The Impact of Layering and Permeable Frictional Interfaces on Hydraulic Fracturing in Unconventional Reservoirs

2021 ◽  
pp. 1-14
Author(s):  
Qian Gao ◽  
Ahmad Ghassemi
Keyword(s):  
Mechanical Properties ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
In Situ Stress ◽  
Height Growth ◽  
Interface Element ◽  
Hydraulic Fractures ◽  
Hydraulic Fracture Propagation ◽  
Fracture Height

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.

scholarly journals Apparent Toughness Anisotropy Induced by “Roughness” of In-Situ Stress: A Mechanism That Hinders Vertical Growth of Hydraulic Fractures and Its Simplified Modeling

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 2148-2162 ◽  
Author(s):  
Pengcheng Fu ◽  
Jixiang Huang ◽  
Randolph R. Settgast ◽  
Joseph P. Morris ◽  
Frederick J. Ryerson
Keyword(s):  
Hydraulic Fracture ◽  
High Stress ◽  
In Situ Stress ◽  
Height Growth ◽  
Hydraulic Fractures ◽  
Simple Relationship ◽  
Vertical Growth ◽  
Stress Profiles ◽  
Fracture Height

Summary The height growth of a hydraulic fracture is known to be affected by many factors that are related to the layered structure of sedimentary rocks. Although these factors are often used to qualitatively explain why hydraulic fractures usually have well–bounded height growth, most of them cannot be directly and quantitatively characterized for a given reservoir to enable a priori prediction of fracture–height growth. In this work, we study the role of the “roughness” of in–situ–stress profiles, in particular alternating low and high stress among rock layers, in determining the tendency of a hydraulic fracture to propagate horizontally vs. vertically. We found that a hydraulic fracture propagates horizontally in low–stress layers ahead of neighboring high–stress layers. Under such a configuration, a fracture–mechanics principle dictates that the net pressure required for horizontal growth of high–stress layers within the current fracture height is significantly lower than that required for additional vertical growth across rock layers. Without explicit consideration of the stress–roughness profile, the system behaves as if the rock is tougher against vertical propagation than it is against horizontal fracture propagation. We developed a simple relationship between the apparent differential rock toughness and characteristics of the stress roughness that induce equivalent overall fracture shapes. This relationship enables existing hydraulic–fracture models to represent the effects of rough in–situ stress on fracture growth without directly representing the fine–resolution rough–stress profiles.

Investigation of Rupture and Slip Mechanisms of Hydraulic Fractures in Multiple-Layered Formations

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 2292-2307 ◽  
Author(s):  
Jizhou Tang ◽  
Kan Wu ◽  
Lihua Zuo ◽  
Lizhi Xiao ◽  
Sijie Sun ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Propagation Model ◽  
Rock Deformation ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Fracture Width ◽  
Hydraulic Fracture Propagation ◽  
Fracture Height

Summary Weak bedding planes (BPs) that exist in many tight oil formations and shale–gas formations might strongly affect fracture–height growth during hydraulic–fracturing treatment. Few of the hydraulic–fracture–propagation models developed for unconventional reservoirs are capable of quantitatively estimating the fracture–height containment or predicting the fracture geometry under the influence of multiple BPs. In this paper, we introduce a coupled 3D hydraulic–fracture–propagation model considering the effects of BPs. In this model, a fully 3D displacement–discontinuity method (3D DDM) is used to model the rock deformation. The advantage of this approach is that it addresses both the mechanical interaction between hydraulic fractures and weak BPs in 3D space and the physical mechanism of slippage along weak BPs. Fluid flow governed by a finite–difference methodology considers the flow in both vertical fractures and opening BPs. An iterative algorithm is used to couple fluid flow and rock deformation. Comparison between the developed model and the Perkins–Kern–Nordgren (PKN) model showed good agreement. I–shaped fracture geometry and crossing–shaped fracture geometry were analyzed in this paper. From numerical investigations, we found that BPs cannot be opened if the difference between overburden stress and minimum horizontal stress is large and only shear displacements exist along the BPs, which damage the planes and thus greatly amplify their hydraulic conductivity. Moreover, sensitivity studies investigate the impact on fracture propagation of parameters such as pumping rate (PR), fluid viscosity, and Young's modulus (YM). We investigated the fracture width near the junction between a vertical fracture and the BPs, the latter including the tensile opening of BPs and shear–displacement discontinuities (SDDs) along them. SDDs along BPs increase at the beginning and then decrease at a distance from the junction. The width near the junctions, the opening of BPs, and SDDs along the planes are directly proportional to PR. Because viscosity increases, the width at a junction increases as do the SDDs. YM greatly influences the opening of BPs at a junction and the SDDs along the BPs. This model estimates the fracture–width distribution and the SDDs along the BPs near junctions between the fracture tip and BPs and enables the assessment of the PR required to ensure that the fracture width at junctions and along intersected BPs is sufficient for proppant transport.

Containment of Massive Hydraulic Fractures

1978 ◽  
Vol 18 (01) ◽  
pp. 27-32 ◽  
Author(s):  
E.R. Simonson ◽  
A.S. Abou-Sayed ◽  
R.J. Clifton
Keyword(s):  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Fracture Propagation ◽  
Rocky Mountain ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Pressure Gradients ◽  
In Situ Stresses ◽  
Gas Bearing

Abstract Hydraulic fracture containment is discussed in relationship to linear elastic fracture mechanics. Three cases are analyzed,the effect of different material properties for the pay zone and the barrier formation,the characteristics of fracture propagation into regions of varying in-situ stress, propagation into regions of varying in-situ stress, andthe effect of hydrostatic pressure gradients on fracture propagation into overlying or underlying barrier formations. Analysis shows the importance of the elastic properties, the in-situ stresses, and the pressure gradients on fracture containment. Introduction Application of massive hydraulic fracture (MHF) techniques to the Rocky Mountain gas fields has been uneven, with some successes and some failures. The primary thrust of rock mechanics research in this area is to understand those factors that contribute to the success of MHF techniques and those conditions that lead to failures. There are many possible reasons why MHF techniques fail, including migration of the fracture into overlying or underlying barrier formations, degradation of permeability caused by application of hydraulic permeability caused by application of hydraulic fracturing fluid, loss of fracturing fluid into preexisting cracks or fissures, or extreme errors in preexisting cracks or fissures, or extreme errors in estimating the quantity of in-place gas. Also, a poor estimate of the in-situ permeability can result in failures that may "appear" to be caused by the hydraulic fracture process. Previous research showed that in-situ permeabilities can be one order of magnitude or more lower than permeabilities measured at near atmospheric conditions. Moreover, studies have investigated the degradation in both fracture permeability and formation permeability caused by the application of hydraulic fracture fluids. Further discussion of this subject is beyond the scope of this paper. This study will deal mainly with the containment of hydraulic fractures to the pay zone. In general, the lithology of the Rocky Mountain region is composed of oil- and gas-bearing sandstone layers interspaced with shales (Fig. 1). However, some sandstone layers may be water aquifers and penetration of the hydraulic fracture into these penetration of the hydraulic fracture into these aquifer layers is undesirable. Also, the shale layers can separate producible oil- and gas-bearing zones from nonproducible ones. Shale layers between the pay zone and other zones can be vital in increasing successful stimulation. If the shale layers act as barrier layers, the hydraulic fracture can be contained within the pay zone. The in-situ stresses and the stiffness, as characterized by the shear modulus of the zones, play significant roles in the containment of a play significant roles in the containment of a hydraulic fracture. The in-situ stresses result from forces in the earth's crust and constitute the compressive far-field stresses that act to close the hydraulic fracture. Fig. 2 shows a schematic representation of in-situ stresses acting on a vertical hydraulic fracture. Horizontal components of in-situ stresses may vary from layer to layer (Fig. 2). For example, direct measurements of in-situ stresses in shales has shown the minimum horizontal principal stress is nearly equal to the overburden principal stress is nearly equal to the overburden stress. SPEJ P. 27

Investigation of the influence of natural fractures and in situ stress on hydraulic fracture propagation using a distinct-element approach

2015 ◽  
Vol 52 (7) ◽  
pp. 926-946 ◽  
Author(s):  
N. Zangeneh ◽  
E. Eberhardt ◽  
R.M. Bustin
Keyword(s):  
Rock Mass ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Distinct Element ◽  
Fracture Propagation ◽  
In Situ Stress ◽  
Natural Fractures ◽  
Geological Conditions ◽  
Hydraulic Fracture Propagation

Hydraulic fracturing is the primary means for enhancing rock mass permeability and improving well productivity in tight reservoir rocks. Significant advances have been made in hydraulic fracturing theory and the development of design simulators; however, these generally rely on continuum treatments of the rock mass. In situ, the geological conditions are much more complex, complicated by the presence of natural fractures and planes of weakness such as bedding planes, joints, and faults. Further complexity arises from the influence of the in situ stress field, which has its own heterogeneity. Together, these factors may either enhance or diminish the effectiveness of the hydraulic fracturing treatment and subsequent hydrocarbon production. Results are presented here from a series of two-dimensional (2-D) numerical experiments investigating the influence of natural fractures on the modeling of hydraulic fracture propagation. Distinct-element techniques applying a transient, coupled hydromechanical solution are evaluated with respect to their ability to account for both tensile rupture of intact rock in response to fluid injection and shear and dilation along existing joints. A Voronoi tessellation scheme is used to add the necessary degrees of freedom to model the propagation path of a hydraulically driven fracture. The analysis is carried out for several geometrical variants related to hypothetical geological scenarios simulating a naturally fractured shale gas reservoir. The results show that key interactions develop with the natural fractures that influence the size, orientation, and path of the hydraulic fracture as well as the stimulated volume. These interactions may also decrease the size and effectiveness of the stimulation by diverting the injected fluid and proppant and by limiting the extent of the hydraulic fracture.

An Improved Equilibrium-Height Model for Predicting Hydraulic Fracture Height Migration in Multi-Layer Formations

2015 ◽  
Author(s):  
Songxia Liu ◽  
Peter P. Valkó
Keyword(s):  
Fracture Toughness ◽  
Hydraulic Fracture ◽  
3D Models ◽  
In Situ Stress ◽  
Height Growth ◽  
Net Pressure ◽  
Fracture Height ◽  
Layer Problem ◽  
Equilibrium Height

Abstract Fracture height is a critical input parameter for 2D hydraulic fracturing design models, and also an important output result of 3D models. While many factors may influence fracture height evolution in multi-layer formations, the consensus is that the so called “equilibrium height belonging to a certain treating pressure” provides an upper limit, at least for non-naturally fractured media. How to solve the “equilibrium height” problem has been known since the 1970s. However, because of the complexity of the algebra involved, published equations are overly simplified and do not provide reliable results. We revisited the equilibrium height problem, and our theoretical and numerical investigations led to a new model that fully characterizes height evolution amid various formation properties (fracture toughness, in-situ stress, thickness, etc.). The new model, for the first time, rigorously solves the equilibrium height mathematically. With the help of computer algebra software, we applied a definition of fracture toughness, incorporated the effects of hydrostatic pressure, and considered non-symmetric variations of layered formation properties. Results were determined for the classic 3-layer problem and then were extended to 6 layers. The effects of reservoir and fluid properties on the fracture height growth were investigated. Tip jump is caused by low in-situ stress; tip stability is imposed by large fracture toughness and/or large in-situ stress. If the fluid density is ignored, the result regarding to which tip will grow into infinity could be totally different. For any multi-layer formation problem, two, 3-layer pseudo problems were constructed to create an outer and inner height envelope, in order to assess the potential effects of reservoir parameter uncertainties on height profile. Second solution pair in the 3-layer problem was investigated numerically and analytically, to avoid misleading results in the 3D models. This improved model can rapidly (in seconds) and reliably calculate the theoretical maximum equilibrium fracture height in layered formations with various rock mechanical properties. Then, the equilibrium height can be used to (1) provide input data for 2D model, (2) improve 3D model governing equations, (3) determine the net pressure needed to achieve a certain height growth, and (4) obtain the maximum net pressure assuring no fracture invasion into aquifers. This model may be incorporated into current hydraulic fracture simulation software to yield more accurate and cost-effective hydraulic fracturing designs.

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