Case History of Gas Lift Conversions in Horizontal Wells in the Williston Basin

1. Case History of Gas Lift Conversions in Horizontal Wells in the Williston Basin Authored by Keith Fangmeier, Terry Fredrickson, Steve Fretland, and Lee Rieger Amerada Hess Corporation

2. Williston Basin Manitoba 212 Million Barrels Saskatchewan 1,776 Million Barrels North Dakota 1,361 Million Barrels Montana 815 Million Barrels South Dakota 31 Million Barrels

3. Beaver Lodge Field

4. Beaver Lodge Madison Unit Historical Production

5. BLMU Field Map

6. BLMU Reservoir Properties

7. Example Horizontal Section 25’

8. BLMU Field Redevelopment • Phase 1: ESP’s and GL with 2-7/8” tubing • Phase 2: ESP’s with advanced gas handling equipment • Phase 3: GL with 3.5” tubing • Phase 4: Facility and pipeline modifications • Phase 5: Future enhancements

9. Phase 1. ESP’s and GL with 2-7/8” Tubing • ESP’s • Installed in the initial completions to recover the large fluid volumes during drilling (~40,000 bbls) • Produced large fluid volumes (~3,000 BFPD) • Replaced with GL ran on 2-7/8” due to continual pump failures (2 failures/well/year) • Failures with consistent gas handling issues

10. Example Rates after Gas Lift Conversion

11. Phase 2. ESP’s with Advanced Gas Handling Equipment • Installed to maximize production • Utilized the new technologies from two ESP manufactures • Initial installation had a favorable run life of 8 months, but subsequent installations had short run lives (< 1 month)

12. Phase 3. GL with 3.5” Tubing • Keeps wells online • Overrides the heading issues • 3.5” tubing provided more tubing capacity

13. Production Tests after Conversion using 3.5” OD Tubing

14. Production Tests after Conversion using 3.5” OD Tubing

15. Summary of Average GVF’s

16. Phase 4. Facility and Pipeline Modifications • Production Enhancement • Install portable production facility (PPF) • Removes gas at well site lowering FTP • Monitor well continuously • Minimizes construction time • Easily removed and moved to other wells • More cost effective than installing larger flowlines

17. Gas Lift Pressure Chart

18. Production After Installation of PPF

19. Lifting Cost Summary • Gas Lift: $0.72/BOE • ESP: $1.31/BOE BOE = BO + (MCF/6)

20. Inflow Performance • Dual Porosity System (matrix/fracture) • Difficult to predict • PI increases with increasing drawdown • FGLR increases with liquid production

21. FLGR Response to Increased Drawdown

22. Future Enhancements • install 4.5” tubing (7-5/8” casing only); • install annular flow with conventional gas lift pressures; and • increase the gas injection pressure, with annular flow, for single point deep injection in the horizontal section.

23. Nodal Analysis Comparing Annular vs. Tubular Flow

24. Automation Overview • SCADA system currently in place • Scheduled to be replaced with a web based surveillance system • New system will allow production engineers to trend • Casing pressure • Injection gas rate • Flowline pressure • Flowline temperature • New system will used to better optimize production

25. Conclusions • The BLMU’s secondary gas cap, natural fractures, and horizontal completions create a production opportunity that is best exploited with gas lift. • Gas lift is more cost effective than ESP’s in the BLMU. • Inflow modeling of a naturally fractured reservoir with horizontal completions is difficult. • The State of North Dakota allows an operator to produce wells at a maximum or most efficient rate. • Increased drawdown permits recovery of lost drilling fluids and solids and subsequently increases GLR’s. • Well performance appears to improve as a result of continuous operations. • High volume lift systems require coordination between production engineering and field operations. • Gas lift is essentially transparent to the problems induced by terrain slugging.

26. Acknowledgments • Fred Roberts of Production Services in Williston, North Dakota • Amerada Hess Management Team