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.

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.

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.

scholarly journals Hydraulic-Fracture-Height Growth Under the Combined Influence of Stress Barriers and Natural Fractures

SPE Journal ◽  
2018 ◽  
Vol 24 (01) ◽  
pp. 302-318 ◽  
Author(s):  
Jixiang Huang ◽  
Joseph P. Morris ◽  
Pengcheng Fu ◽  
Randolph R. Settgast ◽  
Christopher S. Sherman ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Fluid Pressure ◽  
Height Growth ◽  
Two Dimensions ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
3D Interaction ◽  
Fracture Height ◽  
Fully Coupled

Summary A fully coupled finite-element/finite-volume code is used to model 3D hydraulically driven fractures under the influence of strong vertical variations in closure stress interacting with natural fractures. Previously unknown 3D interaction mechanisms on fracture-height growth are revealed. Slipping of a natural fracture, triggered by elevated fluid pressure from an intersecting hydraulic fracture, can induce both increases and decreases of normal stress in the minimum-horizontal-stress direction, toward the center and tip of the natural fracture, respectively. Consequently, natural fractures are expected to be able to both encourage and inhibit the progress of hydraulic fractures propagating through stress barriers, depending on the relative locations between the intersecting fractures. Once the hydraulic fracture propagates above the stress barrier through the weakened segment near a favorably located natural fracture, a configuration consisting of two opposing fractures cuts the stress barrier from above and below. The fluid pressure required to break the stress barrier under such opposing-fracture configurations is substantially lower than that required by a fracture penetrating the same barrier from one side. Sensitivity studies of geologic conditions and operational parameters have also been performed to explore the feasibility of controlled fracture height. The interactions between hydraulic fractures, natural fractures, and geologic factors such as stress barriers in three dimensions are shown to be much more complex than in two dimensions. Although it is impossible to exhaust all the possible configurations, the ability of a 3D, fully coupled numerical model to naturally capture these processes is well-demonstrated.

The Cross-Sectional Shapes of Longitudinal Hydraulic Fractures

1984 ◽  
Vol 106 (4) ◽  
pp. 554-561 ◽  
Author(s):  
D. Segalman
Keyword(s):  
Mathematical Formulation ◽  
High Stress ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Stress Distributions ◽  
Type Problem ◽  
Cross Sectional ◽  
The Cross ◽  
Sectional Shape

A mathematical formulation has been developed for calculating the cross-sectional shape of hydraulic fractures. This formulation treats the problem as a free-boundary-type problem and is modeled after mathematical formulations developed for contact and lubrication problems. Numerical solution of the resulting equations has been used to address problems involving particularly difficult in-situ stress distributions, including problems in which the fracture breaks through high-stress barriers. The technique is illustrated on two example problems.

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

scholarly journals Experimental and Numerical Investigation on Basic Law of Dense Linear Multihole Directional Hydraulic Fracturing

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-19
Author(s):  
Xin Zhang ◽  
Yuqi Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Large Scale ◽  
Pore Water Pressure ◽  
Water Pressure ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Directional Hydraulic Fracturing ◽  
Basic Law

Using the dense linear multihole to control the directional hydraulic fracturing is a significant technical method to realize roof control in mining engineering. By combining the large-scale true triaxial directional hydraulic fracturing experiment with the discrete element numerical simulation experiment, the basic law of dense linear holes controlling directional hydraulic fracturing was studied. The results show the following: (1) Using the dense linear holes to control directional hydraulic fracturing can effectively form directional hydraulic fractures extending along the borehole line. (2) The hydraulic fracturing simulation program is very suitable for studying the basic law of directional hydraulic fracturing. (3) The reason why the hydraulic fracture can be controlled and oriented is that firstly, due to the mutual compression between the dense holes, the maximum effective tangential tensile stress appears on the connecting line of the drilling hole, where the hydraulic fracture is easy to be initiated. Secondly, due to the effect of pore water pressure, the disturbed stress zone appears at the tip of the hydraulic fracture, and the stress concentration zone overlaps with each other to form the stress guiding strip, which controls the propagation and formation of directional hydraulic fractures. (4) The angle between the drilling line and the direction of the maximum principal stress, the in situ stress, and the hole spacing has significant effects on the directional hydraulic fracturing effect. The smaller the angle, the difference of the in situ stress, and the hole spacing, the better the directional hydraulic fracturing effect. (5) The directional effect of synchronous hydraulic fracturing is better than that of sequential hydraulic fracturing. (6) According to the multihole linear codirectional hydraulic fracturing experiments, five typical directional hydraulic fracture propagation modes are summarized.

Hydraulic-Fracture-Height Growth: Real Data

2012 ◽  
Vol 27 (01) ◽  
pp. 8-19 ◽  
Author(s):  
M. Kevin Fisher ◽  
Norman R. Warpinski
Keyword(s):  
Hydraulic Fracture ◽  
Real Data ◽  
Height Growth ◽  
Fracture Height

Comparison of Hydraulic Fracture Models for Highly Elongated Fractures of Variable Height

1986 ◽  
Vol 108 (2) ◽  
pp. 107-115 ◽  
Author(s):  
I. D. Palmer ◽  
C. T. Luiskutty
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Reasonable Agreement ◽  
High Stress ◽  
Vertical Direction ◽  
Critical Examination ◽  
Wellbore Pressure ◽  
Fracture Models ◽  
Fracture Height ◽  
Stress Contrast

There is a pressing need to compare and evaluate hydraulic fracture models which are now being used by industry to predict variable fracture height. The fractures of concern here are vertical fractures which have a pronounced elongation in the direction of the payzone, i.e., there is a dominant one-dimensional fluid flow along the payzone direction. A summary is given of the modeling entailed in the basic ORU fracture model, which calculates fracture height as a function of distance from the wellbore in the case of a continuous sand bounded by zones of higher (but equal) minimum in-situ stress. The elastic parameters are assumed the same in each layer, and injected flow rates and fluid parameters are taken to be constant. Leak-off is included with spurt loss, as well as non-Newtonian flow. An advantage of the model is its small computer run time. Predictions for wellbore height and pressure from the ORU model are compared separately with the AMOCO and MIT pseudo-3D models. In one instance of high stress contrast the ORU wellbore pressure agrees fairly well with the AMOCO model, but the AMOCO wellbore height is greater by 32 percent. Comparison between the ORU and MIT models in two cases (also high stress contrast) indicates height disagreement at the wellbore by factors of 1.5–2.5 with the MIT model giving a lower height. Thus it appears there can be substantial discrepancies between all three models. Next we compare the ORU model results with six cases of elongated fractures from the TERRA-TEK fully-3D model. Although two of these cases are precluded due to anomolous discrepancies, the other four cases show reasonable agreement. We make a critical examination of assumptions that differ in all the models (e.g., the effective modulus-stiffness multiplier approximation in the AMOCO model, the effect of finite fluid flow in the vertical direction in the MIT model, and the effect of 2D flow and limited perforated height in the TERRA-TEK model). Suggestions are made for reconciling some of the discrepancies between the various models. For example, the ORU/AMOCO height discrepancy appears to be resolved; for other discrepancies we have no explanation. Our main conclusion is that the AMOCO, TERRA-TEK and ORU models for fracture height and bottomhole pressure are in reasonable agreement for highly elongated fractures. Despite the difficulties in understanding the different models, the comparisons herein are an encouraging first step towards normalizing these hydraulic fracture models.

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