Optimizing Oil Recovery: CO2 Huff-n-Puff Process in New Mexico and Texas Reservoirs

1. New Mexico Vacuum Fd. Slaughter Fd. Texas CO2 HUFF-n-PUFF PROCESSIN A LIGHT OILSHALLOW SHELF CARBONATE RESERVOIR(Contract No. DE-FC22-94BC14986) SSC DOE Class-II Project Review Univ. of TX - C.E.E.D. Odessa, TX 12.Dec.02 by Scott C. Wehner

2. NORTHERN SHELF Midland - Odessa

3. Pre-1997

4. Generic Information Producing Horizon Grayburg & San Andres Fms Lithology Carbonate w/ few sands Heterogeneous Producing Interval 4,200 – 4,700 ft Avg. Net/Gross Pay Ratio 40/100 Reservoir Temperature 95o to 101o F Injection Pattern 40-A 5-Spot 20-A Line Drive Porosity Range (Avg.) 0 – 23.7 % (11.6%) Permeability Range (Avg.) 0 – 530 md (22.3 md) Reservoir Pressure Above Pb Oil Gravity 38o API Fractures Uncommon Production Drive Mature Waterflood

5. H-n-P Project Objectives • Determine whether oil can be recovered economically in a cyclic CO2 Huff-n-Puff process in a reservoir undergoing a waterflood/drive • Provide guidelines and transfer findings to the industry

6. Relation between Drive Index and Recovery Efficiency of the CO2 H-n-P Process Developed from Gulf-Coast sandstone reservoir field trials

7. Benefits of Wide Application if a Successful Process • Mitigate early negative cashflows in a CO2 flood • Add reserves associated with H-n-P CO2 process • Reduce LOE • Accelerate miscible CO2 process • Maximize recoveries in smaller fields • Maximize recoveries of acreage not targeted for miscible CO2 flooding • Provide early injectivity measures

8. Generalized CAPEX & Response Generalized CAPEX & Response Flood Starts 10 2 CO 8 Base WF MBOPD Miscible H-n-P 6 or 4 $MM 2 0 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Year

9. 12 - 40 Days RESIDUAL OIL ~100 ft RESIDUAL OIL ~300 ft

10. 1 - 4 Weeks RESIDUAL OIL RESIDUAL OIL . . . ABSORBING CO2

11. 2 - 6 Months . . . MOBILIZES ACTIVE LOWER VISCOSITY WATERFLOOD . . . SWELLED OIL

12. Project Components • Reservoir Characterization and Geological Model • Parametric and Site-specific Simulation Study • Field Test • History-match of Field Test • Technology Transfer • Reservoir Characterization and Geological Model • Parametric and Site-specific Simulation Study • Field Test • History-match of Field Test • Technology Transfer

13. Typical H-n-P Performance (parametric simulation) • Peak oil rate is 2 to 5 times the base rate • Incremental oil of 1.5 to 3 MSTB for 25 MMscfCO2 • Peak oil rate returns to the base rate after 40 to 80 days • Incremental oil increases with injected CO2 volume

14. Typical H-n-P Performance (parametric simulation) • Incremental oil increases with watercut • WOR returns to the base level at the same time • Reservoir heterogeneity was not important. Results from 1, 2, 5, and 12 layer models were similar. • Trapped gas saturation was required for incremental oil

15. Typical H-n-P Performance (parametric simulation) • Oil Swelling, viscosity reduction, and near well pressure increase cause initial rise in oil rate but not long term incremental oil • Trapped gas causes long term incremental oil production. Without trapped gas, the oil production rate falls below the base rate after the initial peak because the H-n-P zone is being resaturated with oil

16. 186 187 244 194 193 Site Specific 196 197 Reservoir DOE H-n-P Model 199 200 201 203 204 1 4-D, 3-C Seismic Central Vacuum Unit (CVU) (Excerpt)

17. INJECTION ! Injected ~50 MMscfCO2 ) Avg. 2.21 MMscfCO2/D ) Avg. 3.4o F ) Avg. 622 psig ! CO Containment 2 ! Bottomhole Pressure ! CO Breakthrough 2

18. SOAK 20-Day Soak ! Offset Injectors Activated ! Pressure Increased to 889 psig ! Cross-flow ? !

19. PRODUCTION ! Returned to Active Status ) Avg. 631 psig: 13-18/64" Chokes ) 400 - 900 Mscf/D ! Reduced H O Rate 2 ! 94% CO Gas Stream 2 ! Peak Oil impacted by Chockes/Artificial Lift ! Winter Weather Effects ! Wellbore Loading Gas Handling/Disposal

20. Central Vacuum Unit No. 97

29. Slaughter Sundown Unit (SSU) (Excerpt) DOE H-n-P

30. Sundown Slaughter Unit No. 1341

31. Results/Conclusions • Sg (trapped) Appeared Non-existent in Demo • All injected gas recovered? • Oil production results mixed but lower thansimulations • Economically Challenged • Cannot support trucked/pumped CO2 • Pipeline creates options for consideration • Produced CO2 Disposal Not Always Available

32. Results/Conclusions • Economics burdened by costs to flow/pump wells • Restricting producing rate during flowback reduces recovery • H-n-P may provide indication of reduced H2O injectivity in miscible WAG operations • An estimate of CO2 injectivity can be found • H2O production can be reduced near-term

33. Results/Conclusions • LOE are reduced near-term • Oil response relates to CO2 volume • Higher H2O-cut provides better H-n-P response • Reservoir characterization not so critical • Don’t try this at home boys & girls…… it’s still R&D in SSC Waterflooded Reservoirs

38. One Lingering Question… Can the application of CO2 H-n-P cause an accelerated response from future CO2 miscible flooding?