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

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: 310-320 bar at 1850 m TVD MHN Bubble point pressure: ~200-240 bar at 1850 m TVD MHN GOR: ~ 100 Sm³/Sm³ Viscosity: ~ 0.5 – 1 cp Dip angel in western part: 12-15 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 %

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

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 : …………….

Reservoir Quality Reservoirs: Brent, Cook, Statfjord & Lunde Complex reservoir, very faulted Porosity: 25-35 % 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

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

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

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

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 2018. Ambition: Year 2030 Mill. Sm3 per year

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

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.

Gullfaks Main Field – oil rate prognosis

Gullfaks ”IOR ambition” project Duration: 2006-2008. Main goal: mature the undefined IOR ambition volumes (and more?) to RC 5. Identify specific measures and demonstrate that they may be economical feasible.

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)

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.

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.

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.

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: 216 000 Sm³ which gives a daily rate of around 590 Sm3/d

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

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

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’.

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

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

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 10-20 Mill. Sm³ oil identified. Too high cost totally and therefore a none economic project with to days framework condition.

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.

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.

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.

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.

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

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?