1) The document analyzes the potential of the undrilled northeast flank of the Britannia gas condensate field in the UK North Sea. 2) New techniques like flow zone characterization and fault mapping were used to understand the reservoir structure, quality, and identify controls on the tilted gas contact. 3) Results found the reservoir pinch-out and faults in a WNW-ESE trend, with zones 40 and 45 having the thickest sands and northeast coverage. The gas contact tilt is controlled by an overpressure gradient. 4) Estimates found the northeast area to be economic with faults and prospective without, identifying a low-risk area for a proposed appraisal well.

1. to simplify the Britannia petrofacies
scheme (Fig.5).
Investigation of the remaining potential in the North
East Flank area of the Britannia Field, UKCS
Rebecca. J. Lee¹, Supervisors: Dr Michael Ala¹ and Adrian Machell²
¹ Department of Earth Science and Engineering, Royal School of Mines, Imperial
College London, SW7 2AZ
² ConocoPhillips UK Ltd, Rubislaw House, Anderson Drive, Aberdeen, AB15 6FZ
1) Introduction
2) Aims and Objectives
3) Results/Analysis
4) Conclusions
5) References
6) Acknowledgements
N
0 50km
High region
Oil Fields
Gas cond. Fields
Witch
Ground
Graben
Outer Moray
Firth
South
Halibut
Basin
East
Shetland
Platform
0 12km
Britannia
NE
AOI*
L.CU.CTJ
Britannia
Sandstone
Fm
SolaFmValhallFm
Zone 50
Zone 45
Zone 40
Britannia is the largest Lower
Cretaceous gas condensate field
in the UK North Sea, 225 km NE
of Aberdeen (Fig.1) (Hill & Palfrey,
2003).
Situated within the extensional
basin of the Witch Ground Graben
in the Outer Moray Firth, the
Britannia Sandstone Formation
(Fig.1) comprises a complex
arrangement of deep-water turbidite
sands and shales (Archer et al., 2004)
that are divided into reservoir
zones (Fig.1).
There is little well control in the NE
owing to poor predicted reservoir
quality and there are up to 8 km of
unknown sediments, giving scope for
further study in the NE of Britannia.
Archer, S. G., H. L. Wycherley, G. R. Watt, M. L. Baron, J. Parnell, and H. Chen, 2004, Evidence for focused hot fluid flow within the
Britannia Field, offshore Scotland, UK, Basin Research, vol. 16, no. 3, p. 377-395.
Hailwood, E. and F. Ding, 2000, Sediment transport and dispersal pathways in the Lower Cretaceous sands of the Britannia Field, derived
from magnetic anisotropy, Petroleum Geoscience, vol. 6, no. 4, p. 369-379.
Hill, P. J., Palfrey, A.J., Gluyas, J.G. (editor), H. M. Hichens, and Britannia Operator, 2003, The Britannia Field, blocks 15/29a, 15/30, 16/26,
16/27a, 16/27b, UK North Sea, Memoirs of the Geological Society of London, United Kingdom oil and gas fields commemorative millennium
volume, vol. 20, p. 415-429.
Law, A., A. Raymond, G. White, A. Atkinson, M. Clifton, T. Atherton, I. Dawes, E. Robertson, A. Melvin, and S. Brayley, 2000, The Kopervik
fairway, Moray Firth, UK, Petroleum Geoscience, vol. 6, no. 3, p. 265-274.
The overall aim of the study is to evaluate the potential of the undrilled north
east flank of the Britannia Field and the implications on prospectivity in this
area. New techniques that have not been previously used on Britannia have
been used in this study such as flow zone characterisation and fault mapping.
The main objectives are:
• Understand the structure and position of Britannia sand pinch-out in the NE
• Understand the reservoir quality and sand facies distribution in the NE flank
• Identify controls on the tilted gas fluid contact
• Provide a range of the volume of gas in place in the undrilled NE Flank and
identify sweet spots to estimate where the next well should be drilled.
3.1) Reservoir structure
Fig.1: Top –
location of
Britannia
and, left-
regional
stratigraphy
and zonation
of Britannia
sandstone.
3.2) Reservoir quality and distribution
3.4) Tilted hydrocarbon water contact
3.3) Volumetrics and prospectivity
ZONE 40 ZONE 45
Mixed
Slurry
Debrite
Shale
FrequencyFrequency
FrequencyFrequencyFrequency
Frequency
Hydraulic Unit Hydraulic Unit
Hydraulic UnitHydraulic Unit
Hydraulic Unit Hydraulic Unit
Laminated
Banded
Massive
Sand – good
reservoir quality
Mixed Slurry – poor
reservoir quality
Shale – non
reservoir
125
125
125
125
16/26-3
16/26-B03
16/26-B04
16/26-B07
16/26-B08
16/26-B0916/26-B09Z
16/26-B10
16/26-B11
16/26-B11Z
16/26-B13
16/26-B13Z
16/26-B14
16/26-B16
16/26-B17
16/26-B18
16/26-B19
16/26-B20
16/26-B21
16/26-B22
16/26-B2316/26-B23Z
16/26-B24
16/26-B26
16/26-B27
16/26-B28
16/26-B29
16/26-B30
16/26-B32
16/26-B34
16/26-B40Z
16/26-B41
16/27A-6
16/27A-7
16/27B-4Z
391200 392000 392800 393600 394400 395200 396000 396800 397600 398400
391200 392000 392800 393600 394400 395200 396000 396800 397600 398400
643600064370006438000643900064400006441000644200064430006444000
643600064370006438000643900064400006441000644200064430006444000
0 500 1000 1500 2000 2500m
1:53632
-0.00
25.00
50.00
75.00
100.00
125.00
150.00
175.00
200.00
225.00
Thickness depth [ft]Map
Country Scale
1:53632
Block Contour inc
25
License User name
rebeccl
Model name Date
08/11/2014
Horizon name Signature
High risk
Moderate risk
Low risk
1 km
1 km
• Recommendation: Update reservoir model and drill appraisal well
• BCU to top reservoir structure characterises reservoir thickness and the
northern limit of the Britannia Field.
• WNW-ESE trending faults and minor interlinking faults extend through the
reservoir and may compartmentalise the reservoir through clay smear in
the heterolithic reservoir.
• Flow zone facies are effective in the assessment of reservoir quality on a
large scale compared to a petrofacies scheme.
• Zone 40 and 45 have the thickest sand intervals and greatest NE
coverage and dominant sediment transport direction switched from the
Witch Ground Graben to the South Halibut Fairway region, agreeing with
published models (Hailwood & Ding, 2000; Law et al.,2000).
• NE-SW hydrocarbon water contact tilt is controlled by an overpressure
gradient and is difficult to predict with no well data.
• Volumes suggest NE is economic in faulted case and NE is prospective.
The base reservoir seismic reflection is
poorly imaged but is approximately at the
base Cretaceous unconformity (BCU).The
BCU and top reservoir characterises gross
reservoir thickness and northern limit of
Britannia (Fig.2). Thickness is optimistic
away from pinch-out location.
Fig.2: Gross thickness map with BCU base
defining northern field limit.
Fig.3 (section line Fig. 3) seismic section showing pinch-out structure
and subtle faults through reservoir that may be sealing.
WNW-ESE faults extend
through Britannia reservoir with
subtle throw to the south (Fig.
3). These are slump faults
related to compaction of
Jurassic shales. The degree of
seal on the faults is a large
uncertainty.
Fig.4:Hydraulic unit distribution for current
petrofacies and grouping into simpler facies scheme.
Fig.5: Porosity
permeability plot of
flow zone facies
with permeability
cut offs.
Hydraulic units describe flow character and reservoir quality and were used
New flow zone facies have
Flow zone facies correlations helped to delimit relative sand thickness and
facies distribution. Zone 40 indicates a W-E sediment flow from the Witch
Ground Graben area (Fig.6) and zone 45 indicated a SW-NE flow from the
South Halibut Fairway (Fig.7). Zone 45 has the greatest sand coverage in NE.
Fig.6: Facies map for zone 40 – black arrows represent
W-E sand transport direction.
Fig.7: Facies map for zone 45 – black arrows represent
dominant SW-NE and minor W-E sand transport direction.
There is a flat OWC in the west
and variable GWC in the east with
tilt increasing in a NE-SW direction
at a gradient of 23 m/km.
Overpressured Jurassic shales are
in contact with normally pressured
Britannia reservoir (Fig.8).
Pressure difference causes aquifer
to flow and tilt to be maintained.
Fig.8: Tilted gas water contact (GWC) model.
Fig.9: Net sand thickness map with risk overlay. Low
risk area is best for well location.
Estimates of volumes in NE where
GWC is at faults and where GWC
intersects top reservoir, without faults
are higher than those estimated in the
current Britannia reservoir model.
Low risk area (Fig.9) is where sand
facies maps overly i.e. thickest sand
and there is a minimum permeability
thickness of 1000 mDft.
There are three proposed well locations
in low risk zone with 1km well spacing
and below potentially sealing faults.
Proposed well location
Thanks to ConocoPhillips UK for allowing me to complete my MSc project with them, providing an interesting topic and allowing
me to use their data.
I would like to thank Adrian Machell for guidance and inspiration throughout the project. I would also like to thank Nigel Evans,
Andy Conway and Neil Grant for constructive feedback on my work. Final thanks to Mike Ala for support and taking time to visit
me in Aberdeen.
WNW-ESE
interlinking
fault outline
Zone 20
Zone 10
(feet)
Section line
Northern
pinch-out
a clear permeability trend (Fig.6) and
define good reservoir as >1 mD.