Hydraulic Fracturing Design for Optimum Well Productivity Frank E. Syfan, Jr., PE, SPEE Syfan Engineering, LLC February 26, 2015

Outline Critical Fracture Design Parameters Case Histories: Summary GoFrac, LLC Outline Critical Fracture Design Parameters Rock Mechanics Fracture Mechanics Fluid Systems Proppant Selection Case Histories: Case A: Marcellus Shale Case B: Eagle Ford Shale Case C: Bakken Case D: Cotton Valley Summary Conclusions

Critical Fracture Parameters Rock Mechanics Mineralogy Content: Quartz, calcite, clay (??) Shales: Many are not in strictest geological sense! Poisson’s Ratio 𝒗=− 𝝏 𝜺 𝒕𝒓𝒂𝒏𝒔 𝝏 𝜺 𝒂𝒙𝒊𝒂𝒍 Modulus of Elasticity (Young’s Modulus)  𝒎 ≝ 𝑺𝒕𝒓𝒆𝒔𝒔 𝝈 𝑺𝒕𝒓𝒂𝒊𝒏 𝜺 =𝑬 In-Situ Stress 𝝈 𝑯 = 𝒗 𝟏−𝒗 𝝈 𝒗 − 𝑷 𝒑 + 𝑷 𝒑 + 𝝈 𝝉

Critical Fracture Parameters Fracture Mechanics Fracture Face Skin 𝑺 𝑭𝒂𝒄𝒆 = 𝝅 𝒀 𝒙 𝑿 𝒇 𝒌 𝒓 𝒌 𝑫 −𝟏 Choked Fracture Skin 𝑺 𝒄𝒉 = 𝒉 𝑿 𝒇 𝟏 𝑪 𝒇𝑫 𝒍𝒏 𝒉 𝟐 𝒓 𝒘 − 𝝅 𝟐 Half-Length & Width What is optimum length? Perkins & Kern (1961) Fracture Conductivity!!! wkf CfD

Critical Fracture Parameters Fluid Systems Fluid & Additive Design Slickwater DOESN’T Work Everywhere! Chemical and Fluid Compatibility Gel Stability and Breaker Tests Temperature Ranges Nano-Fluid Non-Emulsifiers Polyacrylamide Breakers ISO 13503-1, 13503-3, 13503-4

Critical Fracture Parameters Proppant Selection Ceramic Resin Coated a-Qtz

Critical Fracture Parameters Proppant Selection Ceramics RC Ceramics Bauxite 13+ 12 8 5 4 Intermediate RC a-Qtz LWC Premium Incr. Closure Pressure, Kpsi Economy Intermediate a-Qtz Incr. Cost & Performance

Critical Fracture Parameters Proppant Selection The Ideal Proppant Crush resistance / high strength Slightly deformable, not brittle No embedment Low specific gravity Chemical resistance No flowback Complete system compatibility Ready availability Cost effective Reality: The Ideal Proppant Doesn’t Exist!!

Critical Fracture Parameters Proppant Selection Infinite vs. Finite Conductivity Formation Permeability Depth/Closure Stress Formation Ductility/Embedment What is Brinell Hardness?

Critical Fracture Parameters Proppant Selection Median Particle Diameter Cyclic Stress Multi-Phase Flow Proppant Flowback Non-Darcy Effects Beta Factor

Critical Fracture Parameters Conductivity Fracture Conductivity – Wkf Single Most Important Factor to Achieve! Dimensionless Conductivity Fracture Flow Capacity Divided by Reservoir Flow Capacity. Considered “Infinite” the fracture deliverability exceeds reservoir deliverability with negligible pressure loss.

Critical Fracture Parameters Conductivity: McGuire & Sikora (1960) GoFrac, LLC Critical Fracture Parameters Conductivity: McGuire & Sikora (1960) Dimensionless Productivity Index vs. Dimensionless Conductivity (Square Reservoir) Dimensionless Productivity Index vs. Dimensionless Conductivity (Rectangular Reservoir – 1/10)

Critical Fracture Parameters Fines Intermediate Strength Ceramic – 8,000 psi 12/20 Hickory/Brady – 6,000 psi RC Proppant – 8,000 psi StimLab Proppant Consortium, 1997 – 2006

Critical Fracture Parameters Depth/Closure Stress Brown vs. Northern White? API 19C (ISO 13503-2) Guidelines Are Specific!! Sieve Distribution Krumbein Factors Turbidity Acid Solubility K-Value (Also Called Crush Resistance) Point Where Fines >10.0% Relative Number Only!!

Critical Fracture Parameters Median Particle Diameter SPE 84304 (2003) Particle Sieve Distribution Variations Field Samples – 20/40 N. White @ 25X 0.545 mm 0.703 mm Courtesy: PropTester – Houston TX

Critical Fracture Parameters Median Particle Diameter Each Proppant Sample Passes ISO 13503-2 Guidelines! Flow Capacity Decreases MPD = 0.543 mm MPD = 0.710 mm Courtesy: PropTester – Houston TX

Critical Fracture Parameters Median Particle Diameter 100 1,000 10,000 Published Data MPD = 0.710 mm Conductivity (md-ft) Actual Data MPD = 0.543 mm 2,000 4,000 6,000 8,000 10,000 Closure Stress (psi) Courtesy: PropTester – Houston TX

Critical Fracture Parameters Beta Factor A Quantity Relating Pressure Loss In The Fracture to Liquid or Gas Production Rates (velocities). Governed by Forchheimer’s Equation Darcy Effects Non-Darcy Effects Inertial Effect 2 - Dominate! PSD Effects Beta

Outline Critical Fracture Design Parameters Case Histories: Summary GoFrac, LLC Outline Critical Fracture Design Parameters Rock Mechanics Fracture Mechanics Fluid Systems Proppant Selection Case Histories: Case A: Marcellus Shale Case B: Eagle Ford Shale Case C: Bakken Case D: Cotton Valley Summary Conclusions

Case History A: Marcellus Shale Reservoir & Fracture Parameters Fracture & Reservoir Match Description Value Reservoir Depth, ft 7.876 Reservoir Thickness, ft 162 Hydrocarbon Porosity, % 4.2 Pore Pressure, psi 4.726 Temperature, oF 175 Drainage Area, ac 80 Aspect Ratio (xe/ye) ¼ BHFP, psi 1,450 – 530 Lateral Length, ft 2,100 Number of Stages 7 Clusters per Stage 5 Description Value Reservoir Permeability, nD 583.0 Permeability-Thickness, md-ft 0.094 Propped Length, ft 320 Fracture Conductivity, md-ft 3.77 Dimensionless Conductivity 20.2 Choked Skin, dim +0.096 Equivalent Fractures 6 SPE 166107

Case History A: Marcellus Shale Predicted Gas Production Rate Predicted Cum. Gas Production SPE 166107

Case History A: Marcellus Shale SPE 166107

Case History B: Eagle Ford Shale Reservoir & Fracture Parameters Fracture & Reservoir Match Description Value Reservoir Depth, ft 10,875 Reservoir Thickness, ft 283 Hydrocarbon Porosity, % 5.76 Pore Pressure, psi 8,350 Temperature, oF 285 Drainage Area, ac 80 Aspect Ratio (xe/ye) ¼ BHFP, psi 3,900 – 1,500 Lateral Length, ft 4,000 Number of Stages 10 Clusters per Stage 4 Description Value Permeability-Thickness, md-ft 0.0049 Propped Length, ft 131 Fracture Conductivity, md-ft 0.86 Dimensionless Conductivity 382 Choked Skin, dim +0.0254 Equivalent Fractures 40 SPE 166107

Case History B: Eagle Ford Shale Predicted Gas Production Rate Predicted Cum. Gas Production SPE 166107

Case History C: Bakken Shale Reservoir & Fracture Parameters Description Value Reservoir Depth, ft 9,881 Drainage Area, ac 640 Reservoir Thickness, ft 46 BHFP, psi 1,500 Rsvr. Permeability, mD 0.002 Effective Frac. Length, ft 420 Porosity, % 5.0 Frac. Conductivity, md-ft 200 Pore Pressure, psi 4,900 Dimensionless Conductivity 238 Temperature, oF 209 Lateral Length, ft 5,000 Rsvr. Compressibility, 1/psi 2.0 E-05 Transverse Fractures 12 Rsvr. Viscosity, cP 0.30 SPE 166107

Case History C: Bakken Shale GoFrac, LLC Case History C: Bakken Shale Predicted Oil Production Rate Predicted Cum. Oil Production SPE 166107

Case History D: E. TX Cotton Valley GoFrac, LLC Case History D: E. TX Cotton Valley Reservoir & Fracture Parameters Description Value Reservoir Depth, ft 9,000 BHFP, psi 1,500 Reservoir Thickness, ft 100 Effective Frac. Length, ft Rsvr. Permeability, mD 0.001 Frac. Conductivity, md-ft 114 Porosity, % 7.0 Dimensionless Conductivity 76 Pore Pressure, psi 6,000 Lateral Length, ft 2,000 Temperature, oF 285 Transverse Fractures 7 Drainage Area, ac 640 SPE 166107

Case History D: E. TX Cotton Valley GoFrac, LLC Case History D: E. TX Cotton Valley Predicted Gas Production Rate Predicted Cum. Gas Production SPE 166107

Outline Critical Fracture Design Parameters Case Histories: Summary GoFrac, LLC Outline Critical Fracture Design Parameters Rock Mechanics Fracture Mechanics Fluid Systems Proppant Selection Case Histories: Case A: Marcellus Shale Case B: Eagle Ford Shale Case C: Bakken Case D: Cotton Valley Summary Conclusions

Summary Proper fracture design and ultimately, fracture optimization, cannot and will not happen without sound engineering practices! Without sound engineering, initial production rates, ultimate recovery, NPV, and rate-of-return will be compromised. At the End of the Day…… SPE 166107

Conclusions Understanding the rock mechanics is essential to consistently achieving high conductivity fractures. McGuire and Sikora (1960) holds true regardless of reservoir type and ultimately dictates reservoir and production performance. Fracture conductivity and dimensionless fracture conductivity ultimately govern the initial production rates and ultimate recoveries regardless of the type of reservoir lithology. SPE 166107

Conclusions Case A (Marcellus Shale) and Case B (Eagle Ford Shale) matches, illustrate the importance of achieving high conductivity transverse fractures in a horizontal wellbores. Increasing fracture conductivity, regardless of reservoir type, results in a significant positive impact on ROR and NPV. SPE 166107

GoFrac, LLC THANK YOU FOR YOUR TIME AND TO THE FORT WORTH SPE SECTION FOR INVITING ME TO MAKE THIS PRESENTATION. QUESTIONS??