bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulation of Injection-Induced Slip on a Rate-and-State Fault Considering Poroelastic Effects: A Comparison with Coulomb Failure Stress Criterion
Authors: Xie Qifeng , Wang Lei , Li Qi
Published: September 2023

The Coulomb failure stress (CFS) criterion based on the Mohr-Coulomb friction theory is commonly used to explain physical mechanisms governing injection-induced seismicity. While the CFS criterion can evaluate the onset of fault reactivation caused by fluid perturbations, it cannot tell the kinematic process of fault failure (seismic or aseismic slip). An alternative model for simulating time-dependent earthquake cycles is the rate-and-state friction model, which provides evolving friction depending on slip rate and slip history. To explore the dynamics and stability of fault slip associated with fluid injection, we extend a spring-slider system with a rate-and-state dependent friction law by incorporating the evolving fluid pressure and poroelastic stress. Simulations of continuous constant fluid mass injection rate scenarios using the developed model suggest that injection-induced fault slip behavior is controlled by fault orientation, diffusivity and poroelasticity, and injection rate. Compared to the CFS criterion, our model can offer a temporal component to fault friction and provide new insights on slip, slip rate and trajectory in phase space. We also investigate the relation between cumulative slip displacement versus cumulative injection volume, as well as the event recurrence interval. Our proposed approach has the potential application for evaluating the reactivation of pre-existing faults embedded in the reservoir associated with fluid pressure operations in the field practice.

INTRODUCTION

It has been well established that fluid injection into subsurface reservoirs can induce earthquakes (Healy et al., 1968; Raleigh et al., 1976). One of the most frequently discussed scientific issues is the physical mechanism that causes earthquakes to nucleate in response to fluid injection. The Coulomb failure stress criterion based on the Mohr-Coulomb friction theory is commonly used to explain the mechanism of induced seismicity (Ge & Saar, 2022). The Coulomb failure stress (CFS) and the change in Coulomb failure stress (ΔCFS) can be expressed as

(Equation)

(Equation)

where μ is the friction coefficient that is assumed to be constant above, τ, σn and P refer to shear stress, normal stress (positive for compression), and pore pressure acting on the fault, respectively. Δτ, Δσn and ΔP denote the changes of shear stress, normal stress and pore pressure, respectively.
Statistical Approach to Characterize Stress Field Heterogeneity
Authors: Jimenez Martinez V. A. , Renner J.
Published: September 2023

Stress tensor determination is of importance in many aspects of geothermal energy provision, from the understanding of the propagation orientation of newly created fractures to the control of the pre-dominant stimulation mechanism, hydro-fracturing vs. hydro-shearing. Hydraulic stimulation experiments were carried out in the research mine Reiche Zeche in Freiberg, Germany, in the framework of the STIMTEC and STIMTEC-X projects. Key objectives were to characterize the stress field of the rock volume and evaluate and enhance hydraulic properties. Injection tests were performed in 28 intervals with 0.7 m length enclosed by a double-packer probe, either with pre-existing fractures or initially intact, in 7 boreholes crisscrossing a rock volume of 60×30×30 m3. The data from the injection experiments typically used to determine components of the stress tensor comprise shut-in and jacking pressures, and the orientation of the pressurized fractures. Impression packer testing and acoustic televiewer logging revealed multiple fracture traces for a number of intervals, and thus we face ambiguity regarding the hydraulically relevant fractures. In total, the data set comprises 28 characteristic pressures assumed to correspond to the normal stress on a fracture, but in total 60 fracture traces were detected with a maximum of four fractures in a single interval. The uncertainty in the association of the characteristic pressure with a fracture trace and the fact that a unique stress tensor cannot explain all the observed data, i.e., the stress field is heterogeneous, motivated a Monte Carlo analysis to characterize the stress field in the rock volume. We randomly select subgroups of 5 out of the tested intervals, with one fracture trace randomly selected out of the observed traces for each interval, and then determine the misfit between observed characteristic pressures and the normal stress on the selected fracture trace associated with randomly selected stress parameters. Selecting 5 intervals in principle sufficed to invert the stress field, since we constrained the vertical stress by the known overburden. The total number of combinations of intervals and fracture traces precludes a systematic stress-parameter determination. The Monte Carlo approach allows us to statistically investigate the role of each particular interval and fracture trace for stress magnitude and stress regime.
Assessment of CO2 Injectivity in Highly Deformable Chalk Reservoirs: A Thermo-Hydro-Mechanical Analysis
Authors: Hosseinzadehsadati S. B. , Amour F. , Hajiabadi M. R. , Nick H. M.
Published: September 2023

Depleted hydrocarbon chalk reservoirs are attractive candidates for CO2 storage in Denmark. However, their highly deformable nature presents challenges for CO2 injectivity and storage. This study investigates the potential for thermal effects on reservoir and caprock integrity caused by a 16 year-long supercritical cold CO2 injection in a depleted gas reservoir using a thermo-hydro-mechanical simulation. We focus on quantifying the additional stresses and strains induced by the thermal expansion and contraction of the rocks and examine whether these changes could trigger fracturing/fault reactivation in the chalk and/or the overlaying shale deposits. To address convergence issues in non-isothermal flow modeling, we assume that the density and viscosity of CO2 remain constant with temperature change in the coupled simulation. Our results demonstrate that, with constant rate injection of CO2, temperature propagation is limited to a short distance around the well, and CO2 only cools down the temperature around the injection site. This study provides insights into the feasibility of cold CO2 injection in hot depleted hydrocarbon reservoirs and highlights the importance of considering thermal effects on faults and fractures behavior.

INTRODUCTION

Carbon Capture and Storage (CCS) can help reduce greenhouse gas emissions while transitioning to renewable energy (IPCC, 2005). Depleted oil and gas reservoirs offer significant potential for CO2 storage (Bonto et al., 2021), using natural subsurface storage space that previously contained hydrocarbons for millions of years and reusing existing infrastructure, such as wells, platforms and pipelines (Amour, Hajiabadi, Hosseinzadehsadati, et al., 2022).

Storing CO2 securely underground in depleted oil and gas fields is critical, and the success of this approach depends on ensuring geomechanical stability during CO2 injection, which can have significant implications for cap rock integrity and fault reactivation (Akhurst et al., 2015). Injecting cold CO2 may cause thermal contraction of the reservoir matrix and unload normal compression on existing fractures and faults (Salimzadeh, Paluszny, & Zimmerman, 2018; Vilarrasa & Rutqvist, 2017). This process can lead to an increase in the aperture of impermeable faults and fractures, potentially creating new pathways for CO2 leakage and inducing seismic activity (Min et al., 2005; Rutqvist, 2012). Therefore, the injection of large amounts of low-temperature CO2 into hot, depleted hydrocarbon chalk reservoirs may induce a range of complex and strongly coupled thermal, hydraulic, mechanical, and chemical (THMC) processes (Yin et al., 2011) involving interactions among reservoir formation fluids, CO2, and chalk minerals. As a result, accurately identifying the stresses, pressures, and temperature changes around the injection well is essential to obtaining practical information for injection design, thermal fracturing, and leakage prevention.
Distant Fault Reactivation Due to Temperature and Pressure Changes Accounting for Rock Matrix and Fault Plasticity
Authors: McLean Matthew L. , Espinoza D. Nicolas
Published: September 2023

Large-scale geothermal energy production and carbon geological storage are emerging technologies. Injection of non-native fluids in the subsurface alters reservoir pore pressure and temperature changing the initial state of stress, even beyond the plume and thermal front, which could potentially lead to the reactivation of distant faults. Published work so far usually neglects elastoplastic rock matrix response and effects of plastified reservoir volume on distant stress changes. This paper presents three-dimensional thermo-hydro-mechanical (THM) numerical simulations of (1) a hydrothermal system with injector-producer doublet and (2) a carbon storage site with single injector, both solved with 3D finite element code ParaGeo. First, simulations show that assuming an elastic response for a geothermal reservoir results in more distant stress changes -which can be enough to disturb critically stressed distant faults-, than incorporating a more realistic elastoplastic model for the reservoir rock. Second, injection (without production) of a cold fluid may result in quick distant fault reactivation because the pressure front travels much faster than the temperature front, in the range of a decade or two in our model. Reservoir plasticity plays a negligible role when reservoir pressure increases and effective stress decreases. This work highlights the importance of using a realistic constitutive model and accurate estimation of in-situ stress for evaluating risks on sites subject to heat depletion or fluid injection.

INTRODUCTION

Subsurface activities that alter the pore pressure and temperature are known to potentially result in non-negligible seismicity (Wesson and Nicholson, 1987; Evans et al., 2012; Guglielmi et al., 2015) and may compromise fault sealing capacity if fault offsets become large (Zoback and Gorelick, 2012). Fluid injection increases pore pressure and may reactivate preexisting faults and fractures, triggering microseismic events (Majer et al., 2007). Reservoir cooling changes effective stress and may alter the state of stress well beyond the thermal plume (Kivi et al., 2022). Recent studies suggest that thermo-hydro-mechanical (THM) processes are likely to operate simultaneously but under different spatial extents, intensifying local stress changes and increasing complexity of distant stress changes (Martínez-Garzón et al., 2014). For example, observed seismicity and history matching at the Geysers geothermal field indicates that preexisting fracture reactivation is the result of reservoir cooling and fracture pressure increase with thermal effects dominating seismicity within the thermal plume (Rutqvist et al., 2015).
Experimental Study on Fracture Propagation During Supercritical CO2 Fracturing in Layered Tight Sandstone Reservoirs
Authors: Li S. H. , Xing H. L. , Jin G. D. , Zhang S. C. , Zou Y. S.
Published: September 2023

Supercritical CO2 (Sc-CO2) has a special physical property of ultra-low viscosity (0.02∼0.16 mPa·s) so that it can create branching hydraulic fractures in brittle rocks. However, the major controlling factors of hydraulic fracture propagation during Sc-CO2 fracturing in layered tight sandstones remain unclear. In this study, laboratory fracturing experiments were conducted to systematically investigate the major controlling factors of fracture propagation driven by Sc-CO2. Experimental results show that the samples with lower strength bedding planes tend to form more complex fracture geometry during Sc-CO2 fracturing. Even under a high vertical stress difference of 8 MPa, Sc-CO2 can still open some low strength bedding planes and create multiple hydraulic fractures. With the decrease of horizontal stress difference, the number of fractures formed by Sc-CO2 fracturing in low-strength samples increases. Compared with conventional water-based fracturing, Sc-CO2 fracturing can create multi-branch fractures. In the case of Sc-CO2 fracturing on samples with high strength bedding planes, increasing the injection rate can effectively increase the complexity of fractures. Based on the results of laboratory fracturing experiments, the major controlling factors of fracture propagation during Sc-CO2 fracturing are summarized as bedding plane strength > vertical stress difference > horizontal stress difference > fracturing fluid viscosity > injection rate.

INTRODUCTION

According to the International Energy Agency data, the global CO2 emission in 2019 is about 33.3 billion tons, and its contribution to the worldwide greenhouse effect has exceeded 60%. CO2 capture, utilization, and storage technology (CCUS) is crucial to reduce greenhouse gases effectively. It is the primary technology to realize carbon neutralization for our humanity [1,2]. CO2 fracturing, CO2 displacing, and CO2 huff-puff are valuable technologies for geological carbon neutralization and enhancing oil recovery in the petroleum industry. Since the 1980s, CO2 fracturing has been widely applied to stimulate the oil and gas reservoirs and coal seams characterized by water sensitivity and low formation pressure [3]. In the recent decade, CO2 fracturing has been exploratively applied to the stimulation of shale oil/gas reservoirs [4,5]. Most of the previous CO2 fracturing treatments have achieved a sound effect of increasing oil/gas production. It can be attributed to the advantages of CO2 fracturing, including creating complex hydraulic fractures, reducing formation damage and oil viscosity [6-9]. Moreover, CO2 fracturing can also save water resources and benefit CO2 geological capture [10]. The abovementioned advantages of non-aqueous CO2 fracturing could minimize the drawbacks of water-based fracturing fluids, such as slickwater, x-linked guar, and gel, which are widely used to stimulate unconventional oil/gas reservoirs.
Performance of Geopolymers in Geothermal Wells
Authors: Ogienagbon A. , Korsnes R. I. , Khalifeh M. , Wu Y. , Salehi S.
Published: September 2023

Geothermal wells play an important role in harnessing geothermal energy stored underground as the push for the strategic development of renewable energy increases. The use of conventional wellbore cement in geothermal wells is commonly associated with challenges due to the harsh and highly corrosive environment encountered in geothermal wells. In this study, we numerically evaluated the performance of a granite-based geopolymer based on its mechanical properties under different underground conditions, such as normal (30°C), moderate temperature (90°C), and elevated temperature (120°C). The elastic parameters of the geopolymer were evaluated under triaxial testing. The values were then input into the numerical model to perform a finite element analysis (FEA). Thermal loads were considered when evaluating the effect of temperature on cement performance. Hoop and radial stresses around the wellbore are presented. This study highlights the advantages of the granite-based geopolymer applied in geothermal well conditions.

INTRODUCTION

Global warming is a fact, and green transition is a must. Geothermal energy is a sub-set of geo-energy that has demonstrated its potential in locations such as Reykjavik in Iceland, San Diego in California, and Turin in Italy. The primary cost drivers associated with geothermal energy production are subsurface activities, including well construction and maintaining well integrity. Poor zonal isolation or loss of well integrity can significantly increase the capital and operational expenses associated with geothermal energy production. Zonal isolation is crucial, and cement is the prime material used for well cementing applications in geothermal wells. However, the performance of API class G cement in temperatures above 120 °C is negatively impacted by retrogression and thus excess source of silica is required (Wang et al., 2017). Furthermore, the shortcomings of cement and the environmental impacts of Ordinary Portland Cement (OPC) production have led to the search for alternatives to fully replace OPC (Arbad & Teodoriu, 2020; Carey et al., 2007). Of these materials, one may refer to geopolymers, blended cement, and pozzolanic cement (IEA, 2022).
Experimental Study on the Evolution Law of Breakthrough Pressure of Mudstone Cap Under Alternating Load
Authors: He Aiguo , Ma Qingyuan , Pang Yuhan , Zhang Xujia , Yin Guojun , Lu Yunhu , Xu Nan , Guan Yueyang
Published: September 2023

Breakthrough pressure, as an index to measure the sealing capacity of cap capillary, has always been the focus of gas storage seal integrity research. In this paper, using the method of SY-T5778-2013 to measure the rock gas breakthrough pressure, a breakthrough pressure test was carried out on the rock samples from the cover of the hydrogen storage reservoir of Well Jintanmao 17, and the influence law of the alternate load, porosity, permeability and breakthrough gas on the breakthrough pressure was analyzed. The results show that: (1) the breakthrough pressure of rock is mainly controlled by the permeability and other parameters, and the permeability is negatively correlated with the breakthrough pressure;(2) The alternating load before the yield point increases the core breakthrough pressure, and the alternating load after the yield point causes the core breakthrough pressure to decrease;(3) The air breakthrough pressure of mudstone is greater than the helium breakthrough pressure under the same conditions. The research results have guiding significance for comprehensive evaluation of gas storage cap bed dynamics.

INTRODUCTION

Different from foreign salt cavern gas reservoir construction in salt dome (salt layer thickness up to 300-500m), domestic rock salt resources are mainly layered rock salt containing interlayers, with poor grade (salt insoluble content in most salt mines is more than 30%), thin salt layer (60-250m), burial depth (more than 2000m in Pingdingshan and Chuzhou), etc. This kind of salt layer with a large number of interlayers is prone to instability of cap layer, weakening of seal property of salt layer and reduction of breakthrough pressure under alternating load, which greatly affects the sealing integrity of salt cavern storage and long-term stable operation of the storage (Han et al, 2006; Ozarslan et al, 2012; Wang J et al, 2019; Zhang et al, 2017; Bérest et al, 2003).

The integrity of the cap layer is essential for the safe storage and recovery of hydrogen storage in salt cavern. The cap layer of hydrogen storage should have a high capillary displacement pressure to prevent hydrogen percolation and diffusion. Breakthrough pressure is the most fundamental and direct evaluation parameter that reflects the sealing ability of cap layer (Deng et al, 2000).
Shearing and Opening of a Pre-Existing Discontinuity in Response to Fluid Injection
Authors: Lecampion B. , Sáez A. , Gupta A.
Published: September 2023

We investigate the fluid-driven growth ofa shear crack along a frictional discontinuity and its transition to hydraulic fracturing (sometimes referred to as hydraulic jacking) under plane-strain conditions. We focus on the case of a constant friction coefficient and account for the permeability changes associated with the fracture opening. By combining the scaling analysis and numerical simulations, we examine the evolution of both the shear and opening fronts as a function of the hydro-mechanical properties of the pre-existing discontinuity, in-situ stress state, and the fluid injection conditions. Further, we derive an approximate analytical solution for the relation between the positions of the slip and opening fronts at large times. We notably show that the ratio between the slip and opening fronts converges to a constant value at late times which only depends on the ratio between the shear stress and shear strength acting initially along the discontinuity. We compare this approximate solution against numerical simulations and demonstrate its usage to serve as a benchmark solution in the development of coupled hydro-mechanical numerical solvers for frictional fluid-driven fractures.

INTRODUCTION

Hydraulic stimulation of pre-existing fractures is used in the geothermal development in order to increase reservoir permeability and achieve economical flow rates - with mixed success (Jung, 2013; McClure and Horne, 2014). Although the primary idea is to shear dilate these pre-existing discontinuities via injection, in a number of field tests (Guglielmi et al., 2020), a large increase of permeability is only observed when fracture opening has been reached (sometimes denoted as hydraulic jacking). Shearing of pre-existing discontinuities can also occur during more traditional hydraulic fracturing operations in oil and gas reservoirs, either by direct fluid pressurization or via stress transfer from the main fractures. In this contribution, we investigate the fluid-driven growth of a shear crack along a frictional discontinuity and its transition to hydraulic fracturing. We focus on the case of a constant friction coefficient and account for permeability changes associated with fracture opening. We use a fully coupled implicit numerical scheme for the solution of this non-linear hydro-mechanical problem. Notably, the frictional interface behavior is modeled using an elastoplastic constitutive relation with a non-associated flow rule.
A Review and Comparison of Coupling Strategies for Modeling Fluid Flow and Geomechanics
Authors: Quevedo R. , Roehl D. M.
Published: September 2023

Coupled hydro-geomechanical processes in the oil and gas industry are usually simulated through the one-way strategy considering only the impact of fluid flow on geomechanics. However, depending on field and operation conditions, geomechanics can also affect the fluid flow. For those cases, more robust and accurate strategies must be adopted. Unfortunately, they require substantial computational effort and are time-consuming. This study reviews the coupling strategies for hydro-geomechanical problems and presents some algorithms that significantly improve their performance and stability. The fully-implicit, the two-way iterative, the two-way explicit, and the one-way strategies are implemented in an in-house framework to make fair comparisons among their results. Some numerical tests are performed considering several field conditions, such as heterogeneous rock properties and different geometrical settings between the reservoir and the surrounding rocks. The accuracy, stability, and required computational effort in each coupling strategy are discussed. The study shows that depending on the coupling level, one or another approach can be advantageous, producing accurate and fast solutions. The paper discussions can orientate in selecting adequate coupling strategies for engineering problems.

INTRODUCTION

Hydro-geomechanical processes in porous media are governed by two equations: mass balance and equilibrium of forces. As those equations are mutually dependent, a natural solution consists in solving them through a single system of coupled equations. This monolithic or fully-implicit strategy has been successfully applied in conceptual models (Sheng et al., 2003; Quevedo & Romanel, 2008; Huang et al., 2015; Mejia et al., 2019). However, due to high computational costs or ill-conditioned systems, the nonlinear behavior of porous materials may make the full-implicit approach unfeasible for large-scale applications.

Alternatively, sequential strategies have been used to link flow and geomechanics analysis codes by exchanging coupling terms. Such splitting in the solution raises the possibility of using different simulators to take advantage of the most appropriate solution methods. For example, different spatial discretizations can be adopted for reservoir flow modeling (limited to the reservoir region) and geomechanical modeling (including the reservoir and surrounding rocks).
The Effect of Graphite and Olive Waste on the Rheological and Filtration Properties of Saudi Class G Cement
Authors: Pratama Muhammad Andiva , Mahmoud Ahmed Abdulhamid , Elkatatny Salaheldin
Published: September 2023

Cementing process is one of the most crucial parts of the drilling operation that could determine the durability and the stability of the oil or gas wells. Many additives had been introduced into the formula of the oil well cement to reach certain quality to support the well. "Greener" materials, such as olive waste, which is waste from the olive oil extraction process, have a huge potential to be utilized in well cementing to reduce the waste material in the environment. This study aims to analyze the effect of olive waste and graphite material on the rheological and filtration properties, compressive strength, and permeability of the cement sheath. Three different formulas of cement, base, graphite-based, and olive waste-based cement were used in this study. The result showed that the graphite and olive waste successfully increased the compressive strength by 106% and 110%, compared to the base cement, respectively. They also decreased the cement permeability as compared with the base samples. Although it increased the plastic viscosity and decreased the yield point of the cement slurry, the incorporation of olive waste into the cement slurry significantly decreased the water filtration.

INTRODUCTION

Oil well cement is the most important component for keeping the well stable and preventing the formation fluid leakage (Lavrov and Torsæter, 2016). However, making an ideal cement sheath in the annulus between the casing and the drilled formation is highly expensive with the materials that are present in the industry right now (Mitchell and Miska, 2011). Many researchers conducted studies to determine the best materials to be utilized to improve the oil well cement properties and reduce the cost of the cementing process while minimizing the need for remedial operations (Mahmoud et al., 2018a; 2018b; Ahmed et al., 2019; 2020a; 2020b; 2023; Mahmoud and Elkatatny, 2019; 2020a; Chen et al, 2022).

The environmental issue is one kind of problem that the industry needs to solve. Finding a much "greener" additive and process that provides high-quality cement is one thing that needs to find. Ridha and Yerikania (2015) have developed a Nano-SiO2 Geopolymer cement that provides as good, even better compressive strength than the conventional Class G cement under High-Pressure High Temperature (HPHT) conditions.
The Effect of the Olive Waste on the Rheological Properties, Thickening Time, Permeability, and Strength of Oil Well Cement
Authors: Ali Ahmed , Mahmoud Ahmed Abdulhamid , Al Ramadan Mustafa , Elkatatny Salaheldin
Published: September 2023

In the oil and gas industry, cementing is a very important process to maintain the stability of the well. The cement slurry is injected downhole to fit the annulus between the casing and formation which in further can perform as an effective plug against fluids movement and at the same time supports the casing. In the design of the cement slurry, different types of additives are used based on operation conditions, incorporation of a new additive considerably affects all properties of the cement slurry and the solidified sheath. In this work, lab experiments were performed to investigate the effect of olive waste on Saudi Class G cement properties, the possibility of replacing the commercial retarder with olive waste was also studied in this work. Five samples with different olive waste content were prepared, and the rheological characteristics, thickening time, mechanical properties, and permeability of the samples were evaluated after 24 hours of curing at 95 °C. The results indicated that olive waste was able to replace the use of a commercial retarder. The addition of olive waste did not affect the cement plastic viscosity, while the yield point, 10-sec and 10-min gel strength of the cement were considerably increased with the increase in the olive waste content. The cement compressive strength was also increased with the incorporation of olive waste of a maximum of 0.375 %, and the permeability was decreasing with the addition of a maximum of 0.25 % olive waste.

INTRODUCTION

In the oil & gas industry, well cementing is an important operation to maintain the stability of the wellbore during drilling operations or production periods. In the cementing process, cement is pumped down the wellbore to fill the annulus between the casing and borehole (Adams & Charrier, 1985; Mitchell, 2006; Nelson & Guillot, 2006a; Hossain & Al-Majed, 2015). This cement can play significant roles and is used to achieve many functions such as providing a barrier between the formation and the wellbore, preventing fluid migration, and supporting the well casing (Al Ramadan et al., 2019, 2021; Fakoya & Shah, 2017; Jorge & Sampaio, 2007).
Numerical Investigation on the Impact of Drift Geometry Representation on the Assessment of Wedge Formation Using DFN Modelling in Underground Hard Rock Mines
Authors: Durham C. , Grenon M. , Karampinos E. , Dorion J. F.
Published: September 2023

Geological discontinuities have a large impact on the rock mass behavior in underground excavations. Under low stress conditions, structurally controlled wedge failure is one of the most critical types of rock instability. The stability analysis, in this case, is essential to consider both the rock mass fracture network and the geometry of the opening. However, current wedge stability analysis tools do not typically examine the detailed geometrical characteristics of the rock discontinuities and the excavation shape in 3D. This paper reports on the development of a comprehensive and more rational numerical approach to assess wedge formation around underground mine openings. The approach considers the structural rock mass complexity using Discrete Fracture Network (DFN) modelling and the detailed 3D underground excavation profile obtained from surveying. The developed methodology was successfully applied to estimate the formation of wedges around an excavation in an underground mine. A detailed investigation on the 3D profile and shape of the excavation indicated that an oversimplification of the excavation geometry in the stability analysis can result in inadequate assessment of wedge formation. Further analysis allowed to identify elongated wedges that may not be critical from a stability perspective and wedges that were not entirely formed in the DFN model but may still be critical for the stability of the excavation.

INTRODUCTION

Under low-stress conditions, the stability of mining excavations is frequently controlled by rock discontinuities (Hoek et al., 2000). Wedges are formed by the intersection of more than two discontinuities on the walls of an underground opening. The structurally defined rock blocks can fall or slide toward the excavation. The most common wedges in the field are tetrahedral blocks defined by the intersection of three fractures and the surface of the underground opening (Windsor, 1999). Under these conditions, analyzing the size distribution and probability of occurrence of wedges is critical for the design and support of underground excavations.
Elongated Hydraulic Fracture Emerging from Layers of Alternating Fracture Toughness
Authors: Peruzzo C. , Lecampion B.
Published: September 2023

Whether used to enhance the hydrocarbon production from low permeability rocks or to measure the minimum in-situ principal stress in rock formations, height growth of a hydraulic fracture above the formation of interest is a key metric for the design of successful hydraulic fracture applications. If the confining stress variation between rock layers represents one of the main reasons for fracture containment at depth, a contrast of fracture toughness can also lead to fracture containment. Fracture toughness contrasts are presents at different scales. They are due to lithological changes at the scale of layers, but they also appear at smaller scales, down to the size of bedding planes. The interaction of a hydraulic fracture with a repetitive sequence of multiple layers of different fracture toughness can ultimately lead to the emergence of an elongated fracture or, alternatively, to the propagation of an elliptical-like fracture with a fixed aspect ratio. Combining theory and simulations, we study the possible emergence of an elongated hydraulic fracture from layers of alternating fracture toughness considering typical hydraulic fracturing treatments as well as micro-hydraulic fracturing test cases.

INTRODUCTION

Hydraulic fracturing is an industrial technology in which a viscous fluid is deliberately injected into a solid to initiate and propagate one or more tensile fractures. This technology is successfully applied to measure the in-situ minimum stress in rock formations (Desroches and Thiercelin, 1993), but also to enhance the hydrocarbon production from low permeability rocks (Economides and Nolte, 2000). These rocks, usually referred as unconventional hydrocarbon reservoirs, are primarily located in sedimentary basins at depths ranging from one to few kilometers. In these basins the in-situ minimum stress is usually directed horizontally causing the hydraulic fracture to propagate on vertical plane and to interact with layer-like heterogeneities. To varying degrees, these heterogeneities comprise differences in the in-situ minimum stress, fracture energy, elastic properties, and leak-off-related quantities. Understanding their effect on the vertical hydraulic fracture growth, above the formation of interest, is of primary importance for the design of a successful hydraulic fracturing application (Bunger and Lecampion, 2017).
Assessing the Viability of Oilwell Cement for Underground Hydrogen Storage
Authors: Hussain A. , Emadi H. , Thiyagarajan S. R. , Ispas I. , Watson M. , Leggett S. E.
Published: September 2023

Encouraging the use of renewable energy is crucial for meeting our energy needs, but it requires bulk storage to be practical. One potential solution is underground hydrogen storage, which could provide a consistent supply of clean energy for the world. Depleted hydrocarbon reservoirs may be a viable storage option for this purpose, given their existing infrastructure. However, ensuring wellbore integrity is a major challenge when storing hydrogen in such reservoirs. To test the feasibility of this approach, a core holder to replicate wellbore conditions having a 12" long, 4" diameter core sample that has a concentric two-inch drilled hole is used in this study. A one-inch perforated pipe, as the casing, is placed inside the 2" hole, and the cement will be placed between the pipe and the core. 72 hours after pouring the cement between the core and the pipe, hydrogen is injected into the sandstone from the casing through the cement. A CT scanner was then used to detect any leakage channels or cracks in the cement that could compromise the integrity of the storage system. One end of the cemented annulus is connected to a Data Acquisition system via transducers to detect any leakage. This new method could offer a promising alternative for underground hydrogen storage in depleted hydrocarbon reservoirs to detect leakage and ensure well integrity.

INTRODUCTION

Hydrogen is seen as a key element in the energy transition towards a more sustainable and low-carbon future as it is a clean energy carrier which makes it an ideal fuel for a low-carbon energy system. Hydrogen can be used in a wide range of applications, including transportation, electricity generation, heating, and industrial processes. The production of hydrogen using renewable energy sources, such as solar or wind power, can help decarbonize the energy system. In addition, hydrogen can be used to replace fossil fuels in a wide range of applications, including transportation and industrial processes (Bechara et al., 2022).

Hydrogen can be stored for long periods of time, making it an important energy storage medium for intermittent renewable energy sources like solar and wind power. This can help balance the grid and ensure that energy is available when it is needed (Canbaz et al., 2021). Salt caverns, aquifers, and depleted hydrocarbon reservoirs can be used to store large quantities of hydrogen for a long period of time. Depleted hydrocarbon reservoirs are the most suited as hydrogen can be produced and transported in a similar way to natural gas, and existing gas infrastructure can be repurposed for hydrogen use. This could help speed up the adoption of hydrogen as an energy carrier, as it can be distributed through existing pipelines and infrastructure (Al-Hadrami et al., 2022).
Slope Stability Analysis and Design for Small-Scale Mines
Authors: Mgiba C. , Rupprecht S. M.
Published: September 2023

Introduction:

Artisanal and small-scale mining (ASM) is the extraction of ore with minimal to no mechanization by individuals or group of people who do not have advanced technical knowledge. Though ASM has gained considerable acceptance, one reason for its unsustainable is because of slope collapses that occur affecting the health and safety of miners and surrounding community. In rock mechanics, slope stability analysis and design has received significant attention in large scale mining to mitigate the risk of slope collapse but minimal implementation in artisanal and small-scale mining. This paper reports back the implementation of slope analysis and design through field observations to demonstrate the process of estimating rock mass rating (RMR) and finding suitable slope angles using Bieniawski (1976) RMR and Heins and Terbrugge stability charts respectively. Further analysis through laboratory strength tests and using numerical modelling software to assess the slope stability of the current and proposed slope design was conducted.

Results:

The slope design used in the ASM operation is unsuitable and the slope analysis using estimation charts required further analysis. Rock strength results were then used in OPTUM G2 to attempt to imitate reality. Suggested mining methods were proposed and mapped in OPTUM G2 where the limit equilibrium analysis showed that the gravity multiplier had increased by 10.04 for the upper limit and 2.79 for the lower limit and the strength reduction factor increased by 1.5.

Significance:

It is essential to continuously refine critical issues and help establish desirable conditions for ASM operations because it has a high potential to contribute towards sustainable development. Implementing cost-effective slope stability analysis systems for sustainable mining and promote achieving Sustainable Development Goal 1,3,8 and 9.

Conclusion:

The estimation process can be used with the guidance of a rock engineering practitioner during the design process of the mine after exposing the rock mass during the exploration stage. However, there may be other factors that can hinder the collection of data and modelling during the design phase as slope stability analysis systems were designed for large-scale mines.
Current Activities at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE): A Laboratory for Characterizing, Creating and Sustaining Enhanced Geothermal Systems
Authors: Moore Joseph , McLennan John , Pankow Kristine , Finnila Aleta , Dyer Ben , Karvounis Dimitrios , Bethmann Falko , Podgorney Robert , Rutledge James , Meir Peter , Xing Pengju , Jones Clay , Barker Benjamin , Simmons Stuart , Damjanac Branko
Published: September 2023

Enhanced Geothermal Systems (EGS) offer the best potential for meeting the U.S. Department of Energy's objective of 90,000 MWe by 2050. The Utah Frontier Observatory for Research in Geothermal Energy (FORGE) was established to de-risk tools and technologies required for commercialization of EGS. Six deep wells have been drilled into the low permeability granitic and metamorphic rocks hosting the reservoir. One is highly deviated and will serve as the injection well during reservoir creation. The deepest well, drilled to a depth of (2,896 m (9500 ft) has an estimated bottom-hole temperature of 241°C (465°F). Injection tests indicate a minimum horizontal stress gradient of 16.74 kPa/m (0.74 psi/ft) and a permeability of ∼20 micro-Darcies. A three-stage stimulation of the injection well was performed in April 2022. In the first stage, slickwater was pumped into the open hole section of the well at 50 bpm (7.95 m3/min). The second and third stages were performed in the cased portion of the well using slickwater and a viscosified fluid. Flow rates of 35 bpm (5.56 m3/min) were achieved in both zones. Microseismic events recorded during the stimulation ranged from −2.3 to +0.5 Mw. Drilling of the production well is planned for 2023.

INTRODUCTION

Enhanced Geothermal Systems (EGS) offers the greatest potential for meeting the U.S. Department of Energy's (DOE) goals of 90,000 MWe by 2050 and reducing the cost of electricity by 90% to $45 per MW-hour. Since the late 1970s, more than a dozen EGS projects have been conducted throughout the world in an effort to create geothermal reservoirs where none exist naturally. None of the projects have achieved commercial scale levels of production.

The Utah Frontier Observatory for Research in Geothermal Energy (FORGE) was developed to de-risk and test techniques for creating, sustaining and monitoring EGS reservoirs. The ultimate goal of the Utah FORGE field-scale project is to demonstrate to the public, stakeholders and the energy industry that EGS technologies have the potential to contribute significantly to future power generation (Moore et al., 2020, 2021).
A Graphical Analysis-Based Elastoplastic Solution for Undrained Wellbore Drilling Problem in Hoek-Brown Rock Formation
Authors: Abu-Dayyeh H. , Wang X. , Chen S. L. , Han Y. H. , Abousleiman Y. N.
Published: September 2023

An analytical solution is developed for evaluating the stability of an impermeable wellbore in rock formation that obeys Hoek-Brown failure criterion in a hydrostatic stress field. The solution is derived in the framework of the graphical analysis method recently developed by Chen and Abousleiman (2022). The graphical analysis approach can effectively overcome two essential limitations that exist in the implementation of the Hoek-Brown model in the current literature, i.e., first, the mathematical difficulties involved in the treatment of corner singularity of the yield surface; and second, the intermediacy assumption for the axial stress with respect to other stresses. The graph-based solution procedure follows two steps: (1) to geometrically track the stress path trajectory laid out in the deviatoric stress plane; and (2) to formulate the constitutive equations and the radial equilibrium equation. It is found that the effective stress path corresponding to the borehole drilling process is composed of piecewise curved and straight lines in the deviatoric stress plane; it eventually terminates in the major sextant with the Lode angle θ ranging from π/2 to 2π/3 or, on the line of θ = π/2, depending on the mechanical properties of the rock. The analytical solution obtained is a rigorous and complete one for the borehole drilling problem.

INTRODUCTION

Wellbore instability is a significant subject in the application of rock mechanics in the oil and gas industry (Santarelli et al, 1986; Yu, 2000). The study and analysis of stresses around wellbores is crucial in the reduction of monetary losses associated with this problem (Yu, 2000; Chen, 2012). Choosing the right model is essential for accurately predicting mud pressure, calculating wellbore stresses, and ensuring safe wellbore drilling (Zoback, 2007; Yu, 2000). Consequently, this can help mitigate two main problems that cause wellbore instability: borehole collapse and borehole fracturing (Santarelli et al, 1986). Estimation of the critical mud pressure is obtained by choosing a failure criterion and using a constitutive model to estimate the stresses induced around the wellbore (Al-Ajmi, 2006).
Machine Learning Modeling of Saudi Arabian basalt/CO2/brine Wettability Prediction: Implications for CO2 Geo-Storage
Authors: Tariq Zeeshan , Ali Muhammad , Yan Bicheng , Sun Shuyu , Hoteit Hussein
Published: September 2023

CO2 wettability and the reservoir rock-fluid interfacial interactions are crucial parameters that regulates the successful CO2 geological sequestration. This study implemented the feed-forward neural network to model the wettability behavior of Saudi Arabian (SA) basaltic rocks in a ternary system of basaltic rocks, CO2, and brine under different operating conditions. To gain higher accuracy of the machine learning models, a sufficient dataset was utilized that was recorded by conducting a large number of laboratory experiments under a realistic pressure range, 0 – 25 MPa and the temperatures range, 298 – 343 K. Different graphical exploratory data analysis techniques, such as heatmaps, violin plots, and pair plots were used to analyze the experimental dataset. The machine learning models were trained to predict the receding and advancing contact angles of SA basalt/CO2/brine systems. Both statistical evaluation and graphical analyses were performed to show the reliability and performance of the developed models. The results showed that the implemented ML model accurately predicted the wettability behavior under various operating conditions.

INTRODUCTION

Geological formations offer a promising solution to reduce global warming and achieve a low-CO2 economy by injecting carbon dioxide (CO2) into them (Alam et al., 2014; Bethke, 2007; Egermann et al., 2005, 2005; Iglauer et al., 2015; Wang et al., 1998). Saudi Arabia, a significant hydrocarbon-producing country, possesses numerous existing infrastructures and transportation pipelines suitable for natural gas storage, which could be utilized for large-scale CO2 storage in depleted hydrocarbon reservoirs, saline aquifers, and salt caverns. Moreover, sedimentary formations like shales, tight sandstone or carbonates, and igneous rocks such as basalts have recently emerged as potential formations to investigate for CO2 storage (Yan et al., 2022c).

Dark-colored, fine-grained igneous rocks called basalts consist mainly of pyroxene, plagioclase, and olivine. They are more abundant and accessible than shales, and the Cenozoic volcanic rocks in Saudi Arabia are one of the largest areas of alkali olivine basalt worldwide, covering nearly 90,000 km2. Carbon mineralization is the primary method of CO2 storage in reactive rocks like basalt, and research has shown that basalt can be suitable for CO2 storage through this method, or residual trapping if the basalt formation is capped. Basalt is distributed worldwide with a favorable mineral composition, significant thickness, and good vesicular texture. In contrast to silica minerals in sedimentary formations, CO2 injection into volcanic rocks like basalt can swiftly initiate carbon mineralization and mineral trapping, as evidenced by successful pilot project trials conducted in Washington State (USA) and Iceland, which showed that most of the injected CO2 was mineralized in less than two years.