Gullfaks field
Rune Instefjord
Project leader, Gullfaks IOR
Key data for GF main field
• Location: northern North Sea
• Discovered: 1978
•
Gullfaks
Gullfaks
•
• Start production: 1986
• Location: northern North Sea
• Start
Baseproduction:
oil reserves: 1986
356 Mill. Sm3
• Discovered: 1978
• Base
Produced
to date:
327Mill.
Mill.Sm
Sm3
reserves:
356
Expected recovery:
61 %Mill. Sm3
• • Produced
to date: 327
•
–
Recovery pr. 2006: 56%
Expected recovery: 61 %
• Initial pressure: 310-320 bar at 1850 m TVD
MHN
• Bubble point pressure: ~200-240 bar at 1850 m
3 500
TVD MHN
Rate 1000 Sm3/month
3 000
2 500
• GOR: ~ 100 Sm³/Sm³
2 000
• Viscosity: ~ 0.5 – 1 cp
1 500
1 000
• Dip angel in western part: 12-15 deg
500
0
1986
1988
1990
Basis Water
1992
1994
1996
1998
IOR Water
2000
2002
2004
Basis OIL
2006
2008
2010
IOR Oil
2012
2014
2016
2018
2020
Start prognosis
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
C
B
C
B
A
• 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 Depth Map, top Statfjord
Fm. View from south.
A
Vertical scale 4x horisontal
msl
5
km
Post-Jurassic
sediments
Domino System
Accommodation
1000 m
Horst
2000 m
Brent Gr.
Statfj.
Fm.
Tordis
breakaway
fault
3000 m
4000 m
Intra-Teist refl.
5000 m
Low-angle
detachment
6000 m
Basement
7000 m
8000 m
Structural interpretation
Line 736
W
CDP 400
600
800
E
1000
1200
1400
0000
0000
HORST
COMPLEX
1000
1000
ACCOMODATION
DOMINO
SYSTEM
2000
2000
3000
3000
4000
Intra-Lomvi
reflector
4000
5000
5000
Cretaceous/Tertiary
sediments
Base Cretaceous
unconformity
Brent
Group
Statfjord
Fm.
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
Secondary:
Secondary:
Secondary:
Secondary:
Secondary:
Gas
••••• Gas
injection,
up-dip
Gas
Gas
Gasinjection,
injection,
injection,
injection,up-dip
up-dip
up-dip
up-dip
•••• WAG
injection
WAG
WAG
WAGinjection
injection
injection
• WAG
injection
(continues)
Why?
Why?
Why?
Why?
••• Avoid
Avoid
Avoid production
production
reduction
reduction
when
when
gas
gas export
export
is
is at
at its
its
production
reduction
when
gas export
• maximum
Avoid production
reduction
when
gas export
is at itsis at its
maximum
maximum
maximum
•• Reduce
Reduce
storage
storage costs
costs and
and CO
CO22 tax
tax
•••• Reduce
storage
costs
and
CO
tax
Reduce
storage
costs
and
CO
Produce
Produce attic
attic oil
oil
2 tax2
•••• Produce
atticoil
oil
Produce
attic
Reduce
Reduce
residual
residual
oil
oil saturation
saturation
•••• Reach
areas
difficult
to reach
injection,
ex.
Reach
Reach
Reduce
areas
areas
residual
difficult
difficult
oil saturation
to
to reach
reach
with
with with
water
waterwater
injection,
injection,
ex.
ex. Ness
Ness
by
by LB
LB
injection
injection
Ness
by
LB
injection
• Reach areas difficult to reach with water injection, ex. Ness by LB
injection
Get
Get uniform
uniform drainage,
drainage, decrease
decrease sand
sand production
production
Drain
Drainuniform
Get
by-passed
by-passed
drainage,
oil
oil decrease sand production
Get uniform drainage, decrease sand production
Drain by-passed oil
Drain
Createby-passed
gas lift, saveoil
drilling costs
Create gas lift, save drilling costs
• Reservoir pressure under bubble point
• Reservoir pressure under bubble point
••
••
••
••
•
Commingle pressure
productionunder bubble point
•• Reservoir
Accelerate
•• Create
gasproduction
lift, save drilling costs
• Commingle production
• Accelerate production
•• Horizontal
Horizontal wells
wells
• Horizontal wells
Horizontal wells
Gullfaks reserves estimates through time
700
700
600
530
540
564
540
560
600
STOOIP (3,6 billion bbl)
581582 587 582581582
538
522
510502
500
588585
579
574
Remaining oil
500
478
400
400
300
321 325
317319
309
332
342
2,2 billion bbls
352 355
BASE PROFILE
300
284
257
230
240
RESERVES
230
211210
200
200
PRODUCED
100
100
Historie
Basis profil
Reserver
STOOIP
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
1993
1992
1991
1990
1989
1988
1987
1986
1985
1984
1983
1982
0
1981
0
1980
Olje (MSm³)
452
Reserves Growth Gullfaks
Sammenligning av prognoser for basis oljeproduksjon
Gullfaks hovedfelt
year
Sm3
Mill.mill
pr. år
Sm 3per
35
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.
30
25
20
Present prognosis for
economical lifetime:
Year 2018. Ambition:
Year 2030
15
10
5
0
88 Rev PUD
93 Høst
94 Høst
RSP 00
RSP 02
RSP 03
RSP 04
2016
2014
2012
2010
2008
2006
2004
2002
2000
1998
1996
1994
1992
1990
1988
1986
Produsert
RSP 96
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.
35
30
25
20
15
10
5
Basis
Basis+ØOU
Ambisjon
2026
2022
2018
2014
2010
2006
2002
1998
1994
1990
0
1986
Millions
Oljeproduksjon (Sm3/år)
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 Hovedfelt
Basis profil
Senfase trykkavlastning Cook
Infill Cook
Lavtrykk Cook
Forbedret sweep i Cook ved økt vanninjeksjon
Nye IOR-brønner i Brent
Massiv vannsirkulering i Brent
Statfjord IOR
Massiv vannsirkulering Statfjord
Krans/Kyrre IOR
Lunde IOR
CO2 prosjekt
Ambisjonsprofil
Lunde IOR 0,4<Sw<0,6
Sum all IOR Measures
0-3
7A
4A
7A
4A
4A
4A
7A
4A
7A
7A
6
7A
7F
Sum
Gullfaks
Cook
Cook
Cook
Cook
Brent
Brent
Statfjord
Statfjord
Krans
Lunde
Brent
Gullfaks
Lunde
All
Mill Sm³
356,7
1,0
0,2
1,1
0,2
10,6
7,0
0,2
1,3
0,5
2,1
17,4
1,7
43,3
Gullfaks Main Field. Improved oil recovery.
Implemented:
Implemented (continued):
• Water injection from start
• Multilateral wells
• Upgrading of water injection capacities
• Coiled Tubing drilling
• Sand control (screens) in most wells
• Through tubing drilling
• ”Designer wells” (horisontal, 3D)
• Rig assisted snubbing
• Extended reach drilling (9 km drilled, 10 km well is beeing
• Underbalanced drilling
drilled)
• Extensive exploration activity within drilling reach from
• Expandable liners
• 4D seismic
platforms => new volumes
• Hydraulic fracturing in low perm reservoirs
Studied, but discarded:
• WAG (Water alternating gas) injection
• Surfactant injection (pilot)
• ”Huff and puff” gas injection
• Gel blocking (pilot)
• Monobore completions
• CO2 miscible injection
• ”Intelligent wells”, remotely operated zone isolation valves
Under evaluation:
• MIOR (Microbiological IOR)
Water circulation
• Main mechanism for IOR at Gullfaks.
1,0
• Done a simulation study with extended
0,8
• Maximum use of platform capacity for all
Krw - Referanse
Krw - Sor = 0.2
Kro - Referanse
Kro - Sor =0.2
0,7
Rel. Perm.
water injection.
0,9
0,6
0,5
0,4
0,3
0,2
phases.
0,1
0,0
0
• Residual oil saturation down to 5% from
0,4
0,6
0,8
1
Water Saturation
lab experiments.
0,10
0,09
0,08
• Drilling infill wells, both injectors and
0,07
Rel. Perm.
producers.
0,2
0,06
0,05
0,04
0,03
0,02
0,01
0,00
0,6
0,65
0,7
0,75
0,8
0,85
Water Saturation
0,9
0,95
1
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.
WCT vs cumulative oil, history and
prediction
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:
Kurve for MSR-testing
 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.
Sand i sandfelle (gram/time)
 Most wells on Gullfaks has sand production.
100
90
80
70
60
50
40
30
20
10
0
0
•Cumulative gain for ASR in 2003: 216 000 Sm³
which gives a daily rate of around 590 Sm3/d
2
4
6
8
10
Tid (timer etter bunn opp på ny rate)
12
Seismic acquisition on Gullfaks
Surface seismic
1985, 1996, 1999,
2003
Shadow area
OBS acquired
in 2001
OBS acquired
In 2003
Based on 4D/4C seismic…
Well B-41A successfully drilled late 2000
Well C-44A successfully drilled
early 2001
After 1996 survey:
Well C-26AT2 drilled in 2003
X
Well C-15C drilled 2003
After 1999 survey:
Potential new well
location cancelled
Well B-15AT4 successfully drilled 2003
After 2001 survey:
Well B-4A successfully drilled in 1999
After 2003 survey:
Well C-43 under drilling
Well A-29A successfully
drilled in 2003
Well A-21A successfully
drilled early 2000
Well A-46T2 drilled mid-2000
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
Simulation
models
Structural
framework
Sedimentology, detailed
stratigraphy
Reservoir
description and
initial volume
Time-lapse
seismic
1985
Top reservoir
OWC
OWC
1999
Top reservoir
Production, injection
rates, RST and PLT
Well position, and
perforation levels
Flooding map
Water flooded
Partly water flooded
Uncertain flooding
Oil producer
Gas flooded or
originally in place
Future producer
WAG injector
Oil filled
Water injector
Gas injector
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?