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Abstract Reliable knowledge of the magnitudes and orientations of in-situ stress is crucial for conducting scientific and engineering activities in the subsurface, especially with regards to subsurface energy and storage applications. A commonly used technique for determining the minimum principal stress is to interpret the fracture closure pressure from the pressure decline transient during the shut-in phase of a minifrac test or a diagnostic fracture injection test (DFIT). However, current minifrac or DFIT analysis methods for interpreting fracture closure pressure often yield inconsistent results, leading to large uncertainties in determining the minimum principal stress. This paper presents a series of small-scale laboratory hydraulic fracturing experiments conducted under true-triaxial compression. The injection scheme consists of a hydraulic fracturing cycle followed by a few fracture propagation cycles and several injection/falloff (DFIT) cycles. The wellbore pressure and acoustic emission (AE) activities of each cycle were concurrently measured to monitor fracture initiation, propagation, and closure during fluid injection and shut-in. The pressure data were used to interpret S3 using different hydraulic fracturing-based methods. The results illustrate that the spatial-temporal evolution of AE activities is well associated with fracture propagation. In relatively low permeable rocks (Test 1 and Test 2), fracture reopening pressure generally provides a reliable estimate of the minimum principal stress (S3). ISIP consistently provides a relatively higher estimate of S3 and can be used as an upper limit for constraining S3. Fracture closure was observed using the so-called "tangent" method in all injection/falloff cycles. However, the "tangent" method using a signature close to the peak GdP/dG tends to significantly underestimate S3. The "compliance" method offers a relatively objective (yet still low) estimate of closure pressure. The signature associated with the change in system stiffness or compliance is observed but not consistently in every DFIT cycle. In the relatively high permeable Scioto Sandstone test (Test 3), the G-function plots exhibit a "normal" leak off behavior, and the "tangent" method provides a good stress estimate, and the compliance method lacks a clear signature for determining fracture closure. The stress interpretation results demonstrate that the process of fracture closure is highly impacted by rock properties, such as permeability and elastic moduli, and cyclic injection operations.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.39)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract Knowledge of in-situ stress is important for many subsurface science and engineering issues. The minimum principal stress (S3, or Shmin in most cases) is typically measured through mini-frac tests. Several methods have been suggested to interpret S3 using pressure data during the injection and/or shut-in phases of a mini-frac test. However, S3 interpreted from different methods is often inconsistent with each other and could result in large uncertainty in determining net pressure. This paper presents a series of small-scale laboratory hydraulic fracturing experiments conducted under true-triaxial compression. The injection scheme consists of a hydraulic fracturing cycle followed by a few fracture propagation cycles and several injection/falloff (DFIT) cycles. The wellbore pressure and acoustic emission (AE) activities of each cycle were concurrently measured to monitor fracture initiation, propagation, and closure during fluid injection and shut-in. The pressure data were used to interpret S3 using different hydraulic fracturing-based methods. The results illustrate that the spatial-temporal evolution of AE activities is well associated with fracture propagation. The stress interpretation results from the DFIT cycles demonstrate that fracture reopening pressure generally provides a reliable estimate of the minimum principal stress (S3). ISIP consistently provides a relatively higher estimate of S3 and can be used as an upper limit for constraining S3. Fracture closure was observed using the so-called "tangent" method in all DFIT tests. However, the "tangent" method using a signature close to the peak GdP/dG tends to significantly underestimate S3. The "compliance" method offers a relatively objective (yet still low) estimate of closure pressure. However, the signature associated with the change in system stiffness or compliance is observed but not consistently present in every DFIT cycle. It has been observed that the non-uniform fracture topography significantly impacts fracture closure behavior and the associated stress interpretation. Considering the complex nature of hydraulic fracturing in the subsurface, multiple techniques may need to be integrated for the determination of S3.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Propagating Hydraulic Fractures from Wellbores: Effects of In-Situ Stress and Near-Wellbore Stress Redistribution
Gao, Qian (College of New Energy, Xi’an Shiyou University) | Zhou, Desheng (College of Petroleum Engineering, Xi’an Shiyou University) | Ghassemi, Ahmad (The University of Oklahoma (Corresponding author)) | Liu, Xiong (College of Petroleum Engineering, Xi’an Shiyou University) | Liu, Yafei (The University of Oklahoma) | Guo, Minhao (College of Petroleum Engineering, Xi’an Shiyou University)
Summary As a mature technology to enhance the permeability of geological formations, hydraulic fracturing has widely been used in geothermal energy development and in the petroleum industry. Due to its effectiveness in practical applications, it attracts many research efforts. Because of the complexity of hydraulic fracturing itself and the complex distribution of stresses around wellbores, accurately describing the behaviors of hydraulic fractures is still a challenging task. In this study, a numerical model is developed to simulate curved propagation of hydraulic fractures from a wellbore, and emphases are placed on influence of in-situ stress and near wellbore stress redistribution. In the developed hydromechanical model, special considerations are given to its ability to simulate curved propagation of hydraulic fractures. The propagation of fractures is modeled through the phase-field method. Several cases on hydraulic fracture initiation and propagation from horizontal wellbores are studied through the proposed model. The model has been successfully verified through analytical solutions. The influence of stress redistribution caused by wellbore pressurization on hydraulic fracture initiation from wellbores is analyzed. Under different in-situ stress configurations and initial fracture orientations (perforation or flaws around wellbores are represented by the initial fractures), several patterns of hydraulic fracture propagation around the wellbores are recognized. It is found that the stress redistribution in the close vicinity of wellbores has great influences on the fracture initiation and propagation, and it makes hydraulic fractures propagate in nonplanar, complex manners. As hydraulic fractures propagate away from the stress redistribution regions around the wellbores, in-situ stress then determines the directions of fracture propagation; the curvature of fracture growth paths is mainly determined by the difference in in-situ stress, for example, σv − σhmin in this study. It has also been demonstrated that, when analyzing fracture propagation from wellbores, the wellbore stability or nonlinear deformation of a wellbore should be considered together with the fracture propagation conditions.
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Propagating Hydraulic Fractures from Wellbores: Effects of In-Situ Stress and Near-Wellbore Stress Redistribution
Gao, Qian (College of New Energy and College of Petroleum Engineering, Xi’an Shiyou University, and The University of Oklahoma (Corresponding author)) | Zhou, Desheng (College of Petroleum Engineering, Xi’an Shiyou University) | Ghassemi, Ahmad (The University of Oklahoma) | Liu, Xiong (College of Petroleum Engineering, Xi’an Shiyou University) | Liu, Yafei (College of Petroleum Engineering, Xi’an Shiyou University) | Guo, Minhao (Northwest University (Xi'an, China))
Summary As a mature technology to enhance the permeability of geological formations, hydraulic fracturing has widely been used in geothermal energy development and in the petroleum industry. Due to its effectiveness in practical applications, it attracts many research efforts. Because of the complexity of hydraulic fracturing itself and the complex distribution of stresses around wellbores, accurately describing the behaviors of hydraulic fractures is still a challenging task. In this study, a numerical model is developed to simulate curved propagation of hydraulic fractures from a wellbore, and emphases are placed on influence of in-situ stress and near wellbore stress redistribution. In the developed hydromechanical model, special considerations are given to its ability to simulate curved propagation of hydraulic fractures. The propagation of fractures is modeled through the phase-field method. Several cases on hydraulic fracture initiation and propagation from horizontal wellbores are studied through the proposed model. The model has been successfully verified through analytical solutions. The influence of stress redistribution caused by wellbore pressurization on hydraulic fracture initiation from wellbores is analyzed. Under different in-situ stress configurations and initial fracture orientations (perforation or flaws around wellbores are represented by the initial fractures), several patterns of hydraulic fracture propagation around the wellbores are recognized. It is found that the stress redistribution in the close vicinity of wellbores has great influences on the fracture initiation and propagation, and it makes hydraulic fractures propagate in nonplanar, complex manners. As hydraulic fractures propagate away from the stress redistribution regions around the wellbores, in-situ stress then determines the directions of fracture propagation; the curvature of fracture growth paths is mainly determined by the difference in in-situ stress, for example, σv − σhmin in this study. It has also been demonstrated that, when analyzing fracture propagation from wellbores, the wellbore stability or nonlinear deformation of a wellbore should be considered together with the fracture propagation conditions.
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
ABSTRACT: In this paper we present the results of a laboratory experimental study to measure the poroelastic properties of Utah FORGE reservoir rock. The target formations are granite and granodioritic rocks of low permeability so that the determination of their poroelastic properties is particularly challenging. In this work, we present the measurements of the Biot’s effective coefficient α and the Skempton’s B. The measurements on α are made by using strain gauges by following two different approaches: (1) α = 1 − K/Ks, K is the drained bulk modulus and Ks the grain bulk modulus; (2) α = −K/H, in which H is the so-called poroelastic expansion coefficient. These approaches yield two sets of data which can be compared. The Skempton’s B measurement is based on the equation α = Δpp/ΔPc|Δmf = 0, i.e., the ratio between pore pressure change and confining pressure change under an undrained condition, and distilled water is used as the pore fluid. The test results show that both the Biot’s coefficient and Skempton’s B are all stress dependent and decrease with the increase of the effective stress. Furthermore, we observe that the Biot’s coefficient falls in the range of [0.5, 1) rather than [0, 1) for many different types of rock, including the rock samples in this research. 1. INTRODUCTION Thermal energy is extracted from the reservoir by coupled transport processes (convective heat transfer in porous and/or fractured regions of rock and conduction through the rock itself). Enhanced Geothermal Systems (EGS) generates flow pathways and heat transfer area through a variety of stimulation methods, including hydraulic stimulation to the locations that lack natural permeability (Ghassemi, 2005; 2012; Tester et al., 2006). The Department of Energy (DOE) has established a dedicated subsurface laboratory called the Utah Frontier Observatory for Research in Geothermal Energy (Utah FORGE) in order to investigate and develop enhanced geothermal technology in 2014. The ultimate goal of the FORGE project is to demonstrate to the public, stakeholders and the energy industry that EGS technologies have the potential to contribute significantly to the future power generation (Moore, et al., 2020).
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.54)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Igneous Rock > Granite (0.36)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (0.34)
- North America > United States > New Mexico > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- North America > United States > Colorado > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Non-Traditional Resources > Geothermal resources (1.00)
A Preliminary Wellbore In-Situ Stress Model for Utah FORGE
Ye, Zhi (Reservoir Geomechanics and Seismicity Research Group, The University of Oklahoma) | Fang, Yuan (Reservoir Geomechanics and Seismicity Research Group, The University of Oklahoma) | Ghassemi, Ahmad (Reservoir Geomechanics and Seismicity Research Group, The University of Oklahoma) | McLennan, John (University of Utah)
ABSTRACT: Knowledge of the in-situ stress is very important to the geothermal reservoir development as well as to the planned R&D activities at the Utah FORGE. Whereas the vertical stress (Sv) and the minimum horizontal principal stress (Shmm) can reliably be determined through density logs and hydraulic fracturing tests, respectively, the determination of the magnitude of maximum horizontal principal stress (SHmax) is challenging. In this paper, we established a preliminary wellbore in-situ stress model for the Utah FORGE based on the drilling-induced fractures and wellbore breakouts observed in borehole image logs. We utilize stress polygon (frictional faulting theory), wellbore failure analysis, drilling-induced fractures, and borehole breakouts to constrain the magnitude of the SHmax in the well 78B-32 where both tensile and compressive failures occur. The constrained SHmax is in the range 0.83-0.98 psi/ft. The results are compiled to obtain a wellbore in-situ stress profile for the well 78B-32 which is in good agreement with other data. 1. INTRODUCTION Understanding the magnitude and orientation of in-situ stress is important to many subsurface science and engineering problems. In the development of an Enhanced Geothermal System (EGS), the knowledge of in-situ stress impacts several aspects such as reservoir characterization, deep well drilling, hydraulic stimulation, and induced seismicity. Constraining the in-situ stress requires the determination of a stress tensor with six independent unknowns (the magnitudes of three principal stresses and their orientations). In most geological settings within the Earth’s upper crust, we can assume that the three principal stresses are vertical stress (Sv), and two horizontal principal stresses (Shmin and SHmax). In general, the magnitude of vertical principal stress (Sv) is obtained by integrating the density logs, and the magnitude of minimum principal stress (Shmin) can be measured through hydraulic fracturing tests (e.g., DFIT, leak-off test, microfrac test). In addition, the orientations of Shmin and SHmax can be identified using observed wellbore failures (breakouts and drilling-induced fractures), crossed-dipole sonic logs, and seismic focal mechanisms. However, the determination of the magnitude of maximum horizontal principal stress (SHmax) is challenging.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (0.34)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Hydraulic fracturing is extensively used to stimulate unconventional oil and gas and geothermal reservoirs. The fluid is pumped into a selected section of the wellbore to create and extend a fracture(s) into the formation. The applied pressure in the fracture(s) re-distributes the pore pressure and stresses in the reservoir. This will cause in-situ stress re-orientation and possibly reversal and potentially lead to rock deformation and failure by fracture initiation, and/or activation of discontinuities such as joints and bedding planes. The net result is the enhancement of the formation permeability. The rock failure process is often accompanied by micro-seismicity that can provide useful information regarding the stimulated volume. In this work, we revisit poroelastic mechanisms and assess their contribution to the creation of a stimulated volume, refracturing, and the occurrence of fracture swarms using fully coupled poroelastic models. Simulation results show that rock failure can occur in the vicinity of the fracture, especially near the fracture tips. The dominant failure mode is tension in the close vicinity of the fracture, where the pore pressure attains its highest values. Shear failure potential exists away from the fracture walls, where shear stresses are sufficiently high to overcome the strength of the rock and/or its fabric features. On the other hand, analysis shows that while the hydraulic fracture is pressurized, it is unlikely that the coupled poroelastic effects would result in the initiation and propagation of multiple hydraulic fractures to form the so-called fracture swarms at some distance away from the hydraulic fracture surfaces. Such a possibility might exist under some special conditions e.g., flow in natural fracture or other higher permeable zones but only when the reservoir pore pressure is nearly equal to the Shmin. In addition, swarm fracture might form if the net stress on the main hydraulic fracture is removed (by depressurization) while the pore pressure has increased to near critical levels. These closely-spaced fractures can propagate in parallel to substantial lengths in the presence of a strong stress differential, lower fracture toughness, and high injection rates. Finally, poroelastic effects promote fracture-driven interactions (FDI). A hydraulic fracture tends to preferentially grow towards the low-pressure zones, resulting in an asymmetric fracture geometry in the lateral or upward direction. Finally, when using pressure monitoring to quantify the next pressure, it is critical to use a reasonable value for the Skempton's pore pressure coefficient. Overestimation of this parameter results in underestimation of the net pressure.
- North America > United States > Texas (1.00)
- North America > United States > California (0.68)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract The communication among the horizontal wells or "frac-hits" issue have been reported in several field observations. These observations show that the "infill" well fractures could have a tendency to propagate towards the "parent" well depending on reservoir in-situ conditions and operational parameters. Drilling the horizontal wells in a "staggered" layout with both horizontal and vertical offset could be a mitigation strategy to prevent the "frac-hits" issue. In this study, we present a detailed geomechanical modeling and analysis of the proposed solution. For numerical modeling, we used our state-of-the-art fully coupled poroelastic model "GeoFrac-3D" which is based on the boundary element method for the rock matrix deformation/fracture propagation and the finite element method for the fracture fluid flow. The "GeoFrac-3D" simulator fully couples pore pressure to stresses and allows for dynamic modeling of production/injection and fracture propagation. The simulation results demonstrate that production from a "parent’ well causes a non-uniform reduction of the reservoir pore pressure around the production fractures, resulting in an anisotropic decrease of the reservoir total stresses, which could affect fracture propagation from the "infill" wells. We examine the optimal orientation and position of the "infill" well based on the numerical analysis to reduce the "frac-hits" issue in the horizontal well refracturing. The posibility of "frac-hits" can be reduced by optimizing the direction and locations of the "infill" wells, as well as re-pressurizing the "parent" well. The results suggest that arranging the horizontal wells in a "staggered" or "wine rack" arrangement decreases direct well interference and could increase the drainage volume.
- North America > United States > Oklahoma (1.00)
- North America > United States > Texas (0.94)
- North America > United States > California (0.94)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (7 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Summary The impacts of formation layering on hydraulic fracture containment and on pumping energy are critical factors in a successful stimulation treatment. Conventionally, it is considered that the in-situ stress is the dominant factor controlling the fracture height. The influence of mechanical properties on fracture height growth is often ignored or is limited to consideration of different Young’s moduli. Also, it is commonly assumed that the interfaces between different layers are perfectly bounded without slippage, and interface permeability is not considered. In-situ experiments have demonstrated that variation of modulus and in-situ stress alone cannot explain the containment of hydraulic fractures observed in the field (Warpinski et al. 1998). Enhanced toughness, in-situ stress, interface slip, and energy dissipation in the layered rocks should be combined to contribute to the fracture containment analysis. In this study, we consider these factors in a fully coupled 3D hydraulic fracture simulator developed based on the finite element method. We use laboratory and numerical simulations to investigate these factors and how they affect hydraulic fracture propagation, height growth, and injection pressure. The 3D fully coupled hydromechanical model uses a special zero-thickness interface element and the cohesive zone model (CZM) to simulate fracture propagation, interface slippage, and fluid flow in fractures. The nonlinear mechanical behavior of frictional sliding along interface surfaces is considered. The hydromechanical model has been verified successfully through benchmarked analytical solutions. The influence of layered Young’s modulus on fracture height growth in layered formations is analyzed. The formation interfaces between different layers are simulated explicitly through the use of the hydromechanical interface element. The impacts of mechanical and hydraulic properties of the formation interfaces on hydraulic fracture propagation are studied. Hydraulic fractures tend to propagate in the layer with lower Young’s modulus so that soft layers could potentially act as barriers to limit the height growth of hydraulic fractures. Contrary to the conventional view, the location of hydraulic fracturing (in softer vs. stiffer layers) does affect fracture geometry evolution. In addition, depending on the mechanical properties and the conductivity of the interfaces, the shear slippage and/or opening along the formation interfaces could result in flow along the interface surfaces and terminate the fracture growth. The frictional slippage along the interfaces can serve as an effective mechanism of containment of hydraulic fractures in layered formations. It is suggested that whether a hydraulic fracture would cross a discontinuity depends not only on the layers’ mechanical properties but also on the hydraulic properties of the discontinuity; both the frictional slippage and fluid pressure along horizontal formation interfaces contribute to the reinitiation of a hydraulic fracture from a pre-existing flaw along the interfaces, producing an offset from the interception point to the reinitiation point.
- North America > United States (1.00)
- North America > Canada > Alberta (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract Containment and what might constitute a barrier to the created fractures is an important technical issue. The question is how to maximize the stimulated volume without encroaching on neighboring strata. Key to effective fracturing and its containment is the understanding of the underlying mechanisms in shale fracturing and its interaction with the bounding layers. The ability of the adjacent strata to act as a barrier depends on the stress state, ductility, fracture toughness, elastic properties, and permeability as well as the interface or discontinuity properties. Rock heterogeneity influences the rock mass stiffness and fracture propagation rates and thus needs to be considered. In this paper we focus on the role of overburden and underburden mechanical properties and toughness contrast on growth of a hydraulic fracture. In view of the 3D problem complexity, we use a fully coupled 3D numerical model to analyze height growth from the payzone into bounding layers. The DD method is very efficient for this type of a problem using different approaches. A more efficient approach for a reservoir bounded by contrasting layers above and below is a 3D DD for multiple bonded planes. The 3D DD method proposed in this study is coupled with a finite difference fluid flow model to simulate the propagation of hydraulic fractures under constant injection rate or injection pressure in layered rocks. Our results show that fracture geometry distorts from its radial shape to a more elliptical shape as stress barriers restrict height propagation. The fracture width profile also starts to deviate from its symmetric shape as the fracture approaches the barrier which has implications in the proppant placement. The simulations indicate that the degree of containment varies depending upon the magnitude of stress barriers, fluid viscosity, pumping rate, and leak-off. The contrast between the elastic modulus of the adjacent layers also influences height containment but its effect was found to be less than that of stress contrast. Although fracture containment and the influence of stress barriers and material heterogeneity is studied in the past, the widely-used P3D models are restricted due to their underlying of the vertical plane-strain condition which dictates a PKN type of fracture. The current model, however, does not prescribe any type of propagation geometry and fracture geometry is determined based on the in-situ conditions. Moreover, the rigorous hydro-mechanical coupling helps to further our understanding of proppant placement in layered rock.
- North America > United States > Texas (0.28)
- North America > United States > Oklahoma (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.61)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (0.95)