Annavarapu, Chandrasekhar (Lawrence Livermore National Laboratory) | Settgast, Randolph (Lawrence Livermore National Laboratory) | Johnson, Scott (Lawrence Livermore National Laboratory) | Fu, Pengcheng (Lawrence Livermore National Laboratory) | Herbold, Eric B. (Lawrence Livermore National Laboratory)
We propose a stabilized approach based on Nitsche's method for enforcing contact constraints over crack surfaces. The proposed method addresses the shortcomings of conventional penalty and augmented Lagrange multiplier approaches by combining their attractive features. Similar to an augmented Lagrange multiplier approach, the proposed method has a consistent variational basis resulting in stronger enforcement of the non-interpenetration constraint. At the same time, the proposed method is purely displacement-based and alleviates the stability challenges common to mixed methods. The method also retains the computational efficiency of penalty approaches by eliminating the outer augmentation loop necessary for augmented Lagrangian approaches and resulting in smaller system matrices.
In this study we will show how fractographic (i.e., fracture surface morphology) data of exfoliation fractures (i.e., fractures subparallel to landscape surfaces limited to near-surface rock masses) and three-dimensional numerical modeling can be used to infer orientations of principal rock mass stresses in topographically complex Alpine areas. Analysis of exfoliation fracture plumose axes, i.e., fractographic features that indicate main fracture propagation directions, and supposed local maximum compressive principal stress (σ1) orientations at the time of fracture formation, suggests complex directional trends of near-surface σ1 within trough valleys of the Grimsel region (central Swiss Alps). We investigated near-surface stress tensors with a threedimensional, elastic numerical model to 1. deduce evidence that plumose axes form parallel to σ1 in an overall compressive (farfield) stress field, and to 2. increase our knowledge of near-surface stress orientations in Alpine settings. Model results illustrate that superposition of topographic stresses with realistic horizontal strains reveals complex near-surface s1 trajectories that widely follow the patterns of plumose axes. The model results demonstrate large variations of stress orientations, which cannot be captured by small numbers of classical stress measurements. In-situ stress measurements support exfoliation fracture formation under compression and principal stress directions as inferred from our numerical model.
Hydraulic fracturing technique has been widely applied in the enhanced geothermal systems, to increase injection rates for geologic sequestration of CO2, and most importantly for the stimulations of oil and gas reservoirs, especially the unconventional shale reservoirs. One of the key points for the success of hydraulic fracturing operations is to accurately estimate the redistribution of pore pressure and stresses around the induced fracture and predict the reactivations of pre-existing faults. The fracture extension as well as pore pressure and stress regime around it are affected by: poro- and thermoelastic phenomena as well as by fracture opening under the combined action of applied pressure and in-situ stress. A couple of numerical studies have been done for the on this for the purpose of analyzing the potential for fault reactivation resulting from pressurization of the hydraulic fracture. In this work, a comprehensive analytical model is constructed to estimate the stress and pore pressure distribution around an injection induced fracture from a single well in an infinite reservoir. The model allows the leak-off distribution in the formation to be three-dimensional with the pressure transient moving ellipsoidcally outward into the reservoir with respect to the fracture surface. The pore pressure and the stress changes in three dimensions at any point around the fracture caused by thermo- and poroelasticity and fracture compression are investigated. Then, the problem of constant water injection into a hydraulic fracture in Barnett shale is presented. In particular, with Mohr-Coulomb failure criterion, we calculate the fault reactivation potential around the fracture. This study is of interest in interpretation of micro-seismicity in hydraulic fracturing and in assessing permeability variation around a stimulation zone, as well as in estimation of the fracture spacing during hydraulic fracturing operations.
This contribution will examine the design and capabilities of a new measuring system, specifically a high-pressure vessel, which not only enables ultrasonic sounding of rock samples by means of longitudinal P waves, but also by two perpendicularly polarized shear waves on spherical samples under hydrostatic pressures up to 100 MPa. The advantage of our approach is that it allows for the simultaneous measurement of P, S1 and S2 wave velocity propagation in 132 independent directions throughout the entire sphere (except the sphere poles). This new system was designed and constructed to enable the use of movable shear wave transducers (transmitter/receiver) in oil under confining stress. The same high-pressure measuring system enables the measurement of sample deformation in the points of P-wave ultrasonic sounding up to 400 MPa, what enables that mutual dependence between static and dynamic rock parameters to be studied. Data obtained will enable the calculation of many important seismic parameters like elastic anisotropy, crack presence and orientation, crack density tensor, their directional changes and closure under pressure, elastic wave attenuation and finally, full elastic stiffness tensor at different values of hydrostatic pressure. A laboratory approach based on this new high-pressure system enables the study of rock dynamic and static bulk moduli under different values of hydrostatic pressure.
In this paper, the results of laboratory studies of hydraulic fracture in homogeneous sandstone blocks with man-made interfaces and heterogeneous shale blocks with weak natural interfaces are reported. Tests were conducted under similar stress conditions, with fluids of different viscosity and at different injection rates. The measurements and analysis allows the identification of fracture initiation and behavior. Fracturing with high viscosity fluids resulted in stable fracture propagation initiated before breakdown, while fracturing with low viscosity fluids resulted in unstable fracture propagation initiated almost simultaneously with breakdown. Analysis also allows us to measure the fluid volume entering the fracture and the fracture volume. Monitoring of Acoustic Emission (AE) hypocenter localizations, indicates the development of created fractured area including the intersection with interfaces, fluid propagation along interfaces, crossing interfaces, and approaching the boundaries of the block. We observe strong differences in hydraulic fracture behavior, fracture geometry and fracture propagation speed, when fracturing with water and high viscosity fluids. We also observed distinct differences between sandstone blocks and shale blocks, when a certain P-wave velocity ray path is intersected by the hydraulic fracture. The velocity increases in sandstones and decreases in shale.
In naturally fractured shale oil and gas reservoirs, it is expected that the hydraulic fracture behavior is significantly influenced by the interaction with pre-existing natural fractures. However, the relationship between fracture behaviors and natural fractures has not been sufficiently clarified because direct observation of all the fractures or microcracks generated during the field or laboratory scale hydraulic fracturing is difficult. In this paper, a series of flow-coupled DEM simulations varying the properties of natural fracture, such as the permeability of natural fractures and the angle between created hydraulic fracture and natural fracture (approach angle), is presented. As a results, different fracture growth patterns were observed with different combination of approach angle and permeability of natural fracture. When the approach angle is high and the permeability is low, the hydraulic fracture ignores the existence of natural fracture and it propagated straight to the direction of maximum compressive principal stress. On the other hand, when the approach angle is low and the permeability is high, hydraulic fracture propagated along with a natural fracture. After that, it branched or curved to the direction of maximum principal stress.
Hydraulic fracturing re-distributes pore pressure and stresses inside rock and causing failure by fracture initiation and/or activation of discontinuities such as natural fractures or layering boundaries. The clear result of this process would be enhancement of the formation permeability. In this paper, poroelastic numerical method is employed to investigate interactions of hydraulic fractures and porous rock. Besides, evolution of potential failure (microseismic events) during hydraulic stimulation is studied. The model uses indirect boundary element method. Temporal variations and pressure-dependent leak-off, hydro mechanical response of porous matrix, fluid flow in matrix, couplings of matrix volumetric deformation and pore fluid dissipation, and hydraulic fractures interaction are taken into account. Results clearly show the modification/redirection of principal stresses around pressurized hydraulic fracture. It also shows that modified stresses cause failure around the fracture tip which generally covers a bigger area than the fracture itself and could results in an overestimation of the stimulated reservoir volume. Then, pressurization of multiple parallel fractures studied. As expected, it is found that fracture geometry and the distance between hydraulic fractures are the most important factors in modifying the stress state and pore pressure and consequently extent of failure region. It was also observed that the opening of a fracture induces shear stresses on adjacent fractures. The SIF for pressurized cracks was calculated for Mode I and Mode II, and it was shown that when the distance between hydraulic fractures increases, the Mode I SIF also increases and the Mode II SIF decreases.'ép.
According to the technical guide for grouting method for dam construction in Japan modified in the year 2003, one of the key issues for grouting is quality assurance and effectiveness by minimizing the amount of injected grout. Hence, the grouting management support system was newly developed by combining joint density diagram and geostatistical simulations. In this system, the joint density diagram was used to determine most effective direction for the grout injection boreholes and the hydraulic conductivity fields before/after grout injection were estimated by geostatistical simulations. In this paper, the newly developed system was introduced and applied to the actual underground structure construction site.
Experiments have been performed with Mancos Shale under Brazilian tensile test conditions, addressing the effect of the angle between layer or bedding planes and the loading direction. A high-speed camera with digital image correlation software is used in combination with acoustic emission recording to monitor the fracture initiation and growth processes during loading. Although a clear anisotropy is observed in the variation of the P-wave velocity with the inclination angle, a significant effect on the Brazilian tensile strength is not observed. The mode of failure depends however on sample orientation. For all specimens, a main diametrical central fracture is induced first. It originates in the middle of the specimen and grows as a straight line or as a zig-zag line, depending on the orientation of the sample with respect to load direction. The zig-zag fracture is then a combination of a fracture along the weak direction and in other directions. Its evolution is an order of magnitude slower than that of a brittle straight diametrical central fracture.
Fracturing stimulation technologies allow the oil and gas industry to effectively use fracturing treatments to improve the production of many shale gas and oil reservoirs. Because of pre-existing natural fractures in such reservoirs and their interactions with hydraulically induced fractures, hydraulic fracturing treatments often result in complex fracture networks (CFNs). The numerical simulation of hydraulic fracturing of these CFNs is necessary for efficient and productive planning and development of such reservoirs. Fundamentally, hydraulic fracturing simulation is a fluid-structure interaction (FSI) that includes the deformation and movement of rock blocks, the fluid flow in opened fractures, and their interactions. A comprehensive study of the physics and engineering aspects of the FSI still present a challenge primarily because of their strong non-linearity and multi-disciplinary nature. This paper presents a tightly coupled FSI numerical model and computational algorithm for hydraulic fracturing simulations in predetermined fracture networks.