1. Tom Beebe Project Manager
Application of Reservoir Characterization and Advanced Technology to Improve Recovery and Economics in a Lower Quality Shallow Shelf Carbonate Reservoir
Class II Project
DE-FC22-94BC14990
Tom Beebe Project Manager

2. Project Location

3. Welch Field Map

4. West Welch Unit History
1939 Discovery
1955 Pilot water flood began
1960 Unitized & initiate water flood
1966 Develop to 40 acre 5 spots
1971 Complete 40 acre 5 spots
1982 Initiate 10 acre well spacing line drive
1991 Complete 10 acre well spacing line drive
1994 Shut-in Prod / Inj Wells over the next 5 years
1997 CO2 pilot w/DOE 6 wells
2000 Drill first horizontal well
2001 Drill 4 horizontal wells

5. Comparison of Fields

6. Technologies Demonstrated
Cross well seismic
3D seismic interpretation
Petrophysical flow description
Reservoir simulation
Cyclic CO2 stimulation
Hydraulic fracture stimulation

7. DOE Project History

8. WWU DOE Project Area – Actual Performance

9. WWU DOE Focus Area – Actual Performance

10. Pattern Tertiary Performance
Green – Tertiary Oil Recovery
Magenta – HCPV CO2 Injected
Red – Annual Throughput (Processing Rate)

11. Producer Well Response & CO2 Injection Cumulative CO2 Injection
Dark Red Peak Incremental BOPD/BWPD/MCFPD
Magenta – Cum CO2 Injected, MMCF

12. Producer Well Response

13. Activities Since 2000
Emphasize on Optimizing Reservoir Processing Rate
Injection Wells
Step Rate Tests
Dip-Ins
Injection Profiles
Producing Wells
Workovers
Horizontal Well
Observation Well Logging
Cross Wellbore Tomography

14. West Welch Unit #4853 Horizontal Lateral

15. WWU #4853 Horizontal Simulation Surveillance
West Welch Unit #4853 (12/07/00)
West Welch Unit #4853 (02/01/01)

16. WWU #4853 Horizontal Well Results

17. 2001 Workover Results in the Focus Area
Spent $450M on 15 workovers (14 PRD & 1 CO2INJ)
Average 10 BOPD Incremental after 30 days Payout ~6 $21/BO and constant BOPD 50 BOPD incremental after ~1 year of production (1/3 of 30 day incremental)

18. Observation Well Logging
Last Column represents CO2 migration through reservoir
Comparison of Neutron log ran in 1994 to 2001 measure porosity change. N M1 M3 M5 Z6

19. Focus Area Forecasted Tertiary Performance
Not from model forecast, but prototype curve

20. Economic Summary

21. Simulation Historical & Forecasted Rates
From SPE West Welch CO2 Flood Simulation with an Equation of State and Mixed Wettability (1998)
Initial update of rate cards with model dataset (2002)

22. Simulation Historical & Forecasted Cumulative
Initial update of rate cards with model dataset (2002)

23. Cross Wellbore Tomography
Advanced Reservoir Technologies, Inc.
P.O. Box 985 Addison, TX
Ph        FAX

24. Summary
WWU & the DOE Area are both low productivity and low reservoir processing rate.
Last 2 years have focused on the demonstration phase with emphasize at optimizing the reservoir processing rate. The exception of wellbore tomography work done by Advanced Reservoir Technology.
Response observed from CO2 injection: Reduction in water production, increase gas production and flattening and incline in oil production.
Low HCPV CO2 injected, however greater volume of CO2 injected into focus area than original DOE area.
Successfully drilled horizontal lateral, however did not improve reservoir processing rate and application of the SURGI tool did not address fluid loss to previously open fracture.
Workover program did result in incremental oil, but results varied and appears to have a high decline rate.
Qualitatively measured CO2 migration through the main pay intervals, however some CO2 migration below pay.
Economics though positive ROR, would not be able to support capital investment and high injection withdraw ratio (IWR) deteriorates the return.
Original forecast from the simulation work does not match due to different CO2 injection scheme and performance.

25. Conclusions CO2 Pilot flood to improve recovery appears not economics.
Tertiary response occurred more often in the closet producer either north or south of the supporting CO2 injection well.
Efforts to improve the processing rate varied. (stimulations, injection tests and the horizontal well) The successful reservoir process rate improvements were not enough to improve flood performance.
Decision to move to the focus area helped improve potential response versus spreading out CO2 injection throughout the project.
The horizontal lateral either connected up existing fractures and / or the stimulation went into the same location.
Some of the well stimulation work appeared to have been needed prior to implementing the CO2 flood.
More attention needed to be addressed to out of zone injection. High IWR is problem during the water flood (evident during the modeling effort) as well as indication of out of zone CO2 injection in the observation well.