Notional Field Development Final Report - EBN

EBN Notional Field Development Plan
3.3.2.3 Fracture Complexity
Fracture complexity was approximated by the use of a dual porosity model. Because the dual porosity
model is fundamentally different from the homogenous (single porosity) case, an equivalent fracture
permeability that mimics the homogenous case (without additional complexity) must be established.
This was found to be .001mD rather than .0001mD used in the single porosity case. Fracture complexity
is then introduced as an improved fracture permeability area around the hydraulic fracture with a
permeability value of 0.15mD.
Figure 3-35, Comparison of Dual Porosity Model (Unmodified & Modified) vs. the Base Case displays an
approximately 53% loss in production using the base case parameters in a dual porosity model. By
incorporating a fracture permeability of .001 mD we are able to closely imitate the single porosity
homogeneous case. By reproducing the same cumulative production with a dual porosity model we can
now accurately forecast how fracture complexity will affect our production.
250,000
3100m Posidonia
Cumulative Gas (MCM) vs. Time (years)
200,000
203419 MCM
BASE CASE: 1500m
Lateral - 22 Frac Stages
Cum Gas (MCM)
150,000
100,000
200817 MCM
CASE B: Dual Porosity
Equivalent Modified
Base Case: Dual Porosity
Unmodified
95424 MCM
50,000
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15
Time (years)
Figure 3-35, Comparison of Dual Porosity Model (Unmodified & Modified) vs. the Base Case
The Figure 3-36, Shale Gas Modeling, describes the different types of hydraulic fracture complexity we
use in single well reservoir simulation.
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