1. Rune Instefjord Project leader, Gullfaks IOR
Gullfaks field
Rune Instefjord
Project leader, Gullfaks IOR

2. Key data for GF main field
Location: northern North Sea
Discovered: 1978
Start production: 1986
Base oil reserves: 356 Mill. Sm3
Produced to date: 327 Mill. Sm3
Expected recovery: 61 %
Recovery pr. 2006: 56%
Initial pressure: bar at 1850 m TVD MHN
Bubble point pressure: ~ bar at 1850 m TVD MHN
GOR: ~ 100 Sm³/Sm³
Viscosity: ~ 0.5 – 1 cp
Dip angel in western part: deg
Gullfaks
Location: northern North Sea
Discovered: 1978
Start production: 1986
Base reserves: 356 Mill. Sm3
Produced to date: 327 Mill. Sm3
Expected recovery: 61 %

3. Gullfaks Field
Structural setting and reservoir performance, Gullfaks Field
Complex fault system
Main fault system trending north-south: large faults (50 – 250 m throw)
Secondary fault system east-west (10 – 100 m throw)
Three structual areas
A major challenge to realise the IOR potential, is a continuous improvement of the structural description by
frequent seismic surveillances (conventional time lapse and Ocean Bottom Seismics)
Use of advanced geological and reservoir simulation models

4. Structural interpretation
Here is an east-west seismic line with interpretation on, and below is shown the corresponding geologic cross section.
I show you this to illustrate the structural complexity, and also to illustrate that the field can be divided into three separate structural regimes : …………….

5. Reservoir Quality Reservoirs: Brent, Cook, Statfjord & Lunde
Complex reservoir, very faulted
Porosity: %
Permeability:
Tarbert, Etive, good Ness, good Statfjord and Cook- 3 >1D
Rannoch, poor Ness, poor Statfjord, Cook-2 and Lunde : 100 mD – 1 D
Moderate-to-High Reservoir Quality
Contrasting layers
Weak formations

6. DRAINAGE STRATEGY (primary)
Aquifer support
Water injection
Reservoir pressure over bubble point
Injectors in the water zone
Producers high on structure

7. Drainage strategy (continues)
Secondary:
Gas injection, up-dip
WAG injection
Horizontal wells
Reservoir pressure under bubble point
Commingle production
Secondary:
Gas injection, up-dip
WAG injection
Horizontal wells
Reservoir pressure under bubble point
Commingle production
Secondary:
Gas injection, up-dip
WAG injection
Horizontal wells
Reservoir pressure under bubble point
Secondary:
Gas injection, up-dip
WAG injection
Horizontal wells
Secondary:
Gas injection, up-dip
WAG injection
Why?
Avoid production reduction when gas export is at its maximum
Reduce storage costs and CO2 tax
Produce attic oil
Reach areas difficult to reach with water injection, ex. Ness by LB injection
Get uniform drainage, decrease sand production
Drain by-passed oil
Create gas lift, save drilling costs
Accelerate production
Why?
Avoid production reduction when gas export is at its maximum
Reduce storage costs and CO2 tax
Produce attic oil
Reduce residual oil saturation
Reach areas difficult to reach with water injection, ex. Ness by LB injection
Get uniform drainage, decrease sand production
Drain by-passed oil
Why?
Avoid production reduction when gas export is at its maximum
Reduce storage costs and CO2 tax
Produce attic oil
Reduce residual oil saturation
Reach areas difficult to reach with water injection, ex. Ness by LB injection
Get uniform drainage, decrease sand production
Drain by-passed oil
Create gas lift, save drilling costs
Accelerate production
Why?
Avoid production reduction when gas export is at its maximum
Reduce storage costs and CO2 tax
Produce attic oil
Reduce residual oil saturation
Reach areas difficult to reach with water injection, ex. Ness by LB injection
Get uniform drainage, decrease sand production
Drain by-passed oil
Create gas lift, save drilling costs
Why?
Avoid production reduction when gas export is at its maximum
Reduce storage costs and CO2 tax
Produce attic oil
Reduce residual oil saturation
Reach areas difficult to reach with water injection, ex. Ness by LB injection

8. Gullfaks reserves estimates through time
STOOIP (3,6 billion bbl)
Remaining oil
2,2 billion bbls
BASE PROFILE
RESERVES
PRODUCED

9. Reserves Growth Gullfaks
In additon, tie-in of satellite fields has increased the oil and gas sales from the field (1994 Tordis, 1998 GF Satellites Phase 1, 2001 GF Satellites Phase 2.
Present prognosis for economical lifetime: Year Ambition: Year 2030
Mill. Sm3 per year

10. IOR at Gullfaks Main reasons for improved recovery
Continuous focus on reservoir description and monitoring
An increased no. of drainage points / wells and the use of superinjectors for water injection
Supplementary gas injection (WAG) in selected reservoir segments
Increased process capacities where necessary both for water (prod/inj), liquid, oil and gas
Reduced inlet separator pressure
Use of time-lapse (4D) seismic to map remaining hydrocarbons

11. Ambitions in Long Range Plan
Produce 400 Mill. Sm³ oil in the field life time. Corresponding to around 70% recovery factor on the main field.
Cost reductions and an active IOR implementation is the most important instrument to reach the ambition.
Lengthening the field life time with several years.
Third parts processing.

12. Gullfaks Main Field – oil rate prognosis

13. Gullfaks ”IOR ambition” project
Duration:
Main goal: mature the undefined IOR ambition volumes (and more?) to RC 5.
Identify specific measures and demonstrate that they may be economical feasible.

14. Gullfaks Main Field. Improved oil recovery.
Implemented:
Water injection from start
Upgrading of water injection capacities
Sand control (screens) in most wells
”Designer wells” (horisontal, 3D)
Extended reach drilling (9 km drilled, 10 km well is beeing drilled)
Extensive exploration activity within drilling reach from platforms => new volumes
Hydraulic fracturing in low perm reservoirs
WAG (Water alternating gas) injection
”Huff and puff” gas injection
Monobore completions
”Intelligent wells”, remotely operated zone isolation valves
Implemented (continued):
Multilateral wells
Coiled Tubing drilling
Through tubing drilling
Rig assisted snubbing
Underbalanced drilling
Expandable liners
4D seismic
Studied, but discarded:
Surfactant injection (pilot)
Gel blocking (pilot)
CO2 miscible injection
Under evaluation:
MIOR (Microbiological IOR)

15. Water circulation Main mechanism for IOR at Gullfaks.
Done a simulation study with extended water injection.
Maximum use of platform capacity for all phases.
Residual oil saturation down to 5% from lab experiments.
Drilling infill wells, both injectors and producers.

16. Water circulation, results
Most important mechanism is the creeping relative permeability and long tail production from each well.
One well has historically produced with oil rate < 100 Sm³ and wct > 0,9 for 7 years.
H2S is a problem, but nitrate injection seems to control it.
Water production may be an environmental challenge.
Added use of today’s medicine
gives the highest contribution
to the future recovery.

17. Drilling history at Gullfaks
3 platforms with 42, 42 and 52 slots.
Started with vertical wells (less than 60 deg) and 6 sub sea wells.
After 4-5 years drilled horizontal wells.
Water breakthrough gave sand problems:
Gravel packed wells, screen,
Fractured wells with proppants.
Last 5 years
Sidetracks.
Through Tubing Drilling.
Multilateral incl. DIACS in the well junction.

18. Sand handling project Assumption:
Most wells on Gullfaks has sand production.
Wells classified after probability for erosion.
Allow higher sand production rate in the cases with low erosion risk.
Monitoring erosion progress.
Started at Gullfaks A in 2003 after a pilot at GFA on 3 wells in 2002.
Installed at all 3 platforms in 2004.
Both accelerate and increase oil recovery.
Cumulative gain for ASR in 2003: Sm³ which gives a daily rate of around 590 Sm3/d

19. Seismic acquisition on Gullfaks
Shadow area
Surface seismic
1985, 1996, 1999,
2003
OBS acquired in 2001
OBS acquired
In 2003

20. Based on 4D/4C seismic… X After 1996 survey: After 1999 survey:
Well B-15AT4 successfully drilled 2003
Well C-44A successfully drilled early 2001
Well A-21A successfully drilled early 2000
Well B-41A successfully drilled late 2000
Well C-43 under drilling
Well A-46T2 drilled mid-2000
Well C-26AT2 drilled in 2003
Well C-15C drilled 2003 X
Potential new well location cancelled
After 1999 survey:
After 2001 survey:
Well B-4A successfully drilled in 1999
After 2003 survey:
Well A-29A successfully drilled in 2003

21. Status 4D
Based on 4D seismic we have drilled more than 10 wells with success.
Top Brent (Tarbert), top Etive, top Cook and top Statfjord are the formations where 4D has been most valuable.
Ness, Rannoch and lower part of Statfjord is more difficult.
Have seen 4D effects in areas around injectors were the pressure is significance higher than initial pressure.
All wells have hit their target and most of them produced more than expected in the ‘Recommendation To Drill’.

22. Flooding map Reservoir monitoring and management Reservoir Team
Structural framework
Sedimentology, detailed stratigraphy
Reservoir description and initial volume
Well position, and perforation levels
Production, injection rates, RST and PLT
Time-lapse seismic
Simulation models
Reservoir monitoring and management
Reservoir Team

23. Flooding map Water flooded Partly water flooded Uncertain flooding
Oil producer
Future producer
WAG injector
Water injector
Gas injector
Partly water flooded
Uncertain flooding
Water flooded
Gas flooded or originally in place
Oil filled

24. Alternative recovery methods
Surfactant pilot in the early 1990’s. Full field project stopped due to:
Chemical cost was too high relative too its efficiency.
Remaining oil saturation after water flooding was lower than expected.
Surfactant system efficiency was too little robust.
CO2 MWAG Study last years
Simulations done on Frontsim and Eclipse 300.
Potential of Mill. Sm³ oil identified.
Too high cost totally and therefore a none economic project with to days framework condition.

25. AMIOR Alternative project to reduce residual oil at Gullfaks.
Add nitrate (doing already due to reduction of H2S), phosphate and oxygen to the injection water.
Reducing surface tension between oil and water and thereby mobilize oil.

26. AMIOR Pilot in well A-41B recommend.
Closed area with steady-state conditions.
Good reservoir understanding.
Good spacing between injector and producer.
A-36 has an established water cut growth.
A-41B is perforated in the oil zone.

27. Prospects A wide range of prospects in the licence.
Drill from the platforms where possible.
Use existing infrastructure to produce from the discoveries.
Commercial solutions for prospects across licence boundary.
Coordinate exploration and production drilling.
Combine targets where possible.

28. Conclusions Recovery of 400 mill. Sm³ (app. 70% recovery factor).
Lengthening the field life time.
Water circulation is the main IOR method.
Drilling of new and less expensive wells important.
Alternative recovery methods may be a substantial part of the future.
Exploration and third part processing contributes.
Close collaboration between the different technical disciplines is an important premise to reach the ambition.

30. Requirements to moving volumes from resource category 7a and 6 to 5a

31. Requirements to moving volumes from resource category 7a and 6 to 5a, cont…
Profitable measure
Assumptions regarding this evaluation are given in Appendix B
Likelihood of implementation equal to or greater than 30 %. A way of calculating the likelihood of implementation is given in Appendix C.
Prepare plan (studies, eventual technology qualification, manning, budget,) and timing for next phase (when is the right time to proceed). The level of detail of such a plan depends on the size of the project/measure.
Documentation shall include;
Production effects (all HC phases) in the targeted reservoir(s)
Simple uncertainty estimation for production effects (low-medium-high)
Is the measure competing with other measures (yes/no – which ones)
Evaluate whether the measure has any consequence for process capacities[1] (yes/no – which ones)
Cost(Capex and OPEX) estimate for the measure (class A)
Economical evaluation
Plan and timing of next phase
[1] If yes; will the measure displace other measures?