Field Development Planning of a Thin Compartmentalised Oil Column: Vincent Field, Offshore Western Australia* Ole Sundsby1, Darren Baker1, Peter Griffiths1, and Hein Knipscheer1 Search and Discovery Article #20067 (2009) Posted May 18, 2009 *Adapted from oral presentation at AAPG International Conference and Exhibition, Cape Town, South Africa, October 26-29, 2008 1
Woodside Energy Ltd, Perth, WA, Australia (
[email protected])
Abstract Fast-track development of a thin compartmentalised oil column in a deepwater setting requires detailed full field layout planning before key subsurface data is available. Flexibility in layout of subsea infrastructure and wells is required to the benefit of the enhanced definition of the resource while it is being developed. A complicating factor is that the thin viscous oil column requires closely spaced horizontal wells with limited room for flexibility, because a shift of well location(s) impacts all other wells and layout of subsea infrastructure. Vincent Field is a relatively small oilfield off the north-western Australian coast in water depths of up to 400m. One discovery and 2 appraisal wells indicated the presence of a compartmentalised, biodegraded oil column with a variable thickness of 12 to 19 meters between a thin gas cap and a large water leg, all in very high quality fluvio-deltaic reservoir rocks. Direct hydrocarbon indicators from excellent quality seismic data were used to define the extent of compartments and potential differences in oil columns. Compartmentalisation is thought to be caused by a combination of stratigraphic seals and faults. The chosen development is by long multilateral horizontal wells drilled from 2 production manifolds in a phased FPSO development. The locations of the manifolds were fine-tuned using late appraisal data, and the number of drilling slots available is compatible with a later full field development. Tie-in points are provided for possible additional subsea infrastructure. The impact of compartmentalisation is thought to have been mitigated by drilling through potential stratigraphic barriers and sealing faults.
Field development planning of a thin compartmentalised oil column: Vincent Field, offshore Western Australia Sundsby, O., Baker, D., Griffiths, P., Knipscheer, H.
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Outline Field location and characteristics Evidence for compartmentalisation FPSO
Compartmentalising mechanisms in Vincent Lazy-Wave Riser Configuration
6-Slot Production Manifold A
Multiphase Pump Station
Seismic data to refine the compartmentalised model (varying contacts, faults and fault seal analysis)
Water Disposal Wells
6” Gas
e Flowlin
Summary and conclusions Umb
ilica
D Pr ual o 1 Flo duc 0” wl tio ine n s
l
Gas Injection / Production Well
6-Slot Production Manifold B
2 VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes: First, I will show you the location of the field and its characteristics. Next I will go through the evidence of compartmentalisation and some of the mechanisms involved. Throughout the article I will highlight the fact that we have used seismic data extensively during the development phase. To wrap it all up, I will summarize the development challenges and solutions along with come concluding remarks.
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Field Location Thailand
Sri Lanka
Philippines Brunei Malaysia
Singapore Indonesia
Papua New Guinea East Timor Christmas Isl. Cocos Is.
A U S T R A L I A
0
1000km 3
VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): The Vincent Field is located offshore at the NW tip of Australia...
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Field overview
FIELD CHARACTERISTICS
~50km EXMOUTH
•
Woodside (operator, 60%), Mitsui (40%)
•
Vincent (south) and Van Gogh (north)
•
Van Gogh to the north operated by Apache
•
Heavy, biodegraded oil
•
Highly permeable deltaic sandstone reservoir (Early Cretaceous)
WESTERN
AUSTRALIA
4 VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.):...and is situated about 50km from coastline along the Exmouth Peninsula. The Vincent Field is operated by Woodside Energy with Mitsui being the JVP. The Vincent Van Gogh accumulation is split in two by a permit boundary; Northern Van Gogh currently operated by Apache. The oil Is heavy and biodegraded, and the reservoir consists of highly permeable deltaic sandstones of Early Cretaceous age. Following are a series of top reservoir maps showing how incremental appraisal has built evidence for compartmentalisation and shaped our understanding over time.
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Discovery and appraisal G
• Vincent-1 (V1) discovery well showed:
O W
• 9m gas • 19m oil • Viscous: 12-16 cP
Apache V1 Woodside
V1 contacts
Development timeline
PRE FID 1998
5
VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): In these illustrations, gas is red, oil is green and water is blue. Note development timeline at the bottom of each slide. Animation may be simulated by constant advancement of the eight (8) pages (slides) that follow. The Vincent story started back in 1998 with the Vincent-1 discovery well encountering a 19-m viscous oil column capped by 9 meters of gas. I shall return to the impact of the high viscosity later in my presentation….
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Pre FID appraisal G
• 1999 Vincent-2 (V2) appraisal well showed:
O W
• OWC in Vincent-1 confirmed • Viscous fluid: 13 cP V1 V2
V1/V2 OWC
Development timeline
PRE FID 1999
Time 6
VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): The Vincent-2 well was drilled the following year, only to confirm the OWC as observed in the discovery well.
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Wells drilled at FID • 2003 Van Gogh-1ST1 (VG1) appraisal well showed: • OWC 6m shallow • Viscous fluid: 26-29 cP
VG1
V1 V2
VG1 OWC
Development timeline
PRE FID 2003
Time 7
VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): When the Van Gogh well was drilled back in 2003, a shallower OWC, considerably higher viscosity was encountered than in V-1 / V-2. These were the first signs of compartmentalisation. When the final investment decision was made by Woodside back in 2006, it was clear that the compartmentalised reservoir required flexibility in development planning.
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Post FID appraisal • 2006 Theo-1 (T1) appraisal well showed: • OWC 4m shallow • Viscous fluid: 20-23 cP
VG1
T1 V1 V2
T1 GOC T1 OWC
FIRST OIL: 2008 Development timeline
Time 2006
8
VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): One thing to note in this illustration is the short time-frame between field development start-up in 2006 and first oil, which was August of this year (2008). Immediately after the Woodside FID, Apache drilled the Theo-1 confirming a compartmentalised accumulation.
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Post FID appraisal G O W
• 2007 Vincent-3 (V3) appraisal well showed: • OWC 4m shallow • Viscous fluid: 20-23 cP
T1 V1
VG1
V3
V2
V3 OWC
Development timeline
Time 2007
9
VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): Immediately prior to drilling our first producer, the third of the Vincent wells observed an OWC 4m shallower than in the Vincent-1 / Vincent-2 pair. Animation, especially for OWC and compartmentalisation, may be simulated by constant advancement of the four (4) slides (pages) that follow. In the SW, contacts were assumed as per V-1, although….
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Appraisal while developing • Notice that seismic amplitudes indicate deeper OWC in the SW
T1 V1
G1
VG1
V3
V2
G1 contacts
Development timeline
N
Time 2007
10
VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): Seismic inversion datasets, or amplitude maps as shown here, clearly indicate a thicker column in this area. It was clear that prior to developing the western part of the field, incremental appraisal of this south western area was required. After having drilled 4 of the production wells in the first priority eastern area, downflank, away from the gas cap, the SW was tested using a pilot hole.
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Appraisal while developing G O
• Notice that seismic amplitudes indicate deeper OWC in the SW • Vincent 1 contacts shown on map T1
VG1
W V1
V3
V2
Incremental appraisal
N
Time 2007
11
VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): Shown here is the pre-drill OWC as per Vincent-1 (in white).
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Appraisal while developing • 2008 Pilot Hole confirmed the contact predicted by seismic: • OWC 11m deep • Viscous fluid: 20-25 cP V1 PH
G1
V3
V2
Incremental appraisal
N
Time 2008
12
VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): After drilling the pilot hole, the contact as predicted by seismic inversion was confirmed to the nearest meter. Obviously these seismic-driven findings meant material changes to the development plan.
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Varying oil column height across the field
19m
14m 17m T1
30m
VG1
Apache Woodside
V1 PH
G1
V3
7km
V2
Incremental appraisal
N
Time 2008
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VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): As a summary of the evidence for compartmentalisation, I show a zig-zag cross section illustrating the OWC stepping up towards the north east.
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Varying oil column height across the field
PH
V2
V1
G1
V3
T1
VG1
GAS
30m
19m
17m ?
OIL
14m
WATER
w Shallo
s er OWC Stratigraphic barriers
Fault
14 VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): Wells are shown in black; only the circled wells were available prior to FID. Notice both faults and stratigraphic barriers are believed to play a role in compartmentalising the field. There are still uncertainties related to the location of these barriers (e.g., seismic distorted close to gas cap). We have seen viscosity vary throughout the field; during biodegradation, bugs consume the lighter components, thereby increasing viscosity, leaving only the heavier components for us to extract.
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Viscosity
WATER ~1 cP
VINCENT (DEAD OIL) ~700 cP
HONEY ~2000 cP
Vincent (in situ) oil viscosity: ~12-23 cP “Honey”, Image credit: USDA - Agricultural Research Service. Photo by Scott Bauer
15 VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): In order to get a feel for the viscosity parameter, I have found the following comparison useful. Some of you may know that viscosity is defined by the ratio of shear stress to shear rate, with water perfectly shearing. The unit of viscosity is centipoise. The Vincent oil with no gas present, and at surface conditions, will have the viscosity somewhere ~midway between water and honey. However, at in situ conditions, the viscosity lies somewhere between 12 and 23 centipoise. The high viscosity and the high API gravity play an important role in compartmentalising the field. However, what is the geology setting up the barriers to flow?
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Structural and depositional setting
V3 V2
16 VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): We have shown the evidence, the varying contacts and viscosity; here is the map of top reservoir again as shown previously. Now I show a seismic line through two of the flank appraisal wells Vincent-2 and -3.
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Compartmentalising mechanisms Vincent-3
Vincent-2
Top Muderong KV
rotation FS9
FS1
17 VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): On this section, gamma-ray logs are shown for the two wells. Notice the parallel stacking pattern formed by the prograding delta-sequences. These sequences have been tilted by some 3 degrees, uplifted and finally eroded at the Valenginian unconformity (KV). Individual flooding surfaces deposited during Lower Barrow highstands are likely to be sealing (COMP). Reservoir is capped by the regionally extensive Muderong Shale. Although most of these sequences can be mapped by seismic, it must be noted that, due to fluid fill effects (particularly gas), the interpretation of onset of erosion is severely hampered.
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Flooding surface 1 fault patterns Vincent-2
Vincent-3
FS1
V3
V2
18 VINCENT FIELD - 29th October 2008 – Ole Sundsby
Here is a map from a fault enhancement seismic volume at flooding surface #1…
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Top reservoir fault patterns Vincent-2
Vincent-3 KV
V3
V2
19 VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): …and here is a map based on the same volume at top reservoir. We can clearly see that fault interpretation also is somewhat hampered by the strong fluid overprint. Iin addition, some faults may have strike-slip component, which is not always favorable for detection on reflection seismic data. However, these discontinuity volumes, when used particularly above and below the HC column, show a large number of small scale, potentially sealing faults.
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Compartmentalising mechanisms - fault seal Factors that would support a connected reservoir: • Field burial history • High net to gross and Darcy permeabilities • High likelihood for sand/sand juxtaposition Evidence for fault seal: • Differences in pressure (MDT) and composition (Geochem) in both gas and oil leg • Deeper OWC in SW These factors are difficult to reconcile without an intricate compartmentalisation model
SHALE
2m ?
GAS
X
OIL
WATER
Sealing factors: • High oil viscosity • Low buoyancy pressures (particularly close to FWL): Cannot overcome even the poorest of fault seal (assuming pre-migration / water wet faults) Ultimately the low oil mobility means that all Vincent faults have the potential to be sealing
20 VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): So, how can we infer sealing faults in this sand-rich system? After all we are dealing with net to gross (NTG) in the high 90s! When we think about it, there are several factors that support a connected reservoir. However, there is some strong evidence for fault seal, and these factors are difficult to reconcile without an intricate compartmentalisation model. The factors supporting a connected reservoir are counteracted by high oil viscosity and low buoyancy pressures. Therefore, virgin compartments are likely near the free water level; significantly virgin compartment boundaries are not expected to break down during production. Capillary effects likely to play an important role with small faults capable of sealing (buoyancy pressures < fault zone capillary threshold pressures). (Faults that are pre-migration: assumed water-wet. Faults sealing due to capillary pressures….)
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Vincent development overview Reservoir: Tilted and eroded Lower Barrow Group prograding delta sequences Dual lateral horizontal well with 4th order high stand stratigraphic barriers
0-10m GAS Excellent quality seismic data capable of imaging individual delta sequences, erosional top seal, HC contacts and meter-scale, potentially sealing faults Appraisal data confirmed a thin, viscous oil column (19m, 20cP / 17° API) m
OIL
2500
14-30m 140-180m Optimal positioning
WATER Low oil mobility and compartmentalisation required dense pattern of extended reach bi- and tri-lateral horizontal wells designed to intersect all compartments Screens and Inflow Control Devices (ICDs) to ensure sand control and even inflow along horizontal well bores in order to delay the breakthrough of gas and water Challenging drilling program and limited room for flexibility, since a shift of well location would impact all other wells and subsea infrastructure 21 VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): This illustration is a cross section of the Vincent reservoir perpendicular to a dual lateral horizontal well. Due to compartmentalisation and likely low-sweep efficiency (viscosity)…mining the oil …through a series of long bi- and tri-lateral wells. We have screens and inflow control devices to ensure sand control, even inflow and delayed water and gas breakthrough. The thin oil column and the carpet drilling strategy meant that positioning had to be spot-on, as even minor deviations could be detrimental to project value.
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Compartmentalisation impacting infrastructure el ll en gt h
=
?
DCA on the fly positioning: Vincent-3: If non-economical column => Place template towards A1 (maximize length in thicker oil)
liz ed
w
V1 OWC
Vincent-3: OK column => Place template towards A2
V-3: ? OWC
ho r
iz on ta
ls
re a
DCB on the fly positioning: Able to drill long on first DCA well => Place template towards B1 (OK column in V3 / realized well length)
FPSO
DC A
B1
FIXED
V2=V1 OWC B target box
flowlines
A2
A target box
A1
umbilical
Top Reservoir 22 VINCENT FIELD - 29th October 2008 – Ole Sundsby
Presenter’s Notes (Cont.): We have noted the flexibility needed due to varying column height and viscosity. This illustration shows that compartmentalisation affected planning of subsea infrastructure down to the length of umbilicals and flowlines. FPSO fixed… Two unkowns…realized well length / OWC in V-3 (seismic unable to image OWC: thin column, interference). This meant that we needed to retain flexibility…as you can imagine….southwest…longer in thick oil…showing how compartmentalisation affected the planning of subsea infrastructure right down to the length of umbilicals and flowlines. The position of the Production, Storage and Offloading facility had been fixed, although not in the field at the start of production drilling. This required us to retain flexibility in the position of both templates. In the scenario where Vincent-3 showed an uneconomical column height, the A template would be moved farther towards the SW. Then after placing the A template, flowlines between templates that had been fabricated in parts were now fitted to place the template at an optimal location based on well coverage and realized well length. Overbought umbilicals and flowlines (flowlines were jig-sawed (joints)).
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Summary and conclusions
Challenges:
Solutions:
Fast tracked schedule, appraisal while developing
Flexible development plan
Compartmentalisation, varying OWCs
Intersecting compartments with long horizontals Utilising high quality seismic data
Thin, viscous oil column VINCENT FIELD - 29th October 2008 – Ole Sundsby
Dense well spacing Precise well placement and inflow control
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Presenter’s Notes (Cont.): As we have seen, we needed to react quickly to appraisal information. Reducing risk of unswept compartments through carpet drilling of extended-reach horizontal dual- and tri-lateral wells. Reducing risk of early gas- and water-breakthrough by optimal well placement and by…ICDs. Final: incremental appraisal crucial for development by retaining flexibility for how to develop the field. These are just a few of the development challenges that affect me as a geoscientist…? Flexible: Extensive contingency planning (well layout and reserves for different options). Fast-tracked development and minimal appraisal at FID required planning for ‘on the fly’ decision making when incremental appraisal data became available. Incremental field appraisal has been crucial for development (retain flexibility for how to develop the field). Reducing risk of unswept compartments through ‘carpet drilling’ of extended-reach horizontal dual- and trilateral producers. Reducing risk of gas- and water-breakthrough by optimal well placement and by the use of inflow control devices – varying viscosity with depth. Acknowledgements: Hein Knipscheer and Vincent development team and our partners Mitsui.
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