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Completion of Hydrocarbon Bearing Shale Reservoirs George Waters Schlumberger Society of Petroleum Engineers Society of Petroleum Engineers Distinguished Lecturer Program www.spe.org/dl
Evolution of US Shales Initially driven by desportion Focus shifts to pore gas Deeper Higher Reservoir Pressures Dramatic increase in production ~1 BCF/day in 1997 +7 BCF/day in 2009 Number of Producing Shale Gas Well s Annual Shale Gas Pro oduction, Bcf 60,000 60k 50,000 50k 40,000 40k 30,000 30k 20,000 20k 10,000 10k Marcellus Shale Shale Haynesville Shale Shale Woodford Shale Shale Fayetteville Shale Shale New Albany Shale Shale Lewis Shale Shale Barnett Shale Shale Antrim Shale Shale Ohio Shale Shale 00 1979 1981 1983841985 1987 1989 1991 1993941995 1997 1999 2001 2003042005 200708 2500 2,500 Marcellus Shale Shale Haynesville Shale Shale Woodford Shale Shale 2000 2,000 Fayetteville Shale Shale New Albany Shale Shale Lewis Shale Shale Barnett Shale Shale 1500 1,500 Antrim Shale Shale Ohio Shale Shale 1000 1,000 500 00 1979 1981 1983841985 1987 1989 1991 1993941995 1997 1999 2001 2003042005 200708
Shale in Perspective: Permeability Arab-D Carbonate Berea Sand Brick Jonah Lance Fm. Organic Shale Salt Unconventional 1000 100 10 1.0 0.1 0.01 0.001 0.0001 0.00001 1e-06 md 100 nd = 0.0000001 D
Shale Stimulation Requirements: Closely Spaced Fractures Extremely Low Matrix Permeabilities Majority of Pressure Drop at Fracture Face At Initial Reservoir Pressure 10s of feet from fracture for years Hydraulic Fracture Complexity induces pressure drop from multiple points Horizontal Wells Frequently Employed Drilled in direction of s h 10 Year Pressure Profile Generate multiple, transverse hydraulic fractures
4500 4000 Pressure Profile After 30 years with 30 Acre Well Spacing 3500 B1 : 1 1 B3 : 1 1 3000 B2 : 1 1 B1 : 1 1 B5 : 1 1 B6 : 1 1 B4 : 1 1 B3 : 1 1 B8 : 1 1 B4 : 1 1 2500 2000 1500 1000 500 4500 4000 3500 3000 2500 Dense Fracture Patterns Required via Closely Spaced Vertical Wells or Horizontal Wells B2 : 1 1 B7 : 1 1 2000 1500 1000 500 Pressure Profile After 30 years with 15 Acre Well Spacing
Lateral Landing Example Best Petrophysics φ, k, GIP Mineralogy Lowest Clay Volume Borehole Stability Breakout Expandable Clays Stress Lowest Closure Stress Optimum Landing Points Frac Simulations to Quantify
In-situ Stress Direction Induced Fractures, Borehole Breakout, Sonic Logs, & Microseismic Induced Fractures oriented in σ H direction Breakout oriented in σ h direction Microseismic events orient in σ H direction
Calibration of In-Situ Stress Isotropic Stress Profile versus Anisotropic Stress Profile Isotropic Stress Anisotropic Stress
Barnett Shale Fracture Geometry Arkoma Shale Fracture Geometry Natural Fractures normal to σ H Low Horizontal Stress Anisotropy Wide Hydraulic Fracture Networks Natural Fractures Parallel to σ H High Horizontal Stress Anisotropy Narrow Hydraulic Fracture Network Lateral Azimuth = σ H Vertical Well
Spacing of Hydraulically Fractures Example: Young s Modulus = 3x10 6 psi Hydraulic Width = 0.0505 in Spacing Stress Increase (ft) (psi) 1 12,500 10 1,250 25 500 50 250 100 125 w = Δb w=δb ε =w/b b b Hooke s Law Δσ = Ε ε = Ε w/b
Simultaneous Hydraulic Fracturing In-situ Pulverization SPE 119635
Simultaneously Hydraulically Fracturing Results 1,000,000 100,000 Ra ate [mscfd], Gas [mscf] 10,000 1,000 100 0.0 50.0 100.0 150.0 200.0 250.0 300.0 350.0 Days Initial Gas Simulfrac Gas Simul Cum Initial Cum
The Role of Effective Stress Do We Need Proppant? Force acting on fracture systems σ = σ - αp f Barnett Shale Example 150000 D = 7,000 ft P r = 0.55 psi/ft σ h = 0.60 psi/ft P wf = 500 psi 120000 σ H = 0.65 psi/ft Initial Conditions σ h = 350 psi σ H = 700 psi Δσ H-h = 350 psi During Production σ h = 3,700 psi σ H = 4,050 psi Haynesville Shale Example D = 11,000 ft P r = 0.85 psi/ft σ h = 0.95 psi/ft P wf = 7,500 psi σ H = 1.00 psi/ft P wf = 3,000 psi Initial Conditions During Production σ h = 1,100 psi σ h = 2,950 psi σ H = 1,650 psi σ H = 3,500 psi Δσ H-h = 550 psi σ h = 7,450 psi σ H = 8,000 psi Permeability (md) 90000 60000 Haynesville early Production 30000 0 Barnett 5 MMPSI, 1.0 lb/ft2 5MMPSI MMPSI, 0.5 05lb/ft2 5 MMPSI, 0.25 lb/ft2 2 MMPSI, 1.0 lb/ft2 2 MMPSI, 0.5 lb/ft2 2 MMPSI, 0.25 lb/ft2 1 MMPSI, 1.0 lb/ft2 1 MMPSI, 0.5 lb/ft2 1 MMPSI, 0.25 lb/ft2 Haynesville late Production 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 Stress on Proppant
Fracturing Fluid Selection Slickwater More Surface Area/Unit Cost Wider Fracture Fairways Gels Fracture Initiation Crosslinked Gel Frac SPE 95568 Foams Low Pore Pressure Swelling Clays Water Shortages Diversion Fibers, Ball Sealers, Sand Slugs Simul-fracs, Zipper-fracs, Refracs Slickwater Refrac Propped Fractures SPE 95568 Propped Fractures Effective Frac Conductivity Prop Volume, Viscous Fluids, Light Weight Props, Foams
Fracturing Fluid Additives Salts Shale Compatibility Swelling Clays Scale Inhibitors Mixed/Reused Waters High TDS Waters Surfactants CST Ra atio 30.0 25.0 20.0 15.0 10.0 Impact Wetting Phase 5.0 Exacerbate Imbibition 00 0.0 Oil or Non-Wetting Bactericides Untreated Water Breakers High MW Polymers oy Iron Stabilizers Chlorite & Pyrite Barite 0 1 2 3 4 5 6 7 KCl [%]
Perforation Practices Impact on NWB Complexity Longer Perforation Clusters Can induce Parallel Fracturing High Density Phasing Tortuous Path leaving the Wellbore Limited Entry Design Perf Clusters per Frac Stage PerfCluster Spacing Can create Fracture Interference Perforation Performance Hard Rocks Shorter Penetration ti Argillaceous Rocks Collapsed Tunnels Sand Jetting Deeper Penetration Physically Remove Rock Single Plane Phasing σ v σ H σ H Colinear Fracture Aligned along Wellbore Axis Secondary & Multiple Competing Fractures Colinear Frac Projection Δp perf Surface = c 1.98 Q 2 Main Fracture d 4 p 2 N ρ 2 p Wellhead Perforations Projection of Main Fracture Projection of Secondary & Multiple Competing Fractures Wellbore Projection
Summary Keys to Optimizing i i Shale Gas Completions: Identify Stimulation Drivers Fracture Height Growth & Complexity Fracture Conductivity & Fluid Compatibility Must Perform Science At Beginning of Development 3D Seismic Acquisition to understand Structure Core Analysis for Mechanical Properties, Conductivity & Fluids Testing Log Analysis to quantify Petrophysics and Geomechanics Microseismic Monitoring to Quantify Hydraulic Fracture Geometry Evolves to Manufacturing Process Maximize Drilling Efficiency Optimize Well Spacing & Completion Process Change Process as Acreage Changes Continually Learn as Project Evolves
Key Parameters for Shale Plays Geology Thermal maturity Organic richness Mineralogy Matrix permeability Thickness Porosity Fluid saturations Hydrocarbons in place Faults and fractures Adjacent water bearing formations Engineering Stress field and magnitude Frac height growth Frac orientation Hydraulic vs. natural Frac complexity Frac conductivity Fluid compatibility
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