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 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. 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
Tampen area
Low recpverable oil reserves comment on this in a few slides !
Daily avg. production-05 (Sm3/d)
1300
Available slots
7/2
Wells drilled 2004 3
Wells producing 5

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
G-3 god produsent med uventet gass gjennombrudd.
Merk at vi er subsea felt knyttet opp mot GFA og GFC plattformene.

8. GFS Statfjord Challenge:
Complex reservoir with low recovery, goal +18% (LTP )
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
drilled
G-3 drilled
DIACS / MLT

10. Gullfaks Area Structural Depthmap – Base Cretaceous
Gullfaks DIACS Wells
New ”Old”
Gullfaks
Gullfaks South
Rimfaks
Topas

11. New DIACS Wells in the Gullfaks Area
Month/Year Completed
Field - Formation
G-1H
02/2004
Gullfaks South – Statfjord fm
C-43
04/ 2004
Gullfaks – Statfjord fm
G-2YH
05/2004
F-2Y1H/F-2Y2H
11/2004
C-46
01/2005
Topas – Brent
D-3CH
05/2005
Gullfaks South – Brent fm
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. Why MLT and Remote Monitoring & Control?
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.

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
This could also be the case for two branches in a ML well. A ML well could be completely dominated by one of its legs
More flexibility for production of depleted low productivity zones versus high productivity GOR zones.
Optimze, if possible, the contribution from each branch, different drawdown and GOR development makes it necessary with smart well technology.
Mitigate early gas breakthrough, smart well insurance.

14. 34/10 – G-1 H Oil producer in segment A3 Well lies 30 m above OWC
Approx 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
30” section shoe
26” section shoe
17 1/2” section shoe
12 1/4” section shoe TD
Lower Statfjord Formation.
Nansen/ Eiriksson 2 Member.
Lunde Fm

15. Gullfaks field – Statfjord I-1 segment
This is an outline of the field the Brent Fm to the east, Cook FM in darker green in the middle and Statfjord Fm. to the west. The A platform is here, B here and the C platform furthest to the north
2. The smart well was drilled to the I1 segment of the Statfjord Fm to the southern edge of the field. Initial Oil-In-Place in the segment is 75 million bbls. This map of the I1-segment is what we call a flooding map and it shows our current best estimate of waterflooding and remaining oil and gas. The area to the east of this fault has been flooded, while to the west there is remaining oil, and this is where we drilled the smart well C-43 . Well C-16 is another producing well here. A41 injected water from 1994, but was replaced with B-40A in PCSI15 is a potential future target.
3. In the next slide I will show you a cross-section of the I1 segment along this red line through the three wells.

16. Gullfaks cross section – I1 Statfjord Fm.
Completed with a two zone DIACS
Production start 20 April 2004
C-16
Prod/gas inj.
B-40A
Waterinjection
0. On this cross section you see the Statfjord zones S11-S1 and the Base Cretaceous. The wellpath of C-43 ishown n black. It is a 6,5 km long well with TD set in the Lunde Fm. The red line is the fault with a low dip of approx. 90 lower that many faults in Gullfaks. A major reason for the smart completion was uncertainties relating to communications across this fault between the different Statfjord zones.
1. The OWC is here, and B-40A is injecting water into the lower part of the reservoir.
2. C-16 has produced 20 million bbl of oil since 1993, and over the last two years we have injected gas into the well to improve recovery.
3. So now – let us look into our experiences with this smart well. First completion design with a two zone DIACS and then the one year of production history.

17. C-43T2 - Completion Schematic
Pressure gauge
Two zone control
0. Well - we decided to try the smart completion that you see here. 150 meter of screens with the constrictors over the two intervals separated by swell-packers. Two downhole hydraulic valves to control flow.
1.These four here are geophones which were run to monitore fluid fronts more acuratly. They added to the complexity, and it was one of the reasons why we decided to have only one pressure gauge in the hole.
2. Flow from lower interval goes through the screens and up in the stinger and are controled by this lower valve.
3. Flow from upper interval goes through the annulus are controled by this upper valve.
As I mentioned, this Completion design was worked out during a two week period after the well was drilled and the logs became available. We had just completed a smart well in one of the Gullfaks satellites, so we had the DIACS valves, the stinger and PBR (Polished Bore Receptible) available. That is another example of people using their knowledge and energy to create the ”smart” well by using the equipment available.

18. DIACS from Schlumberger
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.
0. Perhaps the smartest is the downhole control valves provided by Schlumberger which allows us to adjust production from the two zones by surface-operated valves. The valves are operated by applying hydraulic pressure from surface against a nitrogen coil and bleeding back. The flow area can be adjusted from to 8.67 inches in ten increments plus closed. Return volume is twice as big when valve is being closed, giving a good indication of valve position.

19. G-2 YH MLT with zone control
Oil producer in segment A4
Well lies 20 m above OWC
Approx 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.
A sidetrack from G-2 H became the first opportunity to drill a ML well in 2004.
Hollow whipstock suitable for side tracking old wells.
The sidetrack penetrated the gas cap which was isolated by stage cementing.
Hydraulic system chosen due to high temperature.

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.
7” liner tåler rotasjon, kompaksjon og røff behandling.
Men 7 ” kan vi putte på DIACS videre ut i lateralen.
Med Halliburton (5 ½ ”) og Baker sine whipstock /kryss løsninger får du mindre hull, Baker bruker en expandable løsninging.
Setter vi DIACS kommer vi ikke til løpene, men kan trekkes. Det er ofte dye operasjoner, dyrt å f.ex stenge av en vann sone, men kanskje ikke ønsket resultat, i de fleste tilfellene vil vi heller stenge av og bore en ny lateral som er optimalt plassert og kan nå ”nye” reserver.
Level 3: er ingen mnekanisk tetning eller semnet.
Level 4: sement i krysset.
Vi kjører level 3 med swell packer som etter vår mening kan kvalifiseres til level 4, vi stoler på swell packerne, og forhåpentlig varer de en stund.

21. Cost elements ML & RMC costs D&C section Run upper completion
Drill to top
reservoir
Run upper
completion
D&C
section
ML & RMC costs
Reservoir
Blå boks: 12 ¼ ” seksjonen.
Orange: Produksjons rør
Gul boks: Boring av reservoar seksjonen, antatt disse like lange.
Blå + orange er det som må gjøres uansett, grunnlags investeringer.
The main bore reservoir section is planned to pay for it self in addition to all the other costs. The lateral reservoir section must only cover the incremental cost which is roughly one fifth of the total mainbore cost.
For dype felt som GFS STfh vil det være en fordel med MLT, iom at vi får lange 12 ¼” seksjoner, dermed vil delta kostnadene bli lavere.

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.
TL:G-2 YH: Accelerated production when completing G-2YH as an MLT (including old well bore) versus a pure sidetrack.
BL: F-2YH: Accelerating effect of drilling a MLT versus a single branch well. The cumulative production in 2010 between a single branch well in the north and a MLT is little. Reflects one of the problems quantifying the potential of a MLT when using a coarse and homogenous model. A homogenous model will be able to produce almost the same amount of oil, with fewer drainage points, only using longer time.
TR: G-3YH: 2 branch versus 3 branch well. Simulations which have gas rate limitations on the platform. 3 branch: the majority of volumes on the A2 segment are lower Statfjord sands. The Y2H branch will primarily be producing from these low productivity sands.. This branch has been included to increase the possibility of draining of these lower StFJ volumes than would be possible with only the Y3H branch. The reason for doing it now is that the sands due to production, become more and more depleted, which increases the operational risks of drilling into this segment at a later stage.
F-2 YH uncertainty in geological interpretations has also been simulated as possible outcomes.
Net field production profiles have been used.
Decsions tree evaluating the well concept was used where the main geological uncertainty has been connected to the operational problems. The operational risk of running the whipstock and DIACS have been taken into account (10% chance of fail, and 90 % change of success). In addition the geological uncertainty (20 % chance of low structure, 80 % chance of high structure) has been taken into account. Thus, based on the different possible outcomes and production profiles from the simulation model, referring to the different sensitivities, a NPV was computed for drilling a MLT or single well in the segment. Based on this risk analysis, production experience, the acceleration effect as well as our knowledge of the reservoir, we believe that a MLT is the correct well concept for this reservoir, in this area.

23. Total reservoir exposure vs rig days
ML wells
Gir antall meter komplettert 8,5" ( eller 9,05" ) seksjon dividert med totalt antall riggdøgn. Det blir omtrent ekvivalent til prisen pr meter komplettert reservoarseksjon.
Noen brønner har hatt seksjoner for datainnsamling som F-4 og G-2. Jeg har trukket fra tiden man har brukt på alle tilbakesementerte spor slik at ikke brønner med store hullproblemer eller lete aspekter skulle komme dårlig ut.
For G-2Y2H har jeg tatt antall meter i G-2Y2H og dividert med all tiden vi har brukt siden vi begynte å trekke det kollapsete produksjonsrøret.
Historikken til noen av brønnene er relativt komplisert, så jeg må kontrollere. Det ser imidlertid ut til at F-2H og G-2Y2H kommer godt ut i forhold til snittet for de andre brønnene.

24. Swell packers
Max ID
Min ID GR
Swell packer
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.
D-3CH
Annulus
Tubing
The critical part of the system was the swell packer. The Swell packer shall perform external zone isolation between the reservoir and the predrilled liner. Swell packers set in shale, in F-2 one in a bad quality sand and one in a shale
Gamma ray and caliper log were run in the well before completion, and this figure shows the result.
We can see a shale between 5040 and 5060 m MD, and the caliper shows that the well diameter varies between 10 inches and 8.5 inches - and the placement of the swell packers is marked in black. The swell packer was placed on 5.5 “ liner - with and outer diameter of 8.15”. They were rated to seal of a 9.15” hole with 200 bars pressure difference
What have we learned? The experience with the Swell packer has been very positive
The Lower Statfjord was shut off; the pressure measurement in annulus will show the reservoir pressure in Lower Statfjord (in green)- while Nansen and Eriksson prouced- and the tubing pressure is in blue.
The red shows the difference, and will be the pressure differenced over the swell packer. The difference was measure to 60 bars. This was done only 12 days after the swell packers were run in the well.

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.
Expose more of the reservoir without incresasing the risk of operation.
DIACS reduce future interventions. Rsevoaret lite borbart på sikt…GI planlegges
Possibility and flexibility to produce lower Statfjord formation, improved reservoir knowledge.

26. Reservoir quality Geological cross section Permeability
Good sands: mD
Poor sands: mD
in the reservoir
Porosity 20 %
Limited reservoir communication
This overhead shows the geology of the field – and is a schematic overview over the geology in the Statfjord Formation at Gullfaks Sør:
The upper part consists of marine sandstone with estimated high connectivity and good reservoir quality – upto Darcy sands
Deeper in the structure there are more fluvial channels
The production experience from the Statfjord Formation is only from the upper part.
Production history, as was shown on the previous figure has also shown us that there was less reservoir connectivity than expected.

27. Assessment of smart well solutions
Why
Assessment of result
G-1H
RMC
Zone control
Gained important information from a complex reservoir and contribution from “poor” sands.
Individual tests of the two zones have been performed.
Have not choked back the gas- since it comes from the zone which contribute the most (85% of the total production)
In the future the plan is to choke the gas to increase the outtake from the rest of the sand.
Zone 1 is shut-in to prevent further pressure drop before drilling the next well.
Limited production increase

28. Assessment of smart well solutions
Why
Assessment of result
G-2YH
RMC in junction
MLT with branch control
Both legs are contributing to production.
No isolation between the two branches, due to leaking QMP isolation packer
The well works as a normal well without DIACS, thus no extra production increase using DIACS.
DIACS helped in clean-up of the well
Use of perforated whipstock has probably given a extra gain from the motherbore which we would not have been able to produce from (produces from an isolated segment)
later the mother bore was cleaned up. A leak in the isolation
The sidetrack was put on production first Measured initial PI = 100 Sm3/d/bar, GOF = 170 Sm3/Sm3
The mother bore was tried to start up twice without success. Probably due to low PI due to killing operations combined with heavy mud in the well after perforating the whipstock. About one week packer developed during cleanup of the mother bore.
Partly cleaned the Y1 bore, but to the leakage from Y2 it is uncertain how big the opprenskningsraten in this well bore has been (total rate 2000 Sm3/d)

29. Production experience: total oil rate
G-2YH
F-4AT3H
Add. Perf
G-1H
F-2YH
G-3HT2
Oljeraten har øket (fordi vi har eksponert mer reservoar ved å bore flere brønner og ved å tilleggsperforere. Begge deler var jo anbefalinger fra IOR prosjektet.)
G-2HT3/F-4AT3H