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Summary Microseismic mapping during the hydraulic-fracturing processes in the Vaca Muerta (VM) Shale in Argentina shows a group of microseismic events occurring at shallower depth and at later injection time, and they clearly deviate from the growing planar hydraulic fracture. This spatial and temporal behavior of these shallow microseismic events incurs some questions regarding the nature of these events and their connectivity to the hydraulic fracture. To answer these questions, in this article, we investigate these phenomena by use of a true 3D fracture-propagation-modeling tool along with statistical analysis on the properties of microseismic events. First, we propose a novel technique in Abaqus incorporating fracture intersections in true 3D hydraulic-fracture-propagation simulations by use of a pore-pressure cohesive zone model (CZM), which is validated by comparing our numerical results with the Khristianovic-Geertsma-de Klerk (KGD) solution (Khristianovic and Zheltov 1955; Geertsma and de Klerk 1969). The simulations fully couple slot flow in the fracture with poroelasticity in the matrix and continuum-based leakoff on the fracture walls, and honor the fracture-tip effects in quasibrittle shales. By use of this model, we quantify vertical-natural-fracture activation and fluid infiltration depending on reservoir depth, fracturing-fluid viscosity, mechanical properties of the natural-fracture cohesive layer, natural-fracture conductivity, and horizontal stress contrast. The modeling results demonstrate this natural-fracture activation in coincidence with the hydraulic-fracture-growth complexities at the intersection, such as height throttling, sharp aperture reduction after the intersection, and multibranching at various heights and directions. Finally, we investigate the hydraulic-fracture intersection with a natural fracture in the multilayer VM Shale. We infer the natural-fracture location and orientation from the microseismic-events map and formation microimager log in a nearby vertical well, respectively. We integrate the other field information such as mechanical, geological, and operational data to provide a realistic hydraulic-fracturing simulation in the presence of a natural fracture. Our 3D fracturing simulations equipped with the new fracture-intersection model rigorously simulate the growth of a realistic hydraulic-connection path toward the natural fracture at shallower depths, which was in agreement with our microseismic observations.
Summary The prevailing approach for hydraulic-fracture modeling relies on linear-elastic fracture mechanics (LEFM). Generally, LEFM that uses stress-intensity factor at the fracture tip gives reasonable predictions for hard-rock hydraulic-fracturing processes, but often fails to give accurate predictions of fracture geometry and propagation pressure in formations that can undergo plastic failures, such as poorly consolidated/unconsolidated sands and ductile shales. This is because the fracture-process zone ahead of the crack tip, elasto-plastic material behavior, and strong coupling between flow and stress cannot be neglected in these formations. Recent laboratory testing has revealed that in many cases, fracture-propagation conditions cannot be described by traditional LEFM models. Rather, fractures develop in cohesive zones. In this study, we developed a fully coupled poro-elasto-plastic hydraulic-fracturing model by combining the cohesive-zone method with the Mohr-Coulomb theory of plasticity, which not only can model fracture initiation and growth while considering process-zone effects, but also can capture the effects of plastic deformation in the bulk formation. The impact of the formation plastic properties on the fracture process is investigated, and the results are compared with existing models. In addition, the effects of different parameters on fracture propagation in ductile formations are also investigated through parametric study. The results indicate that plastic and highly deforming formations exhibit greater breakdown and propagation pressure. The more plastic the formation (lower cohesion strength), the higher the net pressure required to propagate the fracture. Also, lower cohesion strength leads to shorter and wider fracture geometry. The effect of formation plasticity on a hydraulic fracture is mostly controlled by initial stress contrast, cohesion strength of formation rock, and pore pressure. We also found that altering the effective fracture toughness can only partially mimic the consequences of increased toughness ahead of the fracture tip in ductile formations, but it fails to capture the effect of shear failure within the entire affected area, which can lead to underestimating the fracture width and overestimating the fracture length. For a more-accurate modeling of fracturing in ductile formations, the entire plastic-deformation region induced by the propagating fracture should be considered, especially when shear-failure areas are large.
Rho, S. (Texas A&M University) | Noynaert, S. (Texas A&M University) | Bunger, A. P. (University of Pittsburgh) | Zolfaghari, N. (University of Pittsburgh) | Xing, P. (University of Pittsburgh) | Abell, B. (W.D. Von Gonten Laboratories) | Suarez-Rivera, R. (W.D. Von Gonten Laboratories)
ABSTRACT: Numerical simulations of hydraulic fracture (HF) propagation through layered rocks show the effects of rock layering and interfaces on fracture height growth. When the contrast in properties between adjacent rock layers is high and abrupt, the resulting interface between these layers is often weak, exhibiting low tensile strength, low friction coefficient, and high hydraulic conductivity. Thus, they easily detach (in tension) and slip (in shear), as the hydraulic fracture crosses them, creating localized obstacles for fracture propagation as well as localized zones of fluid loss. Numerical simulations were conducted using the newly-implemented pore pressure cohesive elements as certain predefined hydraulic fracture and interface opening paths in ABAQUS 2016. To validate the model and for comparison we conducted simulations on elastically-homogeneous and elastically-layered rocks and, for the latter, we used a range of tensile strength and fluid flow properties at the interfaces between layers, to understand their impact on vertical hydraulic fracture (height) growth. Our results show a systematic decrease in fracture height and fracturing fluid efficiency with increasing interface hydraulic conductivity. This relationship is important because of its potential impact on improving fracture diagnostics in the field. We also observe that the interface strength directly affects fracture height growth as well as fluid efficiency. These findings are important for a proper assessment of fracture height growth, a better assessment of the created fracture surface area, and better predictions of well production.
Hydraulic fracturing (HF) treatments have been widely used to enhance oil and gas production (Economides and Nolte, 2000; Holditch, 2006). Improving the representation of these treatments with more adequate numerical modeling is important because it helps to increase the created fracture surface area, to reduce completion costs, and to improve well production. When considering more complex reservoirs, such as shale and mudstone, numerical simulation of the hydraulic fracture treatments is considerably more challenging because of the layered nature of the rock and the impact of the associated interfaces of contact between layers, inhomogeneity, and pre-existing natural fractures on hydraulic fracture growth.
The model fully 2011; Dahi-Taleghani and Olson 2011; Weng et al. 2011; Dahi-couples fluid flow, fracture propagation, and elastic deformation, Taleghani and Olson 2014; Gonzalez et al. 2015) investigations taking into account the friction between the contacting fracture surfaces and the interaction between the HF and the NF. The have been conducted to analyze HF propagation across pre-existing effect of the field conditions--such as in-situ stresses, rock and interfaces. The interaction of an HF with pre-existing NFs fracture mechanical and geometrical (initial conductivity of the depends on in-situ stresses, fracture-intersection angle, rockmechanical NF) properties, intersection angle, and the treatment parameters properties, NF properties (interfacial shear capacity (fracturing fluid viscosity and injection rate)--on the HF propagation and friction), and fracturing-fluid viscosity and injection rate behavior has been analyzed. The finite-element-modeling (Simonson et al. 1978; Warpinski et al. 1982; Blanton 1982; Teufel results provide detailed quantitative information on the development and Clark 1984; Thiercelin et al. 1987; Warpinski and Teufel of various types of HF/NF interaction, interfacial stress distribution, 1987). Assuming that the approaching HF initially will be arrested fracture-geometry evolution, and injection-pressure by a pre-existing NF, and using a linear distribution of the shear history, and allow us to gain an in-depth understanding of the relative and normal stresses along the NF, Blanton (1986) presented a roles of various parameters. The value of a parameter calculated simple analytical criterion for predicting the fracture interaction as the product of fracturing-fluid viscosity and injection rate under various differential-stress and intersection-angle conditions.
Summary We built a 3D geomechanical model using commercially available finite-element-analysis (FEA) software to simulate a propagating hydraulic fracture (HF) and its interaction with a vertical natural fracture (NF) in a tight medium. These newly introduced elements have the ability to model the fluid continuity at an HF/NF intersection, the main area of concern. We observed that, for a high-stress-contrast scenario, the NF cohesive elements showed less damage when compared with the lowstress-contrast case. Also, for the scenario of high stress contrast with principal horizontal stresses reversed, the HF intersected, activated, and opened the NF. Increasing the injection rate resulted in a longer and wider HF but did not significantly affect the NF-activated length. Injection-fluid viscosity displayed an inverse relationship with the HF length and a proportional relationship with the HF opening or width. We observed that a weak NF plane temporarily restricts the HF propagation. On the other hand, a tougher NF, or an NF with properties similar to its surroundings, does not show this type of restriction. The NF activated length was found at its maximum in the case of a weaker NF and at nearly zero in the case of a stronger NF and an NF that has strength similar to its surroundings. In this study we present the results for a three-layered 3D geomechanical model with a single HF and NF orthogonally intersecting each other, using newly introduced cohesive elements for the first time in technical literature. We also conducted a detailed sensitivity analysis considering the effect of stress contrast, injection rate, injection-fluid viscosity, and NF properties on this HF/NF interaction. These results provide an idea of how the idealized resultant fracture geometry will change when several fracture/fracture treatment properties are varied. Introduction The issue of HF and NF interaction has been numerically examined using software packages at both the laboratory and field levels. Warpinski and Teufel (1987) experimentally found that the HFs propagated through joints and formed a multistranded and nonplanar fracture network. The presence of a similar network was also observed in core samples from tight-sandstone reservoirs. Warpinski (1993) and Fisher et al. (2002) interpreted some of the Barnett Shale microseismic data and found that the HF propagation and orientation was affected by the already existing NFs. Lancaster et al. (1992) conducted a core study and found that the HF can propagate along an NF, resulting in propped NFs.