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Application of Reservoir Characterization and Advanced Technology to Improve Recovery and Economics in a Lower

Quality Shallow Shelf Carbonate Reservoir

Class II ProjectDE-FC22-94BC14990

Tom BeebeProject Manager

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Project Location

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Welch Field Map

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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

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Comparison of Fields

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Technologies Demonstrated

• Cross well seismic• 3D seismic interpretation• Petrophysical flow description• Reservoir simulation• Cyclic CO2 stimulation• Hydraulic fracture stimulation

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DOE Project History

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WWU DOE Project Area – Actual Performance

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WWU DOE Focus Area – Actual Performance

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Pattern Tertiary

Performance

•Green – Tertiary Oil Recovery

•Magenta – HCPV CO2 Injected

•Red – Annual Throughput (Processing Rate)

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Producer Well Response & CO2

Injection Cumulative CO2

Injection

•Dark Red Peak IncrementalBOPD/BWPD/MCFPD

•Magenta – Cum CO2 Injected, MMCF

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Producer Well Response

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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

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Well No.Date of HZ completion

Lateral Length Lateral Specifics Completion Technique

WWU #4853 Dec-00 3500 OH - 4-3/4"

1) SURGI completion, Sand Frac 6 locations spread throughout lateral, Pumped 20,000# of 20/40 resin coated sand from 1 to 4 PPG, at 18 BPM down tubing x 4 BPM down csg. However only got good frac on 1st treatment, 2nd and 3rd appared to go into 1st treatment, 2) CO sulfate scale and frac 5 location x same design as previous except new SURGI tool x 14 BPM dn tbg x 4 BPM dn csg. 3) Currently, cmt squeeze 2500' of lateral to abandon and ultimately restimulate remaining 1000'

West Welch Unit #4853 Horizontal

Lateral

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WWU #4853 Horizontal Simulation Surveillance

West Welch Unit #4853 (12/07/00)

West Welch Unit #4853 (02/01/01)

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WWU #4853 Horizontal Well Results

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2001 Workover Results in the Focus Area

Spent $450M on 15 workovers (14 PRD & 1 CO2INJ)

Average 10 BOPD Incremental after 30 daysPayout ~6 Months @ $21/BO and constant BOPD50 BOPD incremental after ~1 year of production (1/3 of 30 day incremental)

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Observation Well

Logging

•Last Column represents CO2 migration through reservoir•Comparison of Neutron log ran in 1994 to 2001 measure porosity change.

M1

M3

M5

Z6

N

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Focus Area Forecasted Tertiary Performance

Not from model forecast, but prototype curve

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Economic Summary

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Simulation Historical & Forecasted Rates

From SPE 39808 West Welch CO2 Flood Simulation with an Equation of State and Mixed Wettability (1998)

Initial update of rate cards with model dataset (2002)

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Simulation Historical & Forecasted Cumulative

Initial update of rate cards with model dataset (2002)

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Cross Wellbore Tomography

Monitor Tomogram

Baseline Tomogram

Difference in Apparent PorosityMonitor - Baseline

First Monitor Surveys

Reconstructed CO2 VolumeEstimating CO2 Saturation

www.advancedreservoir.comAdvanced Reservoir Technologies, Inc. P.O. Box 985 Addison, TX 75001-0985 Ph. 972-418-0992       FAX 972-418-2064

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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.

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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.