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

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

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

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)

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

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

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)

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

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

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

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