Effects of Natural Fracture Reactivation during Hydraulic Fracturing of the Barnett Shale, Fort Worth Basin TX Seth Busetti October 2010 ConocoPhillips Subsurface Technology

Hydraulic Fracturing in Naturally Fractured Rock Barnett Shale (ConocoPhillips) Murphy et al., 1988 Busetti, 2010 Geomechanical Processes: Near-wellbore propagation Fracture Reactivation Shear-slip Shear + dilation Local propagation 3D interactions Macroscopic flow enhancement Residual effects: proppant, damage, pressure perturbation

Models for Fracture Network Stimulation Non-interaction Isolated Interaction *Full Interaction* Tectonic stress, injection qualities, fluid flow, propagation, full scale 3D… Sv Sh SH Sv SH Sh Modified after Baer et al. (1994) Present Analysis: Partial Interaction Tectonic stress, driving pressure, aperture, volume change Busetti, 2009 Busetti, 2008

3D Fracture Reactivation Model (Non-Interaction) Analytical or graphical solution for reactivated fracture planes: (poles to planes) Busetti, 2009 Model Prediction: Stimulated Volume (MEQ cloud) ≈ Fracture Network Dilation Potential σ1 ~2θL ~90-2θ3 σ3 ~2θw σ2 Low θL High θL High θW High θ3 SHmax >> Shmin Tectonic Stress Ratio SHmax ≈ Shmin Low Net P Fracture Fluid Pressure High Net P

3D Non-Interaction Model: Barnett Shale Wells Fracture dilation potential predicts field response reasonably well… …but ignores any interactions (*note no Pp) --θL-- --θW-- --θ3-- 1 3 2 4 Well 5 Modified after Daniels et al. (2007) After Busetti and Reches (2008) → Use Numerical Method to Solve Problem → Use Properties Appropriate for Barnett Shale

Finite Element 3D Model Configuration σ1 =Sv Top View Set 1: 135° Set 2: 45° μ = 0.6 σ2 =SHmax σ3 =Shmin 2m x 2m x 2m Elastic-plastic Layers: E = 30GPa; ν = 0.32 ≈semi-brittle siliceous mudstone Limited plastic propagation Fractures pressurized equally Pf increases linearly 0 – 10 MPa No leak-off

Finite Element 3D Model Results

FE 3D Model Results: Nonlinear Deformation High Frac-Gradient σ3 =34 MPa Pf Shmax>>Shmin σ3 isosurfaces Low Frac-Gradient σ3 =30 MPa Volumetric Strain εV Non-linear volume increase at R > 0.05 R= (Pf-σ3)/(σ1-σ3) Ф= (σ2-σ3)/(σ1-σ3) Fracture Pressure Shmax >> Shmin Volume expansion is non-linear dεV increases with: (1) Internal Fracture Pressure (2) Lower Minimum Stress, σ3 (3) Tectonic stress ratio (differential stresses)

FE 3D Model Results: Non-Linear Deformation Low Frac Gradient: Compilation of 5 Simulations Case 10: Ф = 0.167 σ3 = 30 MPa εY Strain εZ εX Fracture Pressure σ1 Strain ellipses Shmax >> Shmin σ3 εmin σ2 dεY = σ3 ≈ Shmin widening – Set1 fracture dilation dεZ = σ1 ≈ SV subsidence – dip-slip (normal faulting) dεX = σ2 ≈ SHmax obliquity – Set 2 dilation and slip εmid εmax

FE 3D Model Results: Natural Fracture Reactivation vs. Propagation Volumetric Strain σ3 = 34 natural fracture propagation no natural fracture propagation σ3 = 30 3 4 1 2 Ф FE simulations terminate after the onset of fracture propagation at low R. Field stress and pressure data indicates multiple network fractures should propagate.

Summary of Key Results Analytical 3D Non-Interaction Model 1st order approximation for stimulation shape Matches Barnett Shale field data w/o Pp FE 3D Interaction Model for a “Typical” Barnett Shale Configuration Effects of Internal Fracture Pressure R > 0.05 directional and volumetric strain evolves non-linearly R > 0.1 - 0.2 reactivated fractures begin to propagate Effects of Tectonic State of Stress In all cases, σ3-parallel dilation dominates (dilation perpendicular to SHmax) σ1-parallel contraction occurs when fractures are reactivated as small normal faults σ2-parallel dilation occurs for Ф < 0.3-0.4 (dilation oblique to SHmax) Interpretation of Field Stimulation Data Barnett Shale wells indicate likely reactivation and propagation of natural fractures under typical in-situ stress and injection pressure conditions May explain non-planar, non-uniform MEQ patterns observed in the field