1. 1 An Unconventional Bonanza Enhanced Oil & Gas Recovery Copyright - 2011 TBD America, Inc. All rights reserved. Dr. Barry Stevens President TBD America, Inc. a Technology Business Development Consulting Group

2. 2Copyright - 2011 TBD America, Inc. All rights reserved. 1.What is EOR 2.Hydrofracturing Process 3.Hydrofracturing Video 4.Casing and Cementing 5.Well Bore Integrity 6.Hydrofracturing Fluid 7.Model Simulation 8.Shale Gas Extraction 9.Fracture Conductivity 10.Slickwater Fracturing Design 11.Fluid Behavior 12.Design Parameters 13.Guidelines for Limited Entry Treatment 14.Determine Surface Pressure 15.Determine Orifice Flow 16.L.E. Procedure 17.Closing Remarks Agenda

3. 3Copyright - 2011 TBD America, Inc. All rights reserved. Resource Triangle

4. 4Copyright - 2011 TBD America, Inc. All rights reserved. Formation Candidates Sufficient Recoverable Reserves Sufficient Reservoir Pressure Low Permeability (less than 10 mD) Oil-Water & Oil Gas contacts Not Close Good Cementation

5. 5Copyright - 2011 TBD America, Inc. All rights reserved. Criteria for Well Selection State of depletion of producing formation Formation composition & consolidation Formation permeability Formation thickness Isolation of the zone to be treated Condition of well equipment Production history of the well Offset production history\ Location of water, O/W and G/O contacts

6. 6Copyright - 2011 TBD America, Inc. All rights reserved. Hydrofracturing Hydrofracturing (hydraulic fracturing, fracking) consists of pumping into the formation very large volumes of fresh water that generally has been treated with a friction reducer, biocides, scale inhibitor, and surfactants, and contains sand as the propping agent. The water treating fluid maximizes the horizontal length of the fracture while minimizing the vertical fracture height. The fractures, which are held open by the sand, result in increased surface area, which further results in increases in the desorption of the gas from the shale and increases in the mobility of the gas. The result is more efficient recovery of a larger volume of the gas-in- place.

7. 7Copyright - 2011 TBD America, Inc. All rights reserved. Fracturing Classifications Acid Fracturing Non Acid Fluid Fracturing Water Based (Slickwater - light sand frac) HC Based Poly Emulsion Non Conventional Nuclear Explosive HEGS (high energy gas stimulation)

8. 8 Copyright - 2011 TBD America, Inc. All rights reserved. Hydrofracturing Flow

9. 9Copyright - 2011 TBD America, Inc. All rights reserved. Prevent Contamination of Fresh Water Zones Prevent Unstable Upper Formations from Caving-In Provides a Strong Upper Foundation to Drill Deeper Isolates Zones with Different Pressures / Fluids Seals off High Pressure Zones from the Surface Prevents Fluid Loss into Production Zones Provides a Smooth Internal Bore for Equipment Casing and Cementation

10. 10Copyright - 2011 TBD America, Inc. All rights reserved. Wellbore Integrity

11. 11Copyright - 2011 TBD America, Inc. All rights reserved. BAD CEMENT

12. 12Copyright - 2011 TBD America, Inc. All rights reserved. Meeting casing quality and connection requirements as outlined in API Spec. 5 CT. During cementing, using the best available mud displacement method to avoid mud channels. Using both top and bottom cementing plugs. TO DO’s

13. 13Copyright - 2011 TBD America, Inc. All rights reserved. Providing thin and low permeable filter cake from the drilling fluid. Reducing cement slurry filtration to avoid “bridging” during cement setting. Reducing slurry chemical shrinkage to a minimum and improving the bonding. Using right angle setting slurries reduces the amount of time in which gas can migrate within the unset cement.

14. WELLBORE INTEGRITY 14Copyright - 2011 TBD America, Inc. All rights reserved. Using lightweight cements avoids cement losses in the case of weak (surface) formation. Using inflatable annular casing packers to enhance a standard cement job by providing specific points of isolation. For surface casing applications, cement should always come to the surface, without exclusion. Pressure testing the integrity of formation strength below a casing shoe to ensure adequate sealing is mandatory.

15. 15Copyright - 2011 TBD America, Inc. All rights reserved. Hydrofracturing Fluid

16. Allows engineers to evaluate fracture stimulation design in controlled environment. Use data such as porosity, permeability, lithology, fluid saturation, fracture character and stress regimes to determine optimal fracture locations and possible fracture propagations. 16Copyright - 2011 TBD America, Inc. All rights reserved. Model Simulations

17. Shale Gas Extraction 17 Fracture Conductivity Maximize Flowback / Long-Term Productivity Fracture Design Effective Multi-functional Frac Fluids Fracture Placement Fracture Dimensions / Proppant Copyright - 2011 TBD America, Inc. All rights reserved.

18. Conductivity (C f ) is a measure of the fracture’s ability to transmit fluids 18Copyright - 2011 TBD America, Inc. All rights reserved. Conductivity = kfrac*wfrac kfkf Conductivity

19. 19Copyright - 2011 TBD America, Inc. All rights reserved. Laboratory testing – conducted to include as many realistic damage factors as feasible Well testing – what do we infer from pressure transient or decline curve analyses? Field results – how does well production change when fracture width or proppant quality is altered? Determining Realistic Proppant Conductivity

20. 20Copyright - 2011 TBD America, Inc. All rights reserved. Effective conductivities can be less than 1% of API/ISO test values

21. 21Copyright - 2011 TBD America, Inc. All rights reserved. Stimulate the Formation Enhance the Return, or “Flowback” of the Slickwater Solution Following Well Stimulation Increase the Production of Gas from the Reservoir Slickwater Frac Design

22. 22Copyright - 2011 TBD America, Inc. All rights reserved. Low Leak-off Rate Ability to Carry the Propping Agent Low Pumping Friction Loss Easy to Remove from the Formation Compatible with the Natural Formation Fluids Minimum Damage to the Formation Permeability Break Back to a Low Viscosity Fluid for Clean Up After the Treatment Desired Fluid Behavior

23. 23Copyright - 2011 TBD America, Inc. All rights reserved. Fluid Type Viscosity Requirements Fluid Rheology Economics of Fluid Experience With Local Formations Laboratory Data on the Formation Material Availability Proppant Selection Design Parameters

24. The turbulent flow frictional loss in the wellbore and perforations is important to design and perform a fracturing treatment. The frictional losses are used to predict the surface treating pressure and injection rate. The Laminar Flow Behavior of the Fluid is Critical to the Design of Proppant Transport and Fracture Flow Geometry. 24Copyright - 2011 TBD America, Inc. All rights reserved. Turbulent and Laminar Flow

25. 25 Excellent means of diverting fracturing treatments over several zones of interest at a given injection rate. Effectiveness depends directly upon “back pressure” or perforation friction. Pre-determined rate/perforation relationship. Copyright - 2011 TBD America, Inc. All rights reserved. Limited Entry Treatment

26. 26 Number of Perforations Perforation Spacing Near Wellbore Effects Fracture Pressures Stresses, etc. Copyright - 2011 TBD America, Inc. All rights reserved. Perforation Placement

27. 27 P surface = BHTP + ΔP friction + Δ P perf + ΔP net - ΔP hydrostatic where:  BHTP = bottomhole treating pressure (frac gradient x depth), psi  ΔP friction = treating pipe friction pressure (psi) @ injection rate (psi)  Δ P perf = friction pressure through perforations (psi)  ΔP hydrostatic = hydrostatic pressure, psi Copyright - 2011 TBD America, Inc. All rights reserved. Surface Pressure Components

28. ΔP perf = 0.237 ρ Q2 / D4 C2 Where:  Q = flow rate through each perforation (BPM/perf)  D = Diameter of perforation (in.)  C = Perforation coefficient (0.95. for round perforation)  ρ = Fluid density, lbs/gal 28Copyright - 2011 TBD America, Inc. All rights reserved. Orifice Flow Equation

29. 29 1.Determine the value of ΔP perf - Limited Entry back pressure. 2.Determine the rate/perf (Q): Q = D2 C √ΔP/ρ / 0.487 Using 280 psi: D = 0.42 in. (average diameter of perforations) C = 0.95 (coefficient of roundness of jet perforation) ΔP perf = 250 psi; ρ = 8.33 lb/gal Then, Q = 2.0 BPM/perf Copyright - 2011 TBD America, Inc. All rights reserved. L.E. Treatment Procedure

30. 30Copyright - 2011 TBD America, Inc. All rights reserved. 3.Determine the injection rate.

31. 31 4.Specify pay zones and desirable distribution for the Limited Entry hydrofracturing treatment. Using: Injection Rate: 40 BPM Total Number of Perforations: 20 Perforation Friction Pressure: 280 psi Perforation Diameter: 0.42 inches Perforation Phasing: 180o (Wireline Conveyed) Copyright - 2011 TBD America, Inc. All rights reserved.

32. Success Factors Achieving a Low-risk, Safe and Productive Operation Integrating Various Services into a Seamless Operation Up-front Planning Designing Multi-Functional Frac Fluids Understanding Baseline Conditions Adjusting for Realistic Conditions 32 Closing Copyright - 2011 TBD America, Inc. All rights reserved.

33. 33Copyright - 2011 TBD America, Inc. All rights reserved. Dr. Barry Stevens President TBD America, Inc. barry@tbdamericainc.com http://www.tbdamericainc.com