bluuebunny/crossref_metadata_2025 huggingface dataset:
Numerical Modeling of Fluid-Driven Fractures in Permeable Media Using Symmetric Cohesive Elements
Authors: Mejía C. , Rueda J. , Roehl D.
Published: August 2024

Hydraulic fracturing is one of the most widely used techniques adopted in the oil industry to enhance reservoir permeability. In traditional hydraulic fracture modeling, the numerical model simulates half of the fracture geometry by taking advantage of model symmetry. However, hydraulic fracture modeling in heterogeneous rock formations considering a fully coupled formulation can require significant computational effort, especially in 3D models. This work proposes a symmetric cohesive element to simulate fluid-driven fractures in permeable porous media. In this approach, the hydraulic fracture path coincides with the plane of symmetry of the fracture, allowing the simulation of only a quarter of the fracture geometry. The symmetric cohesive element is obtained by imposing suitable constraints on the displacement degrees of freedom. In addition, the hydromechanical properties are updated to induce symmetric hydraulic fracture propagation. The proposed technique is successfully compared against the traditional full model, demonstrating simulation accuracy with substantially reduced computational cost. The numerical results demonstrate the capability of the proposed approach to successfully simulate hydraulic fracturing under under K and propagation regimes. Finally, this approach is an attractive alternative to simulate field scale models considering heterogeneous permeable rock formations.

1. INTRODUCTION

The oil and gas industry employs the hydraulic fracturing technique to enhance unconventional reservoir permeability. The fracturing process involves the high-pressure injection of fracturing fluid to create cracks inside the rock formation, facilitating the migration of trapped hydrocarbon. However, it can lead to geomechanical problems such as seismicity (Rutqvist et al., 2013). Therefore, a better understanding of the hydraulic fracturing behavior is essential to reduce the associated environmental risks. However, the numerical modeling of hydraulic fracturing requires a better understanding of the physical mechanisms and also the ability to build field-scale models (Searles et al., 2016).

In the last decades, numerical models have been developed to simulate hydraulic fracturing problems with complex fracture geometry (J. Adachi et al., 2007). Recently, several authors developed fully coupled HM zero-thickness interface elements, which modeled longitudinal and transversal fluid flow inside the fracture (Ng & Small, 1997; Segura & Carol, 2008). A fully coupled interface element with cohesive law is adopted to model hydraulic fracture propagation in permeable porous media (Chen et al., 2009; Zielonka et al., 2014). The capability of this approach was verified through comparison with available analytical solutions (Carrier & Granet, 2012) and laboratory fracturing tests (Searles et al., 2016). However, accurate modeling of hydraulic fracturing requires refined mesh close to the fracture plane, which is computationally expensive for 3D field-scale models.
Comparison of Geochemical Reactivity of Marcellus and Caney Shale Based on Effluent Analysis
Authors: Dje L. B. , Awejori G. A. , Radonjic M.
Published: August 2024

In this comparative study, we analyzed the changes in elemental concentrations of hydraulic fracturing fluids after interaction with the Marcellus and Caney Shale formations. The focus was on assessing the inherent risks and environmental implications associated with flowback waters, including their impact on soil, ground, and drinking water quality, and human health safety. The chemical compositions of effluents were determined through Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES) and Mass spectrometry (ICP-MS). The Marcellus Shale, showed concentrations of Cd, averaging 0.380 ppm far exceeding safe water thresholds. Significant levels of As, Se, B, and Pb were detected in both shales, raising concerns about soil and water contamination. Analyzing the effluents from representative samples of sections of the Marcellus (S2 and S7) and Caney (R1 and R2) indicates different geochemical responses over 4 weeks of experiments. This comparison underscores the chemical changes and environmental considerations linked to hydraulic fracturing across shale formations, suggesting the value of tailored monitoring and regulatory measures for each type.

1. INTRODUCTION

The Caney and Marcellus shales, differing in geology and geochemistry, represent distinct unconventional reservoirs. The Caney shale, is more ductile, with higher produced water volumes, (Smith et al., 2022) contrasts with the brittle Marcellus shale known for lower brine production but significant data availability. This study aims to elucidate the possible environmental health and safety issues that may arise from the hydraulic fracturing processes.

The interaction between fracturing fluids and clays presents a significant challenge. The primary base of these fluids is water, which, when introduced to clay, can induce swelling and constrict flow pathways. This phenomenon is attributed to water molecules infiltrating the layers of clay, particularly in 2:1-type clays, leading to an increased distance between layers. To counteract this, clay stabilizers are employed (Awejori et al., 2021). Despite their effectiveness, these stabilizers are considered temporary solutions. Upon completion of the fracturing process, a concomitant amount of contaminated waters (flow back), with varied content is collected at the surface. From these, we can infer the geochemical reactions and the environmental challenges associated with these waters. Flowback waters can be reinjected or used for other purposes such as irrigation. This requires adequate screening and treatment for safe use.
Elastic, Viscoelastic, and Permeability Response of Kentucky Sandstone in the Presence of scCO2
Authors: Kamali-Asl A. , Kovscek A. R.
Published: August 2024

We performed a series of hydrostatic and triaxial creep experiments on a Kentucky Sandstone sample using 1% NaCl brine as the pore fluid, before and after interaction with supercritical carbon dioxide (scCO2). We conducted the hydrostatic creep tests at three different pore pressures of 10, 20, and 30 MPa and three different effective stresses of 10, 20, and 30 MPa at each pore pressure, in both loading and unloading conditions. The triaxial creep tests consisted of two levels of pore pressures of [10,20] MPa, under the same confining pressure and differential stress. The bulk moduli showed strong and weak dependency on effective stress and pore pressure, respectively. As expected, creep deformation was notably larger in the triaxial tests compared to hydrostatic tests, which led to an increase in Young's modulus and a gradual loss of permeability during the triaxial tests. After interaction with scCO2, we observed a significant increase in permeability, a significant decrease in Young's modulus, and a modest increase in bulk modulus. Moreover, the triaxial creep deformation was larger after interaction with scCO2.

1. INTRODUCTION

Geological carbon storage has been proposed by many as one of the solutions to the issue of climate change, and as a bridge to transition from hydrocarbon production to renewable and clean geo-resources (Bouckaert et al., 2021). Storage of large volumes of CO2 can be achieved in porous sandstone formations, either in depleted hydrocarbon reservoirs or saline aquifers. However, there are some considerations when CO2 is injected into these sandstone formations (Orr, 2009). The role of geomechanics has often been neglected when the interplay between mechanical and transport characteristics of depleted reservoirs that are then repressurized with CO2 is considered. In particular, how the injection-induced change in the state-of-stress would affect the (i) mechanical (elastic) characteristics of the reservoir over shorter time periods, and (ii) transport characteristics (i.e., permeability) of the reservoir over longer time periods.
Numerical Analysis for the Design Assessment of Underground Mine Operations
Authors: Cammarata G. , Bui T. A. , Brasile S.
Published: August 2024

In the design of room-and-pillar mine systems, the loading capacity of the pillar is equally as important as the stability of the roof and walls to preserve safe working conditions and commercial ore productivity. The optimized design of pillars requires an assessment of the generated stress and available strength which depend on the mechanical behaviour of the rock mass. Moreover, the actual stress level imposed on a pillar depends also on the location of the pillars within the mine layout. These aspects cannot be properly considered by employing empirical and simplified approaches, while numerical methods provide the required accuracy in the determination of stress variations across the pillars as well as the assessment of the pillar strength. In this paper, we adopt numerical modelling to better constrain the implication of employing simplified approaches for a proper definition of the safety margins of a room-and-mine pillar layout. The results highlight the advantage of adopting advanced constitutive laws for the rock mass and discontinuities resulting in fully optimized designed solutions in terms of safe and, at the same time, economical designs.

1. INTRODUCTION

In mining excavations, rock pillars are commonly used in most underground mining methods, either temporary or permanent, to support adjacent underground openings and thus guarantee the stability of the rooms for extracting the ore safely. In the design of room-and-pillar systems a suitable factor of safety that relates the pillar strength, defined as the maximum resistance to the axial compression, to the pillar stress is required.

With this regard, empirical methods for estimating pillar strength and simplified methods for evaluating the pillar stress (i.e., tributary area method) have found wide acceptance in the mining industry. This has led to the formulation of several strength equations (e.g., Hedley and Grant 1972; Von Kimmelmann et al. 1984; Krauland and Soder 1987; Potvin et al. 1989; Sjöberg 1992; Lunder and Pakalnis 1997; Walton and Sinha 2021) which in some cases also consider account the effect of the length for rectangular pillars (e.g., Wagner 1992; Mark and Chase 1997; Dolinar et al. 2007) as well as the impact of large angular discontinuities (e.g., Esterhuizen et al. 2011). However, these methods should be used with caution (e.g., Dressel and Diederichs 2023) because they fail to consider specific failure mechanisms and do not account for the actual stress level imposed on the pillar due to the location of the pillars within the mine layout.
Coupled Reservoir-Geomechanics Simulation of CO2 Storage at the Wyoming CarbonSAFE Storage Hub
Authors: Bai Tao , Yu Ying , Jiao Zunsheng , Johnson Matthew , Nye Charles , McLaughlin J. Fred , Quillinan Scott , Peng Li
Published: August 2024

The Wyoming CarbonSAFE project is aimed at storing more than 50 million metric tons of CO2 over 30 years in a stacked reservoir-caprock system. To alleviate the concerns of potential geomechanical risks associated with geologic carbon storage at the study site, a coupled fluid-flow and geomechanics simulation is conducted to evaluate the geomechanical effects resulting from CO2 injection. A field-scale reservoir model is constructed based on realistic reservoir characterization data including 3D seismic, well logs, core analysis and fluid samples. Both 1D and 3D mechanical earth models are constructed to characterize the rock's mechanical properties and in-situ stress state. It is observed that roughly 84 million metric tons of CO2 can be stored in the study site. The geomechanical analysis indicates that no failure happens for most of the reservoirs and their corresponding caprock, the basement faults remain stable, and a maximum uplift of 7.92 cm is observed at the surface.

1. INTRODUCTION

Geologic carbon storage currently is treated as a promising approach to reducing greenhouse gas emissions by capturing carbon dioxide (CO2) from the industrial process or the atmosphere and then storing it in the subsurface porous media like saline aquifers, depleted oil and gas reservoirs and coal seams (Obdam et al., 2003). The purpose of the U.S. Department of Energy's Carbon Storage Assurance Facility Enterprise (CarbonSAFE) Initiative Projects is to develop commercial-scale storage sites for sequestering more than 50 million metric tons of CO2, from industrial sources, in underground geologic formations (Sullivan et al., 2020). In particular, the Wyoming CarbonSAFE project aims to capture CO2 emissions from a coal-fired power plant, named the Basin Electric Dry Fork Station (DFS) located in eastern Wyoming's Powder River Basin, and store it in three stacked reservoirs (Jiao et al., 2022).

One of the concerns associated with geologic carbon storage is the potential geomechanical risks during CO2 injection. Specifically, the pore pressure over the porous media continuously increases due to the injected CO2, then the in-situ stress state is changed correspondingly. When the reduced effective stress reaches a certain threshold, the integrity of the reservoir and caprock and the stability of preexisting faults are compromised. In the worst condition, the injected CO2 may leak through the induced fractures and reactivated faults, which poses a negative impact on the expected sealing behaviors (Rutqvist, Jonny., 2012). Therefore, these geomechanical effects should be fully characterized to ensure the containment and manage the potential geomechancial risks.
Post-Peak Multi-Stage Triaxial Testing of Miniature Rock Mass Samples
Authors: Cylwik S. D. , Childs D. W. , Mahoney D. M. , Plange K. M. , Grubb C. M.
Published: August 2024

Triaxial tests were performed on rock core samples with 14 confinement stages per test to investigate the post-peak strength and nonlinearity of the failure envelope for fractured rock masses. The confinement stages were tested progressively on each sample, starting at 0.69 MPa, incrementally ascending to 27.6 MPa, and then descending back down to 0.69 MPa. Three types of samples were tested: massive (no defects), continuous pre-existing defect, and jointed. The jointed samples were prepared to imitate a small-scale rock mass by confining brecciated sandstone core within heat shrink film and then mechanically breaking healed veins between the clasts with Brazilian disk load platens prior to testing. The measured post-peak strength of the samples was variable and dependent on the direction and quantity of pre-existing discontinuities within the sample. A generic failure criterion was fit to the test results to determine strength parameters for evaluation and comparison. Two empirical rock mass strength estimation methods were fit to the test results to assess if empirical methods are able to model the measured failure envelopes.

1. INTRODUCTION

Most engineering evaluations rely on empirical methods to estimate rock mass strength properties. Empirical methods generally utilize input parameters that can be readily measured in the laboratory or core shed such as the intact rock strength, fracture shear strength, or the degree of rock mass fracturing. Very few published studies have been performed on fractured rock samples to support or validate existing empirical estimation criteria (González-Fernández et al. 2023). This study presents a novel technique to prepare fissured, but fully interlocked, natural rock samples with mechanically induced fractures on pre-existing weakness planes. These samples are referred to as "miniature rock mass" samples due to their resemblance to a small-scale rock mass. Two of these samples were tested under multi-stage triaxial compression to measure post-peak strength behavior. In addition, two baseline samples were also tested to bracket the potential strength envelopes of a rock mass: one massive sample (no defects) and one sample with a continuous pre-existing defect. The resultant strength envelopes for each sample were then evaluated and fit using two different empirical rock mass strength estimation methods.
Evaluation of Fracturing Fluid Impact on the Productivity of Multi-Stage Fractured Marcellus Shale Horizontal Wells
Authors: El Sgher Mohamed , Aminian Kashy , Ameri Samuel
Published: August 2024

The objective of this study was to examine the effects of various fracturing fluids on proppant transport and its impact on the productivity of a Marcellus shale horizontal well with multiple hydraulic fracture stages. The available data from a Marcellus shale horizontal well were utilized to develop a reservoir model. The reliability of the model was confirmed by the close agreement between the predicted production by the model and the well production data. The impact of fracturing fluids on proppant transport during hydraulic fracturing and consequently on gas production from a Marcellus shale horizontal well were investigated by employing the reservoir models. Slickwater, compared to high viscosity friction reducers (HVFRs), was found to be less effective in horizontal Marcellus shale wells that are fractured in multiple stages. In treatment with the slickwater, all stimulation energy was directed towards the lower Marcellus shale and resulted in fractures with limited height leading to lower gas recovery. The application of the HVFRs resulted in higher fracture heights and improved production.

1. INTRODUCTION

The increasing demand for energy from unconventional reservoirs worldwide, driven by the depletion of conventional resources, has spurred technological advancements in the economic recovery of oil and natural gas from unconventional shale reservoirs. The application of horizontal drilling and hydraulic fracturing techniques in recent years has successfully unlocked substantial reserves of natural gas, making shale gas development a critical component of the global oil and gas industry, especially in North America. The effective placement of proppant in a fracture has a significant impact on the conductivity of the hydraulic fracture and the productivity of the well. During hydraulic fracturing treatments, it is common to inject a slurry containing proppant to maintain the fracture conductivity after fracture closure. The slurry is composed of a carrier fluid, which can either be a low viscosity Newtonian fluid known as "slickwater," or a high viscosity shear-thinning fluid. A suitable fracture fluid should be compatible with the formation. It is crucial that the fluid transports proppants deep into the fracture while keeping them suspended. Fluids with an inherent viscosity will likely develop the fracture width necessary for proppants to be accepted. Additionally, it should have a low friction pressure loss and sufficient stability to retain its viscosity during treatment.
Laboratory Evaluation of Natural Fracture and Hydraulic Fracture Interactions Using Digital Image Correlation
Authors: Shandilaya Shivesh , Roshankhah Shahrzad
Published: August 2024

Hydraulic fracture (HF) refers to inducing fractures in a solid material by injecting a fluid at a high rate into it. Understanding the patterns of induced hydraulic fractures within a rock mass is of high importance to many energy geosystems. In this experimental study, the pattern of induced HFs is evaluated by utilizing digital image correlation (DIC). Specifically, we investigate the interactions between a hydraulic fracture (HF) and a pre-existing natural fracture (NF). Using DIC, we examine the evolution in the local strain field in an intact and a pre-cut PMMA specimens as water is injected into the loaded specimens. From theory, it is anticipated that an HF initiates at the blunted notch fabricated at the top of the model wellbore in the PMMA samples and propagates upward as the applied boundary conditions require. This is verified for the intact PMMA specimen in this experimental study. The presence of an NF however forces the HF to curve and deviate into the NF. The interactions between induced HF and pre-existing natural fractures depend on the stress anisotropy, the relative orientations of natural and hydraulic fractures, and the bonding strength of natural fractures.

1 INTRODUCTION

In many energy geosystems, such as enhanced geothermal and unconventional fossil energy systems, enhancing reservoir permeability relies on strategically creating and expanding fracture networks through hydraulic stimulation. This technique centers on the deliberate interaction between artificially induced hydraulic fractures (HFs) and the pre-existing network of natural fractures (NFs) within the subsurface geological formations. Understanding this interaction is crucial, as it directly influences the effectiveness of production and the extent of induced seismicity (Warpinski & Teufel, 1987; Zhang et al., 2020; Chang & Yoon, 2022). This approach aims to initiate new fractures and extend and interconnect to existing fractures, thereby optimizing the reservoir's permeability and fluid flow pathways. Interactions between HFs and NFs are influenced by various factors such as the angle of intersection between the fracture planes, the prevailing stress field within the reservoir, NF properties, rock matrix permeability, and fluid properties, among others (Warpinski & Teufel, 1987). An intricate convolution among these factors determines the fracture interaction scenarios, like their propagation, arrest, slippage, dilation, etc. (Jeffrey et al., 2009; Chang et al., 2015).
Carbon Mineralization in Mafic Formations: Fracture Topology and Hydro-Chemo-Mechanical Coupling
Authors: Muñoz-Ibáñez A. , Santamarina J. C.
Published: August 2024

Coupled hydro-chemo-mechanical processes affect engineered geosystems, including geothermal energy recovery, long-term nuclear waste disposal, and carbon geological storage. In particular, dissolution-transport-precipitation can significantly alter the permeability field and alter the evolution of these coupled processes. Carbon mineralization in mafic rocks is a salient example. Fractures within these rocks, including column-normal and entablature fractures, serve as conduits for fluid transport and host associated chemical processes. This study investigates fracture characteristics in mafic formations, using photographic records from published studies and data collected by the authors during site visits. Different fracturing topologies – from well-developed columnar structures to irregular patterns – exhibit distinct aperture and spacing characteristics. Additionally, new experimental results reveal the intricate interplay between water absorption kinetics and induced strains, which could potentially impact fracture aperture and, subsequently, permeability. The study also highlights the importance of flow rate and residence time in influencing the evolving pore fluid chemistry, including variations in pH and dissolved species.

1. INTRODUCTION

Carbon mineralization in mafic and ultramafic rocks offers a promising solution for permanent carbon dioxide (CO2) sequestration (Snæbjörnsdóttir et al. 2020). The injection of CO2 into mafic formations such as basalts releases divalent metal cations (e.g., Ca2+, Mg2+, and Fe2+) from silicate minerals, which react with carbonate ions (CO3-) to form stable carbonate minerals such as calcite (CaCO3), magnesite (MgCO3) and siderite (FeCO3). While pilot projects in Iceland (Carbfix; Matter et al., 2016) and United States (Wallula; McGrail et al., 2017) have shown promising results, significant uncertainties remain for industrial-scale operation (Kelemen et al. 2019).

Basalts exhibit distinctive fracture networks, often in the form of vertically aligned polygonal columns, that influence permeability and the extent of hydro-chemomechanical (HCM) processes (Lore et al. 2001; Kelemen et al. 2018). Fractures provide reactive surface area and space for precipitated minerals, which can potentially clog fluid pathways (Adeoye et al. 2017). However, in some cases, a significant decrease in permeability has been reported even with minimal changes in porosity, and the underlying mechanisms remain unclear (Kelemen et al. 2020). The dissolution of basalt, influenced by factors such as mineralogy, fluid chemistry, and flow rate, introduces additional complexity (Gislason and Arnorsson 1993).

This study aims to enhance the understanding of fracture networks in mafic formations and their impact on HCM processes.
Artificial Neural Network for the Prediction of Unconfined Compressive Strength of Ultra Lightweight Cement for Oil and Gas Wells
Authors: Addo-Yobo A. D. , Hussain A. , Emadi H. , Maslowski de Moraes E. , Watson M.
Published: August 2024

This study demonstrates the use of Artificial Neural Network (ANN) modeling techniques to estimate the Unconfined Compressive Strength (UCS) of lightweight oil and gas well cement. At varied simulated wellbore temperatures, 172 cement samples were reinforced with variable doses of strength-enhancing ceramic cenospheres. An Isothermal water bath was used to cure the cement samples for 24 hours and the samples were crushed using a compressive load frame. Multiple samples comprising the same properties were crushed to confirm the consistency of the dataset. The model was trained with 70% of the data set, validated with 15%, and tested with the remaining 15%. The proposed ANN model has four layers: a three-neuron input layer, twenty-five neurons in the first hidden layer, five neurons in the second hidden layer, and a single-neuron output layer. The two hidden layer ANN architecture was determined to be the optimum configuration to prevent overfitting the data. After many rounds of hyperparameter tuning, optimum performance was achieved, and the model parameters were retained and utilized. With a Root Mean Squared Error (RMSE) score of 144 psi, coefficient of determination (R2) exceeding 0.9 and accuracy of approximately 90%, the ANN produced a highly accurate model and signified a good model fit when evaluated on the test set. Similarly strong results were observed on the validation set indicating that the model generalized well to unseen data. These results demonstrate that the ANN approach is adept at producing high fidelity models for UCS prediction of lightweight cement for use in Oil and Gas well cementing operations. This paper discusses a new UCS prediction method as an alternative to rigorous experimental testing for lightweight cement systems where achieving optimum strength is highly important for the proper zonal isolation of the wellbore.

1. INTRODUCTION

Global energy demand has been and is projected to increase steadily in the coming decades. To match this demand, the oil and gas industry continuously expands its capabilities by operating in extreme and challenging environments (Canbaz, et al., 2021). Since many of the easy-to-reach reservoirs are maturing, it is not uncommon to drill multi-mile wells, both vertically and horizontally, to maximize reservoir contact (Anya, 2018). Many of these new wells are drilled into high-pressure and high-temperature zones (Arbad & Teodoriu, 2020), which require differing cement properties from those traditionally used.
Development of Chilean Open Stope Empirical Stability Database Using MineRoc and their Comparison with Literature
Authors: Vallejos J. A. , Retamal F. , Barberán A. , Velásquez J.
Published: August 2024

The optimal dimensions of stopes for underground mining using the Sublevel Stoping method are determined to guarantee the stability of the excavation. The graphical stability method developed by Mathews, later modified by different authors, is used as an analysis tool to achieve this objective. The stability graph plots the hydraulic radius of the stope wall against its stability number N.

In this context, the MineRoc® software is used to perform the back analysis of overbreak of stopes walls exploited through Sublevel Stoping in Chile. A database of over 600 cases is developed, including Chilean geological, geotechnical, and operational conditions. This Chilean database is compared with literature databases, such as those of Mawdesley and Clark.

Based on the comparison of databases, the scope of applicability of literature curves as design guidelines for sublevel stoping in Chile is established. Possible improvements to the empirical method to better reflect the conditions of Chilean mines are discussed.

1. INTRODUCTION

The estimation of the potential instability of the rock mass around underground mine cavities is a subject of study in sublevel stoping (SLS) mining. Over the years, various tools have been developed for the design of unfilled stopes with the aim of improving these estimations.

Mathews et al. (1981), based on a study of 26 historical cases in SLS, proposed the graphical stability method, in which a qualitative stability state is defined for each stope wall based on visual assessments and/or reconciled data. The method presented by Mathews became popular after the expansion of the original database and the recalibration of stability numerical factors. According to Madenova and Suorineni (2020), to date, there are five main variations of the stability graph: Potvin's modified Mathews stability graph (1988), Mawdesley and Trueman's expanded Mathews stability graph (2003), the Equivalent Linear Overbreak Slough (ELOS) stability graph proposed by Clark & Pakalnis (1997), the stability graph for cable bolt support design proposed by Diederichs et al. (1999), and the stability graph based on dilution presented by Papaioanou & Suorineni (2015). Authors such as Nickson (1992), Suorineni (1998), Bewick & Kaiser (2009), Vallejos et al. (2016a, 2018a), Vallejos & Díaz (2020a), and Vallejos et al. (2022), among others, have also contributed by adding new historical cases to the original method, adapting some stability factors, and proposing new qualitative or quantitative boundaries. It should be noted that, in most cases, the stability graph has been adapted for other SLS operations (new site-specific conditions), narrow vein operations, and even for caving operations.
Geotechnical Implications of Large Shale Deposits on the Stability and Productivity of Iron Ore Mines: A Comparative Study
Authors: Mohanty A. , Mishra M. K. , Ghosh S. , Sahoo B. B. , Behera C. , Rostami J. , Sesay M. D.
Published: August 2024

This research study examines challenges of mining in the presence of shale due to its brittle nature. Shale's presence can substantially decrease the ultimate pit angle in a geological setting, reducing extraction. While earlier studies were focused on shale's impact on the slope stability of a soil structure due to its weak geotechnical properties, this paper showcases an analysis of shale's impact on production dynamics by investigating adjustments in mining strategies. The study area focuses on four iron ore mines in the Singhbhum Craton region in India. The research methodology encompassed onsite surveys, laboratory testing, and multiple analyses of iterated geological models replicating real-time situations in numerical codes, as well as a comparative analysis of handling notorious shale layers, both with and without the assistance of support systems. Findings of this study reveal a 10% decrease in yearly production of a mine, solely attributed to the presence of shale. Moreover, this paper provides insights into practiced solutions for managing issues frequently encountered in mines with shale, such as handling the material in varied seasonal conditions and mitigating the ore grade reduction by shale contamination of run-of-mine material.

1. INTRODUCTION

In today's age, on the global pedestal, mining stands as the strongest pillar in the critical structure of modern civilization, supplying essential raw materials fueling various critical industries, ranging from construction to the production of energy and technology. The pivotal role of mining in meeting the world's needs is indeed undeniable. Moreover, every aspect of an individual's daily life dramatically relies on extracting minerals and metals from resourceful ore deposits. The impacting domain ranges from the use of hematite ore used in steel production to rare earth elements like Neodymium (Nd) and europium (Eu), which are crucial for electronics manufacturing-electric vehicles and LEDs, respectively; the breadth and depth of impact of mining are inescapable. In addition, as the growth rate of the urbanizing populations accelerates, the demand for minerals continues to surge, creating unprecedented pressure on mining operations to amplify the production to meet this ever-growing need.
Experimental Investigation of Crack Propagation in High Carbonate Shale
Authors: Zhang Xudong , Wang Xiaoyang , Zhou Linbo , Chang Xin , Guo Yintong , Zhang Xinao
Published: August 2024

In recent times, significant advances have been made in the exploration and exploitation of Permian shale gas reservoirs within the Sichuan Basin, China, resulting in commendable gas production rates. However, challenges have emerged during field tests of Permian shale gas fracturing, particularly in relation to high fracturing pressures and early-stage fracture initiation complexities. Mineralogical assessments have revealed a pronounced elevation in carbonate content within Permian shale formations in comparison to their Ordovician-Silurian counterparts. Presently, there exists a conspicuous dearth of scholarly inquiry into the crack propagation mechanisms operative within high-carbonate shale matrices. This study endeavors to bridge this knowledge gap by undertaking a comprehensive investigation utilizing shale samples exhibiting varying carbonate concentrations through true triaxial fracturing physical model experiments. By meticulously analyzing fracture morphological characteristics and pressure profiles, we are able to discern the nuanced attributes of fracture initiation and expansion across diverse in-situ stress regimes and operational parameters, including viscosity, pumping rates, and acid pretreatment. Our findings serve to elucidate the multifaceted factors governing fracture expansion within high carbonate content shale formations, thereby enhancing the holistic understanding of shale gas extraction dynamics.

1. INTRODUCTION

The Sichuan Basin and its surrounding regions host a variety of organic-rich shale formations, including those from the Cambrian, Ordovician-Silurian, and Permian periods. These regions have emerged as pivotal locales for shale gas extraction in China (Bao et al., 2023). Notably, the Permian strata within the basin serve as crucial hydrocarbon source rocks for the Puguang and Yuanba gas fields. Recent endeavors have witnessed a notable breakthrough with the attainment of high-yield shale gas flows, marking a significant milestone in the exploration and exploitation of deep-seated Permian shale gas resources.

However, unlike their counterparts in shallower strata, Permian shale formations exhibit a substantial carbonate mineral content, averaging 33.9%. Consequently, the tensile strength and fracture toughness of the rock are significantly elevated, posing considerable challenges to the initiation and propagation of shale fractures. Currently, operational strategies primarily are derived from fracturing construction parameters that have been tailored for medium and shallow shale reservoirs. However, a transformational technology specifically addressing the unique attributes of high-carbonate shale reservoirs remains elusive.
Advances in Hot Dry Rock Engineering for Extracting Heat from Earth: From Permeability Enhancement Strategies to Field Experiences in Enhanced Geothermal Systems (EGS)
Authors: Mindygaliyeva B.
Published: August 2024

Geothermal energy, sourced from the Earth's internal heat, offers a renewable solution for clean electricity production. This energy is continuously replenished by heat flowing from the Earth's core to its surface and is especially accessible through hot dry rock (HDR) formations. These formations, located deep underground with high temperatures but low permeability, require innovative engineering to extract heat. The process involves circulating a fluid to transport heat to the surface, thus enabling power generation. The key to utilizing HDR lies in the generation of a conduit path for fluid circulation through methods like hydraulic fracturing, which is the most effective technique for creating extensive surface areas for heat extraction. This approach involves inducing fractures in the rock to facilitate heat flow. Such advancements have led to the development of Enhanced Geothermal Systems (EGS), which build on the HDR concept first realized at Fenton Hill in 1977. This paper reviews significant EGS projects over the last five decades, including notable examples like Fenton Hill and Soultz-sous-Forêts, among others. Our analysis reveals that as a byproduct of stimulation, micro- and macro-fractures can be created and/or some natural fractures may reopen, which would lead to fluid retention. This evaluation underscores the potential and challenges of EGS, offering insights into optimizing geothermal energy extraction from HDR formations.

1 INTRODUCTION

Geothermal energy is a pivotal aspect of renewable energy resources, characterized by its ability to provide consistent, sustainable power derived directly from the Earth's heat. Its significance lies in its vast potential to contribute to the energy mix with minimal environmental impact, offering a solution to the pressing demands for clean, reliable energy sources. Among the various technologies for harnessing geothermal energy, Hot Dry Rock (HDR) or Enhanced Geothermal Systems (EGS) stand out due to their innovative approach to extracting heat from the Earth's crust (Zhang and Zhao, 2020; Breede et al., 2013a).

HDR/EGS technology capitalizes on the Earth's abundant thermal energy stored in dry underground rocks. By creating a man-made geothermal reservoir, these systems inject water into hot rocks, fracturing them to enhance permeability, thereby allowing water to circulate, absorb heat, and be extracted from another well as hot water or steam.

This process effectively turns inaccessible heat resources into viable energy supplies, capable of generating electricity or providing direct heating (Zhang et al., 2019; Gong et al., 2020).
Optimization of Fracturing Parameters for Channelized Tight Sandstone Gas Reservoir Development with Surrogate Models
Authors: Tang Huiying , Ni Yingying , Luo Shangui , Du Cheng , Xiao Honglin , Hou Minghua , Zhang Liehui
Published: August 2024

The channelized tight sandstone gas reservoir in Jinqiu gas field, China, is mainly produced with hydraulic fractured horizontal wells. Currently, the fracturing parameters (e.g, cluster spacing and injection volume) are optimized with given sand body shape, which has strong limitations when applied to complex sand body geometries in practice. In this work, we try to construct a method to find the optimal parameters for arbitrarily shaped sand. First, a surrogate model for fracture geometry prediction based on numerical simulation results is built using a deep neural network (DNN). Then, the embedded discrete fracture model (EDFM) is used to characterize the fractures and evaluate the effectiveness of different fracturing designs. With the above models, we first find the optimal designs of fluid injection volume and fracture spacing for difference reservoir types and sand height/length. Optimization for horizontally and vertically curved sand bodies are then conducted to show the impact of sand geometries on fracturing parameter designs. The surrogate model proposed in this work helps to quickly predict the fracture geometries, which makes it possible to optimize fracturing parameters with optimization algorithms.

1. INTRODUCTION

Tight gas, due to its advantages such as widespread distribution and abundant reserves, has occupied a key position in the development of unconventional natural gas in China (Zeng et al., 2024). Compared with conventional gas reservoirs, tight gas reservoirs usually have characteristics such as low porosity, high water saturation, and low permeability, making the optimization of fracturing parameters more complex (Zhang et al., 2022).

The Shaximiao reservoir in the Jinqiu gas field is a typical tight gas reservoir, with porosity ranging from 8% to 16%, averaging 12.31%, and permeability ranging from 0.01 mD to 1 mD. The channel width is 200 – 4800 m and the sand thickness is 5 – 40 m (Fig. 1 and Fig. 2).

The Jinqiu gas field is a typical narrow channelized sandstone gas reservoir, which is mainly produced with hydraulic fractured horizontal wells. To further increase the production, it is necessary to optimize the fracturing parameters considering the sand body geometries.
Machine Learning Enhanced Interpretation of Wellbore Data for Underground Storage
Authors: Bondarenko N. , Ankul A. , Makhnenko R. Y. , Ganesh P. , Williams-Stroud S. , Goldberg C.
Published: August 2024

The Illinois Basin has an excellent history of pilot- and demonstration-scale CO2 injection projects, positioning it as a promising potential hub for carbon capture and storage. Since the presence of fractures increases risk of an induced seismic response and CO2 leakage, it is essential that potential injection sites are properly characterized before project deployment. Accurately measured distribution of seismic waves velocities is essential for prediction of fracture locations and monitoring of the injected CO2. Site investigation for the pilot-scale CO2 storage projects yielded abundant high-quality data, especially in terms of geophysical wellbore measurements. This information is utilized to create a dataset specific to the Illinois Basin aimed at assistance during the wellbore and seismic data interpretation, which (as any inverse problem) heavily relies on physical constraints to limit the range of potential solutions. The developed machine learning algorithms allow predicting P- and S-wave velocities based on mineralogical composition from ELAN log with accuracy superior to conservative effective media approaches. Three deployed algorithms include random forest, gradient boosting, and neural network – all of them yielded significantly more accurate estimations of seismic velocities compared to the sonic log. Additionally, this technique reconstructs complex patterns in variations of velocities associated with heterogeneities of geologic formations. It opens ways for further enhancement of datasets to evaluate involved hydromechanical parameters (e.g., poroelastic properties and permeability) to refine the velocity models and make identification of subsurface features and monitoring of the fluid migration processes more accurate.

1. INTRODUCTION

Successful implementation of geoenergy projects requires knowledge of the hydromechanical, stratigraphic, and lithological features of the participating geological formations. The access to the sites can be gained during the well boring (1D data), as well as via the use of geophysical methods (3D data), such as seismic, gravimetric, and magnetic surveys (Kearey et al., 2002; Manivannan, 2018). These techniques measure potential, resistivity, porosity, formation factor, temperature, fluid saturation, and sonic data obtained from various wellbore logs (Asquith et al., 2004), as well as mineralogy, lithology, and hydrocarbon content (Pelton et al., 1978). The datasets can contain thousands of records for each of the parameters as a function of depth, and combined, represent huge arrays of data to be interpreted. Machine learning (ML) techniques have been shown to serve as a powerful algorithm for enhancing the datasets and capturing intricate nonlinear relationships within them (Bressan et al., 2020; Glubokovskikh et al., 2020). The overall effort is in augmenting subsurface characterization efforts and enhancing understanding of the geological conditions.
Estimating Pressure and Fronts in Underground Storage Through Tilt Data Inverse Modelling
Authors: Abdollahi R. , Movassagh A. , Kasperczyk D. , Haghighi M.
Published: August 2024

Seismicity and surface deformation are prevalent outcomes of underground reservoir operations. These deformation data serve as a crucial indirect method into the nature and intensity of subsurface activities. Currently, tiltmeter technology is the most accurate monitoring tools with the accuracy of nano radian. This study aims to utilize surface tilt data acquired from underground storage or production sites to estimate reservoir pressure values and their spatial fronts. To accomplish this, a predictive model was designed to compute surface deformation through numerical methodologies. The model segments the reservoir into smaller elements resembling those used in reservoir simulations. It calculates the resulting deformation caused by pressure alterations by aggregating the results from each individual block under constant pressure conditions. The solution for each block, relies on employing the displacement solution for a thermoelastic strain nucleus within a half-space having a traction-free surface. Integrating a reliable inversion technique with this forward model enables the tracking of pressure fronts in subsurface reservoirs using surface tiltmeter data. The model's proficiency was validated through the utilization of synthetic deformations, highlighting the reliable efficiency of the inversion approach with results demonstrating an error rate below 5%.

1. INTRODUCTION

Surface deformation and reservoir compaction have been recorded in a variety of oil and gas fields and storage facilities, stemming from subsurface activities such as fluid extraction or injection, hydraulic fracturing, and fault slippage. (Chen et al., 2023; Du & Olson, 2001; Okada, 1992; Olson et al., 1997). The deformation resulting from subsurface activities or operations can lead to various geo-mechanical challenges, including casing/cement failure, fault reactivation, fracture extension, and surface/subsurface facility failures, as well as caprock failure. This poses a potential risk to the overall well and reservoir integrity. Therefore, monitoring and analyzing deformation data becomes crucial for detecting potential issues. Additionally, these data serve as indirect optimization tools, providing valuable insights into the size and intensity of underground operations or activities, thereby functioning as an indirect monitoring technique for optimizing overall operations.