Layered Modulus Effects on Fracture Propagation, Proppant Placement, and Fracture Modeling

Abstract

Hydraulic fracture geometry (i.e., critical results of length and proppant placement) is driven by four major in situ parameters: Fracture Height (H), Modulus (E), Fluid Loss (C), and "Apparent" Fracture Toughness (KI c-app ). In many (even most) cases, "Height" is the most important of these parameters – due to the need for some height confinement to achieve long fractures, or the need for height growth to insure good pay coverage. Due to this importance, industry research effort and most field measuring techniques concentrate on "Height." In particular, the growing use of seismic imaging is offering a tool to measure height growth away from the wellbore. Results from such diagnostics have often shown, as one expects, that in situ stress variations control height. However, results have also shown situations where this is apparently not the case. This paper examines another in situ parameter, "Layered Modulus," which also affects height. In addition, by controlling the "local" width of a fracture, layered modulus (i.e., layered formations with different layers having significantly different modulus) can have a critical effect on final proppant placement. The importance of layered modulus in directly controlling fracture height is illustrated in this paper, and this is compared with published solutions. In general, it is found that, just as concluded in the past, modulus contrast is probably not an important parameter in terms of direct control of fracture height. The greater importance lies in the effects on local fracture width. These local width changes can have a significant influence on controlling proppant placement – and this can be critical for low net pressure cases such as "water fracs" or fracturing in "soft" formations. It is also noted that layered modulus significantly impacts the average width of a fracture, and thus impacts the critical material balance aspects of fracture modeling if not properly accounted for. Finally, some of the theoretical solution problems created by "Layered Modulus" formations for fracture modeling are discussed and compared. This is done by comparing with 3–D Finite Element (static) solutions, and shows how some common industry "approximations" for layered modulus give incorrect results. Based on this, examples with a fracture propagation model using a finite element-generated stiffness matrix are used to define types of cases where a simple "average" modulus is acceptable, versus cases where more complex calculations are needed. Introduction Six major variables control hydraulic fracturing, fracture geometry, proppant placement, etc. Two of these are the "controllable" variables of fluid viscosity, µ, and pump rate, Q. The remaining four variables are "natural" variables and include:Height. Fracture height (or more generally fracture geometry) is possibly the most important unknown for fracture design and post-frac production success. Generally, it is recognized that in situ stress differences (the in situ stress profile) is the major controlling factor for this behavior. [1] At a minimum, in situ stress differences control the maximum fracture height, i.e., if the net pressure is not available to grow through high stress shale layers, then fracture height must be contained. The importance of fracture height/geometry is clear, and there are many research efforts and technical publications addressing this issue. [1–6]Fluid Loss. Fluid loss is typically characterized for hydraulic fracturing by a fluid loss coefficient, C, which characterizes linear flow fluid loss out of the fracture. This gives the familiar C/ (t-t) form of fluid loss behavior. Again, this variable has been exhaustively discussed in the literature including wall building characteristics of specific fluid systems, effects of natural fractures, behavior of fluid loss additives, etc. [7–16]

Three-dimensional finite element simulation and parametric study for horizontal well hydraulic fracture

“…If the net pressure is not available for penetrating through high stress barrier layers, then fracture height must be contained. Studies have pointed out that modulus contrast can also have significant effect on fracture height growth (Smith et al, 2001;Gu and Siebrits, 2006). Lower modulus layers do not enhance, but hinder fracture height growth (Gu and Siebrits, 2006), which is also verified in the present paper.…”

“…Fracture height has been recognized as one of the critical factors which can determine the success or failure of a hydraulic fracturing treatment. Many studies have been conducted for the effects of in-situ stresses, formation Young's modulus, fracture toughness and layer interfacial slip on hydraulic fracture height containment in layered formations (van Eekelen, 1982;Teufel and Clark, 1984;Thiercelin et al, 1987;Wang and Clifton, 1990;Warpinski et al, 1982Warpinski et al, , 1998Smith et al, 2001;Gu and Siebrits, 2006;Gu et al, 2008;Daneshy, 2009;Iyer and Podladchikov, 2009;Lewis et al, 2009).…”

“…Varieties of numerical models have been developed for hydraulic fracture simulations (Fischer et al, 1994;Siebrits et al, 2001;Smith et al, 2001;Miskimins and Barree, 2003;Hustedt et al, 2006). Hydraulic fracture height containment for thin-bedded reservoirs could be analyzed by the software GOHFER (Miskimins and Barree, 2003).…”

Coupled flow-stress-damage simulation of deviated-wellbore fracturing in hard-rock

“…properties of caprocks and underlying rocks, are close to each other, there is an abrupt change in fracture height which is difficult to control. When fracture propagates from the reservoir with elastic modulus of 75 GPa to the caprocks and underlying rocks with elastic modulus of 80 GPa, the fracture width shrinks at both the top and bottom parts which is identical with the result of Smith et al (Smith et al, 2001) obtained from planar 3D model. The reservoir with low elastic modulus restricts the fracture height growth; however, the control mechanism differs from that in the reservoir of high elastic modulus.…”

A review on hydraulic fracturing of unconventional reservoir

“…Teufel and Clark [81] found that the elastic properties of either side of the interface could influence the propagation of vertical growth by affecting the vertical distribution of the minimum horizontal stress state, because the increase in minimum horizontal in-situ stress in the bounding layers and a weak interfacial shear strength of the layers could contain vertical growth of hydraulic fractures. For composite rock, differences in Young's Moduli and the fluid volume within the fracture and the conductivity and productivity in adjacent layers can influence the width of hydraulic fracture if it grows across the interfaces [28,79]. The first is layers of higher strength may be micro-cracked for they take more stress; yielding in soft rock that dissipates the energy can also contain the fracture or cause discontinuous fractures; interface slip may retain the hydraulic fracture or deviate the path, as shown in [86] (Fig.…”