a scalable full-chain industrial d05 site selection report annex 3 … acorn site selection... ·...

A scalable

full-chain industrial

CCS project

A scalable


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

mailto:[email protected]

A scalable


CCS project

A scalable


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

https://www.ogauthority.co.uk/

A scalable


CCS project

A scalable


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



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



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%


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



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


1From due diligence capacity estimate2From ETI due diligence (ETI, 2015)3Data obtained from the CO2Stored database (ETI, 2016).


Due Diligence Capacity Estimate


Gross Rock Volume Low 96,450 -50%

MMCUM Mid 192,900 Digitised West Grid polygon; thickness from ETI DD

High 385,800 +100%


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


T/m3 Mid 0.783 4200 ft, 134.6 degF, 3354 psi

High 0.791 3500 ft, 117.5 degF, 2795 psi


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


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


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


Porosity

Net to Gross Ratio

CO2 Density


Upside Downside


Gross Rock Volume Low 65,550 -50%

MMCUM Mid 131,100 Digitised East Grid polygon; thickness from ETI DD

High 262,200 +100%


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


T/m3 Mid 0.783 4200 ft, 134.6 degF, 3354 psi

High 0.791 3500 ft, 117.5 degF, 2795 psi


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


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


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


Porosity

Net to Gross Ratio

CO2 Density


Upside Downside


A scalable


CCS project

A scalable


CCS project

Site Summary

Capacity (P50) 1917 MT


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





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.


RiskGeorisk Factor

Fracture

Pressure

Capacity

Seal

degradationDensity

Throw and

fault seal

Fault

Vertical

Extent

Well Total

3 2 3 3 2 1 13



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%


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)


58.71 1.34 128 349Brae East

Brae NorthFlugga Sst


Data obtained from: Millennium Atlas, CDA and the CO2Stored database (ETI, 2016).




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


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.


Column for Northern

North Sea

16/07a-14 Well Log

Hei

md

al S

and

sto

ne


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


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


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


Gross Rock Volume

Porosity

Net to Gross Ratio

CO2 Density

Sensitvity Analysis

Upside Downside


Site C: Heimdal Sandstone Member – East Heimdal

1From due diligence capacity estimate2Input data from CDA3Data obtained from the CO2Stored database (ETI, 2016).


A scalable


CCS project

A scalable


CCS project



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


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



Latitute Longitude

Proximal Upside

Capacity (<20 km

radius) (Mt)

Proximal Upside

Capacity (<50

km radius) (Mt)


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





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.


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


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


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


Porosity

Net to Gross Ratio

CO2 Density


Upside Downside

Levelised cost vs storage efficiency calculated for eight sites

from the ETI SSAP Project. Mey 5 estimated position in

orange.

Mey 5


Efficiency

Saline AquiferOpen, identified

structure5%


Note – Storage efficiency assumed to be

similar to Forties 5 and Captain X

development (ETI SSAP Project).

Site Summary



Formation Lista Formation

Containment Unit Open, with some structures

identified in hydrocarbon fields


UKCS Block 13, 14, 19, 20

Beachhead St Fergus

Water Depth 110m


Region CNS

Poster Summary

Title Site D(a): West Mey 5



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


CCS project

A scalable


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’


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.



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


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



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


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


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


Net to Gross Ratio

Porosity

CO2 Density


Upside Downside

Site Summary

Capacity (P50) 725 MT


Formation Lista Formation

Containment Unit Open, with some structures

identified in hydrocarbon fields


UKCS Block 16/21

Beachhead St Fergus

Water Depth 110m


Region CNS

Poster Summary

Title Site D(b): East Mey 5



Capacity (MT)1 Injectivity (mDm)3 Wells/km2 2 Georisk3 Containment Risk3

Value 725 102102 0.08 14 15

Key Risk Summary


RiskGeorisk Factor

Fracture

Pressure

Capacity

Seal

DegradationDensity

Throw and

Fault Seal

Fault

Vertical

Extent

Well Total

2 2 3 3 2 1 12



Latitute Longitude

Proximal Upside

Capacity (<20 km

radius) (Mt)

Proximal Upside

Capacity (<50 km

radius) (Mt)


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




Unit designateStorage Unit

Type

Storage

efficiency

Ranking

Storage

Efficiency

Saline Aquifer

Open, no

identified

structure

5% 6




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).



Efficiency

Saline AquiferOpen, identified

structure5%


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.



A scalable


CCS project

A scalable


CCS project

Site Summary


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


Region CNS

Poster Summary

Title Site E: Dornoch Formation –

West and East Dornoch





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


References


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


MegaSurvey data coverage in the

Dornoch Formation area – Shape


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


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


T/m3 Mid 0.788 3743 ft, 123.4 degF, 2989 psi

High 0.798 3016 ft, 105.7 degF, 2408 psi


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


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


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


Net to Gross Ratio

Porosity

CO2 Density


Upside Downside


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




Site E: Dornoch Formation – West and East Dornoch



A scalable


CCS project

A scalable


CCS project

Site Summary


Unit designation Oil and Gas Field

Formation Piper Formation

Containment unit Structural/stratigraphic trap


UKCS Block 15/17

Beachhead St Fergus

Water depth 145m


Region CNS

Poster Summary

Title Site F: Piper Oil Field





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



MegaSurvey data coverage in the Piper

Oil Field area – Shape guidance from

CO2Stored.

Image source: courtesy of CDA through

an academic licence agreement – Shape


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


References


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





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


RiskGeorisk factor

Fracture

Pressure

Capacity

Seal

degradationDensity

Throw and

fault seal

Fault

Vertical

Extent

Well Total

1 1 1 1 1 3 8


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.



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


T/m3 Mid 0.808 2440 ft, 91.6 degF, 1948 psi

High 0.811 2253 ft, 87.0 degF, 1799 psi


Mid 0.490 ETI, 2015

High 0.600 +22%

P90 178

P50 233

MT P10 283

CO2 Capacity of Piper

Run - 4


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


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


Porosity

Gross Rock Volume

Net to Gross Ratio

CO2 Density


Upside Downside



a scalable full-chain industrial d05 site selection report annex 3 … acorn site selection... ·...

Documents