomography scan show two macro-fractures inside the sample, reconstructing their development. A qualitative temporal and spatial correlation was observed between the strain localization and the nucleating fractures through measurements of both the fiber optic strain and the seismicity. The seismic deformation accounted for 0.04 percent of the total anelastic deformation.

1 INTRODUCTION
Petroleum and geothermal energy projects inject fluid into the rock mass to enhance production. This large-scale injection operation perturbs the subsurface stress field, which induces the nucleation of seismic events (King Hubbert and Rubey, 1959; Deichmann and Giardini, 2009). This induced seismicity continuously raises public safety concerns, delaying or canceling projects specially geothermal ones (Majer et al., 2007; Ellsworth, 2013; Grigoli et al., 2018). Mitigating injection-related seismic hazards has become a major challenge for geoscientists and geothermal engineers. Solutions to this complex problem rely first on an in-depth understanding of the mechanical deformation during progressive failure of rocks. Scotti and Cornet (1994) and Cornet et al. (1998) gave field evidence that seismic and aseismic deformation is involved during large-scale fluid injection. Bernard (2001) acknowledged the necessity to develop crustal models that include both inertial and slow instabilities to assess seismic hazard. We extend his proposition to study the seismic and aseismic deformation at the laboratory scale.
Novel Environmentally Friendly Nano-Additives for Drilling Fluids
Authors: Yang J. , Kane A. , Didriksen T. , Thorshaug K. , Stenerud G. , Vågenes B. , Lund B. , Latham J.-P. , Xiang J. , Velmurugan N. , Gerbaud L. , Sellami H. 
Published: September 2022

ABSTRACT:
The potential for environmentally friendly nano-additives based drilling fluids is extended here in the context of the ongoing EU project ‘ORCHYD’ where a hybrid drilling technology is developed by combining High Pressure Water Jet (HPWJ) and Percussive Drilling to improve the efficiency of deep geothermal drilling. In this work, different types of nanomaterials such as graphene oxide, hybrid nano silica and their composite nanomaterials are used as additives in a water-based drilling fluid. The influence of additives on the rheological properties and the friction of the drilling fluid has been investigated. The laboratory results showed that an increase in the concentration of additives will increase the viscosity of fluids. A significant reduction in the coefficient of friction (during wear testing of steel material) was also revealed with the addition of GO and chemical functionalization. The need for further characterizing and the perspective to upscale the enhanced nano-additives based fluids for HPWJ and percussive drilling application, in deep geothermal conditions, are discussed.

1. INTRODUCTION
This study is performed in the context of the EU project ORCHYD, https://www.orchyd.eu/proiect/, where an innovative drilling tool combining (high pressure water jetting and percussive drilling) will be developed to increase hard rock drilling rates, in deep geothermal wells. The potential of new green additives to the drilling fluids is thus investigated to account for the best compromise for efficient jetting, cutting and transport of the rock particles, and the lifetime extension the drilling tools.
Deep geothermal reservoirs are being targeted for renewable energy supply worldwide (Huttrer, 2021), however the high pressures and high temperatures in deep geothermal wells impose significant challenges for desiring drilling fluids. Over the past decade, various additives such as polyacrylamide, organic modified clays, poly carboxylic acids, asphaltic compounds, treated lignite have been used in the drilling fluid to optimize the rheological properties, filtration control and reduce the fluid loss, shale inhibitors and thereby improving wellbore stability (Boyou et al., 2019; Vryzas et al. 2017). However, most of the polymer-based materials degraded thermally and chemically at relative low temperature, which lowers their effectiveness.
Measurements of Elastic Moduli and Stress Dependence of Geothermal Rocks
Authors: Kleich S. J. , Folsom M. , Sherman C. , Feigl K. L. , Hampton J. C. 
Published: September 2022

ABSTRACT:
In the WHOLESCALE project we aim to simulate the temporal evolution and spatial distribution of stress in and around the geothermal reservoir at San Emidio, Nevada, United States. To constrain stress modeling efforts, we perform laboratory measurements of static and dynamic elastic stiffnesses using oriented rock samples collected from outcrops located near the San Emidio geothermal field. In this paper, we seek to understand (1) the static and dynamic elastic properties of the rock formations, (2) the existence or absence of anisotropy or heterogeneity-controlled behavior at the millimeter to centimeter scales, (3) whether the elastic properties are stress dependent, and (4) whether there exists any stress induced anisotropy under reasonable net mean stress variations. To evaluate the existence of anisotropy or heterogeneity, we measure ultrasonic velocities, Vp and Vs, at 45-degree increments around the circumference of oriented cylindrical specimens for each rock type. Combining the three-dimensional velocity data with geological and textural descriptions, we address whether the materials are heterogeneity-controlled and/or anisotropic at the plug scale. Static and dynamic elastic moduli were also measured at the net mean stresses of interest for each of the rock types obtained. Dynamic stress dependence and whether the material contained stress induced anisotropy was evaluated via stepped hydrostatic ultrasonic velocity measurements.

1. INTRODUCTION
The geothermal field at San Emidio has provided more than two decades of data collection, with power first being produced in 1987 (Feigl et al., 2022). Since 1987, three DOE-sponsored projects have been awarded to study the geothermal resource at San Emidio. The first DOE-sponsored project (DOE award DE-EE0002847) conducted exploratory drilling between 2010 and 2014 (Feigl et al., 2020). The second and third DOE-sponsored projects (DOE awards DE-EE0007698 and DE-EE0009032) are currently underway to characterize the geothermal resource at San Emidio and to further investigate stress in the geothermal system. One of these DOE-sponsored projects is called WHOLESCALE. As such, the WHOLESCALE acronym stands for "Water and Hole Observations Leverage Effective Stress Calculations and Lessen Expenses".
Integrating Moving Reference Point Analysis Technique with a Planar 3d Model to Understand Fracture Propagation
Authors: Gabry M. A. , Soliman M. Y. , Farouq Ali S. M. 
Published: September 2022

ABSTRACT:
This paper focuses on the validation of the Moving Reference Point (MRP) technique using an independently pressure-matched planar commercially available 3D hydraulic fracturing simulation model with real field cases like multiple perforations and laminated reservoirs. The paper provides a methodology for concluding the lessons learned from hydraulic fracture treatments and taking the right preventative action in the hydraulic fracture treatments. The fracture propagation events like normal fracture propagation, height propagation, or propagation in the excessive leak-off zone were simulated on the pressure calibrated planer 3D model matched the event detected using the moving reference point based on the recorded bottom hole pressure. The integration of simulation and analysis presented in this paper assesses the use of the MRP technique to detect fracture propagation events during the fracture treatments in wells where accurate simulation data is not available. Unlike the previous applications of MRP, this application has complete well-completion data and petro-physical information.

INTRODUCTION
Detection of fracture events during fracture execution has a crucial role in the optimization of hydraulic fracture treatment it is a one-time operation. Once the optimum design is not achieved during execution, it couldn’t be achieved again.
Consequently, taking the right action during fracture treatment is crucial in the success of hydraulic fracture and achieving the optimum post-fracture production. The pumping rate or fluid viscosity can be modified or call for an early flush is requested based on the understanding of fracture propagation during the execution based on the right detection of the fracturing events.
The well-known Nolte-Smith method (1981) analyzes the treating pressure of a formation during pumping assuming all fracture events are referred to the initial fracture initiation point (regardless of the height covered by propagation during main fracture treatment). The net pressure is calculated based on the closure and plotted versus time for the start of the treatment on a log-log scale. Ayoub et al. (1992) introduced the pressure derivative of treating pressure analysis to be a good tool for fracture event detection.