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

2. 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

3. 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

4. 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

5. 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

6. 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

7. Finite Element 3D Model Results

8. 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)

9. 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

10. 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.

11. 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 > 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 < (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