Search for reserves utilizing subsea multilateral and smart well technology

1. Search for reserves utilizing subsea multilateral and smart well technology Vibeke Haugen GF SAT

2. Outline • Background • IOR project – solutions chosen • Why MLT and DIACS • Assessment of smart well technology for GFS Statfjord • Production experience • Experience with swell packers • Conclusion

3. Gullfaks Satellitter • Utbyggingen av Gullfaks Satellitter er gjennomført i to faser • Bygget ut som undervanns produksjonssystem knyttet opp mot eksisterende infrastruktur • Utbyggingen består av feltene Gullveig, Rimfaks og Gullfaks Sør som ligger 10-17 km sør/sørvest for Gullfaks plattformene

4. Gullfaks Satellitter • Fase 1 • Oljeutvinning fra feltene Gullveig, Rimfaks og Gullfaks Sør • Olje/gass produseres til Gullfaks A • Gass reinjiseres på Gullfaks Sør og Rimfaks • Produksjonsstart 10.oktober 1998 • Fase 2 • Gassutvinning fra Gullfaks Sør med tilhørende kondensat • Gass/kondensat produseres til Gullfaks C • Produksjonsstart september 2001

5. Fase 1 utbyggingen • Består av 8 brønnrammer (D, E, F, G, H, I, J og K) • Totalt 31 slisser, hvorav 9 er beregnet på gassinjeksjon og 22 på oljeproduksjon • Gjenstår 1 slisse på G-rammen, 1 på F-rammen og 2 på E-rammen

6. Tampen area Gullfaks Sør – Statfjord formation • Discovered in 1979, and part of the Gullfaks Satellites – tie in to Gullfaks field – 10 km • Statfjord formation consist of 134 m oil zone, and gas cap • Statfjord formation • Production start: April 1999 • Reservoir depth: 3300 m • Pressure, initial: 476 bar • Temp. @ 3300 m: 128 oC

7. Gullfaks Sør Statfjord Formation • PDO 1995: Large volumes in the Statfjord fm. • Main reservoir in the Gullfaks Sat. • 7 wells 2000 Sm3/d. Reserves 12.6 MSm3 • 1999: F-4 T3H and G-2 T3H in production. • Surprise ! Produced much less than expected. • Result: Statfjord Fm. on hold. • 2001: G-3 T2H in production. • Behave in accordance to new/updated • expectations. Unexpected gas breakthrough. • 2002/2003: IOR project initiated. IOR project inititiated. • Identified problems: • Limited reservoir communication • Gas limitation

8. GFS Statfjord Challenge: • Complex reservoir with low recovery, goal +18% (LTP 2003-2008) • PDO – 12.6 MSm3. Today 5.4 MSm3 • Increasing GOR -> reduces the oil rates. Aggressive search to increase recovery factor: EXTENDING THE LIMITS - STEP BY STEPS • Additional perforation of G-2 H and F-4 H in lower Statfjord (summer 2003) • G –1 H with DIACS (2004) • G –2 YH MLT with DIACS (2004) • F –2 YH MLT with DIACS (2004) Currently planning • GI with RMC (MLT ?) (2006)

9. Development of GFS Statfjord reserves F-4 / G-2 drilled DIACS / MLT G-3 drilled

10. Gullfaks AreaStructural Depthmap – Base Cretaceous Gullfaks DIACS Wells New”Old” Gullfaks 1 1 Gullfaks South 4 0 Rimfaks 0 1 Topas 1 0

11. New DIACS Wells in the Gullfaks Area G-1H: Two zone DIACS with swell packers. C-43: Two zone DIACS with swell packers. G-2AH/G-2YH: MLT with DIACS control of two branches. F-2Y1H/F-2Y2H: MLT with DIACS control of two branches. C-46: Four zone DIACS with swell packers. D-3CH: Two zone DIACS with swell packers.

12. Poor reservoir communication and structural complexity  More drainage points reduces the uncertainty. The need for more drainage point is clearly based on the STOOIP and estimated volume pr. well. A smart well and MLT well will be more robust for the geologic complexity and uncertainty in the reservoir. More drainage points will increase the estimated production pr well expose more of the reservoir: minimize the drawdown extra reservoir penetrations also allows access to reserves that otherwise would be likely to be left behind. Why MLT and Remote Monitoring & Control?

13. Why MLT and Remote Monitoring & Control? • Production experience. • Want to keep old wellbore • Verify contribution from each branch • Optimize, if possible, the contribution from each branch, different drawdown and GOR • Adjust production from different zones by surface operated valves. • Clean-up of well easier with DIACS • More flexibility when co-producing with the other wells • Natural gas lift • Limited number of slots • Aquire more data about pressure communication in the reservoir. • Smart well technology is an insurance and it provides more data. • Reduces the need for expensive well interventions

14. 30” section shoe 26” section shoe 17 1/2” section shoe Nansen/ Eiriksson 2 Member. Lunde Fm Lower Statfjord Formation. 12 1/4” section shoe TD 34/10 – G-1 H • Oil producer in segment A3 • Well lies 30 m above OWC • Approx. 1000 m reservoir section (50/50 lower and upper Statfjord) • External zone isolation performed with open hole zone isolation • Swell packer set in Nansen • Pre-drilled liner

15. Gullfaks field – Statfjord I-1 segment

16. Gullfaks cross section – I1 Statfjord Fm. C-43T2 • Completed with a two zone DIACS • Production start 20 April 2004 C-16 Prod/gas inj. B-40A Waterinjection

17. C-43T2 - Completion Schematic Pressure gauge Two zone control

18. Adjusting production from different zones by surface-operated valves Operated by applying hydraulic pressure from surface and bleeding it back. Flow area from 0,055 in2 to 8,67 in2 Requested position verified by measuring bled back volume. DIACS from Schlumberger

19. G-2 YH MLT with zone control • Oil producer in segment A4 • Well lies 20 m above OWC • Approx. 1640 m reservoir section (50/50 L/U Statfjord) • St reservoir as prognosed. Absence of P2 segment. • Completed as MLT with branch control • Predrilled liner • Planar Dual Lateral; Level 4; Ranking E-1-PN-S/4-NR-RMC • The sidetrack penetrates the gas cap which is isolated by stage cementing.

20. Why hollow whipstock ? • Simple and well known operations. • Not necessary to get the lateral liner to TD. • Can impose high loads on the lateral liner while RIH. • Level 3 with swell packers or level 4 if necessary. • Loss of access to motherbore tolerable because: • Access to motherbore blocked anyway by the RMC. • Access after pulling completion not very desirable. New lateral is a more likely option.

21. D&C reservoir section Run upper completion D&C Reservoir section Drill to top reservoir ML & RMC costs Cost elements

22. Production profile one vs. two branches • Eclipse simulations used for justification of MLT • Decision tree, evaluating well concept used. • Increased production and accelerated effect. • Possible to produce from areas of low productivity which otherwise would be left behind. • Limited reservoir communication, need for more drainage points. • Mitigate gas breakthrough.

23. ML wells Total reservoir exposure vs rig days

24. Annulus Tubing D-3CH Max ID Swell packer Min ID GR Swell packers • Perform external zone isolation between the reservoir and the pre-drilled liner. • External zone isolation performed with open hole zone isolation. • Gamma ray and calliper log run.

25. Conclusion • Well solution chosen: • Long horizontal wells, include entire formation. • MLT : Expose more of the reservoir • Smart: Remotely operated downhole valves • Simple: with respect to operations as well as long lifetime for wells (10 years) • Swell packers performs the necessary isolation, but it is not enough to only let the packer swell in OBM, it need produced HC to isolate. • Better data gathering • Pressure gauge failure • Producing from separate zones give valuable reservoir information. • Limited production rate improvement • Mitigate gas breakthrough and balance production from ML legs • Smart wells an insurance and provides data to help in further development of the field • Limited number of slots • Upgraded reserves • MLT well solution accelerates the reserves, gives better NPV, thus further development of low recovery reservoirs is possible. • The experience gained with smart and ML wells has encourage further development of GFS Statfjord.

26. Geological cross section Reservoir quality • Permeability • Good sands: 100-2000 mD • Poor sands: 1-100 mD • 50 - 50 in the reservoir • Porosity 20 % • Limited reservoir communication

27. Assessment of smart well solutions

28. Assessment of smart well solutions

29. F-4AT3H Add. Perf 10.2003 G-1H 02.2004 G-2YH 07.2004 F-2YH 11.2004 G-3HT2 07.2001 Production experience: total oil rate G-2HT3/F-4AT3H 04.1999