David S. Schechter

1. Reservoir Characterization and Reservoir Engineering in the Naturally Fractured Spraberry Trend Area David S. Schechter Harold Vance Department of Petroleum Engineering

3. Summary of CO2 Flooding • SPE 38849 - CO2 recovers tertiary oil in every project surveyed • Technical success is sometimes economic failure • Economic failures primarily due to lack of understanding of reservoir heterogeneity • Proven technology

4. Challenges in CO2 Flooding • Extending the technology to provinces previously thought to be “unreachable” • Extending the technology to reservoirs previously thought to be “unsuitable”

5. Summary of Spraberry Reservoir Study Core Core-Log Log Shaly Sand Analysis Whole Core Analysis Open hole Analysis Identification of fluorescing intervals Modified q-plot Logging identification of fractured intervals Mapping pay zones in pilot area Fluorescing intervals Directional perm Sponge core saturation Fracture description Paleomagnetic orientation CO2 gravity drainage Gamma ray Neutron Sonic Induction FMI Outcrop Study Plug Analysis Spacing Length Connectivity Imbibition Capillary Pressure Wettability Relative Permeability Fracture Correlation Orientation Degree of mineralization Spacing (density) Length Aperture Connectivity Stress sensitivity Termination at lithology contrast Horizontal Core well Fabric Analysis Thin section X-ray diffraction SEM Minipermeametry Stress measurement Spacing Aperture Degree of mineralization

6. Fracture Correlation Well Tests Data Collection Rock Properties & Fluids Pressure/Production Multi well Core Log PVT Seismic Reservoir Simulation Interference Test Pulse/Step-Rate Test Tracer Surveys Humble Pilot O’Daniel Waterflood CO2 Pilot Single well PBU/PDD Injection profiles Imbibition Lab Exp. At ambient and reservoir conditions Static and Dynamic imbibition CO2 Lab Exp. Management Decisions Numerical modeling MMP determination IFT determination Phase behavior determination Gravity drainage Pilot Drill the wells Waterflood Inject CO2

7. O’Daniel Martin Co Canyon Reef Carriers CO2 Supply Shackelford Midland Co Glasscock Co Preston Driver Midkiff Tippett NorthPembrook Merchant Sherrod Pembrook Aldwell Upton Co Reagan Co Benedum Spraberry Trend Area “Largest Uneconomic Field in the World”

8. Key Elements in Designing Water and CO2 Injection Projects in Naturally Fractured Reservoirs I. Extent and location of matrix porosity II. Wettability of oil saturated matrix III. Connectivity of fracture system - Vertical communication - Areal communication IV. Time scale for transfer mechanisms - Capillary imbibition - Diffusion - Gravity drainage

9. I. Matrix characterization • Fluid saturations • Mechanical Properties • II. Core-log integration • Identification of oil saturated intervals • III. Fracture characterization • Spacing • Height • Length and aperture

10. IV. Transfer Mechanisms - Imbibition - CO2 Gravity drainage V. Scaling imbibition to match waterflood performance VI. Prediction of CO2 Performance

11. Upper Spraberry Type Log

12. GR-Porosity Log O’Daniel #37

13. Spraberry Rock Types

15. Clay Point Modified q-plot for Spraberry Trend Area 1.0 0.8 Compacted Shales 0.6 Undercompacted q-Factor 0.4 Tight Non-Producible 0.2 Thinlaminatedpayzones 30 .15 (< 2 ft thickness) .10 20 Producible Massive clean pay zones (< 5 ft thickness) Fluid 0 0 10 20 30 40 0.7 Sand Point Effective Porosity, (%) Point

16. Rock Type A: Main Pay • 0 > 7% • k > 0.1 md • Clay < 7% • Intergranular Pores • Swi: 35 - 50 %

17. Spraberry Rock Type A • Very fine grained sandstones and coarse siltstones • Well sorted • Very well consolidated • Composition:

18. CLAYS AFFECT POROSITY AND PERMEABILITY Authigenic clays occur as pore linings, pore bridgings or discrete particles Depositional clay occurs as dispersed clay particles or as laminae 0.125mm i i Shale Laminae

19. DP 0.05 mm Secondary Porosity Due to Dissolution of Grains and Cements Depth: 7230.3 ft Grain Size: 55 mm Rock Type “A” Porosity: 12% E.T. O'Daniel #37 5U unit

20. Authigenic Cements Destroy Pore Space Quartz Quartz Dolomite P D

21. Vertical, Mineralized Fracture: 1U Payzone Shackelford 1-38A

22. Vertical, Mineralized Fracture: 1U Payzone Shackelford 1-38A

23. Mineralized Fracture: 1U Payzone Shackelford 1-38A

24. Fracture Detection

25. Horizontal Core Well - O’Daniel #28

27. 5U ENE & NNE Fractures in Fluorescing Pay Sand

28. 5U ENE Fracture Set

29. Intersection of Upper Spraberry 5U NNE and ENE Fracture Sets

30. N42E orientation. • Average spacing of 3.2 ft • Smooth mineralized surfaces. • N32E orientation. • Average spacing of 1.62 ft. • Fractures have stepped surfaces. • No mineralization Overlay of 1U and 5U Fractures • N70E orientation. • Spacing skewed normal distribution with an average of 3.79 ft. • Fractures have smooth surfaces • No obvious mineralization.

31. Geomechanical Properties of Upper (1U) and Lower (5U) Sand Intervals • Low average Poisson’s • ratio (0.11) • Elastic moduli of these • units are nearly equal • (about 2.4 x 104 MPa). • Yield stress (mechanical • yield strength) of the upper unit is nearly twice that of the lower unit. Fracture variability between 1U and 5U due to differences in the clay and quartz content, 1U low clay, high cementation - stronger rock than 5U

33. oil Water Field dimension Overview of Imbibition Study • Oil recovery profile • modeling the experiments • Capillary pressure curve • Key variables in dual porosity simulation • Determine critical injection rate • Wettability Index • Aging effect on oil recovery • Effect of P and T on oil recovery • Upscaling the data • Capillary pressure • curve

34. Experimental Set-up for Static Imbibition Tests at Ambient Conditions

35. Wettability index vs aging time for different experimental temperatures Static imbibition A Displacement B Spraberry cores

36. Composite Imbibition Curves

37. Scaling Equations for Static Imbibition ; C = 10.66

38. Effect of Matrix Permeability and Fracture Spacing on Oil Recovery

39. Evidence of Weakly Water-Wet Behavior in Spraberry • Spontaneous imbibition of oil into water saturated Spraberry core • Spontaneous imbibition of oil into water saturated core during static Eq. Pc meas. • Low Pc during drainage and imbibition • Low Amott wettability indices Iw~ 0.2 - 0.3 • Scaled mercury contact angle of 50o • Reservoir condition contact angle measurements of 50o (within 10o)

40. Slow Imbibition is the Rate-Limiting Step Imbibition analogous to sieve slowly leaking fluid onto conveyor belt Conveyor belt analogous to water injection into fractures

41. Static Imbibition Modeling Oil recovered Oil bubble Glass funnel Core plug Brine Governing Equation Assumptions  No gravity effect Only Pc as driving force Fluid and rock are incompressible  

42. Up-scaled Recovery Profile 1U h = 10 ft Ls = 3.79 ft Upper Spraberry 1U Formation (Shackelford-1-38A)

43. Counter-current Exchange Mechanism Matrix Fracture Invaded Zone Matrix Water Oil Fracture Concept of Dynamic Imbibition Process

44. Experimental Set-up for Dynamic Imbibition Tests at Reservoir Temperature Air Bath Confining pressure gauge Brine tank Core holder Graduated cylinder Artificially fractured core N2 Tank (2000 psi) Ruska Pump Fracture Matrix

45. Oil Recovery from Fractured Berea and Spraberry Cores using Different Injection Rates Berea Cores Spraberry Cores

46. Dynamic Imbibition Modeling Single porosity, 2 phase and 3-D Rectangular grid block with grid size : 10 x 10 x 3 (Berea) ; z = 9 layers for Spraberry Fracture layer between the matrix layers Inject into the fracture layer Alter matrix capillary pressure only to match the experimental data zero Pc for fracture straight line for krw and kro fracture use krw and kro matrix from the following equations (Berea core):   

47. Berea Core Match Between Experimental Data and Numerical Solution Cumulative oil production vs. time Cumulative water production vs. time Spraberry Core Cumulative water production vs. time Cumulative oil production vs. time

48. Capillary Pressure Curves Obtained by Matching Experimental Data (Berea and Spraberry Cores)

49. Viscous force (v w Af ) Capillary force ( cos  Am) w h dz Am Af Dimensionless Fracture Capillary Number Lab Units: Field Units:

50. Injection Rate versus Oil-cut