1. Fractured Reservoir Simulation Milind Deo and Craig Forster
University of Utah
Fracture
Dominated
100%
Fracture II I
III
Increasing Role of Fractures
% of Total Permeability IV
100%
Matrix
After Nelson (2001)
% of Total Porosity
100%
Fracture
100%
Matrix
Matrix
Dominated

2. Account for Irregular Geometries
Hypothetical
‘Real System’
Regularized
Equivalent
ECLIPSE
Equivalent
Common Model Properties
Impermeable matrix with f = 0 (Type I, basement reservoir system)
Domain = 1,000 ft by 1,000 ft by 200 feet deep
Total feature length = 30,000 feet
Reference Case: Feature k = 1,000 md, f = 14 %, width = 0.5 feet
OOIP = 53,580 STB
Injection Pressure = 4,300 psi
Injection Well Production Well

3. Model Comparison at 900 days
Hypothetical
‘Real System’ CVFE
Regularized
Equivalent CVFE
ECLIPSE
Equivalent 20 40 60 80
100
120
300
600
900
Time (days)
Oil Production
(STB/day)
Primary
Production
‘Real System’ CVFE
0.50
0.35
0.20
0.80
0.65 So
Regularized Equiv. CVFE
ECLIPSE

4. Parameter Sensitivity (900 days)
1000 md
Base Case
1000 md
1 Connection
Geom. Mean 100 md
33:33:33 Random k
120
1000 md Base Case
0.50
0.35
0.20
0.80
0.65 So
100
Primary
Production 80
1 Connection
Oil Production
(STB/day)
GM 100 md 50:50 60
GM 100 md 33:33:33 40 20
300
600
900
Time (days)

5. Faulted-Fractured Reservoir System
Increasing Fractures
Increasing
Fractures
Fault
k (md)
f (%)
10000
500
100 10 5 11 8
200 ft
1000 ft
kh (md-ft)
Fault thickness = 0.3 ft
Production Wells
Secondary Injection Wells (production wells during primary prod’n)
Sandstone
Shale
Upper
Reservoir
Lower
Reservoir

6. Faulted-Fractured Reservoir
6000 days
Water Flood Start after 600 days
3000 days
Water Flood Start after 600 days
600 days
Primary Production
20 days
Primary Production
0.50
0.35
0.20
0.80
0.65 So
Production Well
Injection Well
Viewed From Bottom of Model Domain

7. Oil Production Rate (STB/day)
Impact of Fault k
Secondary Production after 600 days
3000 days
Secondary Production after 600 days
6000 days
Primary Production
600 days
Fault k = 100 md
Fault k = 10,000 md
20 days
Primary Production
Production Well
Injection Well
Primary Production
Oil Production Rate (STB/day)
400
800
3000
6000
Time (days)
Primary Production
0.70
0.50
0.35
0.20
0.80
0.65 So
Production From
Water Cut (vol/vol)
Fault
0.35
Lower Res.
3000
6000
Time (days)

8. Outcrop-to-Simulation
Joint Zone
High k Features N U D
Cocks Comb Study
Cottonwood
Wash Study
Field
Area
Utah
Teasdale Fault, Utah
10 Kilometers
1800 feet
200 feet
Line Drive 1
Line Drive 2
k (md)
f (%)
100 10 25
16000
2500
kh (md-ft)
Production
Primary 600 days
Production BHP 2200 psi
Injection BHP 3200 psi

9. Well Placement Strategies
3500
1000 days
2000 days
4000 days
6000 days
Line Drive 1 (N to S)
Line Drive 2 (W to E)
2500
Oil Production Rate (STB/day)
1000
Line Drive 2
Line Drive 1
500 So
3000
6000
Time (days)
0.50
0.35
0.20
0.80
0.65
Primary
Production
2100
600 days
Line Drive 2
1800
Gas Oil Ratio
1400
Line Drive 1
1100
3000
6000
Time (days)
View From Bottom of Model Domain

10. Status and Challenges
Preserve geologic integrity while constructing simulation models
Relationship between discrete-fracture models and dual-porosity models
DFN as upscaling/calibration tool for DP models?
Field-wide DFN models in the near future?
Fundamental work
Additional physics?
Upscaling
Integrating geomechanics
Dynamic data updaing
Different discrete-fracture implementations
Discretization schemes
Gridding
Efficiency of solvers
High-performance (parallel) computing

11. Acknowledgements
U.S. DOE Contract DE-FC26-04NT15531 through the National Energy Technology Laboratory.
Schlumberger Inc. – Eclipse academic license
Sandia National Laboratories – CUBIT license
Argonne National Laboratory – PETSc
Our eam
Jim Evans, Professor, Utah State University, Logan, Utah
Tom Doe, Golder and Associates
Yi-kun Yang, Post-doc
Sriram Balasubramaniam, Graduate student
Ganesh Balasubramaniam, Graduate student
Yao Fu, Graduete student
Kan Huang, Graduate student
Zhiqiang Gu, Graduate student
Huabing Wang, Graduete student