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A scalable full-chain industrial D05 Site Selection Report Annex 3 … Acorn Site Selection... ·...
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A scalable
full-chain industrial
CCS project
A scalable
full-chain industrial
CCS projectD05 Site Selection Report – Annex 3 Site Selection Posters
10196ACTC-Rep-08-01
January 2018
Document Summary
Client Research Council of Norway & Department of Business, Energy & Industrial Strategy
Project Title Accelerating CCS Technologies: Acorn Project
Title: D05 Site Selection Report Annex 3 Site Selection Posters
Distribution: Client & Public Domain
Date of Issue: 8th January 2018
Prepared by: Dr Juan Alcalde, Dr Clare Bond (University of Aberdeen), Hazel Robertson (Pale Blue Dot Energy)
Approved by: Alan James, Managing Director (Pale Blue Dot Energy)
Amendment Record
Rev Date Description Issued By Checked By Approved By
V01 08/01/18 First Issue C Hartley T Dumenil S Murphy
Terms of Use
The ACT Acorn Consortium partners reserve all rights in this material and retain full
copyright. Any reference to this material or use of the material must include full
acknowledgement of the source of the material, including the reports full title and its
authors. The material contains third party IP, used in accordance with those third party’s
terms and credited as such where appropriate. Any subsequent reference to this third
party material must also reference its original source. The material is made available in
the interest of progressing CCS by sharing this ACT work done on the Acorn project.
Pale Blue Dot Energy reserve all rights over the use of the material in connection with the
development of the Acorn Project. In the event of any questions over the use of this
material please contact [email protected].
www.actacorn.eu
A scalable
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CCS project
A scalable
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CCS project
Site Summary
Capacity (P50) 104MT
Unit designation Condensate Gas Field
Formation Brae Formation
Containment unit Structural/stratigraphic trap
Availability (COP) 2016
UKCS Block 16/7
Beachhead St Fergus
Water depth 104m
Reservoir depth 3802m
Region CNS
Poster Summary
Title Site A: Brae North
Condensate Field
Project Title ERA-NET ACT Acorn
Date of issue 08/01/2018
Major offshore areas covered by CO2Stored (© Energy
Technologies Institute)
Location of the Brae North Condensate Field in relation with the
Miller Gas System (MGS - Yellow), the Western Area Gas
Evacuation System (WAGES - Green) or the Goldeneye (GY - Blue)
pipelines. Pipeline and field data from Oil and Gas Authority
(https://www.ogauthority.co.uk/).
A
A
’
B
B’
3200 ms
4600 ms
3900 ms
Time interpretation of the near Top Middle Jurassic in
the Brae North Condensate Field area– Alcalde, 2017
- Shape guidance from CO2Stored.
Capacity
(MT)1
Injectivity
(mDm)4 Wells/km2 2 Georisk3 Containment risk3
104 89100 2.1 5 8
Key Risk Summary
Cumulative Gas Production 62028 106 scm
Cumulative Oil Production - 106 scm
Cumulative Water Production 6.2 106 scm
Cumulative Water Injection - 106 scm
Theoretical Storage Capacity (hc) 128.2 MT
Capacity Calculation
Seal Characterisation Fracture CharacterisationEngineering
RiskGeorisk Factor
Fracture
Pressure
Capacity
Seal
degradationDensity
Throw and
fault seal
Fault
Vertical
Extent
Well Total
1 1 1 1 1 3 8
Low=1 Medium=2 High=3
Containment Validation
References
Brehm, 2003, The Brae North and Beinn Fields, Block 16/7a, UK North Sea (in Gluyas, J. G. & Hichens, H. M. (eds) 2003. United Kingdom Oil and Gas
Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 199-209.
Stephenson, M.A., 1991. The Brae North Field, Block 16/7a, UK North Sea. From Abbotts, I. L. (ed.), 1991, United Kingdom Oil and Gas Fields, 25
Years Commemorative Volume, Geological Society Memoir No. 14, pp. 43-48
ETI SSAP, 2016, Progressing Development of the UK’s Strategic Carbon Dioxide Storage Resource: A summary of Results from the Strategic UK CO2
Storage Appraisal Project.
Latitute Longitude
Proximal Upside
Capacity (<20 km
radius) (MT)
Proximal Upside
Capacity (<50 km
radius) (MT)
Sites within <50 km radius
55.88 1.54 905 905
East Brae
Condensate FieldFluuga Sandstone
Heimdal Sandstone
Proximal Upside Potential
Data obtained from the CO2Stored database (ETI, 2016).Data obtained from the CO2Stored database (ETI, 2016).
Data obtained from the CO2Stored database (ETI, 2016).
Unit Designate Storage Unit TypeStorage
Efficiency
Ranking Storage
Efficiency
Gas
Condensate
Structural /
Stratigraphic trap47% 1
Storage Efficiency Appraisal
Pipeline Borehole
Total Cost
(£M)Distance to
the Pipeline
(km)
Pipeline
Cost (£M)
Percentage
of Total Cost
Average
Depth (m)
Drilling
Costs (£M)
Percentage
of Total Cost
8.6 9.45 12.7% 3802 64.64 87.3% 74.1
Development Cost
Note – Storage efficiency calculated by assuming it to be between
the high values of the very depleted gas fields (over 70%) and the
lower values of the confined aquifers (20%) (values from ETI
SSAP Project).
Estimating factors of £1.1m/ km of installed pipeline and £17m/km of well depth were used (ETI, 2016).
Generalized Brae
North stratigraphy.
From Stephenson,
1991.
DATA
Brae North Condensate Field is covered by the 3D seismic from the CNS PGS MegaSurvey.
The data quality is generally good.
CDA well data is available over the Brae North Condensate Field and surrounding areas.
There are a total of 34 wells in the area divided in 1 discovery well, 6 appraisal wells and 27
development wells. Abandoned wells in the area are likely well prepared to avoid vertical
hydrocarbon migration from the Brae Formation, so are probably well suited to the storage of
CO2.
Location of Site
Levelised cost vs storage efficiency calculated for
eight sites from the ETI SSAP Project. Brae North
Condensate Field estimated position in orange.
Brae North
Brae Formation accumulations within Brae North – Brehm, 2003
OVERVIEW
The Brae North Field is one of three gas/condensate fields in the Brae fields area of the South Viking
Graben in the UK Sector of the North Sea. Brae North is located at the proximal end of a large
turbidite and debris flow, submarine fan system and is characterised by massive conglomerates and
sandstones.
CONTAINMENT
The Brae North field presents a complex trap, formed by a faulted anticline. Its reservoir consists
of Upper Jurassic submarine-fan conglomerates and sandstones of the Brae Formation. The
Kimmeridge Clay formation, overlying the Brae Formation reservoir sequence provides the
vertical trap. The clay is variable in thickness from 55 to over 250ft in thickness, with thicker clay
occurring in areas of more rapid reservoir subsidence in main channel areas. In spite of the
faults present, the Brae Formation has hosted hydrocarbons for millions of years and thus are
considered a suitable reservoir-seal system for CO2 storage.
The great depth of the reservoir increase the chance of secondary containment in the overlying
formations. However, this depth will increase the development cost, reducing the suitability of the
site.
Cross section in the Brae North and Bracken fields. From
Brehm, 2003.
SW-NE section Seismic section SW–NE showing elevation of the Beinn structure at top Sleipner and thinning of the overlying
sequences to top Kimmeridge Clay indicative of syn-depositionalst rupturing. From Brehm, 2003.
The site is located below the Heimdal Sandstone, another of the top 6 sites considered in this project, and could be a
secondary containment to this site.
PROPERTIES
Porosity in the Main Channel reservoir varies from 16 to 22% in
clean sandstones (average 17.8%) and between 10 and 15% in
conglomerates (average 12.7%). Average permeability is 300
mD.
Due Diligence capacity estimate
Site A: Brae North Condensate Field
INJECTIVITY
The injectivity is calculated to be 89100mDm which is considered to be
suitable for CO2 storage.
Parameter Inputs Comments
Gross Rock Volume Low 1776 -10%
MMCUM Mid 1974 Brehm 2003 in Millenium Volume
High 2171 +10%
Net to Gross Ratio Low 0.77 -10%
Mid 0.85 Brehm 2003 in Millenium Volume
High 0.94 +10%
Porosity Low 0.13 Brehm 2003 in Millenium Volume
Mid 0.18 Brehm 2003 in Millenium Volume
High 0.22 Brehm 2003 in Millenium Volume
CO2 Density Low 0.748 13260 ft, 355.9 degF, 10588 psi
T/m3 Mid 0.749 12867.5 ft, 346.3 degF, 10275 psi
High 0.749 12475 ft, 336.7 degF, 9962 psi
CO2 Storage Efficiency Low 0.300 -39%
Mid 0.490 ETI, 2015
High 0.600 +22%
P90 80
P50 104
MT P10 129
CO2 Capacity of Brae North
Run - 4
Dynamic Storage Capacity
Distribution
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 20 40 60 80 100 120 140 160 180 200
Re
lati
ve P
rob
abili
ty
Dynamic Storage Capacity (MT)
0.54
0.20
2,082.66
0.90
0.75
0.38
0.15
1,864.47
0.80
0.75
60.00 80.00 100.00 120.00 140.00
CO2 Storage Efficiency
Porosity
Gross Rock Volume
Net to Gross Ratio
CO2 Density
Sensitivity Analysis
Upside Downside
Timeline sample showing the PGS
MegaSurvey data coverage in the Brae
North Condensate Field area – Shape
guidance from CO2Stored.
Image source: courtesy of CDA through
an academic licence agreement.
North
Brae
Bre Oil
Field
Miller
KingfisherWest
Brae
Beinn
1From due diligence2Input data from CDA3Data obtained from the CO2Stored database (ETI, 2016)4Millennium Volume
A scalable
full-chain industrial
CCS project
A scalable
full-chain industrial
CCS project
Time interpretation of the Top Palaeocene in the Grid
Sandstone area – Alcalde, 2017 - Shape guidance from
CO2Stored.
Site B: Grid Sandstone Member – West and East Grid
Site Summary
Capacity (P50) 2174 MT West Grid
1477 MT East Grid
Unit Designation Saline aquifer
Formation Horda fm
Containment Unit Open, no identified structure
Availability (COP) n/a
UKCS Block 15/20
Beachhead St Fergus
Water Depth 120m
Reservoir Depth 1299m
Region CNS
Poster Summary
Title Site B: Grid Sandstone
Member – West and East
Grid
Project Title ERA-NET ACT Acorn
Date of issue 08/01/2018
Injectivity Validation
Seal Characterisation Fracture Characterisation Engineering Risk Georisk Factor
Fracture
Pressure
Capacity
Seal
degradationDensity
Throw and fault
seal
Fault Vertical
ExtentWell Total
1 1 1 2 1 1 6
Low=1 Medium=2 High=3
Containment Validation
References
Wills, J. M., 1991, The Forties Field, Block 21/10, 22/6a, UK North Sea. From Abbotts, I. L. (ed.), 1991, United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume, Geological Society Memoir No. 14, pp. 301-308
ETI SSAP, 2016, Progressing Development of the UK’s Strategic Carbon Dioxide Storage Resource: A summary of Results from the Strategic UK CO2 Storage Appraisal Project.
Jones, E. et. al., 2003, Chapter 15: Eocene. From Evans, D. Graham, C. Armour, A. and Bathurst, P. (ed.), 2003, The Millennium Atlas: The Petroleum Geology of the Central and Northern North Sea, The Geological Society of London.
Average
Thickness
(m) 1
Permeability
(mD) 2Kh
(mDm)
West and
East Grid 150 2800 273000
1Estimated from CDA logs – taken from ETI (2015) 2Millennium Atlas
Unit Designate Storage Unit Type Storage Efficiency
Saline Aquifer Open, no identified structure 5%
Storage Efficiency Appraisal
Pipeline BoreholeTotal Cost
(£M)Distance to the
Pipeline (km)
Pipeline Cost
(£M)
Percentage of
Total Cost
Average Depth
(m)
Drilling Costs
(£M)
Percentage of
Total Cost
10.1 11.1 33.5% 1299 22.1 66.5% 33.2
Development Cost
Note – Storage efficiency assumed to be similar to Forties 5 and Captain X development (ETI SSAP Project).
Estimating factors of £1.1M/ km of installed pipeline and £17M/km of well depth were used (ETI, 2016).
Simplified Stratigraphic column for
Northern North Sea showing no
secondary containment formations
above the Grid Sandstone. Image
source: modified from Wills, 1991
Simplified Stratigraphic
Column for Northern
North Sea
Major offshore areas covered by CO2Stored (© Energy
Technologies Institute)
Location of the Grid Sandstone Member in relation with the Miller
Gas System (MGS - Yellow), the Western Area Gas Evacuation
System (WAGES - Green) or the Goldeneye (GY - Blue) pipelines.
Source: Google Earth Pro Pipeline and field data from Oil and Gas
Authority (https://www.ogauthority.co.uk/).
Location of Site
Levelised cost vs storage efficiency calculated for eight sites from the
ETI SSAP Project. Grid Sandstone estimated position in orange.
Grid Sst
Well 9/27a-4 (East Grid Area)
9/27a-4 (MD)Shaliness
9/27a-4 (MD)Shaliness
Image source: Data derived from CDA through an open licence agreement. Original interpretation from Axis Well Technology, 2015
9/27a-4 Well Log
Overview
The Grid Sandstone is an extensive turbidite system and so the thickness of the sand is influenced heavily by deposition. The area of study for this work has been prioritised to ensure 3D seismic data coverage as well as being in the vicinity
of the pipeline (see figure above) and so two areas have been selected, named as West and East Grid.
Containment
In general for the Grid Sandstone, to the east the closure is structural and to the west is stratigraphic. The laterally continuous caprock is provided by the Eocene silty shales and claystones of the Horda Mudstone Group. The Alba and
Chestnut fields are in the Grid sandstone member and so these provide examples of a working seal. The ETI Due Diligence review of the PGS CNS mega-survey and the Millennium Atlas identified extensive polygonal faulting within the Grid
Sandstone. The western pinch-out limit is not always covered by seismic along its entire length and so this represents a gap in current knowledge.
Injection features are found in both the Alba and Chestnut fields. These features form from rapid compaction and create fractures which can be a few hundred feet above top sand causing containment challenges and reservoir complexity.
Due to the shallow nature of the Grid Sandstone Member there are no secondary containment reservoirs and so there are less barriers between the reservoir and seabed than for other potential storage sites. This represents a challenge for
what could be one of the first CO2 storage sites in the UKCS. This applies to both the West and East Grid.
Engineering Risk
In the West Grid area (1286km2) there are 186 wells (including side tracks), which gives a low well density of 0.14wells/km2. This is even lower than for the entire Grid area (0.22 well/km2). There are areas within West Grid that could
provide an initial injection site with even lower well density.
In the East Grid area (874km2) there are also about 186 wells (including side tracks), which gives a low well density of 0.21 wells/km2.
Injectivity
The injectivity is calculated to be 273000mDm which is considered to be good.
Data
A significant amount of well data is available over the West and East Grid Sandstone Sites and surrounding areas, available at CDA. Both areas have been selected to have full 3D seismic coverage.
Timeslice showing the PGS MegaSurvey data coverage in the Grid
Sandstone Member area – Shape guidance from CO2Stored
West Grid
East Grid
Image showing location of West Grid and East Grid – both lie within a 15km distance from the MGS pipeline and have full 3D
seismic data coverage. The fields in the vicinity of West Grid área have either ceased production or are expected to cease
production by the time injection is due to begin. Hydrocarbon field and pipeline data source: Oil and Gas Authority.
AA’ B
B’
NE-SWSE-NW
Alba Field Summary
Water Depth 134m
Maximum gross thickness
137m
Average net pay 53.3m
Reservoir porosity Up to 38%
Reservoir permeability
2800mD
Initial res pressure 2853psi
Reservoir Nauchlan and Brioc sandstone units of the Grid Sandstone Member within the Horda Formation
This figure is a seismic section from the Alba Field showing an abrupt reflector termination against a channel wall, indicating the erosive nature of the channel. Two images are of the same line, presented at similar scale. The Alba field was difficult to image on seismic. Channel sandstones are shale plugged. Oil-filled sands above the main reservoir are known to be injected and remobilised sands from the main reservoir body. Injection features are also found in the Chestnut field. These features form from rapid compaction and create fractures which can be a few hundred feet above top sand causing containment challenges and reservoir complexity. Source: Millennium Atlas p628
This table is a summary of information from the Alba oil field. Source: Millennium Atlas p628
Alba Field
B
B
’
A
’
B
B
’
A
A
’
West Grid
East Grid
A
East Grid
B B’
NW-SE
A A’
SW-NE
Near Top Grid Sandstone
Base Grid Sandstone
Near Top Palaeocene
Images source: Seismic data provided by PGS under Licence Agreement. Original
interpretation from Alcalde, 2017.
Map showing the location of the extensive Grid Sandstone Member. Source: Millennium Atlas
Edge of 3D seismic data coverage so
uncertainty beyond this point
Grid Sst up-dip to the NW
Grid Sst up-dip to the NW
Eocene Stratigraphic comparison chart. Image source: Millennium Atlas.
Capacity (MT)1 Injectivity (mDm)2 Wells/km2 1 Georisk3 Containment Risk3
2174 West Grid
1477 East Grid273000
0.14 West Grid
0.21 East Grid6 7
Key Risk Summary
Latitute Longitude
Proximal Upside
Capacity (<20 km
radius) (Mt)
Proximal Upside
Capacity (<50
km radius) (Mt)
Sites Within <50 km radius
58.24 0.86 204 4003
Firthcoal_015_13
Forties 5
Maureen 2
Mey 5
Pentland_016_21
Pibroch_015_21
Piper Oil Field
Proximal Upside Potential
1From due diligence capacity estimate2From ETI due diligence (ETI, 2015)3Data obtained from the CO2Stored database (ETI, 2016).
Data obtained from the CO2Stored database (ETI, 2016).
Due Diligence Capacity Estimate
Parameter Inputs Comments
Gross Rock Volume Low 96,450 -50%
MMCUM Mid 192,900 Digitised West Grid polygon; thickness from ETI DD
High 385,800 +100%
Net to Gross Ratio Low 0.59 -10%
Mid 0.65 ETI DD, 2015
High 0.72 10%
Porosity Low 0.30 Phi vs Depth from Millenium (at 5000 ft depth)
Mid 0.33 ETI DD, 2015
High 0.38 Millennium Atlas
CO2 Density Low 0.776 4900 ft, 151.7 degF, 3913 psi
T/m3 Mid 0.783 4200 ft, 134.6 degF, 3354 psi
High 0.791 3500 ft, 117.5 degF, 2795 psi
CO2 Storage Efficiency Low 0.030 -40%
Mid 0.050 ETI, 2015
High 0.100 +100%
P90 1,313
P50 2,174
MT P10 3,538
CO2 Capacity of West Grid
Run - 4
Dynamic Storage Capacity
Distribution
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000
Re
lati
ve P
rob
abili
ty
Dynamic Storage Capacity (MT)
311,090.15
0.08
0.36
0.69
0.79
149,277.84
0.04
0.31
0.61
0.78
1,000.00 1,500.00 2,000.00 2,500.00 3,000.00 3,500.00
Gross Rock Volume
CO2 Storage Efficiency
Porosity
Net to Gross Ratio
CO2 Density
Sensitivity Analysis
Upside Downside
Parameter Inputs Comments
Gross Rock Volume Low 65,550 -50%
MMCUM Mid 131,100 Digitised East Grid polygon; thickness from ETI DD
High 262,200 +100%
Net to Gross Ratio Low 0.59 -10%
Mid 0.65 ETI DD, 2015
High 0.72 10%
Porosity Low 0.30 Phi vs Depth from Millenium (at 5000 ft depth)
Mid 0.33 ETI DD, 2015
High 0.38 Millennium Atlas
CO2 Density Low 0.776 4900 ft, 151.7 degF, 3913 psi
T/m3 Mid 0.783 4200 ft, 134.6 degF, 3354 psi
High 0.791 3500 ft, 117.5 degF, 2795 psi
CO2 Storage Efficiency Low 0.030 -40%
Mid 0.050 ETI, 2015
High 0.100 +100%
P90 892
P50 1,477
MT P10 2,404
CO2 Capacity of East Grid
Run - 2
Dynamic Storage Capacity
Distribution
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000
Re
lati
ve P
rob
abili
ty
Dynamic Storage Capacity (MT)
211,425.19
0.08
0.36
0.69
0.79
101,453.21
0.04
0.31
0.61
0.78
500.00 1,000.00 1,500.00 2,000.00 2,500.00
Gross Rock Volume
CO2 Storage Efficiency
Porosity
Net to Gross Ratio
CO2 Density
Sensitivity Analysis
Upside Downside
A scalable
full-chain industrial
CCS project
A scalable
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CCS project
Site Summary
Capacity (P50) 1917 MT
Unit Designation Saline aquifer
Formation Lista fm
Containment Unit Fully confined (closed box)
Availability (COP) n/a
UKCS Block 16
Beachhead St Fergus
Water Depth 110
Reservoir Depth 1668
Region CNS
Poster Summary
Title Site C: Heimdal Sandstone
Member – East Heimdal
Project Title ERA-NET ACT Acorn
Date of issue 08/01/2018
Major offshore areas covered by CO2Stored (© Energy
Technologies Institute)
Location of the Heimdal Sandstone Member in relation with the
Miller Gas System (MGS - Yellow), the Western Area Gas
Evacuation System (WAGES - Green) or the Goldeneye (GY - Blue)
pipelines. Pipeline and field data from Oil and Gas Authority
(https://www.ogauthority.co.uk/).
Time interpretation of the near Top Paleocene in the Heimdal area
showing the outline of the East Heimdal Area – Alcalde, 2017 -
Shape guidance from CO2Stored.
Seal Characterisation Fracture CharacterisationEngineering
RiskGeorisk Factor
Fracture
Pressure
Capacity
Seal
degradationDensity
Throw and
fault seal
Fault
Vertical
Extent
Well Total
3 2 3 3 2 1 13
Low=1 Medium=2 High=3
Containment Validation
References
ETI SSAP, 2016, Progressing Development of the UK’s Strategic Carbon Dioxide Storage Resource: A summary of Results from the Strategic UK CO2 Storage Appraisal Project.
Schwab, A.M., Jameson, E.W., and Townsley, A., Volund Field: development of an Eocene sandstone injection complex, offshore Norway. From: McKie, T., Rose, P. T. S., Hartley, A. J., Jones, D. W. & Armstrong, T. L. (eds) 2015. Tertiary Deep-Marine Reservoirs of the
North Sea Region. Geological Society, London, Special Publications, 403, 247–260. First published online February 5, 2014.
Unit designate Storage Unit Type Storage efficiency
Saline AquiferFully Confined (closed
box)0.5%
Storage Efficiency Appraisal
Location of Site
Levelised cost vs storage efficiency calculated for eight sites from the ETI SSAP Project.
Heimdal Sandstone Member estimated position in orange.
Heimdal Sandstone Member
Injectivity Validation
Average
Thickness
(m) 1
Permeability
(mD) 1
Kh
(mDm)
492 891 4410011CO2Stored
Near Top Palaeocene
Base Tertiary
Near Top Lower Cretaceous
Base Cretaceous Unconformity
Near Top Middle Jurassic
Near Top Permian
Image source: Seismic data provided by PGS
under Licence Agreement. Original
interpretation from Alcalde, 2017.
AA’
NE-SW
B’B
NW-SE
B
B’
A’
A
East Heimdal
Simplified Stratigraphic column for the
Northern North Sea showing Heimdal
Sandstone with secondary
containment formations in Hermod,
Flugga and Grid sandstone above.
Image source: modified from Wills,
1991
Map of what has been named “East Heimdal” – a subset of the Heimdal sandstone formation that lies in full 3D
seismic data covereage via the PGS MegaMerge and within 15km of the pipeline.
Image source: Hydrocarbon field and pipeline data from Oil and Gas Authority. Shape guidance from CO2Stored.
Timeslice sample showing the PGS MegaSurvey data coverage in
the Heimdal Sandstone Member area – Shape guidance from
CO2Stored.
Well correlation panel (4 on map)
showing Heimdal Sandstone
Member. Source: Millennium Atlas
Lithostratigraphy showing that Mey Sandstone is Central North Sea equivalent of the Northern North
Sea Heimdal. Source: Millennium Atlas
Well log showing Heimdal Sandstone
with presence of interbedded shales.
Source: CDA under licence agreement
Capacity
(MT)1
Injectivity
(mDm)3 Wells/km2 2 Georisk3 Containment Risk3
1917 441001 0.21 13 14
Key Risk Summary
Latitute Longitude
Proximal Upside
Capacity (<20 km
radius) (MT)
Proximal
Upside
Capacity (<50
km radius) (MT)
Sites Within <50 km radius
58.71 1.34 128 349Brae East
Brae NorthFlugga Sst
Proximal Upside Potential
Data obtained from: Millennium Atlas, CDA and the CO2Stored database (ETI, 2016).
Data obtained from the CO2Stored database (ETI, 2016).
Pipeline BoreholeTotal Cost
(£M)Distance to the
Pipeline (km)
Pipeline Cost
(£M)
Percentage of
Total Cost
Average Depth
(m)
Drilling Costs
(£M)
Percentage of
Total Cost
3.27 3.6 11.2% 1668 28.4 88.7 32
Development Cost
Estimating factors of £1.1m/ km of installed pipeline and £17m/km of well depth were used (ETI, 2016).
Overview
The Heimdal Sandstone Member is the northern North Sea lateral equivalent of the Central North Sea Mey Sandstone Member, part of the Lista formation. This Paleocene formation typically overlies the
Maureen. The reservoir varies from medium to poorly sorted, fine to medium grained, normally with interbedded claystones or siltstones. The Jotun field lies in the Heimdal sandstone member in the
Norwegian sector – sandstone content of up to 60% and a thickness ranging from 300 to 500m. The area of study for this work has been prioritised to ensure 3D seismic data coverage as well as being in
the vicinity (<15km) of the pipeline (see figure above). It has been named East Heimdal.
CO2Stored has classified the Heimdal Sandstone Member as a confined aquifer, however this is considered erroneous due to the size of the aquifer and so the storage efficiency will likely be greater than
0.5%.
Containment
19 Palaeocene fields have the Lista Formation as their reservoir, with the overlying hemipelagic shales deposited during higher frequency transgressions providing the caprock. This demonstrates a
working seal. No obvious containment challenges in the seismic were seen, however no structures within the East Heimdal area are currently known.
Secondary containment formations are in the Hermod, Flugga and Grid Sandstones which lie between Heimdal and the seabed, thus reducing the risk of any CO2 reaching the seabed via the overburden.
Engineering Risk
In the East Heimdal area (899km2) there are about 186 wells (including sidetracks), which gives a well density of 0.21wells/km2. This is lower than the North Sea average.
Many of the wells drilled through Heimdal Fm will have been targeting deeper Brae fields so may not be properly abandoned in the Heimdal formation itself, posing a potential containment risk.
Injectivity
Injectivity is 441001mDm which is considered to be excellent.
Data
A significant amount of well data is available over the Heimdal Sandstone Member and surrounding areas, available at CDA. East Heimdal has been selected to have full 3D seismic coverage.
Since hydrocarbon fields exist within the Heimdal formation, there is likely to be dynamic data available, however none of these fields are within the East Heimdal area and so the relevance of anydynamic data is uncertain.
The hydrocarbon fields in East Heimdal area are in deeper formations and so any data for the Heimdal formation from these wells may be poorer quality as it would not have been part of the primaryexploration target.
Simplified Stratigraphic
Column for Northern
North Sea
16/07a-14 Well Log
Hei
md
al S
and
sto
ne
Parameter Inputs Comments
Gross Rock Volume Low 135,000 Assume thickness of 300m (lower end of range given in Mi l lennium Atlas )
MMCUM Mid 402,600 Assume average thickness of 492 from CO2Stored
High 742,500 Assume thickness of 550m (upper end of range given in Mi l lennium Atlas )
Net to Gross Ratio Low 0.50 eye-bal led off log 16/07a-14
Mid 0.55 average of low and high
High 0.60 Mil lennium Atlas - Jotun field in Norwegian sector (up to 60% sand volume)
Porosity Low 0.20 poros i ty depth trend
Mid 0.22 poros i ty depth trend
High 0.25 CO2Stored
CO2 Density Low 0.756 8850 ft, 248.2 degF, 7067 ps i
T/m3 Mid 0.759 7903 ft, 225.0 degF, 6311 ps i
High 0.763 6956 ft, 201.9 degF, 5554 ps i
CO2 Storage Efficiency Low 0.005 From CO2Stored - assumes confined aqui fer
Mid 0.050 mid-case > Capta in X (0.003) as shale baffles may enhance s torage effi
High 0.100 high-case assumes shale baffles in Heimdal may enhance s torage efficiency
P90 843
P50 1,917
MT P10 3,453
CO2 Capacity of East Heimdal
Run - 3
Dynamic Storage Capacity
Distribution
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000
Re
lati
ve P
rob
abili
ty
Dynamic Storage Capacity (MT)
0.08
598,802.66
0.24
0.58
0.76
0.03
262,501.76
0.21
0.52
0.76
0.00 1,000.00 2,000.00 3,000.00 4,000.00
CO2 Storage Efficiency
Gross Rock Volume
Porosity
Net to Gross Ratio
CO2 Density
Sensitvity Analysis
Upside Downside
Due Diligence Capacity Estimate
Site C: Heimdal Sandstone Member – East Heimdal
1From due diligence capacity estimate2Input data from CDA3Data obtained from the CO2Stored database (ETI, 2016).
A scalable
full-chain industrial
CCS project
A scalable
full-chain industrial
CCS project
Major offshore areas covered by CO2Stored (© Energy
Technologies Institute)
Location of the Mey 5 in relation with the Miller Gas System (MGS -
Yellow), the Western Area Gas Evacuation System (WAGES -
Green) or the Goldeneye (GY - Blue) pipelines. Pipeline and field
data from Oil and Gas Authority (https://www.ogauthority.co.uk/).
Time interpretation of the near Top Paleocene in the Mey 5 area –
Alcalde, 2017 - Shape guidance from CO2Stored.
Image source:
modified from
Wills, 1991 Images source: Seismic data provided by PGS under Licence Agreement. Original interpretation from
Alcalde, 2017.
Location of Site
OVERVIEW
The Mey Sandstone member is a part of the Palaeocene Lista formation and is the time equivalent of the Heimdal sandstone which is distributed to the
east. The Mey Sandstone and its Lista formation mudstone caprock is the primary reservoir and caprock system for a number of large oil and gas fields
in the Central North Sea including Donan, Macculloch, Cyrus, Andrew, Balmoral, Blenheim and Bladon.
West Mey
“West Mey” is an area which extends from its westerly pinch out (erosional limit) in the vicinity of the Cromarty gas field eastwards to limit of the 3D
seismic in the vicinity of the Hannay field. “West Mey” therefore is accessible from all three pipelines and also overlies the Captain sandstone fairway in
the eastern part of Captain X and Goldeneye. Geographically therefore this interval is highly convenient for development alongside the deeper Captain
Sandstone interval. Its subsurface configuration at the western margin raises significant concerns regarding the potential integrity of the site since it is
shallow and appears to subcrop to Holocene sediments.
There are no petroleum accumulations in this part of the Mey sandstone, but the section has been extensively explored in its role as a secondary
petroleum reservoir target to the deeper Cretaceous and Jurassic exploration programmes. Depositionally, this area is characterised in the Millenium
Atlas as a shelf environment for the Palaeocene.
Shell have reported in their work on Goldeneye that the Mey in this area exhibits lateral variation due to onlapping horizons of differing lithology and that
this creates some challenges in the tracking of the top reservoir seismic event across the areas. Indeed for the Goldeneye project the Mey sandstone
was seen as a secondary storage horizon, but was never studied in detail. Shell reported that whilst some small NW-SE faults are seen rarely in the
Mey sandstone on 3D seismic, that these are not connected to the deeper Captain Sandstone or to the shallower layers. (Shell KT Seismic
Interpretation Report).
The Lista Mudstone comprises non-calcareous, bioturbated, non-carbonaceous and non-pyritic mudstones, grading into claystones in places. The
dominant colour is pale green-grey to grey-green. The lower boundary is marked by a GR decrease and sonic velocity increase associated with the
development of massive well developed sand facies. The Lista Mudstone facies is widely present in the Halibut Trough area (60 out of 72 wells) and is
present in all overburden model AOI and closest offset wells. It is 60m to 120m thick in the Goldeneye area, and appears to thin slightly to the west. The
Lista mudstone facies overlies approximately 1200m of stratigraphy believed to be of aquifer quality: the Mey Sandstone Member, Upper and Lower
Balmoral Units, Maureen Ekofisk, Tor, Hod and Herring Formations. These intervals, together with the Lista Formation as their seal, offer the main
possibility for secondary containment of CO2 above the Goldeneye field.
The base Lista Formation/top Mey Sandstone Member surface dips regionally from west to east along the Halibut Trough at approximately 1° to 1.5° to
the east. Any CO2 reaching the base of the Lista Formation is expected to migrate in a west to north-westerly direction. The Lista Formation is believed
to crop out at seabed about 150km to the west of Goldeneye, in the Inner Moray Firth, but this is uncertain due to the poor quality of the regional seismic
data available to the project.
A’ AGY
GY
GY
GY
Near Top Palaeocene
Base Tertiary
Near Top Lower Cretaceous
Base Cretaceous Unconformity
Near Top Middle Jurassic
Near Top Permian
Depositional architecture and distribution of the Mey and
Heimdal Sandstone
Images source: Evans et al. (2003).
B’B
CONTAINMENT
On the issue of containment, this due diligence has not addressed this in detail, but has drawn the
following observations:-
Faulting
The Seismic data suggests that there are no major faults that cut the Mey sandstone interval and rise
to the surface.
Shell reported that whilst some small NW-SE faults are seen rarely in the Mey sandstone on 3D
seismic, that these are not connected to the deeper Captain Sandstone or to the shallower layers.
(Shell KT Seismic Interpretation Report).
The dip line extracted from the PGS MegaSurvey A’ to A shown above shows the interval rising
steadily towards a shallow subcrop of Holocene sediments within the target polygon. This raises
some significant concerns regarding site integrity for a significant CO2 inventory within this West Mey
site.
The West Mey site has many positive aspects in its favour including high quality reservoir which
would facilitate high injectivity. It is also located in a position which could see any one of the three
potential pipeline systems servicing its supply. There are few issues or concerns around the technical
capacity, its storage efficiency is unlikely to be very high because of its unstructured configuration.
Even so it should be improved on that afforded by the deeper Captain sandstone, because the Mey
Sandstone contains significant hemipelagic mudstone interbeds which will slow down the rise to CO2
to the top of the sandstone interval and encourage the CO2 to pass through a larger pore volume as it
migrates away from the injection point.
There is a critical concern raised around the containment configuration at the western end of the site
where the Mey sandstone appears to subcrop at a very shallow depth to what appears to be
Holocene sediments. At present this would appear to critically compromise the West Mey site in the
context of any significant injected CO2 inventory (although it may perform satisfactorily against the
introduction of a small inventory from a deeper Captain Sandstone in a role as a secondary
containment reservoir.
It is therefore recommended that the West Mey is not progressed any further in the search for Site
number 2.
Containment Concern
Capacity
(MT)1
Injectivity
(mDm)3 Wells/km2 2 Georisk3 Containment
Risk3
3281 102102 0.09 12 13
Key Risk Summary
Data obtained from the CO2Stored database (ETI, 2016).
Pipeline Borehole
Total Cost
(£M)Distance to
the pipeline
(km)
Pipeline cost
(£M)
Percentage
of Total Cost
Average
Depth (m)
Drilling Costs
(£M)
Percentage
of Total Cost
2 2.2 12% 3069 17.8 88% 19
Development Cost
Estimating factors of £1.1m/ km of
installed pipeline and £17m/km of
well depth were used (ETI, 2016).
Seal Characterisation Fracture Characterisation Engineering Risk Georisk Factor
Fracture
Pressure
Capacity
Seal
DegradationDensity
Throw and
Fault Seal
Fault
Vertical
Extent
Well Total
2 2 3 3 2 1 12
Low=1 Medium=2 High=3
Containment Validation
Latitute Longitude
Proximal Upside
Capacity (<20 km
radius) (Mt)
Proximal Upside
Capacity (<50
km radius) (Mt)
Sites Within <50 km radius
58.20 0.21 57 4145
Claymore_014_18
Cromarty Sst
Firthcoal_015_13
Forties 5
Grid Sst
Maureen 2
Pentland_016_21
Pibroch_015_21
Piper Oil Field
Scapa_014_20
Proximal Upside Potential
Data obtained from the CO2Stored database (ETI, 2016).
Data obtained from the CO2Stored database (ETI, 2016).
Due Diligence capacity estimate
ENGINEERING RISK
In the West Mey area the well density is 0.09 wells/km2
As the Mey is a mature oil producing reservoir, abandonment procedures are designed to
eliminate the escape of oil and gas from the Mey. These should be helpful in retaining high
CO2 integrity. In details these will have to be reviewed on a case by case basis, especially
for wells in which no Mey oil and gas shows were encountered.
INJECTIVITY
The injectivity is 102102mDm which is considered to be suitable for CO2 storage
operations.
DATA
A significant amount of well data is available over the West Mey and surrounding areas,
available at CDA. East Mey has been selected to have full 3D seismic coverage.
Since hydrocarbon fields exist within the Mey formation, there is likely to be good access to
dynamic data available.
Image showing location of West and East Mey– both lie within a 15km distance from the MGS pipeline and have full 3D seismic data coverage.
Hydrocarbon field and pipeline data source: Oil and Gas Authority.
References
ETI SSAP, 2016, Progressing Development of the UK’s Strategic Carbon Dioxide Storage Resource: A summary of Results from the Strategic UK CO2 Storage
Appraisal Project.
Evans, D., Graham, C., Armour, C., and Bathurst, P. (2003). The Millennium Atlas: Petroleum geology of the Central and Northern North Sea.
Parameter Inputs Comments
Gross Rock Volume Low 108,199 Area times thickness
MMCUM Mid 400,000 from well data
High 811,490
Net to Gross Ratio Low 0.50 14/29a-3 qnd 14/29a-5
Mid 0.65 set the mean
High 0.75
Porosity Low 0.20
Mid 0.28
High 0.35
CO2 Density Low 0.778 4700 ft, 146.8 degF, 3753 psi
T/m3 Mid 0.794 3250 ft, 111.4 degF, 2595 psi
High 0.817 2000 ft, 80.9 degF, 1597 psi
CO2 Storage Efficiency Low 0.03
Mid 0.05
High 0.09
P90 1,735
P50 3,281
MT P10 5,523
Dynamic Storage
Capacity
14/29a-5 calc suggests >30%-
also regional phi vs depth
relationship from Millenium
Based on s torage Efficiency for
Open Aqui fers . Should be better
than Capta in
Distribution
CO2 Storage Resource Estimate for
West MeyRun - 2
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 2,000 4,000 6,000 8,000 10,000 12,000
Re
lati
ve P
rob
abili
ty
Dynamic Storage Capacity (MT)
641,373.21
0.07
0.32
0.70
0.81
251,454.37
0.04
0.23
0.56
0.79
1,000.00 2,000.00 3,000.00 4,000.00 5,000.00 6,000.00
Gross Rock Volume
CO2 Storage Efficiency
Porosity
Net to Gross Ratio
CO2 Density
Sensitivity Analysis
Upside Downside
Levelised cost vs storage efficiency calculated for eight sites
from the ETI SSAP Project. Mey 5 estimated position in
orange.
Mey 5
Unit Designate Storage Unit TypeStorage
Efficiency
Saline AquiferOpen, identified
structure5%
Storage Efficiency Appraisal
Note – Storage efficiency assumed to be
similar to Forties 5 and Captain X
development (ETI SSAP Project).
Site Summary
Capacity (P50) 3281MT
Unit Designation Saline aquifer
Formation Lista Formation
Containment Unit Open, with some structures
identified in hydrocarbon fields
Availability (COP) 2023
UKCS Block 13, 14, 19, 20
Beachhead St Fergus
Water Depth 110m
Reservoir Depth 990m
Region CNS
Poster Summary
Title Site D(a): West Mey 5
Project Title ERA-NET ACT Acorn
Date of issue 08/01/2018
Site D(a): West Mey 5
1From due diligence2Input data from CDA3Data obtained from the CO2Stored database (ETI, 2016).
Correlation panel showing Mey Sandstone.
Source: CDA under licence agreement
A scalable
full-chain industrial
CCS project
A scalable
full-chain industrial
CCS project
Levelised cost vs storage efficiency calculated
for eight sites from the ETI SSAP Project. Mey
5 estimated position in orange.
Mey 5
OverviewThe Mey Sandstone member is a part of the Palaeocene Lista formation and is the time equivalent of the Heimdal sandstone which is distributed to the east. The Mey sandstone fairway covers a very large area of the Central North Sea. In the context of Acorn, this has been reduced by considering only those areas which are:-1. Within 15km of one of the three potentially re-usable pipelines2. Supported with good 3D seismic coverage from the PGS megamerge data set3. Available for access by 2023 and do not carry significant long lived producing petroleum assets.
Two segments of the Mey sandstone fairway have therefore been identified, named as “West Mey” and “East Mey”.
The “East Mey” area extends from the Rob Roy – Hamish area in the west, eastwards to the Donan field and beyond. The western part of this area is under long term petroleum development around the Scott field. Due to this it is recommended that this part of the East Mey area is excluded from further consideration at this time. The main part of East Mey is the Mey Sandstone petroleum province which is now largely played out with most all fields having reached the end of their producing lives.
Published data from the Millenium volume on Macculloch suggests that at this location, the Mey Sandstone has a thickness of 175 to 540ft. Further south at Balmoral the thickness reaches 850ft. These reservoirs are in the deeper water slope depositional province of the Mey Sandstone and comprises a turbidite complex with interbedded sand rich high density turbidites with muddier hemipelagic intervals and low density turbidites. Average porosity is reported to be 25 to 28% with permeabilities between 200mD and 2D.
A A’ B B’
Simplified Stratigraphic
Column for the Central
North Sea
Image source: Seismic data provided by PGS under Licence Agreement. Original interpretation from Alcalde, 2017.
Depositional architecture and distribution of the Mey and Heimdal Sandstone
Images source: Millennium Atlas
Time interpretation of the near Top Palaeocene in the Mey 5 area –
Alcalde, 2017 - Shape guidance from CO2Stored.
ContainmentThe Mey sandstone and its Lista formation mudstone caprock is the primary reservoir and caprock system for a number of large oil and gas fields in the Central North Sea including Donan, Macculloch, Cyrus, Andrew, Balmoral, Blenheim and Bladon and so in this area the Mey sandstone is a major petroleum play in its own right and has proven containment through a number of oilfields within and adjacent to this area. The containment risk linked to caprock efficiency is therefore considered to be minimal.
Significant oil columns are supported by the overlying Lista mudstrone caprock. Several of the fields contain a palaeo oil leg suggesting some late stage re-adjustment of the structure. All mapped structures are reported full to the mapped spill point again supporting the view that the caprock is of high integrity.
Review of selected seismic lines suggest that there are no major faults cutting the Top Mey sandstone, although minor faults do exist and have been mapped in several structures.
On lateral containment, it is likely that the development site will be focussed upon the location of a depleted oilfield so that the buoyant CO2 can be trapped within the structure in addition to residual tapping in the body of the underlying aquifer.
Engineering Risk
In the East Mey area the well density is 0.28 wells/km2
As the Mey is a mature oil producing reservoir, abandonment procedures are designed to eliminate the escape of oil and gas from the Mey, These should be helpful in retaining high CO2 integrity. In details these will have to be reviewed on a case by case basis, especially for wells in which no Mey oil and gas shows were encountered.
InjectivityThe injectivity is 102102mDm which is considered to be good.
DataA significant amount of well data is available over the East Mey and surrounding areas, available at CDA. East Mey has been selected to have full 3D seismic coverage.
Since hydrocarbon fields exist within the Mey formation, there is likely to be good access to dynamic data available.
ConclusionsThe East Mey is a strong candidate for consideration as Site 2. Reservoir quality and extent is good with high injectivity anticipated. Reservoir architecture indicates some shale baffles which will help to enhance storage efficiency. The overall area also has some structural closures in addition to the body of the underlying aquifer affording an ability to buoyantly trap some CO2.
It is understood that the Balmoral field was briefly considered as a potential CO2 storage site by a previous operator during the UK Government DEMO2 procurement process.
Major offshore areas covered by CO2Stored (© Energy
Technologies Institute)
Location of the Mey 5 in relation with the Miller Gas System (MGS -
Yellow), the Western Area Gas Evacuation System (WAGES -
Green) or the Goldeneye (GY - Blue) pipelines. Pipeline and field
data from Oil and Gas Authority (https://www.ogauthority.co.uk/).
Location of Site
Balmoral Seismic line and MacCullogh field summary from
Millennium Volume
Palaeocene Porosity vs Depth plot
Images source: Evans et al. (2003).
Site D(b): East Mey 5
Image showing location of West and East Mey– both lie within a 15km distance from the MGS pipeline and have full 3D seismic data coverage.
Hydrocarbon field and pipeline data source: Oil and Gas Authority.
Image source: modified from
Wills, 1991
Due Diligence Capacity Estimate
Parameter Inputs Comments
Gross Rock Volume Low 21,000 Area from fairway analysis
MMCUM Mid 90,000
High 197,000
Net to Gross Ratio Low 0.40
Mid 0.65
High 0.90
Porosity Low 0.22
Mid 0.28
High 0.3
CO2 Density Low 0.765 6540 ft, 191.7 degF, 5222 psi
T/m3 Mid 0.767 6270 ft, 185.1 degF, 5007 psi
High 0.768 6000 ft, 178.6 degF, 4791 psi
CO2 Storage EfficiencyLow 0.03
Mid 0.05
High 0.09
P90 374
P50 725
MT P10 1,269
Dynamic Storage
Capacity
MacCulloch paper plus
regional depth trend from
Millenium Volume
Based on storage Efficiency
for Open Aquifers. Should be
better than Captain
Distribution
CO2 Storage Resource Estimate for
East Mey
Run - 2
Millenium Volume data on
MacCulloch field
Thickness from MacCulloch
paper
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 500 1,000 1,500 2,000 2,500 3,000
Re
lati
ve P
rob
abili
ty
Dynamic Storage Capacity (MT)
153,604.15
0.07
0.79
0.29
0.77
55,848.24
0.04
0.51
0.24
0.77
0.00 500.00 1,000.00 1,500.00
Gross Rock Volume
CO2 Storage Efficiency
Net to Gross Ratio
Porosity
CO2 Density
Sensitivity Analysis
Upside Downside
Site Summary
Capacity (P50) 725 MT
Unit Designation Saline aquifer
Formation Lista Formation
Containment Unit Open, with some structures
identified in hydrocarbon fields
Availability (COP) 2023
UKCS Block 16/21
Beachhead St Fergus
Water Depth 110m
Reservoir Depth 1875m
Region CNS
Poster Summary
Title Site D(b): East Mey 5
Project Title ERA-NET ACT Acorn
Date of issue 08/01/2018
Capacity (MT)1 Injectivity (mDm)3 Wells/km2 2 Georisk3 Containment Risk3
Value 725 102102 0.08 14 15
Key Risk Summary
Seal Characterisation Fracture CharacterisationEngineering
RiskGeorisk Factor
Fracture
Pressure
Capacity
Seal
DegradationDensity
Throw and
Fault Seal
Fault
Vertical
Extent
Well Total
2 2 3 3 2 1 12
Low=1 Medium=2 High=3
Containment Validation
Latitute Longitude
Proximal Upside
Capacity (<20 km
radius) (Mt)
Proximal Upside
Capacity (<50 km
radius) (Mt)
Sites Within <50 km radius
58.20 0.21 57 4145
Claymore_014_18
Cromarty Sst
Firthcoal_015_13
Forties 5
Grid Sst
Maureen 2
Pentland_016_21
Pibroch_015_21
Piper Oil Field
Scapa_014_20
Proximal Upside Potential
Data obtained from the CO2Stored database (ETI, 2016).
Data obtained from the CO2Stored database (ETI, 2016).
Unit designateStorage Unit
Type
Storage
efficiency
Ranking
Storage
Efficiency
Saline Aquifer
Open, no
identified
structure
5% 6
Storage Efficiency Appraisal
Pipeline BoreholeTotal Cost
(£M)Distance to the
pipeline (km)
Pipeline cost
(£M)
Percentage of
Total Cost
Average Depth
(m)
Drilling Costs
(£M)
Percentage of
Total Cost
0.2 0.22 0.01% 3069 52.2 99.9% 52.4
Development Cost
Note – Storage efficiency assumed to be similar to Forties 5 and Captain X
development (ETI SSAP Project).
Estimating factors of £1.1m/ km of installed pipeline and £17m/km of well depth were used (ETI, 2016).
Unit Designate Storage Unit TypeStorage
Efficiency
Saline AquiferOpen, identified
structure5%
Storage Efficiency Appraisal
Note – Storage efficiency assumed to be similar to
Forties 5 and Captain X development (ETI SSAP
Project).
References
ETI SSAP, 2016, Progressing Development of the UK’s Strategic Carbon Dioxide Storage Resource: A summary of Results from the Strategic UK CO2 Storage Appraisal
Project.
Evans, D., Graham, C., Armour, C., and Bathurst, P. (2003). The Millennium Atlas: Petroleum geology of the Central and Northern North Sea.
1From due diligence2Input data from CDA3Data obtained from the CO2Stored database (ETI, 2016).
A scalable
full-chain industrial
CCS project
A scalable
full-chain industrial
CCS project
Site Summary
Capacity (P50) 808MT
Unit designation Saline aquifer
Formation Dornoch Formation
Containment unit Open, no identified
confinement
Availability (COP) -
UKCS Block 14, 15, 19, 20.
Beachhead St Fergus
Water depth 115m
Reservoir depth 1207m
Region CNS
Poster Summary
Title Site E: Dornoch Formation –
West and East Dornoch
Project Title ERA-NET ACT Acorn
Date of issue 08/01/2018
Major offshore areas covered by CO2Stored (© Energy
Technologies Institute)
Location of the Dornoch Fm in relation with the Miller Gas System
(MGS - Yellow), the Western Area Gas Evacuation System (WAGES
- Green) or the Goldeneye (GY - Blue) pipelines. Pipeline and field
data from Oil and Gas Authority (https://www.ogauthority.co.uk/).
References
ETI SSAP, 2016, Progressing Development of the UK’s Strategic Carbon Dioxide Storage Resource: A summary of Results from the Strategic UK CO2 Storage
Appraisal Project.
Century Exploration (UK) Limited, Licence P1105 (Block 21/6b) Relinquishment Report, September 2006. The Geological Society of London.
Evans, D., Graham, C., Armour, C., and Bathurst, P. (2003). The millennium atlas: Petroleum geology of the Central and Northern North Sea.
Spence, B., Horana, D., & Tucker, O. (2014). The Peterhead-Goldeneye gas post-combustion CCS project. Energy Procedia, 63, 6258 – 6266.
Unit designate Storage Unit TypeStorage
efficiency
Saline AquiferOpen aquifer, no
identified structure 5%
Storage efficiency appraisal
Pipeline Borehole
Total Cost
(£M)Distance to
the Pipeline
(km)
Pipeline
Cost (£M)
Percentage
of Total
Cost
Average
Depth (m)
Drilling
Costs (£M)
Percentage
of Total
Cost
2 2.2 10.2% 1133 19.26 89.7% 42.44
Development Cost
Note – Storage efficiency assumed to be similar
to Captain X and Forties 5 (ETI SSAP Project).
Estimating factors of £1.1m/ km of installed pipeline and £17m/km of well depth
were used (ETI, 2016).
Location of Site
Timeline sample showing the PGS
MegaSurvey data coverage in the
Dornoch Formation area – Shape
guidance from CO2Stored.
Image source: courtesy of CDA
through an academic licence
agreement, and GoogleEarth –
Shape guidance from CO2Stored.
DATA
About 60% of the Dornoch Formation site is covered by the 3D seismic from the CNS
PGS MegaSurvey. The site is located above several oil and gas fields (including
Piper Oil Field), especially in the central part. There is a major gap in the seismic
coverage right at the intersection with the MGS pipeline.
SITE SELECTION
In order to restrict the potential location of the CO2 storage site within the Dornoch Formation, a 15 km corridor
across the pipelines was created (Right figure, in red). This corridor goes across the gap in seismic coverage
from the PGS MegaSurvey (white polygon), leaving two sides of the Dornoch Formation within 15 km of the
pipeline and with seismic coverage in them: East Dornoch and West Dornoch.
East Dornoch has a 20% smaller area than the West Dornoch. Furthermore, well-log data in East Dornoch
shows that the Dornoch Sandstone reservoir is divided into Upper and Lower Dornoch by a 100 foot thick
mudstone layer. This has a strong impact in the capacity of East Dornoch, and therefore it has been ruled out in
favour of West Dornoch, which will be taken as the main potential site.
OVERVIEWThe Dornoch Formation is composed of shelf and deltaic sediments from Late Palaeocene-Early Eocene age. It is theequivalent of the Forties Sandstone Member in the Moray Firth. It contains sandstones (Dornoch Sst) and mudstone(Dornoch Mudstone). To the East, the formation splits into Upper and Lower Dornoch Sandstone, separated by mudstone.
Palaeogeographic map of the Sele and Dornoch Formations (above left), lithostratigraphy of the Palaeocene (above centre) and well correlation panels showing the E-W distribution of the Dornoch Formation in the Moray Firth-
Central Norh Sea area (bottom). Source: Evans et al. (2003).
Two potential sites within the Dornoch Formation (dark blue): West Dornoch and East
Dornoch.
Seismic coverage
Seismiccoverage
Lack of seismiccoverage (white)
15km corridor around Pipelines (red)
15km corridor around Pipelines (red)
Dornoch Formation(CO2Stored area)
West Dornoch
East Dornoch
E
Time interpretation of the near Top
Palaeocene in the Dornoch Fm area –
Alcalde, 2017 - Shape guidance from
CO2Stored.
Images source: Seismic data provided by PGS under
Licence Agreement. Original interpretation from Alcalde,
2017.
Dornoch Formation
CONTAINMENT
Palaeocene sandstones are typically excellent reservoirs, with good regional
connectivity and minor depth-related diagenesis, and are rarely affected by polygonal
faults (Evans et al., 2003).
The Dornoch Formation is qualified as an open aquifer with known storage structure.
Faults or other geological features that could affect the containment of the site are
not anticipated from the seismic sections or drilling reports reviewed.
ENGINEERING RISK
There are only 11 wells in the area, which results in a very low well-density (0.00003
wells per km2), and consequently a low risk of leakage through abandoned wells.
INJECTIVITY
The injectivity of West Dornoch is calculated to be 800000mDm which is considered
to be very good.
PROXIMAL UPSIDE POTENTIAL
West Dornoch is located right on top of West Mey
(another of the top 6 sites selected in this Project)
and on top of the Goldeneye Field, which has been
studied by Shell as a potential site for CCS in the
Peterhead-Goldeneye Project (Spence et al., 2014).
Levelised cost vs storage efficiency calculated for eight
sites from the ETI SSAP Project. Dornoch Fm estimated
position in orange.
Dornoch Fm
Capacity
(MT)1
Injectivity
(mDm)3
Wells
/km2 2 Georisk3 Containment
Risk3
808 800000 0.00003 8 9
Key Risk Summary
Parameter Inputs Comments
Gross Rock Volume Low 33,035 Assume thickness of 190m (well 14/29a-4
MMCUM Mid 89,804 Assume average thickness of 235.5m (average from wells)
High 146,572 Assume thickness of 281m (well 14/29a-5)
Net to Gross Ratio Low 0.50 Estimated from wells 20/04a-5, 14/29a
Mid 0.65
High 0.90
Porosity Low 0.23 Forties 5 (analogue in Central Graben)
Mid 0.28 Mid point
High 0.32 Phi vs Depth curve Millenium Atlas
CO2 Density Low 0.780 4470 ft, 141.2 degF, 3569 psi
T/m3 Mid 0.788 3743 ft, 123.4 degF, 2989 psi
High 0.798 3016 ft, 105.7 degF, 2408 psi
CO2 Storage Efficiency Low 0.030 -50%
Mid 0.060 Forties 5 (analogue in Central Graben)
High 0.100 +67%
P90 482
P50 808
MT P10 1,288
CO2 Capacity of West Dornoch
Run - 4
Dynamic Storage Capacity
Distribution
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 500 1,000 1,500 2,000 2,500
Re
lati
ve P
rob
abili
ty
Dynamic Storage Capacity (MT)
121,184.47
0.08
0.80
0.30
0.79
58,422.76
0.04
0.58
0.25
0.78
200.00 400.00 600.00 800.00 1,000.00 1,200.00 1,400.00
Gross Rock Volume
CO2 Storage Efficiency
Net to Gross Ratio
Porosity
CO2 Density
Sensitivity Analysis
Upside Downside
Due Diligence capacity estimate
Seal characterisation Fracture characterisationEngineering
risk
Georisk
factor
Fracture
Pressure
Capacity
Seal
Chemical
Reactivity
DensityThrow and
fault Seal
Fault
Vertical
Extent
Well Total
1 1 2 3 1 1 8
Low=1 Medium=2 High=3
Containment Validation
Data obtained from the CO2Stored database (ETI, 2016).
Site E: Dornoch Formation – West and East Dornoch
1From due diligence2Input data from CDA3Data obtained from the CO2Stored database (ETI, 2016).
A scalable
full-chain industrial
CCS project
A scalable
full-chain industrial
CCS project
Site Summary
Capacity (P50) 233MT
Unit designation Oil and Gas Field
Formation Piper Formation
Containment unit Structural/stratigraphic trap
Availability (COP) 2020
UKCS Block 15/17
Beachhead St Fergus
Water depth 145m
Reservoir depth 1682m
Region CNS
Poster Summary
Title Site F: Piper Oil Field
Project Title ERA-NET ACT Acorn
Date of issue 08/01/2018
Major offshore areas covered by CO2Stored (© Energy
Technologies Institute)
Location of the Piper Oil Field in relation with the Miller Gas System
(MGS - Yellow), the Western Area Gas Evacuation System (WAGES
- Green) or the Goldeneye (GY - Blue) pipelines. Pipeline and field
data from Oil and Gas Authority (https://www.ogauthority.co.uk/).
Timeline sample showing the PGS
MegaSurvey data coverage in the Piper
Oil Field area – Shape guidance from
CO2Stored.
Image source: courtesy of CDA through
an academic licence agreement – Shape
guidance from CO2Stored.
DATA
Piper Oil Field is covered by the 3D
seismic from the CNS PGS
MegaSurvey. The data quality is
generally moderate due to low fold of
coverage in the shallow section.
CDA well data is available over the
Piper Field and surrounding areas.
The Piper Field contains 84 drilled
wells: 3 exploration wells from 1973-
74, 8 Appraisal wells from 1973-74
and 1984-88; and 77 Development
wells, ranging from 1973 to 2016.
The wells abandoned after the Piper
Alpha incident is uncertain and
potentially bear high risk to the
storage of CO2, making the Piper Oil
Field an unsuitable site for this
project.
Capacity
(MT)1
Injectivity
(mDm)3 Wells/km2 2 Georisk3 Containment
Risk3
233 388000 2.7 5 8
Key Risk Summary
Cumulative Gas Production 5043.8 106 scm
Cumulative Oil Production 175 106 scm
Cumulative Water Production 180 106 scm
Cumulative Water Injection 225 106 scm
Theoretical Storage Capacity (hc) 126.5 Mt
Capacity Calculation
Containment Validation
References
ETI SSAP, 2016, Progressing Development of the UK’s Strategic Carbon Dioxide Storage Resource: A summary of Results from the Strategic UK CO2 Storage
Appraisal Project.
Harker, S.D., 1998, The palingenesy of the Piper oil field, UK North Sea, Petroleum Geoscience, Vol. 4 1998, pp. 271–286.
Schmitt, H. R. H. & Gordon, A. F. 1991. The Piper Field, Block 15/17, UK North Sea. In: Abbots, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years
Commemorative Volume. Memoir, 14, 361–368. Geological Society, London.
Slater, J., and Bamford, M. 2009. Piper Field, Past, Present & Future Presentation to Institute of Materials, Minerals & Mining. BP.
Williams, J. J., Conner, D. C. & Peterson, K. E. 1975. The Piper Oil-Field, UK North Sea: a Fault-Block Structure with Upper Jurassic Beach-Bar Reservoir
Sands. Bulletin of the Geologists, 59, 1581–1601.American Association of Petroleum Geologists.
Latitute Longitude
Proximal Upside
Capacity (<20 km
radius) (Mt)
Proximal Upside
Capacity (<50 km
radius) (Mt)
Sites within <50 km radius
58.46 0.26 317 5628
Claymore_014_18;
Firthcoal_015_13;
Grid Sandstone
Maureen 2
Mey 5
Pentland_016_21
Pibroch_015_21
Scapa_014_20
Proximal Upside Potential
Data obtained from the CO2Stored database (ETI, 2016).
Data obtained from the CO2Stored database (ETI, 2016).
Data obtained from the CO2Stored database (ETI, 2016).
Unit designate Storage Unit TypeStorage
Efficiency
Ranking Storage
Efficiency
Oil & GasStructural /
Stratigraphic Trap47% 2
Storage efficiency appraisal
Pipeline Borehole
Total Cost
(£M)Distance to
the Pipeline
(km)
Pipeline
Cost (£M)
Percentage
of Total
Cost
Average
Depth (m)1
Drilling
Costs (£M)
Percentage
of Total
Cost
28.53 31.39 40% 2682 45.59 59% 76.98
Development Cost
1The average depth of the target formation was calculated from Harker (1998).
Note – Storage efficiency calculated by assuming it to be between
the high values of the very depleted gas fields (over 70%) and the
lower values of the confined aquifers (20%) (values from ETI
SSAP Project).
Estimating factors of £M1.1/ km of installed pipeline and £M17/km of well depth were
used (ETI, 2016).
Location of Site
Levelised cost vs storage efficiency calculated for
eight sites from the ETI SSAP Project. Piper Field
estimated position in orange.
Piper Field
Reinterpret field based on 2008 PreSDM seismic
processing. Slater and Bamford, BP, 2009
Piper stratigraphy. Slater and Bamford, BP, 2009
Seal Characterisation Fracture CharacterisationEngineering
RiskGeorisk factor
Fracture
Pressure
Capacity
Seal
degradationDensity
Throw and
fault seal
Fault
Vertical
Extent
Well Total
1 1 1 1 1 3 8
Low=1 Medium=2 High=3
OVERVIEWThe Upper Jurassic transgression is marked by sandstones, shalesand coals of the paralic to shallow marine Sgiath Formation, theOxfordian reservoir of the Piper field. The I shale represents a‘Maximum Flooding Event’ of regional scale and the succeedingshallow marine Piper sandstones are Early Kimmeridgian in age. Thetop Piper sandstones over most of the field are truncated, with deepmarine anoxic mudstones of the Middle Volgian age KimmeridgeClay to younger Cretaceous rocks capping the reservoir section.Downflank, late Kimmeridgian to Volgian age Kimmeridge Clay andGalley turbidites are present. The Kimmeridge Clay is the prolificsource rock of the North Sea oil fields. The Lower Cretaceous marlsare only present downflank and the Upper Cretaceous Floundermarls ultimately cap the Piper structure. The Maastrichtian Tor Chalkis unconformably overlain by Palaeocene deep marine clastics.
Interpreted seismic section in the Piper Oil Field area – Slater and Bamford, 2009
Site F: Piper Oil Field
INJECTIVITY
The injectivity is calculated to be 388000mDm which is
considered to be very suitable for CO2 storage.
CONTAINMENT
The Piper Oil Field has hosted hydrocarbons for
millions of years and thus are considered a suitable
reservoir-seal system for CO2 storage.
Due Diligence capacity estimate
Parameter Inputs Comments
Gross Rock Volume Low 2,664 Harker 1998
MMCUM Mid 2,772 Williams, et al 1975. AAPG
High 3,395 Schmitt & Gordon, 1991.
Net to Gross Ratio Low 0.70 Slater and Bamford, BP, 2009
Mid 0.8
High 0.90
Porosity Low 0.22 Harker 1998
Mid 0.24 Slater and Bamford, BP, 2009
High 0.32 Slater and Bamford, BP, 2009
CO2 Density Low 0.804 2627 ft, 96.2 degF, 2098 psi
T/m3 Mid 0.808 2440 ft, 91.6 degF, 1948 psi
High 0.811 2253 ft, 87.0 degF, 1799 psi
CO2 Storage Efficiency Low 0.300 -30%
Mid 0.490 ETI, 2015
High 0.600 +22%
P90 178
P50 233
MT P10 283
CO2 Capacity of Piper
Run - 4
Dynamic Storage Capacity
Distribution
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 50 100 150 200 250 300 350 400 450
Rela
tive
Pro
babi
lity
Dynamic Storage Capacity (MT)
0.54
0.29
3,181.37
0.86
0.81
0.38
0.23
2,753.09
0.74
0.81
150.00 200.00 250.00 300.00
CO2 Storage Efficiency
Porosity
Gross Rock Volume
Net to Gross Ratio
CO2 Density
Sensitivity Analysis
Upside Downside
1From due diligence2Input data from CDA3Data obtained from the CO2Stored database (ETI, 2016).