The Relationship Between Fracture Complexity, Reservoir Properties, and Fracture Treatment Design

Abstract

In many reservoirs fracture growth may be complex due to the interaction of the hydraulic fracture with natural fractures, fissures, and other geologic heterogeneities. The decision whether to control or exploit fracture complexity has significant impact on fracture design and well performance. This paper investigates fracture treatment design issues as they relate to various degrees and types of fracture complexity (i.e., simple planar fractures, complex planar fractures, and network fracture behavior), including the effect of fracture fluid viscosity on fracture complexity, proppant distribution in complex fractures, and fracture conductivity requirements for complex fractures. The impact of reservoir properties (including permeability, stress and modulus) on treatment design is also evaluated. The paper includes general guidelines for treatment design when fracture growth is complex. This includes criteria for the application of water-fracs, hybrid fracs, and crosslinked fluids. The paper begins with an evaluation of microseismic fracture mapping data that illustrates how fracture complexity can be maximized using low viscosity fluids, which includes an example of how microseismic data can be used to estimate the permeability and spacing of secondary or network fractures. The effect of proppant distribution on gas well performance is also examined for cases when fracture growth is complex, assuming that proppant was either concentrated in a primary planar fracture or evenly distributed in a fracture network. Examples are presented that show when fracture growth is complex the average proppant concentration will likely be too low to materially impact well performance if proppant is evenly distributed in the fracture network and un-propped fracture conductivity will control gas production. This paper also extends published conductivity data for un-propped fractures and embedment predictions for partially propped fractures to lower modulus rock to provide insights into fracture design decisions. Exploiting fracture complexity may not possible when Young's modulus is 2 x 106 psi or lower due to insufficient network conductivity resulting from asperity deformation and proppant embedment. Fracture conductivity requirements are examined for a wide range of reservoir permeability and fracture complexity. Reservoir simulations illustrate that the network fracture conductivity required to maximize production is proportional to the square-root of fracture spacing, indicating that increasing fracture complexity will reduce conductivity requirements. The reservoir simulations show that fracture conductivity requirements are proportional k1/2 for small networks and k1/4 for large networks, indicating much higher conductivity requirements for low permeability reservoirs than would be predicted using classical dimensionless conductivity calculations (Fcd) where conductivity requirements are proportionate to reservoir permeability (k). The results show that when fracture growth is complex, proppant distribution will have a significant impact on network conductivity requirement and well performance. If an infinite conductivity primary fracture can be created, network fracture conductivity requirements are reduced by a factor of 10 to 100 depending on the size of the network. The decision to exploit or control fracture complexity depends on reservoir permeability, the degree of fracture complexity, and un-propped fracture conductivity. The paper also examines the effect of fluid leakoff on maximum fracture area, illustrating potential limits for fracture complexity as reservoir permeability increases. Although the expected range of un-propped fracture conductivity is controlled by Young's modulus and closure stress, in many reservoirs it can be beneficial to exploit fracture complexity when the permeability is on order 0.0001 mD by generating large fracture networks using low viscosity fluids (water-fracs). As reservoir permeability approaches 0.01 mD, fluid efficiency decreases and fracture conductivity requirements increase, fracture designs can be tailored to generate small networks with improved conductivity using medium viscosity or multiple fluids (hybrid fracs). Fracture complexity should be controlled using high viscosity fluids and fracture conductivity optimized for moderate permeability reservoirs, on order 1 mD.

Numerical study of the effect of uneven proppant distribution between multiple fractures on shale gas well performance

“…Multiple long hydraulic fractures with uniform proppant distribution and sufficient fracture conductivity play an important role in achieving effective well stimulation and economic production of shale reservoirs [1][2][3][4][5][6][7]. Cipolla et al [8] studied the effect of proppant distribution in the fracture network on well performance and showed that proppant distribution significantly affects the fracture network conductivity and treatment design. Gu et al [9] presented that proppant transport in natural fractures has an important impact on critical fracture conductivity required for stimulation of shale reservoirs.…”

Experimental and theoretical study of the anisotropic properties of shale

“…Hydraulic Fracturing by Stimulated Reservoir Volume (SRV) [44] is a major technology to achieve commercial development of shale gas. However, the formation mechanism of effective fracture network has not been well understood.…”

Complementary hydro-mechanical coupled finite/discrete element and microseismic modelling to predict hydraulic fracture propagation in tight shale reservoirs

“…(15) leads to the final transient equation that is then used to update the nodal network pressures: (17) Once is equated then the fluid pressure terms in Eq. (13) and (14) are updated to the current problem time . In the present formulation the implicit solution initially advances ahead of the explicit solution of the structure field and during this stage the aperture and aperture strain rate terms are assumed constant over a single implicit solution time increment.…”

“…In broad terms the main numerical schemes appropriate for this class of problem include the FEM (Finite Element Method) [10,11,12] in its pure continuum form [13], the Discrete Fracture Network (DFN) geomechanical and continuum flow models [14], the Displacement Discontinuity Method (DDM) geomechanical and flow models [15,16,17], the combined FEM/DEM (Discrete Element Method) [18] technique plus the more recent Extended Finite Element Method (XFEM) [4,19].…”

“…The DFN geomechanical and continuum flow models are often used within the petroleum industry [14]. They permit the use of different discretisations for the geomechanical and flow fields (e.g.…”