Project: ACT Acorn Feasibility Study Acorn - Acorn... · 2019. 2. 25. · D07 Acorn CO2 Storage Site Development Plan 10196ACTC-Rep-27-01 August 2018 Acorn ACT Acorn, project 271500,

Project: ACT Acorn Feasibility Study

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the reports full title and its authors. The material contains third party IP, used in accordance with those third

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D07 Acorn CO2 Storage Site Development Plan 10196ACTC-Rep-27-01

August 2018

www.actacorn.eu

Acorn

ACT Acorn, project 271500, has received funding from BEIS (UK), RCN (NO) and RVO (NL), and is co-funded by the European Commission under the ERA-Net instrument of the Horizon 2020 programme. ACT Grant number 691712.

D07 Acorn CO2 Storage Site Development Plan Contents

ACT Acorn Consortium Page 3 of 151

Contents

Document Summary

Client Research Council of Norway & Department of Business, Energy & Industrial Strategy

Project Title Accelerating CCS Technologies: Acorn Project

Title: D07 Acorn CO2 Storage Site Development Plan

Distribution: Client & Public Domain

Date of Issue: 30th August 2018

Prepared by: Dr Juan Alcalde and Dr Clare Bond (both University of Aberdeen), Dr Saeed Ghanbari and Dr Eric Mackay (both Heriot Watt-University), Dr Niklas Heinemann and Dr Stuart Haszeldine (both The University of Edinburgh), Dr Philippa Parmiter and Indira Mann (both SCCS), Hazel Robertson, Alan James, Tim Dumenil, David Pilbeam and Charlie Hartley (all Pale Blue Dot Energy)

Approved by: Steve Murphy, ACT Acorn Project Director

Disclaimer:

While the authors consider that the data and opinions contained in this report are sound, all parties must rely upon their own skill and judgement when using it. The authors do not make any representation or

warranty, expressed or implied, as to the accuracy or completeness of the report. The authors assume no liability for any loss or damage arising from decisions made on the basis of this report. The views and

judgements expressed here are the opinions of the authors and do not reflect those of the client or any of the stakeholders consulted during the course of this project.

The ACT Acorn consortium is led by Pale Blue Dot Energy and includes Bellona Foundation, Heriot-Watt University, Radboud University, Scottish Carbon Capture and Storage (SCCS), University of Aberdeen,

University of Edinburgh and University of Liverpool.

Amendment Record

Rev Date Description Issued By Checked By Approved By

V0.1 09/03/18 First Draft N Heinemann H Robertson P Parmiter

V1.0 30/08/18 First Issue N Heinemann H Robertson P Parmiter



Table of Contents

CONTENTS ................................................................................................................................................................................................................................................... 3

1.0 EXECUTIVE SUMMARY .................................................................................................................................................................................................................. 12

2.0 INTRODUCTION TO ACT ACORN .................................................................................................................................................................................................. 16

3.0 SCOPE AND OBJECTIVES ............................................................................................................................................................................................................. 21

4.0 SITE CHARACTERISATION ........................................................................................................................................................................................................... 23

5.0 APPRAISAL PLANNING ................................................................................................................................................................................................................. 99

6.0 DEVELOPMENT PLANNING ......................................................................................................................................................................................................... 100

7.0 BUDGET & SCHEDULE ................................................................................................................................................................................................................ 122

8.0 CONCLUSIONS & RECOMMENDATIONS ................................................................................................................................................................................... 126

9.0 REFERENCES ............................................................................................................................................................................................................................... 132

10.0 ANNEXES ....................................................................................................................................................................................................................................... 135



CONTENTS ................................................................................................................................................................................................................................................... 3

TABLE OF CONTENTS .................................................................................................................................................................................................................................... 4

FIGURES ...................................................................................................................................................................................................................................................... 7

TABLES ...................................................................................................................................................................................................................................................... 10

1.0 EXECUTIVE SUMMARY .................................................................................................................................................................................................................. 12

2.0 INTRODUCTION TO ACT ACORN .................................................................................................................................................................................................. 16

2.1 ACT ACORN OVERVIEW................................................................................................................................................................................................................... 16

2.2 ACORN DEVELOPMENT CONCEPT ..................................................................................................................................................................................................... 19

3.0 SCOPE AND OBJECTIVES ............................................................................................................................................................................................................. 21

3.1 PURPOSE ........................................................................................................................................................................................................................................ 21

3.2 SCOPE ............................................................................................................................................................................................................................................ 21

4.0 SITE CHARACTERISATION ........................................................................................................................................................................................................... 23

4.1 GEOLOGICAL SETTING ..................................................................................................................................................................................................................... 23

4.2 SITE HISTORY AND DATABASE .......................................................................................................................................................................................................... 24

4.3 STORAGE STRATIGRAPHY ................................................................................................................................................................................................................ 30

4.4 SEISMIC CHARACTERISATION ........................................................................................................................................................................................................... 31

4.5 GEOLOGICAL CHARACTERISATION .................................................................................................................................................................................................... 37

4.6 INJECTION PERFORMANCE CHARACTERISATION ................................................................................................................................................................................ 40

4.7 CONTAINMENT CHARACTERISATION .................................................................................................................................................................................................. 81

5.0 APPRAISAL PLANNING ................................................................................................................................................................................................................. 99

6.0 DEVELOPMENT PLANNING ......................................................................................................................................................................................................... 100

6.1 DESCRIPTION OF DEVELOPMENT .................................................................................................................................................................................................... 100

6.2 CO2 SUPPLY PROFILE ................................................................................................................................................................................................................... 100

6.3 WELL DEVELOPMENT PLAN ............................................................................................................................................................................................................ 101



6.4 OFFSHORE INFRASTRUCTURE DEVELOPMENT PLAN ........................................................................................................................................................................ 106

6.5 OPERATIONS ................................................................................................................................................................................................................................. 116

6.6 DECOMMISSIONING ........................................................................................................................................................................................................................ 116

6.7 POST CLOSURE PLAN .................................................................................................................................................................................................................... 117

6.8 HANDOVER TO AUTHORITY ............................................................................................................................................................................................................. 117

6.9 DEVELOPMENT RISK ASSESSMENT ................................................................................................................................................................................................. 117

7.0 BUDGET & SCHEDULE ................................................................................................................................................................................................................ 122

7.1 COST ESTIMATING BASIS ............................................................................................................................................................................................................... 122

7.2 CAPITAL EXPENDITURE ESTIMATE .................................................................................................................................................................................................. 123

7.3 OPERATING EXPENDITURE ESTIMATE ............................................................................................................................................................................................. 124

7.4 ABANDONMENT EXPENDITURE ESTIMATE ........................................................................................................................................................................................ 124

7.5 UNCERTAINTY OF COST ESTIMATES ............................................................................................................................................................................................... 125

7.6 SCHEDULE .................................................................................................................................................................................................................................... 125

8.0 CONCLUSIONS & RECOMMENDATIONS ................................................................................................................................................................................... 126

8.1 CONCLUSIONS ............................................................................................................................................................................................................................... 126

8.2 RECOMMENDATIONS ...................................................................................................................................................................................................................... 129

9.0 REFERENCES ............................................................................................................................................................................................................................... 132

10.0 ANNEXES ....................................................................................................................................................................................................................................... 135

10.1 ANNEX 1 – DATA INVENTORY .......................................................................................................................................................................................................... 135

10.2 ANNEX 2: RISK REGISTER .............................................................................................................................................................................................................. 141

10.3 ANNEX 3: LEAKAGE WORKSHOP SPIDER DIAGRAMS ........................................................................................................................................................................ 142



Figures

FIGURE 1-1: LOCATION MAP OF ACORN CO2 STORAGE SITE COMPLEX.............................................................................................................................................................. 13

FIGURE 1-2: PRIMARY AND SECONDARY CONTAINMENT OF THE ACORN CO2 STORAGE SITE ............................................................................................................................... 13

FIGURE 1-3: ACORN CCS PROJECT SCHEDULE .............................................................................................................................................................................................. 14

FIGURE 2-1: ACT ACORN CONSORTIUM PARTNERS .......................................................................................................................................................................................... 16

FIGURE 2-2: KEY AREAS OF INNOVATION ......................................................................................................................................................................................................... 17

FIGURE 2-3: ACT ACORN WORK BREAKDOWN STRUCTURE .............................................................................................................................................................................. 17

FIGURE 2-4: A SCALABLE FULL-CHAIN INDUSTRIAL CCS PROJECT ..................................................................................................................................................................... 19

FIGURE 2-5: ACORN BUILD OUT SCENARIO FROM THE 2017 PCI APPLICATION ................................................................................................................................................... 20

FIGURE 3-1: ACORN CCS PROJECT PHASE 1 AND BUILD-OUT OPTIONS ............................................................................................................................................................ 21

FIGURE 4-1: CAPTAIN SANDSTONE FAIRWAY ................................................................................................................................................................................................... 23

FIGURE 4-2: TWO-WAY-TIME MAP SHOWING OUTLINE OF ACORN CO2 STORAGE SITE AND CAPTAIN X AREA ........................................................................................................ 24

FIGURE 4-3: TIME SLICE OF THE PGS MEGASURVEY SHOWING SEISMIC COVERAGE AND EXTENT OF THE INTERPRETATIONS IN THE ACORN CO2 STORAGE SITE AREA ................... 27

FIGURE 4-4: MAP OF WELLS AVAILABLE IN THE CAPTAIN FAIRWAY, INCLUDING THESE USED IN THE INTERPRETATION (IN RED, BLUE AND YELLOW) ................................................. 29

FIGURE 4-5: STRATIGRAPHIC COLUMN ............................................................................................................................................................................................................ 30

FIGURE 4-6: SYNTHETIC SEISMOGRAM FROM THE WELL 13/24A- 6 .................................................................................................................................................................... 32

FIGURE 4-7: TOP CAPTAIN SANDSTONE TWO-WAY TIME MAP AND FAULTING ...................................................................................................................................................... 34

FIGURE 4-8: DEPTH CONVERSION SUMMARY.................................................................................................................................................................................................... 36

FIGURE 4-9: PETROPHYSICAL WORKFLOW ....................................................................................................................................................................................................... 37

FIGURE 4-10: EFFECT OF IMPURITIES ON THE PHASE ENVELOPE ....................................................................................................................................................................... 42

FIGURE 4-11: RATES ACHIEVABLE BY CASE FOR MINIMUM AND MAXIMUM TUBING HEAD PRESSURE ..................................................................................................................... 47

FIGURE 4-12: PRESSURE / TEMPERATURE PROFILES – 4½’’ TUBING – MIN/MAX TUBING HEAD PRESSURE ............................................................................................................ 47

FIGURE 4-13: PRESSURE / TEMPERATURE PROFILES – 27/8’’ TUBING – MIN/MAX TUBING HEAD PRESSURE ........................................................................................................... 47

FIGURE 4-14: PRESSURE / TEMPERATURE PROFILES – DUAL 27/8’’’TUBING – MIN/MAX TUBING HEAD PRESSURE ................................................................................................... 48

FIGURE 4-15: CASE 11B (MAXIMUM THP) – PRESSURE AND TEMPERATURE V DEPTH PLOT ................................................................................................................................ 48

FIGURE 4-16: PERFORMANCE ENVELOPE - 27/8’’ SINGLE TUBING STRING ........................................................................................................................................................... 50

FIGURE 4-17: PERFORMANCE ENVELOPE - 4½’’ SINGLE TUBING STRINGINJECTIVITY AND NEAR WELLBORE ISSUES ............................................................................................. 50



FIGURE 4-18: PROFILE OF TEMPERATURE AND PRESSURE AWAY FROM INJECTION WELL, 100 DAYS AFTER THE START OF CO2 INJECTION. ........................................................... 53

FIGURE 4-19: DIFFERENT REGIONS USED IN THE ETI SSAP WORK. LOCATION OF MODEL FRACTURING PRESSURE THRESHOLD SHOWN AS RED POINT ......................................... 57

FIGURE 4-20: GAS SATURATION (TOP) AND CO2 MOLE FRACTION IN THE GAS PHASE (BOTTOM); BOTH IMMEDIATELY AFTER CO2 INJECTION STOPS (2042) .................................... 60

FIGURE 4-21: GAS SATURATION (TOP) AND CO2 MOLE FRACTION IN THE GAS PHASE (BOTTOM) PROFILES 1000 YEARS AFTER CO2 INJECTION IS STOPPED (YEAR 3042) ............... 61

FIGURE 4-22: LIGHT GAS MOLE FRACTION IN THE GAS PHASE PROFILE 1000 YEARS AFTER CO2 INJECTION TERMINATION (YEAR 3042) ................................................................ 61

FIGURE 4-23: CO2 SUPPLY SCENARIOS ........................................................................................................................................................................................................... 62

FIGURE 4-24: CO2 STORAGE ZONES ............................................................................................................................................................................................................... 63

FIGURE 4-25: BHP AND THP PROFILES FOR WELL G02 FOR THE PHASE 1 (4MT) SCENARIO ............................................................................................................................. 64

FIGURE 4-26: PHASE 1 (SUPPLY SCENARIO 1 - 4MT) CO2 SUPPLY SCENARIO GAS SATURATION PROFILE .......................................................................................................... 65

FIGURE 4-27: RETAINED CO2 AND TRAPPING MECHANISM FRACTIONS FOR 4MT CO2 SUPPLY SCENARIO ............................................................................................................ 66

FIGURE 4-28: CO2 PLUME MIGRATION AT THE END OF INJECTION (ABOVE) AND AFTER 1000 YEARS SHUT-IN (BELOW) FOR PHASE 1 (4.2MT) ....................................................... 66

FIGURE 4-29: GAS SATURATION PROFILE AFTER THE END OF CO2 INJECTION (TOP) AND 1000 YEARS LATER (BOTTOM) FOR THE 64MT CO2 SUPPLY SCENARIO ........................... 67

FIGURE 4-30: CO2 MOLE FRACTION IN THE GAS PHASE 1000 YEARS AFTER CO2 INJECTION IS STOPPED FOR THE PHASE 2 (SCENARIO 2 - 64MT) CO2 SUPPLY SCENARIO ............ 68

FIGURE 4-31: BHP AND THP PROFILES FOR WELLS G2 AND G4 FOR PHASE 2 64MT SCENARIO........................................................................................................................ 68

FIGURE 4-32: RETAINED CO2 AND TRAPPING MECHANISM FRACTIONS FOR 64MT CO2 SUPPLY SCENARIO .......................................................................................................... 68

FIGURE 4-33: ACORN CO2 STORAGE SITE STORAGE COMPLEX OUTLINE SHOWING CAPTAIN X AREA AND GOLDENEYE SEGMENT ......................................................................... 69

FIGURE 4-34: GAS SATURATION PROFILE FOR PHASE 3 (SCENARIO 3 - 152MT) CO2 SUPPLY SCENARIO ............................................................................................................ 70

FIGURE 4-35: CO2 MOLE FRACTION IN THE GAS PHASE 1000 YEARS AFTER CO2 INJECTION HAS STOPPED FOR THE THIRD CO2 SUPPLY SCENARIO (SIMULATION RUN SR20) ........ 72

FIGURE 4-36: RETAINED CO2 AND TRAPPING MECHANISM FRACTIONS FOR PHASE 3 CO2 SUPPLY SCENARIO ...................................................................................................... 72

FIGURE 4-37: BHP AND THP PROFILES FOR WELLS G1-4 FOR SR20 ............................................................................................................................................................... 72

FIGURE 4-38: PROFILE OF CO2 DISTRIBUTION IN THE SECOND SIMULATION RUN AFTER 1000 YEARS. WELL G1 IS NOW AT THE BOTTOM OF THE MODEL NEAR THE GOLDENEYE FIELD

.............................................................................................................................................................................................................................................................. 74

FIGURE 4-39: PROFILE OF CO2 DISTRIBUTION IN THE THIRD SIMULATION RUN AFTER 1000 YEARS. BOTH WELLS G1 AND G3 ARE NOW AT THE BOTTOM OF THE MODEL NEAR THE

GOLDENEYE FIELD .................................................................................................................................................................................................................................. 74

FIGURE 4-40: RETAINED CO2 AND TRAPPING MECHANISM FRACTIONS FOR THE PHASE 3 THIRD SIMULATION RUN ................................................................................................ 75

FIGURE 4-41: PIE CHARTS SHOWING FRACTION OF FREE, TRAPPED AND DISSOLVED CO2 FOR DIFFERENT STRATEGIES ....................................................................................... 78

FIGURE 4-42: BAR CHARTS SHOWING FRACTION OF FREE, TRAPPED AND DISSOLVED CO2 FOR DIFFERENT STRATEGIES ...................................................................................... 79

FIGURE 4-43: FRACTION AND DISTRIBUTION OF CO2 FOR DIFFERENT WELL PLACEMENT STRATEGIES ................................................................................................................. 80



FIGURE 4-44: COMPARISON OF FINAL GAS SATURATION PROFILES .................................................................................................................................................................... 81

FIGURE 4-45: ACORN CO2 STORAGE SITE STORAGE COMPLEX OUTLINE ............................................................................................................................................................ 82

FIGURE 4-46: PRIMARY AND SECONDARY CONTAINMENT .................................................................................................................................................................................. 82

FIGURE 4-47: WELL CORRELATION ................................................................................................................................................................................................................. 84

FIGURE 4-48: ADJUSTED BOW-TIE DIAGRAM DISPLAYING THE TWO MAIN STEPS OF THE RISK ASSESSMENT: THE LEAKAGE SCENARIO ANALYSIS AND THE CONSEQUENCE ANALYSIS . 89

FIGURE 4-49: THE 11 LEAKAGE SCENARIOS CONSIDERED AS RELEVANT FOR THE AREA INVESTIGATED ............................................................................................................... 91

FIGURE 4-50: SUMMARY OF THE RISK OF ALL LEAKAGE SCENARIOS; PRIMARY PATHWAYS IN BLACK AND SECONDARY PATHWAYS IN PURPLE ......................................................... 93

FIGURE 4-51: SUMMARY OF CONSEQUENCE IMPACT OF ALL LEAKAGE SCENARIOS ............................................................................................................................................. 94

FIGURE 4-52: LEAKAGE SCENARIO MAPPING TO MMV TECHNOLOGY. THE COLOURS CORRESPOND TO THE RISK MATRIX IN FIGURE 4-50 ............................................................. 97

FIGURE 6-1: KEY ELEMENTS OF OFFSHORE INFRASTRUCTURE ........................................................................................................................................................................ 100

FIGURE 6-2: THREE DIFFERENT CO2 SUPPLY SCENARIOS ENVISAGED FOR THE ACORN PROJECT ..................................................................................................................... 101

FIGURE 6-3: WELL PROFILE TO THE RESERVOIR ............................................................................................................................................................................................. 103

FIGURE 6-4: WELL CONSTRUCTION ILLUSTRATION ......................................................................................................................................................................................... 105

FIGURE 6-5: TRANSPORTATION INFRASTRUCTURE OVERIVEW ......................................................................................................................................................................... 108

FIGURE 6-6: ATLANTIC AND CROMARTY FIELD LAYOUT ................................................................................................................................................................................... 108

FIGURE 6-7: OPERATING CONDITIONS ALONG THE ATLANTIC PIPELINE ............................................................................................................................................................ 113

FIGURE 6-8: PRESSURE/TEMPERATURE PROFILE OBSERVED IN THE ATLANTIC PIPELINE FOR DIFFERENT SUPPLY SCENARIOS. ARROWS SHOW THE DIRECTION OF THE PROFILE FROM

ST FERGUS TO INJECTION SITE ON THE LEFT. THE RED REGION IS THE LIKELY HYDRATE FORMATION REGION ............................................................................................. 115

FIGURE 7-1: DEVELOPMENT SCHEDULE ......................................................................................................................................................................................................... 125

FIGURE 10-1: PGS MEGA SURVEY TIME SLICE SHOWING THE SEISMIC DATA EXTENT AND TILES USED IN THE CAPTAIN AQUIFER EVALUATION ..................................................... 135

FIGURE 10-2: THE 11 LEAKAGE SCENARIOS CONSIDERED AS RELEVANT FOR THE AREA INVESTIGATED ............................................................................................................. 142

FIGURE 10-3: SPIDER DIAGRAM SHOWING THE IMPACT OF CONSEQUENCES .................................................................................................................................................... 143









FIGURE 10-10: SPIDER DIAGRAM SHOWING THE IMPACT OF CONSEQUENCES................................................................................................................................................... 148




Tables

TABLE 1-1: CAPITAL EXPENDITURE ................................................................................................................................................................................................................. 15

TABLE 2-1: ACT ACORN MILESTONES AND DELIVERABLES .............................................................................................................................................................................. 18

TABLE 3-1: SCOPE SUMMARY ......................................................................................................................................................................................................................... 22

TABLE 4-1: FIRST PRODUCTION AND CESSATION OF PRODUCTION DATES FOR CAPTAIN SANDSTONE FIELDS ....................................................................................................... 25

TABLE 4-2: ACORN CO2 STORAGE SITE AVAILABLE WELL DATA ......................................................................................................................................................................... 28

TABLE 4-3: SUMMARY OF SEISMIC HORIZONS INTERPRETED IN THE ETI SSAP WORK ........................................................................................................................................ 33

TABLE 4-4: SUMMARY OF PRIMARY AND SECONDARY STORAGE FORMATIONS .................................................................................................................................................... 38

TABLE 4-5: FAIRWAY MODEL POROSITY AND PERMEABILITY MODELLING RESULTS .............................................................................................................................................. 40

TABLE 4-6: MODELLED FACIES PROPORTIONS ................................................................................................................................................................................................. 40

TABLE 4-7: GROSS ROCK AND PORE VOLUMES FOR THE CAPTAIN FAIRWAY MODEL ........................................................................................................................................... 40

TABLE 4-8: PVT DEFINITION ........................................................................................................................................................................................................................... 41

TABLE 4-9: CAPTAIN RESERVOIR DATA ............................................................................................................................................................................................................ 43

TABLE 4-10: CAPTAIN FIELD AND WELL DATA ................................................................................................................................................................................................... 44

TABLE 4-11: CAPTAIN IPR INPUT DATA............................................................................................................................................................................................................ 44

TABLE 4-12: INJECTION PRESSURE LIMITS ....................................................................................................................................................................................................... 44

TABLE 4-13: RATES ACHIEVABLE BY CASE FOR MINIMUM AND MAXIMUM TUBING HEAD PRESSURE ....................................................................................................................... 46

TABLE 4-14: ETI SSAP RESERVOIR MODEL PROPERTIES ................................................................................................................................................................................. 57

TABLE 4-15: INITIALISATION DEPTHS AND CORRESPONDING PRESSURES AT CONTACT DEPTHS FOR DIFFERENT MODEL REGIONS .......................................................................... 58

TABLE 4-16: PARAMETERS OF THE FLUID MODEL ............................................................................................................................................................................................. 59

TABLE 4-17: TARGET STORAGE ZONES AND TARGET INJECTION WELLS FOR EACH CO2 SUPPLY SCENARIO .......................................................................................................... 63

TABLE 4-18: RESERVOIR ENGINEERING WELL SUMMARY FOR PHASE 1 AND 2 WELLS ......................................................................................................................................... 64

TABLE 4-19: PHASE 2 INJECTION RATES PER WELL .......................................................................................................................................................................................... 67



TABLE 4-20: DIFFERENT SIMULATIONS MODELLED TO ADDRESS THE PHASE 3 CO2 SUPPLY SCENARIO INJECTED INTO THE CAPTAIN X AREA ONLY ................................................ 71

TABLE 4-21: WELL LOCATIONS FOR PHASE 3 152MT SCENARIO ...................................................................................................................................................................... 73

TABLE 4-22: INDIVIDUAL WELL INJECTION PROFILES TO ACHIEVE THE TARGET 152MT CO2 INJECTION ................................................................................................................ 73

TABLE 4-23: SUMMARY OF 8 CAPTAIN X AREA LEGACY WELLS REVIEWED IN DETAIL ........................................................................................................................................... 88

TABLE 4-24: LIKELIHOOD SCALE USED IN LEAKAGE WORKSHOP ....................................................................................................................................................................... 90

TABLE 4-25: SEVERITY SCALE USED IN THE LEAKAGE WORKSHOP .................................................................................................................................................................... 90

TABLE 4-26: SUMMARY OF CATEGORIES AND GRADES OF CONSEQUENCES ....................................................................................................................................................... 92

TABLE 4-27: OUTLINE CORRECTIVE MEASURES PLAN ....................................................................................................................................................................................... 98

TABLE 6-1: PRELIMINARY WELL LOCATION USED IN WELL DESIGN .................................................................................................................................................................... 102

TABLE 6-2: WELL LOCATION AS DETERMINED FROM DYNAMIC MODELLING ....................................................................................................................................................... 102

TABLE 6-3: OUTLINE WELL CONSTRUCTION PROGRAMME ............................................................................................................................................................................... 105

TABLE 6-4: INJECTION PROFILE ..................................................................................................................................................................................................................... 106

TABLE 6-5: ATLANTIC PIPELINE DESIGN PARAMETERS .................................................................................................................................................................................... 110

TABLE 6-6: MAXIMUM OPERATING PRESSURE UNDER DIFFERENT CO2 SUPPLY SCENARIOS .............................................................................................................................. 114

TABLE 7-1: COST ESTIMATE CLASS DEFINITIONS (AACEI 18R-97) ................................................................................................................................................................ 122

TABLE 7-2: CAPEX ESTIMATE ........................................................................................................................................................................................................................ 124

TABLE 7-3: OPEX ESTIMATE .......................................................................................................................................................................................................................... 124

TABLE 7-4: ABEX ESTIMATE .......................................................................................................................................................................................................................... 125

TABLE 10-1: SEG-Y SURVEY DATUM AND MAP PROJECTIONS ......................................................................................................................................................................... 135

TABLE 10-2: SEG-Y TILES FOR CAPTAIN AQUIFER EVALUATION ..................................................................................................................................................................... 135

TABLE 10-3: SUMMARY OF WELL DATA USED IN THE CAPTAIN AQUIFER EVALUATION ........................................................................................................................................ 139

TABLE 10-4: LIST OF CORE DATA USED IN THE CHARACTERISATION OF THE ACORN CO2 STORAGE SITE ........................................................................................................... 140

TABLE 10-5: SUMMARY OF CATEGORIES AND GRADES OF CONSEQUENCES ..................................................................................................................................................... 142

D07 Acorn CO2 Storage Site Development Plan Executive Summary


1.0 Executive Summary

The main objectives of this Acorn CO2 Storage Site storage development plan

were: to build upon the results of previous work and update the development

plan to align with the scalable approach for the Acorn CCS Project.

This Storage Development Plan has been built on the existing work of the

Energy Technologies Institute (ETI) Strategic UK Carbon Capture and Storage

Appraisal Project (ETI SSAP), (Pale Blue Dot Energy & Axis Well Technology,

2016), which accelerated the development of strategically important storage

capacity to meet UK needs.

The work undertaken for the ACT research study has confirmed that the Acorn

CO2 storage site offers a low cost, flexible and scalable development plan

solution for the Acorn CCS Project. This opportunity is created by: -

• Pipeline optionality - Two existing and redundant pipelines, Atlantic

and Goldeneye, both run from St Fergus to the Acorn CO2 storage

site. These can be re-used and offer cost savings over a new build

pipeline. The initial re-use of the Atlantic pipeline is the reference

case for the Acorn CCS Project initialisation.

• Low cost flexible well design - A single dual completion subsea

injection well provides lower capital cost than a platform well and is

designed to handle a range of injection rates, from 0.1MT to 2MT/yr,

meaning it can be used in subsequent phases of the project.

• Scalable storage resource - It has been demonstrated through

careful dynamic modelling of the reservoir that up to 152MT can be

securely stored within the Acorn CO2 storage site storage complex,

providing scalability and additional storage resource beyond the

initial Phase 1 (200kT/yr) of the project.

The Acorn CO2 storage site and corresponding

development plan offers a low cost, flexible and

scalable solution for the Acorn CCS Project.

The storage site can safely contain 152MT (5MT/yr

injection rate) within the proposed storage complex

boundary for a minimum of 1000 years after cessation

of injection and is readily scalable.

Phase 1 development consists of 200kT/yr injected

via one dual completion subsea well, starting in 2023.

The base case for transportation is via the existing

redundant 78km 16” Atlantic pipeline, from St Fergus.

An ambitious programme can achieve Final

Investment Decision in 2020 and first injection in

2023.

A capital investment of £177 million is estimated for

the scalable offshore transport and storage.



The proposed storage complex for the Acorn CO2 storage site covers an area

of 971km2, extending from the west of the Blake oilfield, to the east of the

Goldeneye gas field in the Outer Moray Firth, approximately 80km from St

Fergus. This is illustrated in Figure 1-1 (Pale Blue Dot Energy & Axis Well

Technology, 2016).

Figure 1-1: Location Map of Acorn CO2 storage site complex

The primary storage unit is the Captain Sandstone within the Lower Cretaceous

Cromer Knoll Group. The primary seal is provided by the mudstones within the

Rodby and Carrick Formations, as shown in Figure 1-2 (Pale Blue Dot Energy

& Axis Well Technology, 2016).

Figure 1-2: Primary and secondary containment of the Acorn CO2 storage site

The Captain Sandstone consists of channel dominated turbidite deposits of

generally excellent reservoir quality, with an average porosity of 27% and an

average permeability of 1400mD. The Upper Captain (D) Sandstone is

extensive across the fairway and is separated from the less extensive Lower

Captain (A) Sandstone, by the Mid Captain Shale.

Secure vertical containment is provided by laterally extensive mudstones and

shales of the Rodby and Carrick Formations which are a proven seal for multiple



hydrocarbon fields in the Central North Sea and provides an excellent caprock

for the storage complex.

The seismic interpretation and geological model build work flow that was carried

out in the ETI SSAP study was reviewed, and the dynamic reservoir model

upgraded to account for possible CO2-hydrocarbon behaviour in the depleted

gas fields of Atlantic and Cromary. This “compositional” model was then used

for the ACT Acorn reservoir simulation scenarios. Well injection performance

modelling and well design was carried out specifically for this project.

The dynamic modelling results show that injection into the Captain Sandstone

presents no challenges. However due to high vertical permeability and

connectivity of the Captain Sandstone, the CO2 flow within the reservoir is

expected to be strongly gravity dominated; the lack of permeability baffles to

slow its migration to the top of the Upper Captain Formation suggest that the

CO2 will be highly mobile. This, coupled with the shallow regional dip (1-2o) of

the top of the Captain sandstone means that the ultimate footprint of the plume

is spread out for large injected inventories, which results in low dynamic storage

efficiencies for the site in the order of ~1-2%. Techniques that are common in

the petroleum industry were investigated in an effort to enhance this dynamic

storage efficiency, however the cost effective options proved largely ineffective.

The basis for the development plan for Phase 1 is an assumed CO2 supply of

200kT/yr to be provided from the shore terminal at St. Fergus commencing in

2023. CO2 will be transported offshore in dense-phase via the existing 78km 16”

Atlantic pipeline from St. Fergus, plus an additional flowline to an injection site

in between the Atlantic and Cromarty depleted fields. Phase 1 injection will be

via a single subsea injection well with a dual completion which can provide

injection rates from 0.1kT/yr to 2MT/yr, making it suitable for use during low rate

commissioning and for higher rates during later phases of the project without

further well intervention. Future potential build out scenarios were also modelled,

with rates up to 5MT/yr using additional wells and a storage resource of 152MT

safely contained within the Acorn CO2 storage site storage complex for 1000

years after injection ceases.

Figure 1-3: Acorn CCS Project Schedule

As shown in Figure 1-3, the development schedule has 5 main phases of activity

after this ACT study. Concept, FEED, appraisal and contracting activities will

commence just over 2 years prior to the final investment decision (FID) in 2020.

The capital intensive activities of procurement and construction follow FID (Final

Investment Decision) and take place over a 2.5 year period. First injection is

forecasted to take place in late 2023.



The Phase 1 offshore transportation and injection infrastructure is estimated to

require a capital investment of £177 million. When including the onshore plant

this increases to £276 million. The capital costs are summarised in Table 1-1.

Work area Net

Cost (£M)

Contingency (£M)

Gross Cost (£M)

Offshore

Concept & FEED (including inspection pig)

16.9 1.0 17.9

MMV 9.0 0.1 9.2

Pipeline 16.1 6.0 22.1

Umbilical 60.2 24.1 84.3

Subsea 11.0 4.4 15.4

Well 20.7 6.9 27.6

Total Offshore 133.8 42.5 176.5

Onshore Onshore plant 76.5 23.5 99.9

Full Chain Total Full Chain 210.3 66.0 276.4

Table 1-1: Capital Expenditure

D07 Acorn CO2 Storage Site Development Plan Introduction to ACT Acorn


2.0 Introduction to ACT Acorn

2.1 ACT Acorn Overview

ACT Acorn, project 271500, has received funding from BEIS (UK), RCN (NO)

and RVO (NL), and is co-funded by the European Commission under the ERA-

Net instrument of the Horizon 2020 programme. ACT grant number 691712.

ACT Acorn is a collaborative project between seven organisations across

Europe led by Pale Blue Dot Energy in the UK, as shown in Figure 2-1.

Figure 2-1: ACT Acorn consortium partners

The research and innovation study addresses all thematic areas of the ACT Call

including ‘Chain Integration’. The project includes a mix of both technical and

non-technical innovation activities as well as leading edge scientific research.

Together these enable the development of the technical specification for an

ultra-low cost, integrated CCS hub that can be scaled up at marginal cost. It will

move the Acorn development opportunity from proof-of-concept (TRL3) to the

pre-FEED stage (TRL5/6) including iterative engagement with relevant investors

in the private and public sectors.

Specific objectives of the project are to:

Produce a costed technical development plan for a full chain CCS

hub that will capture CO2 emissions from the St Fergus Gas

Terminal in north east Scotland and store the CO2 at an offshore

storage site under the North Sea

Identify technical options to increase the storage efficiency of the

selected storage site based on scientific evidence from

geomechanical experiments and dynamic CO2 flow modelling and

through this drive scientific advancement and innovation in these

areas.

Explore build-out options including interconnections to the nearby

Peterhead Port, other large sources of CO2 emissions in the UK

region and CO2 utilisation plants

Identify other potential locations for CCS hubs around the North Sea

regions and develop policy recommendations to protect relevant



infrastructure from premature decommissioning and for the future

ownership of potential CO2 stores.

Engage with CCS and low carbon economy stakeholders in Europe

and worldwide to disseminate the lessons from the project and

encourage deployment of key learnings.

CCS is an emerging industry. Maturity improvements are required in the

application of technology, the commercial structure of projects, the scope of

each development and the policy framework.

The key areas of innovation in which the project will seek insights are

summarised in Figure 2-2.

Figure 2-2: Key areas of innovation

The project activity has been organised into 6 work packages as illustrated in

Figure 2-3. Specific areas being addressed include; regional CO2 emissions; St

Fergus capture plant concept; CO2 storage site assessments and development

plans; reservoir CO2 flow modelling, geomechanics; CCS policy development;

infrastructure re-use; lifecycle analysis; environmental impact; economic

modelling; FEED and development plans; and build out growth assessment.

The project will be delivered over a 19-month period, concluding on the 28th

February 2019. During that time, it will create and publish 21 items known as

Deliverables. Collectively these will provide a platform for industry, local

partnerships and government to move the project forward in subsequent

phases. It will be driven by business case logic and inform the development of

UK and European policy around infrastructure preservation. The deliverables

are listed in Table 2-1.

Figure 2-3: ACT Acorn work breakdown structure



Milestone Deliverable

1) St Fergus Hub Design

D01 Kick-off Meeting Report

D02 CO2 Supply Options

D17 Feeder 10 Business Case

2) Site Screening & Selection

D03 Basis of Design for St Fergus Facilities

D04 Site Screening Methodology

D05 Site Selection Report

D13 Plan and Budget for FEED

3) Expansion Options D18 Expansion Options

4) Full Chain Business Case

D10 Policy Options Report

D11 Infrastructure Reuse Report

D14 Outline Environmental Impact Assessment

D15 Economic Model and Documentation

D16 Full Chain Development Plan and Budget

5) Geomechanics D06 Geomechanics Report

D07 Acorn Storage Site Storage Development Plan and Budget

6) Storage Development Plans D08 East Mey Storage Site Storage Development Plan and Budget

D09 Eclipse Model Files

7) Lifecycle Assessment D12 Carbon Lifecycle Analysis

8) Project Completion

D21 Societal Acceptance Report

D19 Material for Knowledge Dissemination Events

D20 Publishable Final Summary Report

Table 2-1: ACT Acorn Milestones and Deliverables



The Consortium includes a mix of industrial, scientific and CCS policy experts in

keeping with the multidisciplinary nature of the project. The project is led by Pale

Blue Dot Energy along with University of Aberdeen, University of Edinburgh,

University of Liverpool, Heriot Watt University, Scottish Carbon Capture &

Storage (SCCS), Radboud University and The Bellona Foundation. Pale Blue

Dot Energy affiliate CO2DeepStore are providing certain input material.

2.2 Acorn Development Concept

Many CCS projects have been burdened with achieving “economies of scale”

immediately to be deemed cost effective. This inevitably increases the initial cost

hurdle to achieve a lower lifecycle unit cost (be that £/MWh or £/T) which raises

the bar from the perspectives of initial capital requirement and overall project

risk.

The Acorn development concept uses a Minimum Viable Development (MVD)

approach. This takes the view of designing a full-chain CCS development of

industrial scale (which minimises or eliminates the scale up risk) but at the

lowest capital cost possible, accepting that the unit cost for the initial project may

be high for the first small tranche of sequestered emissions.

Acorn will use the unique combination of legacy circumstances in North East

Scotland to engineer a scalable full-chain carbon capture, transport and offshore

storage project to initiate CCS in the UK. The project is illustrated in Figure 2-4

and seeks to re-purpose an existing gas sweetening plant (or build a new

capture facility if required) with existing offshore pipeline infrastructure

connected to a well understood offshore basin, rich in storage opportunities. All

the components are in place to create an industrial CCS development in North

East Scotland, leading to offshore CO2 storage by the early 2020s.

Figure 2-4: A scalable full-chain industrial CCS project



A successful project will provide the platform and improve confidence for further

low-cost growth and incremental development. This will accelerate CCS

deployment on a commercial basis and will provide a cost effective practical

stepping stone from which to grow a regional cluster and an international CO2

hub.

The seed infrastructure can be developed by adding further CO2 capture points

such as from hydrogen manufacture for transport and heat, future CO2 shipping

through Peterhead Port to and from Europe and connection to UK national

onshore transport infrastructure such as the Feeder 10 pipeline which can bring

additional CO2 from emissions sites in the industrial central belt of Scotland

including the proposed Caledonia Clean Energy Project, CCEP. A build out

scenario for Acorn used in the 2017 Projects of Common Interest (PCI)

application is included as Figure 2-5.

Pale Blue Dot Energy is exploring various ways and partners to develop the

Acorn project.

Figure 2-5: Acorn build out scenario from the 2017 PCI application

D07 Acorn CO2 Storage Site Development Plan Scope and Objectives


3.0 Scope and Objectives

3.1 Purpose

The purpose of the ACT Acorn Project Deliverable D07 Acorn CO2 Storage Site

Development Plan (D07) is to document a coherent storage development plan

for the site.

3.2 Scope

The scope of D07 draws heavily on the work from the Strategic UK CO2 Storage

Appraisal Project (ETI SSAP), which accelerated development of strategic

storage resource in UK Continental Shelf and produced Storage Development

Plans (SDPs) for five sites.

One of these five sites was the “Captain X” storage area (Pale Blue Dot Energy

& Axis Well Technology, 2016), which was investigated as a candidate for CO2

storage in the UK Continental Shelf operating alongside the Goldeneye storage

project which, at the time of the ETI project, was being considered in the UK

Government CCS Commercialisation programme.

The Acorn CO2 storage site (see Figure 4-2) is the area considered for the Acorn

CCS Project and this Storage Development Plan. The Captain X storage area

is a sub-area of the Acorn CO2 Storage Site, which extends further east to

include the depleted Goldeneye gas field. The initial stages of development are

focussed near the Atlantic and Cromarty depleted gas fields. Subsequent

phases, to incorporate CO2 from build-out options (Figure 3-1), will likely

incorporate additional injection sites in the broader Acorn CO2 storage site.

Figure 3-1: Acorn CCS Project Phase 1 and build-out options

Whilst the publicly released ETI SSAP work has provided a foundation for the

Acorn CCS Project, additional development plan refinement, option evaluation,

fundamental work and research has been carried out for this ACT Study.

Table 3-1 summarises which parts of the scope include a review of the ETI

SSAP work and which are new. It also highlights which area of the Acorn CO2

storage site the work has been carried out over, e.g. the whole area, or the

smaller Captain X area.

Any assumptions made during this scope of work have been explicitly stated

throughout the text.

D07 Acorn CO2 Storage Site Development Plan Scope and Objectives


Scope Item

Geographical Area of Scope Work for Scope Comments

(if applicable) Acorn CO2 Storage Site

Captain X area (initial Phase 1 injection site)

From ETI SSAP

Revised for ACT

Geological setting, reservoir properties, exploration history ✓ ✓ Review of ETI SSAP work

Geophysical interpretation ✓ ✓ Review of ETI SSAP work

Petrophysical interpretation ✓ ✓ Review of ETI SSAP work

Geological model build ✓ ✓ Review of ETI SSAP work

Dynamic model build ✓ ✓ Review of ETI SSAP work – used ETI SSAP Black Oil Eclipse model as

starting point

Dynamic modelling scenarios and storage capacity assessment

✓ ✓ Conversion of black oil Eclipse model to fully compositional model; range of modelling runs from 200kT/yr up to 5MT/yr

Storage complex definition ✓ ✓ Storage complex lateral extent extended from ETI SSAP from west of Blake to east of Goldeneye.

Injectivity performance and well design ✓ ✓ Well design for initial injection well covering range of injection rates

High level review of abandoned wells ✓ ✓ ETI SSAP work used

Leakage scenario workshop ✓ ✓ Workshop held focussing on initial Phase 1 injection site area (Acorn)

Monitoring, measurement & verification plan

✓ ✓ ETI SSAP MMV plan used as basis and modified slightly for Phase 1

Infrastructure requirements, decommissioning

✓ ✓ Revised – subsea injection well plus reuse of existing Atlantic pipeline

Cost estimate, schedule, risk register ✓ ✓ Revised – based on Phase 1

Outline development plan and budget ✓ ✓ Revised – based on Phase 1

Table 3-1: Scope summary

D07 Acorn CO2 Storage Site Development Plan Site Characterisation


4.0 Site Characterisation

4.1 Geological Setting

The pan shaped Captain fairway is an open aquifer system in the UK Central

North Sea (CNS) that stretches for almost 200km from its shallowest part in the

north west, where it has its widest extent and is found to sub-crop at the seabed,

to its deepest extent in the far south east where it exceeds depths of 3660m

(12,000ft). To the east the fairway is a confined corridor representing the “pan

handle”. The fairway has been the subject of significant petroleum activity over

the years and hosts productive fields, Captain, Blake, Cromarty, Atlantic,

Goldeneye and Hannay. The Britannia condensate reservoir in the far east is

also an equivalent of the Captain sandstone. From 2010 to 2015, the Goldeneye

depleted gas field was the location of a proposed CO2 storage development,

initially for the Longannet Power station and then for the Peterhead Power

station (Tucker & Tinios, 2017).

The primary storage unit for the Acorn CO2 storage site is the Captain

Sandstone Member of the Lower Cretaceous Cromer Knoll Group. The Captain

Sandstone Member is an extensive sandy turbidite system, with mass flow

sediments deposited in a long, confined north west to south east fairway.

This proposed development area covers over 971km2, including the Blake oil

field in the northwest, the Atlantic and Cromarty depleted gas fields (blocks

14/26 and 13/30 respectively) and stretches beyond the Goldeneye depleted

gas reservoir in the southeast. These fields all have the Captain Sandstone as

their primary reservoir.

The distribution of the Captain Sandstone in the UK sector of the CNS, and the

fairway model outline is shown in Figure 4-1 (Pale Blue Dot Energy & Axis Well

Technology, 2016).

Figure 4-1: Captain Sandstone fairway

An area referred to as “Captain X” (to avoid confusion with other Captain

sandstone CO2 studies or the Chevron operated Captain oilfield) was studied in

the Energy Technologies Institute’s Strategic UK CO2 Storage Appraisal Project

(ETI SSAP). The Captain X area sits within the broader Acorn CO2 storage site,



as shown in Figure 4-2 (modified from ETI SSAP (Pale Blue Dot Energy & Axis

Well Technology, 2016)).

Figure 4-2: Two-way-time map showing outline of Acorn CO2 storage site and Captain X area

4.2 Site History and Database

4.2.1 Geological History

The Acorn CO2 storage site development area comprises an open saline aquifer

system with associated depleted gas fields. The Captain sandstone dips

regionally to the south east at approximately 1 to 2 degrees, with a steep ramp

of up to 20 degrees close to the West Halibut fault at the north western end.

During the Jurassic and Lower Cretaceous, the main structural element in the

area was the east-west trending Halibut Horst. Parts of this remained above sea

level through most of the Jurassic and Lower Cretaceous, contributing

significantly to the deposition of sandy turbidites during the Lower Cretaceous.

The Captain Sand fairway is a 5-10km wide ribbon of sand deposited along the

long southern edge of the Halibut Horst and South Halibut Shelf extending east

across the South Halibut Basin towards the Britannia Field. The sands were

deposited as deep water marine turbidites, controlled by the existing basin

topography, and were triggered in response to a major fall in sea level.

4.2.2 Hydrocarbon Exploration

Within the Central North Sea (CNS) the Captain Sandstone is a prolific

hydrocarbon reservoir with many hydrocarbon fields such as Captain, Blake,

Cromarty, Atlantic, Goldeneye and Hannay. The effective top seal for these is

provided by mudstones of the Carrack (Sola) and Rodby Formations (Pinnock

& Clitheroe, 2003).

The underlying Lower Cretaceous sands of the Punt and Coracle are also

prospective for hydrocarbons, with Punt Sandstone an oil bearing reservoir in

Golden Eagle, Peregrine, Hobby and Solitaire fields nearby.

The deeper Burns and Piper Sandstones of the Upper Jurassic (deeper than the

Lower Cretaceous) are also well documented hydrocarbon reservoirs within the

CNS.

Solitaire is a single well (14/26-8) oilfield in an Upper Jurassic Burns Sandstone

reservoir which lies at 464ft below the top of the Captain Sandstone (235ft below

the Base Captain Sandstone) underneath the Atlantic gas condensate field. First

oil from Solitaire was in 2015, with end of production forecast in 2028 coinciding



with the cessation of production (CoP) of the Golden Eagle development to

which it is tied back. Further west, the Upper Jurassic Ross oil field also partially

lies below the Captain Sand fairway. Neither are considered to be hydraulically

connected to the Captain sandstone. In the case of Ross, none of the wells

targeting this deeper interval penetrate the Captain Sandstone as mapped.

The reservoirs of the Cromarty (gas), Blake (oil) and Atlantic (condensate) fields

are part of the Captain Sandstone fairway itself. Both Atlantic and Cromarty are

undergoing decommissioning. First production and expected Cessation of

Production dates are shown in Table 4-1 below.

Field First Production

End of Production

Cessation of Production (CoP)

Blake 2001 (oil) Estimated 2026

Cromarty 2006 (gas) 2009 2011

Atlantic 2006 (oil) 2009 2011

Table 4-1: First production and cessation of production dates for Captain Sandstone fields

The late Jurassic Kimmeridge Clay Formation provides the source rock for the

hydrocarbons, which have migrated into the Cretaceous Captain reservoir from

the West Halibut Basin and Smith Bank Graben, (Pinnock & Clitheroe, 2003).

4.2.3 Previous Studies

Several previous studies have considered the Captain sandstone as a potential

CO2 storage site. This includes the 2015 CO2Multistore joint industry project led

by SCCS which concluded that “stakeholders can have increased confidence

that at least 360 million tonnes of CO2 captured over the coming 35 years could

be permanently injected, at a rate of between 6 and 12 million tonnes per year,

using two injection sites.”, (Shell, The Crown Estate, Scottish Government,

Scottish Enterprise and Vattenfall, 2015).

Whilst it would be possible to engineer a CO2 storage development plan in many

parts of the Captain fairway it was decided to focus upon that part of the “pan

handle” between Blake and Goldeneye, which has pipeline access via existing

redundant pipelines that can be repurposed for CO2 transportation. Whilst the

western “pan” area north of Blake and Captain oil fields represents a large

potential target, it is very shallow, often less than 800m, which is the average

depth below which the CO2 remains in supercritical state. This area also

contains the Captain oilfield which is estimated to continue operations until at

least 2030. Furthermore, the 3D seismic coverage available to this project was

incomplete over the area of the “pan” itself. For these reasons the western “pan”

area was not selected as a potential storage site target.

There have been several CO2 storage studies completed on different aspects of

the Captain Sandstone. These include:

2016 - Strategic UK CO2 Storage Appraisal Project (ETI SSAP). This

project was commissioned and funded by the Energy Technologies

Institute (ETI). ETI SSAP resulted in a portfolio of five storage sites

(which included the Captain X area that sits within the broader Acorn

CO2 storage site) that had potential to mobilise commercial scale CCS

projects in the UK (for power and industry), and prepared storage

development plans and budgets for each of the selected sites (Pale Blue

Dot Energy & Axis Well Technology, 2016).

2015 - Goldeneye FEED with injection planned at Goldeneye via the

Goldeneye platform using CO2 from Peterhead Power station. This



project was part of the UK Government’s CCS Commercialisation

Programme (Shell, 2015).

2015 - CO2 Multistore JIP with injection at Sites “A” and “B” (Shell, The

Crown Estate, Scottish Government, Scottish Enterprise and Vattenfall,

2015)/

2012 - Jin, Mackay, Quinn et al with injection sites 1 through 12 (Jin,

Mackay, Quinn, Hitchen, & Akhurst, 2012).

2011 - Goldeneye FEED with injection planned at Goldeneye via the

Goldeneye platform using CO2 from Longannet Power Station. This

project was part of the UK Government’s first CCS Competition

(ScottishPower CCS Consortium, 2010).

4.2.4 Site Database

4.2.4.1 Seismic data

The seismic data used for this study is the PGS Central North Sea MegaSurvey,

(PGS, 2015). Seismic coverage over the Captain Sandstone fairway is nearly

complete apart from data gaps to the south west of Cromarty Field and to the

north west of the Blake Field. The seismic volume is made up of several different

surveys that were merged post stack, (Figure 4-3, adapted from (Pale Blue Dot

Energy & Axis Well Technology, 2016)). The seismic data does not cover the

entire target area, but the interpreted surfaces were interpolated across areas

with no seismic data coverage.

The wavelet extraction identified the seismic data to be SEG normal polarity (i.e.

peak for positive, trough for negative acoustic impedances) and close to zero-

phase.



Figure 4-3: Time slice of the PGS MegaSurvey showing seismic coverage and extent of the interpretations in the Acorn CO2 storage site area



4.2.4.2 Well data

The well log data used in this project was obtained from the publicly available

CDA database, (www.ukoilandgasdata.com). This database contains data for

the 57 wells crossing the Captain fairway. Of these, 16 wells have the most

suitable data for the geological modelling (i.e. wireline data, Measurement While

Drilling (MWD), and core data) and were used in the Acorn site characterisation,

(Table 4-2). The location of these wells is shown in Figure 4-4 (from (Pale Blue

Dot Energy & Axis Well Technology, 2016)), along with those that were used in

the seismic interpretation. Seven of these wells were cored and their coverage

is extensive for all the Captain sands in these wells. The quality of the data was

good in general and has been reported in detail in the ETI SSAP.

An inventory of well data accessed is included in Annex 1 – Data inventory.

4.2.4.3 Core Data

The core data used in the geomechanical rock strength analysis was carried out

on wells: 14/26-1; 14/26a-6; 14/26a-7, 7A; and 14/26a-8, near the proposed

primary CO2 injection site. The depth intervals chosen for sampling for each

respective well were chosen according to number of parameters, including:

availability of core, depth, occurrence in the oil/water-leg; porosity; and general

lithological variation, as determined from hand specimen observations, gamma

ray and density wireline logs.

Well ID Wireline MWD Core

13/23b- 5 Yes Yes Yes

13/24a- 4 Yes Yes Yes



13/24b- 3 Yes No Yes


13/30 - 3 Yes No Yes





14/28b- 2 No Yes Yes





Table 4-2: Acorn CO2 storage site available well data

https://www.ukoilandgasdata.com/



Figure 4-4: Map of wells available in the Captain fairway, including these used in the interpretation (in red, blue and yellow)



4.3 Storage Stratigraphy

A stratigraphic column is shown in Figure 4-5 (Pale Blue Dot Energy & Axis Well

Technology, 2016) and a short description of the key stratigraphy is provided

below.

Upper Jurassic

The Kimmeridge Clay Formation is at the top of the Upper Jurassic, comprising

of marine hemipelagic claystones and shales, which makes it a source rock for

many hydrocarbon fields in the region. Within the Kimmeridge Clay Formation

are local deep water mass flows of the Ettrick and Burns Sand Members

Lower Cretaceous - Cromer Knoll Group

During the Early Cretaceous, deep-water turbidite sands were deposited into a

background of hemipelagic shales and marls that made up the Valhall Formation

(Copestake, et al., 2003). Some of the turbiditic sand units include the Punt,

Coracle and Captain sandstones, and the hemipelagic shales form the top, base

and lateral seal for many of these sand units.

Captain Sandstone Member - The Captain Sandstone is the primary storage

target, consisting of a sand fairway with a north west to south east orientation

and the Halibut Horst to the north. The Captain Sandstone is split into Upper

and Lower Captain Sandstones separated by the mid-Captain shale, with the

Lower Captain Sandstone having a more local deposition than the Upper

Captain Sandstone, which is a thick sand deposited along the length of the

fairway.

The thickness of the full Captain Sandstone unit can be up to 143 m (470 ft)

thick in the centre of the fairway and pinches out to the north and the south. On

average, the thickness of the full unit is 54m (180ft) and the thickness of the mid-

Captain shale (between the upper and lower sands) averages 15m (50ft) thick.

Overlying the Captain Sandstone, but immediately below the Rodby Formation

are the Carrack Formation shales, which provide an additional seal interval.

Figure 4-5: Stratigraphic Column



Rodby Formation - The Rodby Formation consists of mudstones, marls and

occasional thin argillaceous limestone beds and is a proven hydrocarbon seal

for many fields in the area, including within the Captain fairway. Across the

Acorn CO2 storage site area, the Top Rodby to Top Captain shale interval has

an average thickness of 90m (300ft) and in the ETI SSAP work it was stated as

being confidently mapped across the Captain Sandstone fairway.

Upper Cretaceous - Chalk Group

Plenus Marl and Hidra Formations – Directly overlying the Rodby Formation and

at the base of the Chalk Group are the Plenus Marl Formation (black anoxic

calcareous mudstones) and Hidra Formation (argillaceous limestones, marls

and mudstones), which are both impermeable. Across the Acorn CO2 storage

site area, the Top Plenus Marl to Top Rodby interval has an average thickness

of 70m (230ft).

Ekofisk, Tor, Hod and Herring Formations – Sitting above the Hidra is a thick

sequence (450-600m; 1500-2000ft) of limestone, which has been deposited as

pelagic chalks and is interbedded with the occasional claystone and marl bed.

Tertiary

Maureen Formation (Montrose Group) - The Maureen Formation is found

regionally within the Central Graben and usually sits above the Chalk Group. It

is comprised predominantly of amalgamated gravity flow sands interbedded with

siltstones and reworked basinal carbonates (chalk).

Lista Formation (Montrose Group) – The Lista Formation and overlying Lista

shale forms the secondary containment for the Acorn CO2 storage site. In this

area, the Lista Formation is made up of grey mudstone deposited in a marine

basin or outer shelf environment, interbedded with sandstones which have been

deposited as submarine gravity flows. In the Outer Moray Firth and Central

Graben these sandstones are assigned to the Mey Sandstone Member, with

local names as the Andrew and Balmoral sandstones.

The Lista Shale is a proven caprock for several Palaeocene fields, the closest

being the Rubie and MacCulloch Fields, (Shell, 2015).

Quaternary - Nordland Group

The thickness of the Nordland Group within the area is over 640m (2100ft) and

is formed of a thick accumulation of undifferentiated mudstones, claystones and

occasionally marls.

4.4 Seismic Characterisation

To validate the static geological model generated for ETI SSAP, (Pale Blue Dot

Energy & Axis Well Technology, 2016), the documentation of the model building

process for the Petrel project generated for the ETI SSAP project was reviewed.

This included a review of the following aspects of seismic characterisation:

• Seismic interpretation of horizons across full storage complex for the

Acorn CO2 storage site.

• Mapping of faults and structures.

• Depth conversion and geological correlation.

The depth conversion for the ETI SSAP project was carried out using the time-

depth relationships found in 12 of the wells. Of these 12, nine (13/24a-4, 13/24a-

6, 13/29b-8, 14/26a-8, 14/26a-9, 14/26b-5, 14-29a-2, 14/29a-5, 20/04b-6) also

contained sonic-logs used in the synthetic seismic trace calibration. The

synthetic seismograms allowed matching the position of different reflections to



the main surfaces interpreted in the well log data. An example of this process is

shown in Figure 4-6, (Pale Blue Dot Energy & Axis Well Technology, 2016).

Eight main horizons were interpreted from the seismic data: seabed, top Beauly

Coal, top Chalk, top Plenus Marl Formation, top Rodby Formation, top Captain

Sandstone, Base Captain Sandstone and Base Cretaceous Unconformity

(BCU). The variable and poor seismic response of the top and base Captain

made their interpretation very difficult and prevented the reliable use of auto

tracking methods.

Figure 4-6: Synthetic seismogram from the well 13/24a- 6

4.4.1.1 Seismic horizons

Table 4-3 summarises the events interpreted in the ETI SSAP project that fed

into the ACT Acorn Project. For more detail about these events, see the Captain

X Site Storage Development Plan report, (Pale Blue Dot Energy & Axis Well

Technology, 2016). In the table a peak represents an increase in acoustic

impedance and a trough represents a decrease in acoustic impedance (SEG

normal polarity).



Seismic Event Pick Amplitude Comments

Seabed Peak High Acquisition footprint seen in southeast of fairway

Top Beauly Coal Trough High Thickness variation (thicker in the east). Northwest to southeast trending channel incisions observed southeast of the Cromarty field. Outcrops at the seabed to northwest of Blake.

Top Chalk (Top Ekofisk)

Peak High Strong reflector continuous across the Captain Sandstone fairway, with the Halibut Fault offsetting the Top Chalk at the northern edge of the fairway. The Chalk has a rugose nature due to some minor faulting and erosion, which causes it to be variable.

Top Plenus Marl Trough Moderately high Continuous across the Captain sandstone fairway, thickening to the southeast and northwest, and was used as a marker to tie the wells in the ETI SSAP work. The West Halibut fault offsets this formation and it is absent in some areas of the Halibut Horst.

Top Rodby Trough Medium to high Follows similar topography as the Plenus Marl. In the ETI SSAP work, this pick was used to constrain the Captain Sandstone interpretation. Limited well control indicates the Rodby is absent on the Halibut Horst, north of the West Halibut fault.

Top Captain Sandstone

Peak, trough, zero crossing

Variable

The seismic imaging of the reservoir is hindered by a lack of acoustic impedance contrast across the interface between the Rodby/Carrack Shale and the Captain Sandstone, plus the existence of a multiple caused by the overlying Chalk.

Due to the variable nature of the Top Captain seismic response, it was interpreted in the ETI SSAP using the Top Rodby Horizon pick, Top Captain Sandstone well picks, seismic character and Shell’s sand pinch out edge polygon to help guide the interpretation.

Base Captain Sandstone

Mainly peak (can also be trough or zero-crossing)

Variable Challenging to interpret and so a Captain Sandstone depth thickness map (isochore) from the wells was converted to time to give a time thickness map (isochron), which was added to the Top Captain time map to give an approximate Base Captain time map to help guide the interpretation.

Base Cretaceous Unconformity

Trough Moderate to high The Base Cretaceous unconformity is the top of the Kimmeridge Clay formation. The West Halibut and Captain Field Boundary Faults offset it.

Table 4-3: Summary of seismic horizons interpreted in the ETI SSAP work



Figure 4-7: Top Captain Sandstone two-way time map and faulting



4.4.1.2 Faulting

The east-west trending Captain Fault separates the Captain Sandstone fairway

from the Captain oil field to the north of it, (Figure 4-7). The seismic interpretation

for the ETI SSAP project indicates that the West Halibut Fault appears to extend

this limit to the southeast with the Captain Sandstone fairway lying to south of

the fault in the downthrown hanging wall. Uncertainty exists on whether the

Captain Sandstone extends right to the West Halibut Fault or pinches out before.

This is due to the poor seismic of the Top Captain. Most of this section is

summarised from the Captain X SDP (Pale Blue Dot Energy & Axis Well

Technology, 2016).

Between Blake and Goldeneye there are nine wells on the southern side of the

fault with no Captain Sandstone which confirms that the sandstone is absent

and must pinch-out before reaching this fault. At the Blake oil field, the operator

interprets the Captain to extend to the West Halibut Fault and the fault is likely

to be sealing here, due to the presence of trapped oil. West of the small oil

discovery (Tain - northwest of Blake), the amount of offset on the Captain fault

is seen to decrease and it is likely the Captain Sandstone is juxtaposed against

older Triassic and Jurassic units here which contain sandstones, presenting

increased risk of lateral containment.

Guariguata-Rojas and Underhill (2017) interpreted several west southwest to

east northeast striking normal faults cutting through the Captain Sandstone

saline aquifer in the north western area about 100km from the Acorn Phase 1

injection site. The authors state these could present a risk to any potential CO2

storage in the studied region. As noted in Section 4.2.3, CO2 storage in this north

western region of the Captain Aquifer is unlikely due to the shallow nature of the

Captain Sandstone.

The Captain Sandstone fairway contains several 4-way dip closed and 3-way

dip plus stratigraphic pinch out structures which provide the trapping

mechanisms for four significant Captain Sandstone hydrocarbon accumulations,

Blake, Cromarty, Atlantic and Goldeneye. The West Halibut Fault extends

upwards into the shallow Tertiary section but does not reach the seabed.

Between Atlantic and Tain the Lista (secondary cap-rock) is offset by this fault.

Further to the west it is not clear if the Captain Fault extends to the seabed due

to poor shallow seismic data quality.

Captain Sandstone is not present on the Halibut Horst. Due to the poor seismic

imaging of the Captain Sandstone, faulting may be more significant than

currently identified. However, the Top Rodby is a reliable seismic marker and

this is the top of the primary seal. Top Rodby has potential small-scale features,

running in a north west to south east orientation that could be due to seismic

artefacts or to real faults. These are very minor faults that do not breach the

Rodby/Carrack primary seal or suggest the presence of potential barrier to the

flow of CO2 within the Captain Sandstone, and thus they were not included within

the ETI SSAP Static Model.

The Top Chalk features numerous lineaments mainly orientated north west to

south east. Most of these lineaments appear to be erosional in nature although

some are probably due to faulting. This faulting does not extend far into the

overburden and they do not appear to be connected with the small scale deeper

faulting within the Captain Sandstone and Top Rodby shale. The overburden

model includes the West Halibut Fault, but no faults were included in the ETI

SSAP Captain Sandstone Fairway model.



4.4.1.3 Depth conversion method

In the ETI SSAP project, the depth conversion of the interpreted events was

reported as challenging because of rapid lateral velocity changes in the

overburden, particularly related to lithology variations within the Tertiary section

and rugosity of the Top Chalk surface (which is the top of a high velocity interval).

In the ETI SSAP study, each surface was depth converted following different

steps, outlined in Figure 4-8, (Pale Blue Dot Energy & Axis Well Technology,

2016). A single layer depth conversion method was used from Mean Sea Level

(MSL) down to Top Rodby using an average velocity map (Step 1). This is similar

to the method Shell used for their Captain Sandstone fairway depth conversion,

(Shell, 2015). The Top Rodby depth surface was then used as a depth reference

surface and the rest of the layers in Figure 4-8. These were depth converted by

multiplying the different isochrons (time difference surfaces between different

layers) by a constant velocity, obtained from well data from the surrounding

areas.

The steps described fully in (Pale Blue Dot Energy & Axis Well Technology,

2016) are:

• Step 1 - MSL to Top Rodby using single layer depth conversion

• Step 2 - Top Rodby to Top Captain

• Step 3 - Top Captain to Base Captain

• Step 4 - Top Rodby to Base Cretaceous Unconformity

• Step 5 - Seabed

• Step 6 - Seabed to Top Beauly Coal

• Step 7 - MSL to Top Chalk

• Step 8 - Top Plenus Marl

The sensitivity of the depth conversion method was tested by manual

modification of the Top Captain depth surface, which was then used as a

sensitivity test within the dynamic reservoir modelling work. Here, whilst

absolute depth control is only significant for well placement, the detailed shape

of the Top Captain Sandstone surface was found to be a key control on the

lateral migration of the injected CO2 plume. An awareness of the seismic

uncertainty in the definition of this surface must be maintained throughout

development planning.

Figure 4-8: Depth conversion summary



4.5 Geological Characterisation

To validate the static geological model generated for ETI SSAP (Pale Blue Dot

Energy & Axis Well Technology, 2016), the model-building process was

reviewed. The geological characterisation carried out for the ETI SSAP included:

• Formation evaluation from logs.

• Static model build (geocellular).

The assumptions made during the ETI SSAP project have been reviewed and

considered. Overall the methodology followed is robust, representing good

practice and the results arising from the work are generally applicable and

relevant to the Acorn CCS Project.

4.5.1 Formation Evaluation

The formation evaluation process in the ETI SSAP project involved the use of

wireline logs and core data extracted from the CDA database. The petrophysics

study used as a reference a previous report for the Blake Field (Colley, 1999)

for five wells within the Captain fairway. This information was used to check the

validity of the results of the study by comparing them to the results in the report.

A summary of the petrophysical workflow used is shown in Figure 4-9. The

results were used to build the static model, (Pale Blue Dot Energy & Axis Well

Technology, 2016).

A summary of the primary store, primary caprock, secondary store and

secondary caprock formations is described in Table 4-4.

Figure 4-9: Petrophysical workflow



Subsurface Unit Aspect Summary

Primary store: Captain Sandstone Member (Cromer Knoll Group)

Depositional model

Sand rich deep water marine turbidite system deposited as a 5-10km wide ribbon of sand along the southern edge of the Halibut Horst.

Excellent rock quality: net to gross ratio >75%; average porosity of 25% (max 30%); average permeability of 1400mD, often >2000mD.

4 lithostratigraphic zones: A, C, D, E (bottom to top). Captain A: massive medium grained sandstone, present at the site location; Captain C: heterogeneous with mudstone and shale, but not full sealing anticipated at the site; Captain D: main reservoir unit for the hydrocarbon fields in the Captain Sand Fairway; massive sandstone laterally extensive.

Reservoir Connectivity

No significant lateral baffles or barriers along the fairway which might result in compartmentalisation.

Geomechanics No significant issues related to drilling risk, fracturing risk or sand failure risk detected.

Geochemistry Injection of CO2 into the Captain X area is not expected to lead to any significant risk of loss of strength or significant change in reservoir quality.

Primary caprock

(Carrick and Rodby Fms., and Chalk Group)

Depositional model 90m shale from Top Captain to Top Rodby.

Secondary seal from shales and mudstones of the Valhall and Carrack Formations.

Rock and fluid properties

Core data available. Effective seals in nearby hydrocarbon fields.

Geomechanics

No significant issues related to drilling risk, fracturing risk or sand failure risk were found during the ETI SSAP work.

The ACT Acorn rock laboratory testing (Section 4.7.1.4) concluded that the Captain Sandstone is very friable and poorly cemented and so fracturing will likely be accompanied by extensive disaggregation of the wellbore. Disaggregation may hamper injection and so keeping fluid injection pressures below the fracture gradient will be a requirement.

Geochemistry The calcareous, clay rich Rodby Formation and equivalent caprocks are unlikely to be affected in a way that increases permeability. Rodby Formation seal failure is, therefore, unlikely to be induced by mineral reactions with the CO2.

Secondary store (Maureen and Mey Fms.)

Reservoir and seal geology

Palaeocene sandstones have excellent reservoir quality and good regional connectivity; porosities up to 35% and Darcy permeabilities.

Lista Formation provides the secondary seal; 30m thickness.

Rock and fluid properties

Full characterisation required.

Table 4-4: Summary of primary and secondary storage formations



4.5.2 Static Modelling

As part of the site characterisation works in the ETI SSAP project, three static

models were generated:

Fairway model - Semi-regional model covering over 800km2 across

the Captain Fairway, used to select the final site and understand the

connectivity to the nearby hydrocarbon fields. It includes from Top

Rodby to Base Captain formations, and the Halibut Horst fault, in a

grid of 16.1 million cells. The upscaled version of this Fairway model

was used in the dynamic reservoir simulations for the Acorn CO2

Storage Site.

Injection Site model - Reduced section from the Fairway model,

used as basis for building the reservoir simulation models in the ETI

SSAP project.

Overburden model - Used to describe the overburden geology up

to the seafloor and determine containment risk issues.

The Fairway model included:

• The static modelling of porosity (using the available interpreted PHIE

log) and permeability (using the available core data and correlated

to the modelled porosity) modelling for the Captain Sandstone zones

(Captain A, C, D & E). Modelling results are summarised in Table 4-5

(Pale Blue Dot Energy & Axis Well Technology, 2016). The average

modelled porosity within the main Captain D sand is 27%, the same

as the average from well logs for the Captain D. The average

modelled within the Captain A is 24%. The assumed porosity of the

caprock is zero. In the core data within the reservoir, permeability

shows strong positive correlation with the porosity. Whilst the vertical

permeability is less than the horizontal, no barriers to vertical flow

are anticipated within the Captain D interval. The deeper Captain A

sand is separated from the Captain D sand by the shaley Captain C

interval. This creates a significant internal pressure baffle, but even

the Captain A sands have been depleted by production in the

Captain D sands to some degree.

• Facies logs were calculated using Vshale, Density and Sonic logs

for the 16 representative wells, plus Vshale calculation in an extra

16 wells. The facies logs from the 32 wells were used to control the

facies modelling. Facies modelling was then performed in all Captain

zones using the Sequential Indicator Simulation (SIS) across the

entire area, and using the sand, shale and cement proportions

resulting from the well data. Net to gross trend maps derived from

well data were used to control the lateral proportion of sand/shales.

The available well data indicate that the edges of the Captain

Sandstone fairway can sometimes have reduced net to gross, but

this has little to no impact in the capacity or containment due to the

small thickness of these areas. Results from the facies modelling are

summarised in Table 4-6, (Pale Blue Dot Energy & Axis Well

Technology, 2016).

• The bulk rock and pore volumes of the different zones were

calculated as part of the static modelling Table 4-7, (Pale Blue Dot

Energy & Axis Well Technology, 2016).

The poor seismic imaging of the Top and Base Captain Sandstone horizons

adds substantial uncertainty to the models, especially in areas with little or

absent well control, but the results are in line with other experiences, in particular

regarding the hydrocarbon activities in the region.



Zone Average

porosity (%) Average horizontal permeability (mD)

Average vertical permeability (mD)

E 21.9 274 219

D 26.6 1753 1402

C 21.4 634 507

A 24.1 704 563

Table 4-5: Fairway model porosity and permeability modelling results

Zone Sand (%) Shale (%) Cement (%)

E 52.8 42.8 4.4

D 82.4 15.9 1.7

C 28 68.18 3.83

A 76.8 18.5 4.7

Table 4-6: Modelled facies proportions

Zone Bulk volume (x 106 m3) Pore volume (x 106 m3)

E 2,081 295

D 24,458 5,935

C 12,204 2,527

A 38,743 8,757

Table 4-7: Gross rock and pore volumes for the Captain Fairway model

4.6 Injection Performance Characterisation

Phase 1 of the Acorn CCS Project will inject approximately 200kT of CO2 per

year over 15 years reaching a total amount of injected CO2 of 4.2MT. The rate

of CO2 modelled in the injection performance characterisation is that which is

currently available at the St Fergus site and ramps up from 200kT/yr for the first

three years, to 281kT/yr thereafter. This CO2 will be used to kick-start the project

as a scalable development.

Additionally, the Acorn CCS Project will seek opportunities to store additional

CO2 as part of a broader regional decarbonisation plan. This will increase the

injection rate and the overall scale of the storage project once Phase 1 has

commenced. Additional CO2 storage beyond the 200kT/yr is referred to as

Phase 2 and 3. The three phases and their dynamic modelling cases are

summarised below and discussed in Section 4.6.5:

• Phase 1 – Minimum Viable Development Case (Scenario 1):

~200kT/yr from part of the current St Fergus emissions, injected via

one subsea injection to an injection site in between the Atlantic and

Cromarty depleted fields, starting in 2023.

• Phase 2 – 64MT Case (Scenario 2): Emissions include those in the

Scenario 1, plus those from a potential build-out scenario, including

CO2 captured from hydrogen generation and importation of CO2 via

Peterhead Harbour (from shipping), with a maximum injection of

2.7MT/yr.

• Phase 3 – 152MT Case (Scenario 3): A supply rate capped at

5MT/yr (259mmscfd) via four injection wells at several injection sites,

including one near the Goldeneye depleted gas field, and brine

production for pressure management. Emissions include those in the



Base Case, plus those from a potential build-out scenario, including

CO2 captured from hydrogen generation, importation of CO2 via

Peterhead Harbour (from shipping) and importation of Grangemouth

emissions via the Feeder 10 pipeline to St Fergus.

This chapter describes the well performance modelling for Phase 1 (well design

for subsequent phases will be determined later) and the well placement strategy

and dynamic modelling for Phases 1, 2 and 3.

4.6.1 Well Performance Modelling

The purpose of well performance modelling is three-fold:

to select a suitable injection tubing size;

to evaluate some of the factors that may limit injection performance;

and

to compare this performance with injection targets.

The results from well performance modelling feeds in to the reservoir

engineering in the form of “lift curves”, which are then used to define well

performance in the reservoir simulation models.

The well engineering aspects of the Acorn CO2 Storage Site were delivered by

Axis Well Technology, (Axis Well Technology, 2017).

4.6.1.1 Methodology

Well modelling was carried out using Petroleum Experts’ Prosper software. At

this early stage full details of the planned well and its anticipated trajectory were

not yet available and so modelling assumptions were made, which are

summarised in the sections below. They are based on a previous study

conducted on the Captain X area and are subject to change as the Acorn CCS

Project proceeds. Flow rates from 0.1 to 2MT/yr were modelled for a single

subsea injection well.

4.6.1.2 PVT

In line with Petroleum Experts’ recommendations, the Pressure, Volume and

Temperature (PVT) in Prosper was modelled using the Equation of State option

with Peng Robinson as the equation of state. The CO2 density correction

implemented by Petroleum Experts was enabled for modelling CO2 injection.

The injection fluid was modelled as 100% CO2 in compliance with project CO2

composition limits. The PVT description used is shown in Table 4-8 below, (Axis

Well Technology, 2017).

Property Units Value

Critical Temperature °C 30.98

Critical Pressure bara 73.77

Critical Volume m3/kg.mole 0.0939

Acentric Factor (-) 0.239

Molecular Weight (-) 44.01

Specific Gravity (-) 1.53

Boiling Point °C -78.45

Table 4-8: PVT definition

CO2 physical properties that strongly affect tubing flow and hence transport are

density (ρ) and viscosity (μ). To test the validity of the Prosper PVT model,

predicted in-situ CO2 densities and viscosities were compared with pure-

component CO2 properties which were calculated using the thermophysical

properties of Fluid Systems from the National Institute of Standards and



Technology ((NIST), 2018). Comparisons were carried out for a range of

temperatures (4-100°C) and pressures (5-450bara) with the following results:

• Density differs from the NIST calculated value by a maximum of

1.1% with an average of 0.3%.

• Viscosity differs from the NIST calculated value by a maximum of

14.3% with an average of 7.3%.

These results were considered adequate for the purposes of this study.

4.6.1.3 CO2 impurity sensitivity

The well and tubing design work assumed that the CO2 will be contaminant free.

In practice, however, a small amount of other gases may be present in the

injection gas. The main effect of this is that the phase envelope, which simplifies

to a line in the case of pure CO2, has a two-phase region and so the minimum

injection pressure required to ensure a single-phase liquid injection has to be

increased (Figure 4-10). For small amounts of impurities this shift is minor, but

in order to simulate the effect of possible contamination a 10% safety region has

been defined around the pure CO2 phase envelope and this region has been

avoided during the well design work.

A further effect of the presence of contaminants is that the fluid viscosity and

density will change, which influences the flow behaviour. However, this should

be minor for insignificant contaminant content.

Figure 4-10: Effect of impurities on the phase envelope

4.6.1.4 Wellhead and downhole equipment

The subsea well head has been assumed to be located on the seabed, with

water depth assumed to be 115m. To evaluate a suitable tubing size for the

subsea well, a set of sensitivity cases on downhole equipment were defined.

4.6.1.5 Wellbore trajectory

The detailed wellbore trajectory plan for the subsea well had not been finalised

at the time of wellbore modelling and so a synthetic trajectory was constructed

as follows:

• The well was assumed to be vertical between the sea bed and 600m

above the top of the Captain Sandstone, assumed to be at 2015m

TVDSS.

• The well was then kicked off to 60 degrees through the reservoir at

a build rate of 3 degrees per 30m.



4.6.1.6 Temperature model

The Prosper software offers three heat transfer models: rough approximation,

improved approximation and enthalpy balance.

The rough approximation model estimates heat transfer and hence fluid

temperatures from background temperature information, an overall heat transfer

coefficient and user-supplied values for the average heat capacity (Cp value) for

oil, gas and water. In an application in which accurate temperature prediction is

required, this model is considered too inaccurate, especially since it neglects

Joule-Thomson effects, which can be essential in predicting the behaviour of a

CO2 injector. As such this model was not considered.

The full enthalpy balance model performs more rigorous heat transfer

calculations (including capturing Joule-Thomson effects) and estimates the heat

transfer coefficients as a function of depth from a full specification of drilling

information, completion details and lithology. However, at the current stage in

the design cycle many of the input parameters are still unknown e.g. mud

densities.

For this reason, the improved approximation model was chosen for this work.

The sole difference between this model and the full enthalpy balance model is

that the user supplies reasonable values for the heat transfer coefficient rather

than having them estimated from the completion information and lithology. In

line with Petroleum Experts recommendations, a uniform heat transfer

coefficient of 3BTU/h/ft2/F (17.04W/m2/K) was chosen.

For the modelling, a seabed temperature of 6°C was assumed and the required

background temperature gradient was defined as 6°C at the seabed and

reservoir temperature at top perforation depth.

Since it is anticipated that CO2 is delivered to the wellhead through a long (78km)

delivery pipeline, the temperature of the injection fluid at the wellhead was

assumed to be at the seabed temperature. Little to no seasonal variation is

expected at this water depth and latitude in the North Sea.

4.6.1.7 Reservoir data and Inflow Performance Relationship (IPR)

Reservoir and field parameters were taken from the ETI SSAP study. The inflow

performance relationship (IPR) modelling was based on estimates which are

summarised in Table 4-9 and Table 4-10, (Axis Well Technology, 2017).

Parameter Unit Low Best Estimate High

Formation Top Depth - Datum

mTVDSS (ft TVDSS)

2015 (-6611)

Formation Gross Thickness

m (ft) 18

(60) 21 (70) 26 (85)

Reservoir Pressure at Datum

bara (psia) 206 (2984)

Reservoir Temperature at Datum

°C (°F) 69 (157)

Permeability mD 700 1350 2500

Permeability Anisotropy (Kv/Kh)

- 0.4 0.65 0.9

Formation Water Salinity

ppm 56,600

Table 4-9: Captain reservoir data



Parameter Unit Low Best

Estimate High

Water Depth m (ft) 115 (377)

Pressure Gradient bar/m (psi /ft)

0.102

(0.451)

Geothermal Gradient °C/100m (°F/100ft)

3.4 (1.87)

Table 4-10: Captain field and well data

Using these data from the previous tables, three IPR models were defined in

Prosper to represent high, medium and low reservoir performance. These

models are summarised in Table 4-11 below, (Axis Well Technology, 2017).

Parameter Unit Low Medium High

IPR Model n/a Jones

Permeability mD 700 1350 2500

Reservoir Thickness

ft 60 70 85

Drainage Area acres 1213

Dietz Shape Factor (-) 31.6

Perforation Interval ft 60 70 85

Skin (-) 20 10 0

Table 4-11: Captain IPR input data

4.6.1.8 Tubing selection

Injection Limits

Pressure and temperature limits on injection operations have been defined and

have been summarised in Table 4-12 below (Axis Well Technology, 2017).

Parameter Unit Value

Fracture Limit at Top Perforation Depth bara (psia) 283 (4105)

Minimum Fluid Temperature at Perforation Depth °C 0

Maximum Pipeline Delivery Pressure at Wellhead bara (psia) 160 (2321)

Table 4-12: Injection pressure limits

It should be noted that:

• The fracture limit at top perforation depth has been derived using a

fracture gradient of 0.16bar/m (0.69psi/ft) and a top perforation depth

of 2015m (6611ft) TVDSS. An uncertainty factor of 0.9 was applied

to the calculated fracture pressure.

• The minimum fluid temperature at perforation depth exists to prevent

formation water from freezing during injection.

Sensitivity Cases

The sensitivity cases considered are summarised in Table 4-13 below. The

injection temperature at the well head is 6°C for all cases. The high, medium

and low reservoir cases are as described in the section above.

Single and dual completions were considered for the Phase 1 well. Note, that a

95/8‘’ casing was assumed and a dual 4½‘’ completion is incompatible with this



choice and was therefore not considered. For dual completions it was assumed

that only a single string was open for the low-pressure injection case; for the

high-pressure injection case both strings were considered open.

The minimum tubing head pressure (THP) (44.5bara) is the minimum pressure

required to ensure single phase liquid injection throughout the tubing. The

maximum tubing head pressure (160bara) represents the maximum pipeline

delivery pressure. Not all tubing choices can achieve injection at the lower

injection pressure. Where this is the case the minimum pressure for injection

has been calculated.

Table 4-13 summarises the rates achievable for the various sensitivity cases

and Figure 4-11 provides a graphical representation of the data in the table.

Prosper uses volumetric flow rates and the conversion to mass flowrate is based

on a density of 1.87kg/m3 at standard conditions. The calculated figure is

highlighted in red where the minimum tubing head pressure needed to be raised

to achieve injection.



Case Reservoir Case Completion Tubing Size Max and Min THP (bara) Rate (MMscf/d) Rate (MMte/yr)

1 High Single 4½’’ (12.6 ppf) 44.5 25.9 0.50

160 125.4 2.43

2 Medium Single 4½’’ (12.6 ppf) 44.5 23.1 0.45

160 123 2.38

3 Low Single 4½’’ (12.6 ppf) 44.5 14.2 0.27

160 115.9 2.24

4 High Single 3½’’ (9.2 ppf) 44.5 9.6 0.19

160 60.8 1.18

5 Medium Single 3½’’ (9.2 ppf) 44.5 7.6 0.15

160 60.3 1.17

6 Low Single 3½’’ (9.2 ppf) 45.3 7.5 0.14

160 58.7 1.14

7 High Single 27/8’’ (6.5 ppf) 45.75 4.7 0.09

160 35.6 0.69

8 Medium Single 27/8’’ (6.5 ppf) 45.95 5 0.10

160 35.4 0.69

9 Low Single 27/8’’ (6.5 ppf) 46.5 5 0.10

160 34.8 0.67

10 High Dual 2 * 3½’’ (9.2 ppf) 44.5 9.6 0.19

160 120.8 2.34

11 Medium Dual 2 * 3½’’ (9.2 ppf) 44.5 7.6 0.15

160 118.6 2.30

12 Low Dual 2 * 3½’’ (9.2 ppf) 45.3 7.5 0.14

160 112.3 2.17

13 High Dual 2 * 27/8’’ (6.5 ppf) 45.75 4.7 0.09

160 71.4 1.38

14 Medium Dual 2 * 27/8’’ (6.5 ppf) 45.95 5 0.10

160 70.5 1.36

15 Low Dual 2 * 27/8’’ (6.5 ppf) 46.5 5 0.10

160 68 1.32

Table 4-13: Rates achievable by case for minimum and maximum tubing head pressure



Figure 4-11: Rates achievable by case for minimum and maximum tubing head pressure

Figure 4-12 to Figure 4-14 show the pressure and temperature behaviour along

the tubing, plotted as pressure versus temperature for relevant tubing sizes and

well head injection pressures. The graphs also show the phase boundary with

an upper and lower safety limit and the various pressure and temperature limits.

Figure 4-15 shows a pressure and temperature versus depth profile for a typical

injection case.

Figure 4-12: Pressure / temperature profiles – 4½’’ tubing – min/max tubing head pressure

Figure 4-13: Pressure / temperature profiles – 27/8’’ tubing – min/max tubing head pressure

0

0.5

1

1.5

2

2.5

3

Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8 Case 9 Case 10 Case 11 Case 12 Case 13 Case 14 Case 15

Ra

te (

MM

te/y

r)

Injection Rates Achievable

0

50

100

150

200

250

300

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42

Pre

ssu

re (b

ara)

Temperature (deg C)

Pressure / Temperature Gradients

Case 1a

Case 2a

Case 3a

Case 1b

Case 2b

Case 3b

Phase Envelope

Phase Envlope Upper

Phase Envelope Lower

Fracture Pressure Limit

THP Limit

0

50

100

150

200

250

300

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44

Pre

ssu

re (b

ara)

Temperature (deg C)


Case 7a

Case 8a

Case 9a

Case 7b

Case 8b

Case 9b

Phase Envelope

Phase Envlope Upper



THP Limit



Figure 4-14: Pressure / temperature profiles – dual 27/8’’’tubing – min/max tubing head pressure

Figure 4-15: Case 11b (maximum THP) – pressure and temperature v depth plot

The results shown in Table 4-13 and Figure 4-12 to Figure 4-15 can be

summarised as follows:

• Achieving injection rates ranging from 0.1MT/yr to 2.0MT/yr over

injection field life with a single completion design will be challenging.

In the modelling, only the dual 3 ½’’ and the 4 ½’’ tubing can achieve

a target rate of 2MT/yr under initial reservoir conditions. However,

neither provide an option for the low range of 0.1MT/yr.

• Note that it is not currently possible to model dual completions

explicitly in Prosper. A workaround is provided, which relies on the

user specifying a single string and then providing a multiplier for that

string that defines the fraction of total flow going through it. Prosper

then grosses up this flow contribution to total flow for all remaining

calculations, (e.g. the IPR calculations). For a dual completion

consisting of two identical tubing strings the multiplier is easy to

define as 0.5. For mixed dual completions this is more complex and

Petroleum Expert's GAP software, in which dual completions can be

defined and evaluated rigorously, should be used. It is hence

recommended that a full evaluation of a dual completion is

performed in GAP.

• Though not explicitly modelled, a dual completion consisting of a

27/8’’ tubing string and a 4½’’ does appear to achieve the target

injection range. The combined injection rate will be less than the sum

of the two individual strings (3.06MT/yr), but will easily achieve the

target 2MT/yr.

• Note that a dual completion consisting of a 27/8’’ and a 4½’’ tubing

string is not commonly run and will provide challenges for well design

(potentially requiring an increase in casing size from 95/8’’to 10¾”

0

50

100

150

200

250

300

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44

Pre

ssu

re (b

ara)

Temperature (deg C)


Case 13a

Case 14a

Case 15a

Case 13b

Case 14b

Case 15b

Phase Envelope

Phase Envlope Upper



THP Limit

0.0 5.0 10.0 15.0 20.0 25.0 30.0 35.0 40.0 45.0 50.0

0

1000

2000

3000

4000

5000

6000

7000

8000

0

1000

2000

3000

4000

5000

6000

7000

8000

0.0 50.0 100.0 150.0 200.0 250.0

Temperature (deg C)

Me

asu

red

De

pth

(ft

)

Pressure (bara)

Case 11b (Rate = 118.6 MMscf/d)

Pressure

Temperature



and modifications to existing subsea tree designs) but is considered

technically achievable.

• Beyond the inability to achieve the extended target range of injection

rates in most cases none of the tubing options considered violate

any of the restrictions specified, including:

o Temperature limits: a fluid temperature of 0°C is not reached

by any of the scenarios considered.

o Fracture Limits: this limit is not reached by any of the cases

considered.

o Phase changes to the gas phase are avoided (though the

fluid may be supercritical at the injection point for some low

rate cases, which is not considered an issue).

Based on the results of the modelling, a well with a dual tubing of 27/8’’ and 4½’’,

with a 95/8’’ casing (although noting that this may potentially require an increase

in casing size to 10¾”) has been proposed for Phase 1 of the Acorn CCS Project.

The Phase 1 well design will be based on 95/8’’ casing for the purposes of this

study and investigated further during the next phase of work. Well design for

subsequent phases will be undertaken at the appropriate time and will likely be

for a single bore design.

4.6.1.9 Vertical lift performance curve generation

Vertical lift performance (VLP) curves were generated for three different

completion options:

• 27/8’’ tubing string

• 3½’’ tubing string

• 4½’’ tubing string

A well with a dual tubing of 27/8’’ and 4½’’ has been proposed for Phase 1 of the

Acorn CCS Project. Hence, results of the 3½’’ tubing string modelling are not

presented here. To allow sensitivities to injection pressure limits and other

quantities to be run in Eclipse without extrapolation, the curves were generated

for pressures and rates that were adjusted to Eclipse requirements.

Input parameters were as follows:

For the 27/8’’ single string:

• Tubing Head Pressures: 44.5bara (645psia) to 172.4bara (2500psia)

in 10 steps

• Gas Rates: 2.5MMscf/d to 50MMscf/d in 20 steps

For the 4½’’ single string:

• Tubing Head Pressures: 44.5bara (645psia) to 172.4bara (2500psia)

in 10 steps

• Gas Rates: 2.5MMscf/d to 180MMscf/d in 20 steps

The performance envelopes of the well are shown in Figure 4-16 and Figure

4-17. It was ensured that, for all points shown on the curves, dense phase

injection was maintained throughout the tubing and that the temperature limit of

0°C was not reached.



Figure 4-16: Performance envelope - 27/8’’ single tubing string

Figure 4-17: Performance envelope - 4½’’ single tubing stringInjectivity and Near Wellbore Issues

The effects of long term CO2 injection into a sandstone reservoir are not yet fully

defined. Despite some experience of the process gained in the industry, the

reservoir, injection profiles and development scenarios are different for each

CO2 storage site. The reservoir rock is subject to pressure and thermally induced

stresses, applied in sometimes random patterns (cyclic stressing from variations

in supply conditions). These stresses can lead to rock failure or damage to the

rock fabric and therefore permeability changes. Interaction of CO2 with in-place

reservoir rock and fluids may also alter the ability of the rock to conduct fluids.

Some of the more recognised issues are discussed below, along with their effect

on the storage potential of the Acorn CO2 storage site.



4.6.1.10 Halite

When CO2 is injected into formations containing saline brine, most of the brine

will be pushed away from the wellbore by the injected CO2. However, some brine

will remain in pores and adhering to rock matrix. As CO2 and water are miscible,

CO2 will absorb the water. However, the salt in the brine is not soluble in CO2,

thus precipitating the salt out of solution as halite. In other words, the near

wellbore is dehydrated (water removed), leaving the salts behind. If all the water

is removed, the total insoluble (in CO2) content of the brine will be deposited.

The volume of solid salt crystals produced depends on brine salinity, residual

brine volume (left after the ‘sweep’’ of CO2), interactions at the CO2 flood front

and the propensity of the brine to re-saturate the near wellbore during shut-in

periods. Capillary pressure also plays a part in re-saturation but is likely to be

masked by CO2 buoyancy effects (CO2 rising in the fluid column, allowing brine

to recharge from below). As the re-saturation will depend on the number and

length of shut-ins, predictions of actual salt precipitation volumes are not

possible at this stage.

However, on the assumption from the ETI SSAP study that the Captain brine is

relatively low salinity (56,600ppm – see Captain X Storage Development Plan

Section 3.6.3.5 for a discussion about this number, (Pale Blue Dot Energy &

Axis Well Technology, 2016), there is a possibility that near wellbore

permeability will remain unchanged by dehydration, or possibly enhanced. With

connate water saturations assumed to be approximately 30% in the Captain,

removal of this water will significantly increase the pore volume of the rock in the

near wellbore region. Even if all halite (salt) was precipitated, less than 2% of

the pore volume would be occupied with halite.

Halite will only become an issue if the halite crystals are mobilised and form

bridges / plugs in the matrix rock pore throats. Given the large injection area

(sand face) planned in the Captain wells, fluid velocity through the matrix will be

low and mobilisation may not occur. Alternatively, if the halite concentration is

small and the crystals are small with respect to pore throat size, salt crystals

may be mobilised away from the wellbore and deposited in low velocity zones.

At a distance from the wellbore they no longer pose a significant risk to injectivity

(diffusion effect).

Considerable uncertainty remains surrounding the actual halite risk to injectivity

in a low saline system such as Captain, although lessons could be learned from

Equinor’s Snøhvit project. Injectivity in Snøhvit was lower than expected, with

pressure building up earlier. Salt precipitation was suspected, and lab tests

appeared to support this. However, the effect was determined to be relatively

minor in horizontal cores, with a conclusion that limited reservoir heterogeneities

and limited volume were the primary culprits, although halite and pore filling fines

may result in some injection efficiency reductions. Salinity at Snøhvit is more

than twice as high as Captain, at ~ 168,000ppm (Pham, Maast, Hellevang, &

Aagaard, 2011), and permeability was an order of magnitude lower.

The effect of halite precipitation can be mitigated by ‘washing’ the near wellbore

with fresh water. The wash water dissolves the salt and carries it away from the

near wellbore region, where the effects of permeability reduction have most

impact. However, as the halite risk for Captain is currently considered to be low,

the addition of wash water facilities for these operations is not considered

practicable for the subsea well. A residual risk therefore remains.

4.6.1.11 Thermal fracturing

The CO2 stream injected into the Captain formation is colder (less than 20oC

depending on input assumptions) than the modelled ambient reservoir

temperature (52 to 87oC, with a best estimate of 62oC). This reduction in



temperature is limited to a region close to the wellbore. A drop in temperature

will influence the near wellbore stresses and will make rock more liable to

fracture (tensile failure). The effect this has on the fracture pressure has not

been investigated in this study. However, as the magnitude of temperature drop

is low and restricted in extent, it is not expected to be problematic in the Captain

Sandstone.

The applied safety margin (10%) on fracture pressure and a stand-off from

injection point to cap rock will provide some security with respect to cap rock

fracturing and containment issues. Furthermore, the effect of increasing fracture

pressure with increased pore pressure (pore pressure increases throughout the

injection period) has not been taken into consideration when defining fracture

limits and this is likely to have a countering effect to the potential for thermal

effects on fracture pressure. It is recommended that these issues be reconciled

in the next development stage.

4.6.1.12 Sand failure

As with water injection wells, there is a potential for sand failure in CO2 injection

wells. The principal causes of this are similar:

• Flow back (unlikely to occur in CO2 injection wells without some form

of pre-flow pad);

• Hammer effects during shut-in;

• Downhole crossflow during shut-in (from and to formation zones with

different charging profiles);

• Well to well crossflow during shut-in (if individual wells are charged

to different pressures and surface valves are left open, allowing

cross-flow via the injection manifold).

The effects of sand failure are that near wellbore injectivity can be reduced

(failed sand packs the perforation tunnels or plugs the formation) or that the well

can be filled with sand (reducing injectivity and potentially plugging the well

completely).

The pre-requisite for sand failure is that the effective near wellbore stresses,

because of depletion and drawdown, exceed the strength of the formation. The

in-situ stresses at the wellbore wall, while predominantly a function of the

overburden and tectonic forces, will vary dependent on the trajectory (deviation

and azimuth) of the proposed wellbore. So, while field wide values can be

generalised, the specifics of the well can impact on the required conditions for

failure of the formation.

The ETI SSAP study applied a generic critical drawdown process to selected

well strength logs to provide a guide for the pressure drops required for failure

in a CO2 injector. The study concluded that the Captain sandstone was a

consolidated formation with limited weak zones (due to uncertainty in rock

strength calibration). However, given that the Captain oil field has suffered sand

production (albeit from shallower and weaker sands) and that Goldeneye has

recommended sand control, the base case development recommendation will

be stand-alone sand screens (SAS). To provide some offset from the caprock

penetration point to the first injection point through the sand screens, it is

recommended that the 95/8’’ shoe is set at least 40ft into the top Captain

Sandstone, and that a further joint of blank pipe with annular isolation is set

above the screens.

More detailed work will be carried out during Concept and FEED.



4.6.1.13 Near wellbore thermal effects

In this section, the thermal effects due to CO2 expansion near the wellbore are

further discussed. Compared to typical hydrocarbon gases, CO2 is more

compressible and so on injection, there may be a pressure drop around the

injection well as the CO2 is displaced into the formation, which may cause rapid

expansion of CO2, lowering its temperature. If the temperature drop is

significant, micro fractures could be created within the formation.

A thermal 1-D radial simulation scenario, using a broad range of properties taken

from the Captain Sandstone, was undertaken. Figure 4-18 (top) shows the

temperature and pressure profile after 100 days of CO2 injection and

displacement away from the injection well. A temperature front can be identified

within the system in that the temperature sharply increases from the injection

temperature (18°C) to ambient temperature (65°C).

Figure 4-18: Profile of temperature and pressure away from injection well, 100 days after the start of CO2 injection.

Top: Profile of temperature and pressure away from injection well, 100 days after

the start of CO2 injection. Bottom: Enlarged view of the green dashed area shown in

the above image.



The minimum temperature occurs just at the edge of the CO2 thermal front,

which is 17.6°C, only 2% (0.4°C) lower than injection temperature, Figure 4-18

(bottom). One reason for this low temperature effect is the relatively lower

degree of CO2 expansion that occurs near the injection as the permeability is

very high in the Captain Sandstone. The pressure drop around the injection well

is small, with the drop between wellbore to formation observed to be 14barg in

the modelling. Note that the further the CO2 front advances, the cooler it

becomes, but again the effect is expected to be very small and can be safely

ignored.

4.6.2 Transient Well Behaviour

In the Captain injection site, CO2 remains in liquid or dense phase in all injection

scenarios, providing minimum rates of injection are achieved. However, if the

wells are shut-in at surface, the tubing head pressure (THP) will drop below

critical pressure and CO2 will boil off into the gas phase. This will generate

significant temperature drops and create a two-phase scenario when the well is

re-started. These effects are transient but have significant impact on well design

(temperature resistance).

With a surface shut-in, the pressure at the top of the well, below the shut-in point,

falls to below the phase boundary, so gas will evolve, leading to significant

cooling (and gas slugging when injection starts up again). When injection starts

again, the pressure will be low at the wellhead at the top of the CO2 column and

there will be a short transitional period of high pressure liquid entering a low-

pressure gas environment, leading to further cooling effects.

The transient pressure effects of a surface shut-in could be modelled using a

simulator such as OLGA, for example. This would give a better prediction of the

maximum and minimum pressures in the wellbore and highlight if the pressure

variations (for example, the ‘water hammer’ effect) cause problems at the sand

face.

If significant issues are identified, a possible solution to transitional effects is to

add a deep-set shut-in valve to the completion. The deep-set valve would act as

the primary shut-in. Note that a combined deep-set shut-in valve / choke valve

could provide the solution to the variable rates (high injection range) required for

this development, and further investigation of this solution is recommended in

the Concept phase.

Shut-in closer to the formation reduces the hydrostatic head of CO2 acting on

the formation and removes the risk of damaging pressure pulses (‘water

hammer’ effect) affecting the sand face integrity. After shut-in the well could be

left with the CO2 supply pressure applied and therefore mitigate cooling effects

at the wellhead on restart. The pressure differential across the downhole valve

will be minimal and cause no problematic transitional effects. Some OLGA

modelling would be required to determine the minimum depth of shut-in and a

suitable valve specified.

For the purposes of this work, it is assumed that a suitable mechanism is

available to perform the downhole shut-in function. Transient effects are

therefore mitigated. However, further work is required in the Concept and FEED

stages to substantiate this approach, or to provide alternate solutions. In all

cases, well design should reflect the potential for very low temperatures should

these mitigations fail.

4.6.3 Safe Operating Envelope Definition

With respect to CO2 injection, safe operating limits are those that allow the

continuous injection of CO2 without compromising the integrity of the well or the



geological store. Since wells are designed to cope with the expected injection

pressures and temperatures, the primary risk to integrity is uncontrolled

fracturing of the formation rock, leading to an escape of CO2 through the caprock

(adjacent to the wellbore or at a point anywhere in the storage complex). The

pressure at which fractures can propagate through formation rock is called the

fracture pressure and is usually defined as a gradient, as it varies with true

vertical depth.

To prevent CO2 migrating from the storage site and storage complex, fracturing

the caprock should be avoided. This can be done by limiting the pressure to

which the caprock is exposed, in both the near wellbore and the storage site

complex as a whole. The pressure limit at any one point depends on the caprock

properties, including strength, elasticity and thickness. Given that there is always

uncertainty in rock properties as you move away from ‘control’ wells, and that

caprock properties are generally not measured and documented to the same

degree as permeable formation rock, there is a high degree of uncertainty

surrounding caprock fracture initiation pressures and the vertical extent of any

resulting fracture (fully penetrating or partially penetrating).

For this reason, this study has used the permeable formation fracture pressure

as the pressure limit (which, in most cases considered for CO2 storage, is lower

than the caprock fracture pressure) rather than that of the caprock itself. This

provides a conservative approach and allays concerns over the concentration

of cold CO2 at high pressure that might be delivered to the caprock boundary

through fracture propagation in the target formation. A further safety margin of

10% is taken from the estimated formation fracture pressure to allow for

variations (and unknowns) within the formation rock properties.

A further risk to well integrity and the well injection performance is the poor

understanding of operating a CO2 injection well close to the gas / liquid phase

boundary. Due to the characteristics of CO2, changes in phase can be

accompanied by significant changes in temperature as well as flow performance

(pressure drops due to friction within the wellbore). For example, across the

phase boundary, CO2 is boiling and condensing, making it an extremely complex

system to model, from both a temperature and flow perspective. This complexity

introduces significant uncertainty.

4.6.3.1 Fracture pressures

The fracture and pore pressures have been taken from the ETI SSAP study,

which incorporated a full geomechanical review, (Pale Blue Dot Energy & Axis

Well Technology, 2016). Well data from within the Captain storage site was

used.

An initial reservoir fracture gradient of 0.17bar/m (0.73psi/ft) was determined

and then corrected for reservoir depletion of 27.58bar (400psi) to give a safe

working assumption of 0.16bar/m (0.69psi/ft) for the study. A safety margin of

10% is applied to this figure to account for local variations and uncertainties,

resulting in a limiting injection pressure gradient of 0.14bar/m (0.62psi/ft).

4.6.3.2 Phase envelope

To minimise the risk associated with the uncertainty introduced by operating

wells across a phase boundary, all injection will be limited to single phase. With

the reservoir pressure of Captain (187bara) being above the critical point for

CO2 (74bara), injection will be limited to liquid (below critical temperature) or

dense phase (above critical temperature). CO2 will be delivered to the injection

sites in liquid phase, with assumed pipeline operating pressures of up to

160bara.



4.6.4 Dynamic Modelling – Compositional Fluid Flow Model

For the Acorn modelling study, the ETI SSAP Eclipse dynamic Captain Fairway

model was used as a starting point. The “black oil” Fairway model was initially

converted to a “compositional” model for the following reasons:

To provide a comparison with the black oil modelling study

undertaken previously by ETI SSAP.

To correctly represent the mixing effect between CO2 and lighter

residual methane gas, which cannot be represented in a black oil

model. There are several depleted gas fields that still contain light

gas trapped in their structure within the Captain Fairway model.

Mixing of CO2 with these lighter gases causes a more significant

buoyancy effect between water and CO2/HC mixture than that

observed in a black oil modelling study between water and pure

CO2.

To provide better representation of the CO2-water interaction.

4.6.4.1 Model inputs

The Captain Fairway model consists of two major sand bodies, Captain D

(shallower) and Captain A (deeper), which are separated by the mid-Captain (C)

Shale layer. The lower Captain A Sandstone is not laterally extensive and there

is a suggestion that this sandstone is only poorly connected with the more

extensive Captain D, as outlined in the Captain X SDP, (Pale Blue Dot Energy

& Axis Well Technology, 2016).

The Captain D Sandstone has a higher quality reservoir character along with

better connectivity. Almost 65% of the available pore volume in the Captain X

area resides in the Captain D Sandstone, which is why it was considered for

CO2 storage in the previous ETI SSAP study and also now for the Acorn CCS

Project. Table 4-14 shows a summary of the ETI SSAP model parameters, (Pale

Blue Dot Energy & Axis Well Technology, 2016).

The model consists of 766,080 grid blocks of which only 131,000 grid blocks are

active. The model is divided in several regions principally to allocate different:

initialisation conditions, PVT regions for representing the existing hydrocarbon

fields in the model (for the black oil model) and saturation functions regions,

(Figure 4-19).



Parameter Value

Initial Pressure @ datum 197bar

Temperature 65°C

Rock Compressibility 3.5×10-7 at 2500psi

CO2 density 673kg/m3

CO2 viscosity 0.054cP

Brine Salinity 56,600ppm

Porosity 0.185

Permeability H 836mD

Permeability V 445mD

Grid Block 228×112×30

Cell size 400m×400m

Cell Thickness 2.1m

Number of (active) Cells 131,000

Table 4-14: ETI SSAP reservoir model properties

Figure 4-19: Different regions used in the ETI SSAP work. Location of model fracturing pressure threshold shown as red point

The model is an isothermal model at 65°C. At these conditions the injected CO2

will be at supercritical conditions, with a density comparable with liquids and a

viscosity like that of a gas. The in-situ brine salinity is 56,600ppm. Brine salinity

affects the degree of CO2 dissolution in the brine phase. The hydrocarbon fields

considered in the initialisation of the ETI SSAP model include the Blake oil field

and Atlantic and Cromarty (A&C) gas fields.

Like the ETI SSAP study, relative permeability data has been supplied from the

Goldeneye field, (Pale Blue Dot Energy & Axis Well Technology, 2016); (Shell,

2011). For this modelling, hysteresis was considered in the gas phase. The

effect was far less significant for the water phase as it was the wetting phase. A

trapped gas saturation of 30% is defined in the model. A rock compressibility

factor of 3.5×107(1/psia) has been used for the ACT Acorn study. Additionally,

the rock fracture gradient has been assumed as 0.14bar/m (0.62psi/ft), which



includes a 10% safety margin. CO2 injection is terminated in the model if the

pressure at the shallowest point located at the Blake field reaches the threshold

fracturing pressure at this correspondence depth (198.91bar/2885psi). Figure

4-19 shows the approximate location of this point at the Blake field.

A high-level calibration has been performed in the ETI SSAP model for matching

the observed pressure in the Captain fairway just before CO2 injection initiation,

between 2011 and 2022. The pressure is matched in the northern and southern

regions by adjusting the observed production data from the existing hydrocarbon

fields and also by varying the size of the connected aquifers to either side of the

model. This prepares the model for CO2 injection which begins at the end of

2022 and continues until 2042 injecting a 60MT inventory of CO2, the same as

in the ETI SSAP model.

A number of equilibration regions have been used in the black oil model that sit

next to each other and are hydraulically communicating. They have been used

to initialise pressure at the start of modelling. The fluid contact depths along with

pressure at the contacts have been depicted in Table 4-15, (Pale Blue Dot

Energy & Axis Well Technology, 2016). Figure 4-19 also shows the

corresponding initialisation regions. The same strategy was undertaken here

except that the Blake oil water contact (OWC) has been updated to 1603m

(5260ft) SS (Du, Pai, Brown, Moore, & Simmons, 2000).

Region Pressure (bar) Pressure (psi)

North Boundary 190 2756

Blake Field 190 2756

Cromarty Field 160 2321

Atlantic Field 156 2263

Captain Aquifer 193 2799

South Boundary 156 2263

Table 4-15: Initialisation depths and corresponding pressures at contact depths for different model regions

4.6.4.2 Compositional fluid flow model

The fluid model used for Acorn CO2 storage site modelling study is the

Eclipse300 compositional simulator, which simulates the solubility of CO2 in the

water phase via the “CO2SOL” option (Eclipse 300 Reference Manual, 2016).

The choice of compositional reservoir simulator in this study allowed for more

accurate estimation of water and CO2 properties and also CO2 solubility in water

and gives more flexibility should parameters that affect CO2 solubility vary.

CO2 properties were automatically calculated via the Peng-Robinson Equation

of State (EOS), while care was taken to accurately estimate water properties in

the aquifer at ambient conditions, considering salinity and CO2 solubility in

water. As with the ETI SSAP model, water evaporation in the supercritical CO2

phase was not considered as it is typically very small (less than 1%) and would

only have a negligible effect on water properties, or the inventory of CO2 at the

end of storage simulation.

The fluid model is a three-component model composed of one light, one heavy

and one CO2 component. Water will also be present in the system but is not

accounted for as a hydrocarbon component. The light and heavy components

were used respectively to replicate the remaining hydrocarbon gas in the Atlantic

and Cromarty (A&C) fields and the relatively heavy oil in the Blake field.



Component CO2 C1 C2+

Mw 44 40 90

ΩA 0.457 0.457 0.457

ΩB 0.078 0.078 0.078

Pc (psi) 1071 668 666

Tc (°R) 548 343 1012

Vc (ft3/lb-mole) 1.51 1.57 10

Vc (ft3/lb-mole) 1.51 0.30 5.75

Ω 0.225 0.013 0.570

γCO2-i 0.1 0.1 0.032

Table 4-16: Parameters of the fluid model

Table 4-16 shows the details of the fluid model constructed for this modelling

study. Fluid properties will be estimated by Peng-Robinson EOS. Additionally,

the CO2SOL model calculates a relative density increase as CO2 dissolves in

the brine phase.

The light gas in Atlantic & Cromarty (A&C) is represented by 100%C1. A mixture

of 12%C1 and 88%C2+ replicates the heavy oil in the Blake field. At the ambient

condition of the Captain fairway, the light gas has a density and viscosity of

15.8lb/ft3 and 0.02cP respectively. Similarly, the oil defined for the Blake Field

has a density and viscosity of 57.1lb/ft3 (914.7 kg/m3) and 3.38cP respectively.

The CO2SOL model of Eclipse 300 replicates the interaction between water and

CO2, i.e. the quantity of dissolved CO2 and the relative density increase of brine

as a result of CO2 dissolution at different pressures. The CO2 solubility data in

the water phase is generated via the Chang, Coat and Nolen correlation. The

density of CO2 saturated brine is calculated with Ezrokhi’s method considering

the effect of salt and CO2 on the density of pure water, (Schlumberger, 2014).

Water viscosity at ambient temperature and salinity found in the Captain

sandstone fairway was matched with the CO2STORE model, (Schlumberger,

2014), and was also found to be close to the black oil model at 0.5cP. As with

the ETI SSAP study, water evaporation in the supercritical CO2 phase has not

been considered as the impact is minimal.

4.6.4.3 Fluid mixing

CO2 storage in the Captain Sandstone Member is very gravity dominated due to

the following factors:

• a considerable density difference exists between water and CO2 at

ambient aquifer conditions;

• excellent formation characteristics with low heterogeneity; and

• the tilted nature of the aquifer fairway.

To investigate the role of fluid mixing, 60MT of CO2 was modelled, over a 20-

year injection period. The simulation was further extended to 1000 years

thereafter (to year 3042) to investigate how much of the injected CO2 would be

retained within the Captain X storage complex of the ETI SSAP study. Injecting

the same volumes as for the ETI SSAP study and using the same boundary

enabled a direct comparison between the black oil model (used in the ETI SSAP)

and the compositional model (used in this work).



The modelling results at cessation of injection (Figure 4-20) show that during

CO2 injection, part of the injected CO2 has entered into the A&C fields and has

mixed with their remaining hydrocarbon gas that is structurally trapped in these

fields (note the colour change that occurs at the edges of the CO2 plume in the

bottom figure). The light gases in the A&C fields are significantly lighter than

pure CO2, and upon mixing, the buoyancy effects between brine and the gas

mixture (CO2 and C1) become even more significant than in the corresponding

black oil model’s prediction.

Figure 4-21 and Figure 4-22 show final profiles 1000 years after cessation of

injection. Now it can be seen that part of the CO2 has migrated into the northwest

of the Captain fairway. The profile of light component mole fraction in the gas

phase after 1000 years, (Figure 4-22), shows that a significant volume of A&C

light gas has been mobilised by the injected CO2 and has also been displaced

into the northwest.

Figure 4-20: Gas saturation (top) and CO2 mole fraction in the gas phase (bottom); both immediately after CO2 injection stops (2042)



Figure 4-21: Gas saturation (top) and CO2 mole fraction in the gas phase (bottom) profiles 1000 years after CO2 injection is stopped (year 3042)

The inclusion of the mixing effect can reduce the overall calculated storage

capacity compared to black oil model predictions. To investigate how much CO2

can now be stored within the previous ETI SSAP storage complex boundary and

to thus enable a comparison with the previous modelling work, the CO2 inventory

was reduced successively from 60MT in 3MT steps. It was identified that with

this configuration of well placement and injection profile, between 45MT and

48MT CO2 could be stored within the ETI SSAP storage complex boundaries,

versus the original 60MT using the black oil simulator. This shows the

significance of mixing on the overall CO2 storage capacity and the importance

of compositional simulation in correctly addressing the mixing effect.

Figure 4-22: Light gas mole fraction in the gas phase profile 1000 years after CO2 injection termination (year 3042)

There is a degree of uncertainty regarding the quantity of remaining light gas in

the A&C fields after their abandonment. The A&C fields were under production

from 2005 to 2009, and this may provide additional pore volume for CO2 storage

in Acorn CO2 storage site. Should this depletion be considered, a different result

could be expected.



4.6.5 Dynamic Modelling - CO2 Supply Profiles

This section discusses the methodology and results of the dynamic modelling

for the Acorn CO2 storage site. The results of three modelling scenarios are

presented:



one subsea well in the injection site in between the Atlantic and

Cromarty depleted fields, starting in 2023.


Phase 1, plus those from a potential build-out scenario, including



2.7MT/yr.


5MT/yr (259mmscfd) via four injection wells at different injection

sites, including one near the Goldeneye depleted gas field, and a

brine production well for pressure management. Emissions include

those in the Base Case, plus those from a potential build-out

scenario, including CO2 captured from hydrogen generation,

importation of CO2 via Peterhead Harbour (from shipping) and

importation of Grangemouth emissions via the Feeder 10 pipeline to

St Fergus.

These scenarios are taken from ACT Acorn Deliverable D02 CO2 Supply

Profiles. Figure 4-23 illustrates the three different CO2 supply profiles.

Figure 4-23: CO2 supply scenarios

Three different CO2 supply scenarios envisaged for the Acorn project. The

cumulative CO2 inventory is calculated and shown for each supply scenario

4.6.5.1 Well placement criteria

The strategy for well placement is particularly important for storage security and

to maximise the available storage capacity. For each CO2 supply profile, a

different development strategy was considered, using wells G01, G02, G03 and

G04.

Three distinct storage zones have been identified within the Captain X area,

shown in Figure 4-24:



• Zone 1 - Adjacent to the Blake field where only one well was

positioned (G04 well);

• Zone 2 - Between the A&C fields where two wells were positioned

(G01 and G02 wells);

• Zone 3 - on the west side of the Cromarty field where the fourth well

was positioned (well G03).

Figure 4-24 also shows the position of wells G01 to G04 in each storage zone.

Due to the communication between zones, increasing CO2 storage in one could

limit the storage capacity in another.

Figure 4-24: CO2 storage zones

Three distinct storage zones along with the position of injection wells in each storage

zone used for CO2 storage within the storage site area (white circles). Also shown is

well 13/30b-07, an abandoned well (red circle)

Depending on the CO2 injection profiles, one or more storage zones could

become target for CO2 storage. Table 4-17 shows the target storage zones for

each specific CO2 supply. For the first CO2 supply scenarios, zone 2 located

between the A&C fields would be enough, while for the second phase CO2

injection profile, both zones 1 and 2 will be needed. For the Phase 3 CO2

injection profile (152MT cumulative CO2 stored), all the three storage zones in

the Captain X area plus Goldeneye Segment (shown in Figure 4-33) are

targeted for storing CO2.This is discussed further in Section 4.6.5.4.

Acorn Injection Phase

Final Inventory and Maximum CO2 Injection Rate

Target Storage Zones and Target Injection Wells

Phase 1 4.2MT, 281kT/yr Zone 2, well G02

Phase 2 64MT, 2.7MT/yr Zones 1 and 2, wells G02 and G04

Phase 3 152MT, 5MT/yr

Zones 1, 2 and 3 and additional Goldeneye Segment, wells G01, G02, G03 and G04 and brine producer

Table 4-17: Target storage zones and target injection wells for each CO2 supply scenario

Table 4-18 shows a summary of the injection wells used in the reservoir

modelling study. Since the CO2 injection rate of the first well, G02, varies

significantly across the supply scenarios, a dual completion well has been used

for this well as described in Section 4.6.1.8. The maximum allowable THP is



130barg, after which injection into each well will be controlled by THP. All the

remaining three wells (G01, G03 and G04) are single bore wells. One brine

producer is used in the Phase 3 case (Section 4.6.5.4).

Well Number G01 G02 G03 G04

UTM North (m) 6436090 6440286 6439233 6447894

UTM East (m) 264719 264946 257146 259536

Grid coordinates (X,Y) (83,45) (90,53) (102,37) (113,57)

Single/Dual Single bore

Dual bore Single bore

Single bore

Depth (m) 2020 2005 1930 1976

Fracturing pressure (barg) 283 281 271 277

Table 4-18: Reservoir engineering well summary for Phase 1 and 2 wells

To maximise CO2 contact with the reservoir, enhance dynamic storage

efficiency and thus reduce the risk of early CO2 migration out of the Acorn CO2

storage site storage complex boundaries, injectors were placed deep within the

Captain D Sandstone.

In addition, CO2 placement and accumulation around well 13/30b-7 was avoided

where possible. This is due to uncertainty regarding the security of its state.

4.6.5.2 Phase 1 results (Supply Scenario 1 - 4MT)

The Storage Zone 2 was targeted via injector G02 located between the Atlantic

and Cromarty fields, with the injection rate in this well equal to the supply profile.

Figure 4-26 shows the gas saturation profile after the end of CO2 injection

(above) and 1000 years later (below).

With this small injection volume, the risk of CO2 migration out of the storage

complex is negligible. Figure 4-25 compares the tubing head pressure (THP)

and bottom hole pressure (BHP) for this well; note that the bottom hole pressure

(BHP) is significantly lower than the fracturing pressure at this well depth.

Similarly, THP is considerably lower than the threshold of 130barg.

Figure 4-25: BHP and THP profiles for well G02 for the Phase 1 (4MT) scenario

Figure 4-27 shows the fraction of stored CO2 within the different geographic

locations of the Acorn CO2 storage site (left) and the fraction of stored CO2 by

the different storage mechanisms (right). The geographic locations are: Captain

X (the original storage complex for the ETI SSAP project), NW (to the northwest



of Captain X, including Blake) and SE (to the southeast of Captain X, including

Goldeneye).

In this Phase 1 scenario, all the injected CO2 has been stored within the Captain

X area and no CO2 is within either the northwest or southeast neighbouring

structures.

Figure 4-26: Phase 1 (Supply Scenario 1 - 4MT) CO2 supply scenario gas saturation profile

Top: at the end of CO2 injection and bottom: 1000 years later



Figure 4-27: Retained CO2 and trapping mechanism fractions for 4MT CO2 supply scenario

Left, fraction of CO2 retained at Captain X area, SE and NW structures. Right,

fraction of CO2 stored by different trapping mechanisms.

The dynamic modelling confirms that the limited inventory of 4.2MT of CO2 can

be injected safely into the Acorn CO2 storage site (Captain X area) with one well.

The CO2 plume migration is shown in Figure 4-28. For the Acorn CO2 storage

site to be a viable storage site the CO2 must be contained within the storage

complex boundary, 1000 years after injection ceases.

The results of the modelling show that the risk of any of this small inventory of

CO2 migrating out of the storage complex is negligible. The injection profile is

highlighted in Table 6-4. As CO2 is less dense than the brine within the saline

aquifer, the CO2 movement is primarily gravity driven. Post injection, the CO2 is

mainly present in the Atlantic and the Cromarty structural highs to the south west

pinch-out edge of the model. After 1000 years the CO2 plume is still in that

position.

Figure 4-28: CO2 Plume migration at the end of injection (above) and after 1000 years shut-in (below) for Phase 1 (4.2MT)



4.6.5.3 Phase 2 results (Scenario 2 - 64MT)

For the Phase 2 CO2 supply profile, two storage zones (1 and 2) were targeted

via two wells, G02 and G04. Injection into the G02 well ran from 2022 to 2057.

The rates injected into each well are summarised in Table 4-19 below.

Year G2

(MT/yr)

G4

(MT/yr)

Sum

(MT/yr)

2022 0.70 0 0.70

2023 - 2024 0.90 0 0.90

2025 - 2029 0.98 0 0.98

2030 - 2037 0.56 1.32 1.88

2038 - 2039 1.34 1.34 2.68

2040 - 2057 0.57 1.33 1.90

2058 - 2059 0 0.90 0.90

Sum (MT) 24.86 38.96 63.82

Table 4-19: Phase 2 injection rates per well

For the G04 well, injection started in 2030 and finished in 2059. Note that 61%

of CO2 injection in the Acorn CO2 storage site has been carried out via well G04.

Figure 4-29 shows the gas saturation profile after CO2 injection has ended

(above) and 1000 years later (below).

Figure 4-29: Gas saturation profile after the end of CO2 injection (top) and 1000 years later (bottom) for the 64MT CO2 supply scenario



Figure 4-30 shows CO2 mole fraction in the gas phase. Comparing Figure 4-30

with Figure 4-29, it can be seen that the front of the CO2 plume in the Blake area

is slightly different between these two figures. This is because of CO2 dissolution

in the residual oil phase of Blake, which removes CO2 from the gaseous phase.

Additionally and importantly, no free CO2 in the supercritical phase is found

around the well 13/30b-7.

Figure 4-30: CO2 mole fraction in the gas phase 1000 years after CO2 injection is stopped for the Phase 2 (Scenario 2 - 64MT) CO2 supply scenario

Figure 4-31 shows the evolution of the BHP and THP for this scenario; none of

the BHP and THP criteria have been violated.

Figure 4-31: BHP and THP profiles for wells G2 and G4 for Phase 2 64MT scenario

Figure 4-32: Retained CO2 and trapping mechanism fractions for 64MT CO2 supply scenario

Left, fraction of CO2 retained in the Captain X area, southeast and northwest

structures. Right, fraction of CO2 stored by different trapping mechanisms.

Figure 4-32 shows the fraction of stored CO2 by area (left) and the fraction of

stored CO2 by different storage mechanisms (right). Almost 14% of the



cumulative injected CO2 has been trapped by dissolution in the remaining oil in

the Blake field. It is important to note that the CO2 does not meet the Blake

residual oil until after 2050, well after the Blake field has ceased production and

been abandoned.

4.6.5.4 Phase 3 results (Supply Scenario 3 – 152MT)

For this scenario, all four wells and the three storage zones discussed previously

become an integral part of the target storage scenario. Using four wells enables

better distribution of the CO2 inventory before reaching the threshold fracturing

pressure at any of the wells. As it is not possible to store all the 152MT CO2 in

the Captain X area, the full Acorn CO2 Storage Site Area was used, which

included the Goldeneye Segment (Figure 4-33 – adapted from (Pale Blue Dot

Energy & Axis Well Technology, 2016)).

The Phase 3 results are split into two sections – Section 4.6.5.4.1 highlights the

results of injecting the 5MT/yr supply profile for Phase 3 into the Captain X

injection area only. Section 4.6.5.4.2 presents the results of injecting the 5MT/yr

supply profile into the full Acorn CO2 Storage Site area.

4.6.5.4.1 Phase 3 - Captain X injection area only

To investigate the likely storage potential under this last CO2 supply profile,

several simulation runs were modelled, (Table 4-20). For each simulation run,

the CO2 injection profile, including timing and rate and CO2 allocation for each

well, were varied until the system was able to safely retain the maximum injected

CO2 for 1000 years. Note that the criterion for CO2 storage modelling for this

scenario is that no CO2 as a free supercritical phase can leave the storage

complex from the northwest boundary. No CO2 could be expected to leave the

Blake structure, unless it is filled up to its spill point, which is not the case for

either of the depicted simulation runs in Table 4-20.

Figure 4-33: Acorn CO2 storage site storage complex outline showing Captain X area and Goldeneye Segment

The maximum CO2 injection rate for this simulation run was capped at 5MT/yr

from 2030 to 2055. In one of the simulations runs (SR3 – full list in Table 4-20),

the CO2 inventory was divided between the four injection wells and injection was

carried out at 5MT/yr injection rate for as long as possible. It was, however,

noted that injecting CO2 at this high rate causes early triggering of the threshold

fracturing pressure within the Blake field. Only 97MT of CO2 could be injected

under this injection strategy, and injection can be sustained only until year 2046,

though more than 4.5% of this injected CO2 breaks through to the nearby

northwest structure within 1000 years. This shows that the system is not able to



absorb the rapid pressure response created by CO2 injection at this high

injection rate (5MT/yr) using the assumptions made.

Figure 4-34: Gas saturation profile for Phase 3 (Scenario 3 - 152MT) CO2 supply scenario

Top: after CO2 injection has stopped and bottom: 1000 years later (Simulation Run

SR20)

Lowering the injection rate and better allocation of CO2 inventory across wells

could improve the storage response. This is the strategy that was completed for

the remaining simulation runs in Table 4-20, where the overall injection rate was

limited to 3MT/yr to enable the system to absorb the rapid pressure increase

due to CO2 injection. The use of brine production wells in this area to counteract

this pressure increase would be of little applicability because the storage

response in the Captain formation is limited by buoyancy driven CO2 migration.

Figure 4-34 shows the gas saturation profile after CO2 injection stopped (top)

and 1000 years later (bottom) for the chosen SR20 scenario. Again, the CO2

plume remains clear of the 13/30b-7 well. Figure 4-35 shows CO2 mole fraction

in the gas phase.



Scenario G1 (MT) G2 (MT) G3 (MT) G4 (MT) Sum (MT) Retained CO2 after

1000 Years

Proportion of CO2 into

Southeast Structure

Proportion of CO2 into Northwest (Supercritical)


Northwest (Dissolved in

Oil)


Northwest (Dissolved in

Water)

SR3 24.13 25.38 25.38 22.5 97.4 95.25% 0.42% 3.83% 0.00% 0.50%

SR4 9.13 6.63 45.63 39 100.4 98.74% 0.14% 0.90% 0.14% 0.08%

SR7 11.13 8.63 45.63 39 104.4 98.53% 0.24% 0.98% 0.16% 0.09%

SR11 11.13 8.63 40.43 44.2 104.4 98.83% 0.23% 0.56% 0.32% 0.06%

SR14 14.13 11.63 40.43 44.2 110.4 98.68% 0.29% 0.64% 0.33% 0.07%

SR15 7 13.63 45.63 48.13 114.4 98.05% 0.09% 1.10% 0.63% 0.13%

SR16 14.13 11.63 32.63 44.2 102.6 99.02% 0.26% 0.31% 0.36% 0.05%

SR17 14.13 11.63 24.83 44.2 94.8 99.37% 0.25% 0.02% 0.33% 0.03%

SR18 14.13 11.63 17.03 44.2 87 99.44% 0.24% 0.00% 0.29% 0.02%

SR19 14.13 11.63 20.93 44.2 90.9 99.42% 0.25% 0.00% 0.31% 0.02%

SR20 14.13 11.63 22.23 44.2 92.2 99.41% 0.25% 0.00% 0.32% 0.02%

Table 4-20: Different simulations modelled to address the Phase 3 CO2 supply scenario injected into the Captain X area only

The chosen simulation run (SR20) has been highlighted



Figure 4-35: CO2 mole fraction in the gas phase 1000 years after CO2 injection has stopped for the third CO2 supply scenario (Simulation Run SR20)

Figure 4-36 shows the fraction of CO2 stored at different regions within the Acorn

CO2 storage site structure (left). The fraction of stored CO2 as dissolved, mobile

and trapped can be observed in this figure (right).

Figure 4-36: Retained CO2 and trapping mechanism fractions for Phase 3 CO2 supply scenario

Left: fraction of CO2 retained at Captain X, southeast and northwest structures.

Right: fraction of CO2 trapped by different trapping mechanisms. Both figures are

simulation run SR20

Figure 4-37: BHP and THP profiles for wells G1-4 for SR20

Figure 4-37 shows the evolution of the BHP and the THP for all four wells used

in SR20. The BHPs for wells G01, G02 and G03 are below their limiting

threshold, although for well G04 only, the injection rate becomes limited by BHP

only when this well starts injecting in around 2030, and for only 30 days, after

which its BHP decreases below the fracturing pressure as the gas saturation in

the near wellbore region increases. The THP is also below the threshold

pressure, except again for well G04; this occurs just as the well starts injection;

THP almost reaches the 130barg limit after which it declines. Ignoring these

short-term spikes, which are manageable by gradual ramping up the injection

rates, the chosen THP or BHP limits are not violated in any wells at any time.



4.6.5.4.2 Full Acorn CO2 Storage Site Area

Given the storage resource potential using the Captain X injection area only is

still lower than potential CO2 available for injection in Scenario 3 (92.2MT

compared to 152MT), possible injection locations were explored further

southeast.

The well locations for this scenario are in Table 4-21.

Well Latitude Longitude

G1 58°00'18.8918"N 6°29'57.2750"W

G2 58°02'30.0516"N 6°58'57.5443"W

G3 57°59'23.5607"N 6°33'37.7828"W

G4 58°06'25.0057"N 7°04'54.5989"W

Brine Producer 58°00'14.7837"N 6°43'31.5730"W

Table 4-21: Well locations for Phase 3 152MT scenario

Individual well injection profiles are depicted in Table 4-22.

Year G1

(MT/yr)

G2

(MT/yr)

G3

(MT/yr)

G4

(MT/yr)

Sum

(MT/yr)

2022 0.7 0 0 0 0.7

2023-2024 0.9 0 0 0 0.9

2025-2029 1.6 1.2 1.2 0 4.0

2030-2055 1.7 0.8 0.8 1.7 5.0

Sum (MT) 54.7 26.8 26.8 44.2 152.4

Table 4-22: Individual well injection profiles to achieve the target 152MT CO2 injection

First simulation run

In the first run, the location of well G1 was brought down-dip into the Goldeneye

Segment near the Goldeneye field and its BHP was corrected for the

corresponding depth at which it is now located. However, injection was stopped

after only 112MT of CO2 due to pressure increase beyond the threshold

fracturing pressure limit observed adjacent to the Blake field. This showed that,

unlike the previous simulations, to inject the 152MT CO2 inventory, the storage

performance could become limited by pressure build up and that offset brine

production wells may need to be deployed.

Second simulation run

In the second run, one offset brine production well was added in the model

between the new well G01 position and the southeast boundary of the Acorn

CO2 storage site (well WP in Figure 4-38). The offset brine producer produces

brine at a fixed rate of 3180m3/day with a minimum BHP of 203barg to avoid



excessive adverse drawdown. Additionally, as soon as its CO2 production rate

increased above 28.3x103m3/day (1000Mscf/day), it is automatically shut-in to

avoid CO2 back production. Figure 4-38 shows final CO2 plume under this CO2

injection strategy. Results show that the storage performance after 1000 years

is not now limited by the pressure response, instead it is limited by the vertical

migration of CO2 plume toward the northwest structure.

Third simulation run

In the third run, well G03 was also brought down-dip close to well G01, and its

maximum injection BHP was corrected for its new depth (Figure 4-39). Now two

wells are located down-dip near the Goldeneye field. The injection profiles are

still as previously identified in Table 4-22. Figure 4-39 shows the final CO2 profile

1000 years after CO2 injection termination. No breakthrough of supercritical CO2

to the northwest structure was identified, but it was observed that only 149MT

of CO2 (97.6% of the 152MT target) had been injected. The reason for this is

less than defined CO2 injection from well G1; it was observed that injection from

well G1 now becomes limited by its BHP, given another high rate injection well

is now located in its vicinity.

Figure 4-38: Profile of CO2 distribution in the second simulation run after 1000 years. Well G1 is now at the bottom of the model near the Goldeneye field

Figure 4-39: Profile of CO2 distribution in the third simulation run after 1000 years. Both wells G1 and G3 are now at the bottom of the model near the Goldeneye field



Figure 4-40 compares the CO2 storage at the end of the simulations described

in this section for the second (Figure 4-38) and third (Figure 4-39) simulation

runs. More CO2 has been stored in the southeast structure for the third

simulation run than for the second.

Figure 4-40: Retained CO2 and trapping mechanism fractions for the Phase 3 third simulation run

Top row: second simulation run. Bottom row: third simulation run. Left: fraction of

CO2 retained at the Captain X area, southeast and northwest structures when

expanding the storage boundary to southeast. Right: fraction of CO2 trapped by

different trapping mechanisms

4.6.5.5 Uncertainty analysis

Sensitivity analysis has been carried out for the maximum CO2 storage inventory

in the Captain X area, i.e. SR20 injecting 92.2MT CO2 (Table 4-20). Results are

expected to be less sensitive to variation of model parameters for the first two

CO2 injection profiles (Phase 1 and 2), since the cumulative CO2 inventories for

these three CO2 injection profiles are small.

Compressibility factor: Results show that an order of magnitude reduction of

the compressibility factor increases the maximum pressure experienced in this

block by 1.4barg, which is still smaller than the limiting criterion of 199barg at

this depth. However, increasing the compressibility factor can relax the

maximum pressure by almost 8.3barg. This shows that a relatively small rock

compressibility has been allocated for the Captain Sandstone.

Transmissibility across the Shale Layer: In this sensitivity analysis, the

vertical permeability of the Captain shale layer was varied by an order of

magnitude higher and lower compared to its base case value (0.001md). It was

observed that increasing or decreasing the Captain shale vertical permeability

within this range does not affect the pressure response of the system at all.

Nevertheless, a very small quantity of CO2 migrates to underneath the Captain

shale layer; increasing/decreasing the vertical shale layer transmissibility could

only increase/decrease this migration.

The Degree of Depletion of the A&C Fields: An uncertainty exists regarding

the remaining quantity of light gas at the beginning of CO2 injection that could

affect the storage results. Results show that if depletion from the A&C fields is

considered, the ultimate storage capacity of the system could increase from

45MT-48MT to almost 60MT, a 12MT-15MT increase. Similarly, a sensitivity

scenario was investigated here in that if the contact depths of the A&C fields

were modified for SR20 to account for the cumulative gas production from these

fields, which occurred between 2005 and 2009. Results show that the leading

edge of the CO2 plume is now distant from the northwest storage boundary. The



storage potential of the system (under SR20) could now be increased by almost

10-15MT because of this adjustment, and thus the final stored CO2 inventory

could be increased from 92MT to 102-107MT. This may need alternate well

injection profiles than those used for SR20.

Uncertainty in the Top Structure Map: There is a degree of uncertainty in the

interpretation of the top structure map along the Captain fairway, (Pale Blue Dot

Energy & Axis Well Technology, 2016), related to challenges with the

overburden velocity and therefore the seismic depth conversion process and the

lack of acoustic impedance contrast at the top reservoir event. Different

realisations of the Top Captain structure map were modelled in the ETI SSAP

study, which had a direct impact on plume migration. This uncertainty still exists.

Impact of CO2 injection in Captain Sandstone on the Solitaire field: Solitaire

is a single well oilfield in an Upper Jurassic Burns Sandstone reservoir which

lies at 464ft below the top of the Captain Sandstone (235ft below the Base

Captain Sandstone) in the 14/26-8 well underneath the Atlantic gas condensate

field, and the geography of the main Captain Sandstone fairway. First oil from

Solitaire was in 2015, with end of production forecast in 2028 coinciding with the

cessation of production (CoP) of the Golden Eagle development to which it is

tied back. The Captain Sandstone and deeper Burns sandstone are

hydraulically isolated, and it would take a large pressure gradient between the

Captain Sandstone and the depleted Burns Sandstone and a well penetrating

both formations for any CO2 from the Captain Sandstone to reach the Burns

Sandstone. This is highly unlikely and no impact to Solitaire operations is

anticipated.



4.6.6 Strategies to Increase CO2 Storage Efficiency

Both the previous ETI SSAP study and the work conducted in the ACT Acorn

study have concluded that the CO2 storage efficiency in the Captain Formation

is low, in the order of 3% pore volume (PV) or less. Given the low storage

efficiency observed, a range of strategies were explored to investigate if it could

be improved. Improving the storage efficiency can potentially directly reduce the

cost of development as the pore space is used more efficiently and less wells

may be required.

In this work, storage efficiency is defined as:

Storage efficiency = Pore volume of full injected and contained CO2 inventory

Pore volume within the footprint of the plume

It can be concluded from the ACT Acorn modelling work that irrespective of the

degree of heterogeneity, the CO2 storage (displacement) process is strongly

gravity dominated; permeability is excellent, the Captain Formation is tilted, and

considerable density difference exists between brine and CO2, all of which make

the displacement gravity dominated.

This causes injected CO2 to rapidly segregate and travel underneath the cap

rock with resultant minimum contact between brine and CO2 during and post

CO2 injection periods producing low macroscopic storage (sweep) efficiency.

4.6.6.1 Overview of strategies

Several alternative strategies to improve the CO2 storage efficiency in the

Captain Formation are listed below, with an indication as to whether or not they

were modelled in this study. All strategies are used in the petroleum industry to

improve recovery efficiency which is a similar process:

• Altering the perforation strategy - studied

• Using water-alternating-gas (WAG) instead of continuous CO2

injection - studied

• Use of horizontal/deviated wells - studied

• Varying the CO2 injection rate - studied

• Use of offset brine production wells (up-dip and down-dip)- studied

• Altering the brine chemistry- studied

• Carbonated water injection - not studied

• Use of polymers- not studied

4.6.6.2 Methodology and results

To enable a direct comparison between strategies, the overall injected CO2

volume was limited to 60MT for all the strategies listed above. The fraction of

retained CO2 within the Captain X area and storage efficiency could then be

compared between different strategies.

Figure 4-41 summarises the results of applying the different strategies and

shows the fraction of CO2 stored by different trapping mechanisms right after

CO2 injection termination and 1,000 years later, with the corresponding storage

efficiency shown in red. Stacked bar charts show the same data in a different

way in Figure 4-42.

Comparison of the results for each strategy with the base case model storage

performance shows that none of the strategies investigated so far are potentially

useful for improving the CO2 storage efficiency in the Captain Formation. This is

primarily because of the exceedingly gravity dominated nature of the storage

process that lets the plume migrate to shallower depths whilst restricting

interaction between brine and CO2 post CO2 injection.



Figure 4-41: Pie charts showing fraction of free, trapped and dissolved CO2 for different strategies

The charts are for both after CO2 injection termination and 1,000 years later.

Numbers below each injection strategy respectively illustrate fraction of retained CO2

and corresponding storage efficiency (in red)

4.6.6.3 Enhancing the retention of CO2 within any proposed lease area

Enhancing the retention of CO2 within any proposed lease area was also

investigated (although no direct storage efficiency calculation was carried out).

To do this, additional pore volume that had not previously had contact with CO2

was targeted. Two options were looked at: positioning wells in new areas of the

model and by further depleting the potential trapping structures within the

storage area (i.e. Atlantic and Cromarty fields) to create additional pore volume

for CO2 storage.



Figure 4-42: Bar charts showing fraction of free, trapped and dissolved CO2 for different strategies

Well placement alteration

Regions into which CO2 has not been able to propagate can be regarded as

additional targets for CO2 storage in Acorn CO2 storage site and this can be

achieved with appropriate well placement. To investigate this strategy, the two

injection wells present in the model used to investigate storage efficiency were

relocated to several different injection locations and the impact of their relocation

was analysed.

Ten different well placement scenarios were constructed and simulated.

Additionally, the final CO2 inventory was increased from 60MT in the base case

storage efficiency model to 90MT, i.e. each well now injects 45MT of CO2 for 30

years at 1.5MT/year each. Figure 4-43 show the final results in terms of ultimate

retained CO2 in the Captain X area (based on the ETI work), north west and

south east structures (top rows images), and the distribution of stored CO2 due

to different trapping mechanisms (bottom row of Figure 4-43 ).

Overall, the results show that altering well placement may improving retention

of the CO2 within a proposed lease area (in this case, the same Captain X area

as was used in the ETI SSAP work).



Figure 4-43: Fraction and distribution of CO2 for different well placement strategies

Top rows: Fraction of retained CO2 in different regions of the model. Bottom rows:

Distribution of CO2 due to different trapping mechanisms 1,000 years after cessation

of CO2 injection

Deliberate depletion of Atlantic and Cromarty Fields

Another strategy for enhancing the retention of CO2 within any proposed lease

area was investigated. This strategy involved producing the remaining gas in the

Atlantic and Cromarty fields to release additional pore volume for CO2 storage

and to reduce the impact of CO2 mixing with the remaining gas in these gas

fields, which may have undesired effects as discussed earlier (Section 4.6.4.3).

This strategy may also resemble an Enhanced Gas Recovery process where

the remaining hydrocarbon gas is produced via CO2 injection, although its

application depends on the availability of infrastructure.

Modelling results show that the Atlantic and Cromarty producers are shut-in,

respectively, after 4 and 7 years of production due to excessive CO2

breakthrough, although by that time they would have produced 86 and 76 BCF

respectively. Only 0.24MT of the injected CO2 is back produced, although it is

expected and thus controlled. Figure 4-44 compares the gas saturation profile

after 1,000 years of CO2 injection between the base case model and Atlantic

and Cromarty depleted versions. The extent of the gas plume in the case where

the Atlantic and Cromarty fields are depleted is much smaller than in the base

case model. This illustrates that the ultimate storage capacity could likely

increase considerably beyond the 60MT because of additional pore volume that

becomes available because of further depleting these fields. Whilst interesting,

this option is practically and economically challenging due to the costs

associated with producing, treating and exporting this gas.



Figure 4-44: Comparison of final gas saturation profiles

Comparison between the base case (above) and Atlantic and Cromarty (A&C)

depleted alternatives (below), 1,000 years after cessation of injection (60MT CO2

injected).

4.7 Containment Characterisation

4.7.1 Storage Complex Definition

The Acorn storage complex includes a large proportion of the Captain

panhandle and extends from the Blake oil field in the northwest, down beyond

the Goldeneye depleted gas condensate field in the southeast, as shown in

Figure 4-45.

The vertical limits of the complex are bound by the Base Cretaceous depth

surface below and the Top Lista Shale Formation above. The Top Lista Shale

is the secondary caprock of the storage system, providing an additional barrier

between the storage reservoir and the seabed.

Laterally, the limits of the complex were defined based on the geological and

dynamic modelling. Due to poor seismic imaging, uncertainty exists in the pinch-

out of the Captain Sandstone and the exact location of the West Halibut Fault.

To take this into account, the storage complex boundary has been extended by

~2km. There is no Captain Sandstone present on the Halibut Horst.

The dynamic modelling indicates that the Phase 1 base case CO2 volumes of

4.2MT can be safely stored within this area. Subsequent build out phases can

also be safely stored, including Phase 3 (volumes of 152MT of CO2). For Phase

3, some of this CO2 will eventually reach the Blake oil field, but not until many

years after its anticipated cessation of production.



Figure 4-45: Acorn CO2 storage site storage complex outline

4.7.1.1 Top, base and lateral seal

Immediately overlying the Top Captain Sandstone is a thick interval of Carrick

and Rodby Formation mudstone and shales which have been chosen as the

primary caprock interval (Figure 4-46 and Figure 4-47 – both from Pale Blue Dot

& Axis Well Technology (2016)). The thickness varies across the storage site

from approximately 30m to over 120m (circa 90 to >400 ft). These are a proven

effective seal for many hydrocarbon fields within the main Captain Fairway.

There is some evidence of seismically visible small-scale faulting within the

Captain Sandstone. These faults are limited in vertical extent and do not offset

the overlying Rodby/Carrack formation. Within the Captain Sandstone fault

throws appear to be small and due to sand on sand contact on either side of the

faults it is not expected that they will provide a significant barrier or baffle to the

flow of CO2. The calcareous marls of the overlying Hidra Formation provide

additional primary store containment.

Figure 4-46: Primary and secondary containment

Where the Captain Sandstone pinches/ shales out on the southern and northern

margins of the fairway, the lateral seal is also provided by the mudstones of the

Valhall Formation as proven by the Goldeneye Field. Due to poor seismic



quality, there is uncertainty associated with the exact location of this pinch out

edge, however there is good well control in places which demonstrate that this

pinch out can be very rapid. An example of this is the 20/01-11 well which

contained no Captain Sand, whilst the side-track less than 1km to the North

contained over 20m (60ft) of net sand.

The Captain fairway is open at both ends, to the north west the sands open out

into the pan handle, and to the south east the sand fairway continues towards

the Hannay oilfield. The base seal is provided by the underlying mudstones of

the Valhall Formation.

4.7.1.2 Hydraulic communication

As can be seen in Figure 4-47, the Upper Captain D Sandstone is laterally

extensive across the full fairway. Lateral connectivity across the fairway within

this zone is expected to be good due to evidence of pressure communication

between producing hydrocarbon fields in this interval. The lower Captain A sand

is more restricted in distribution and has poorer lateral connectivity. Injection will

be in the Captain D Sandstone.

Below the Captain Sandstone, the base seal is provided by mudstones of the

Valhall Formation, which has some thin sand interbeds which are not expected

to be laterally extensive and are at least 25m (80ft) deeper than the Captain,

separated by mudstone.

Below the base Captain Sand are reservoir quality sands of the Coracle and

Punt, which do not appear to be in hydraulic communication with the Captain

Sand. The deeper Upper Jurassic Burns sand intervals (e.g. those of the single

well (14/26-8) Solitaire development below the southern part of the Atlantic field,

where they sit 464ft below the top of the Captain Sandstone and 235ft below the

Base Captain Sandstone) appear to be hydraulically isolated from the Captain

sands, (Pale Blue Dot Energy & Axis Well Technology, 2016). During future

work, the continued isolation of this sand should be carefully considered.



Figure 4-47: Well correlation

4.7.1.3 Overburden model

In the ETI SSAP study, an overburden model was built over the same area as

the static model. For more information, please see the ETI SSAP Captain X

Development Plan, (Pale Blue Dot Energy & Axis Well Technology, 2016).

4.7.1.4 Geomechanical analysis and results

4.7.1.4.1 Previous Work

Geomechanical modelling of the primary store was carried out in the ETI SSAP

study to confirm the strength of the storage formation and its ability to withstand

injection operations without suffering mechanical failure at any point during

those operations. No significant issues of drill ability, fracturing risk or sand

failure risk were identified. Further details are included in Section 3.6.6 of the

ETI SSAP Captain X Development Plan.

4.7.1.4.2 ACT Geomechanical Analysis

As part of the ACT work programme, the tensile strength of the Captain

Sandstone was investigated in a rock laboratory using core samples. This is

described and discussed in more detail in ACT Acorn Deliverable D06

Geomechanics, (Pale Blue Dot Energy and University of Liverpool, 2018), with

a short summary presented in this section.

The failure of a wellbore surface by tensile fracturing can be induced when fluid

pressures overcome the rock tensile strength and/or the local least principal



stress. This process is known as hydraulic fracturing and can be purposely

performed to increase the transmissibility of rock, when used with proppants, for

hydrocarbon extraction (shale gas) and geothermal fluids. However, these

tensile fractures can result in an unstable wellbore which may hamper long term

fluid injection and borehole integrity. To sustain prolonged injection operations

and preserve borehole integrity such as is required for CO2 storage, which would

operate over several decades, fluid pressures must be maintained at conditions

below the tensile failure strength of the reservoir rock.

The geomechanical study carried out investigated the tensile strength of the

Captain Sandstone.

The geographic location of the sampled wells, 14/26-1; 14/26a-6; 14/26a-7, 7A;

and 14/26a-8, correspond to the proposed primary CO2 injection site. The depth

intervals chosen for sampling for each respective well were chosen according

to number of parameters, including: availability of core, depth, occurrence in the

oil/water-leg; porosity; and general lithological variation, as determined from

hand specimen observations, gamma ray and density wireline logs.

4.7.1.4.3 Geomechanical Testing Methods

The indirect (also known as Brazilian) tensile testing of rock cores is

accomplished by applying diametric compressive stresses on two opposing

curved surfaces of a rock disc. This generates a uniform tensile stress on the

plane containing the axis of the disc and the loaded surfaces, producing Mode

I- tensile fractures through the test specimen, replicating the stress conditions

of hydraulic fracturing.

The tests detailed in this study were conducted using a uniaxial press in a

Brazilian test jig. The specimen (within the test jig) is compressed unconfined

(σ2 = σ3 = 0) between a fixed plate and hydraulic piston at a constant loading

rate and at room temperature. The applied load is measured using a load cell

(Tedea-Huntleigh compression load cell, model 220, grade C4), the load signal

is fed through a National Instruments USB-6210 (analogue to digital convertor)

to a computer were the load signal is recorded using LabVIEW software. These

tests were undertaken according to ASTM D3967-08 (2008) standards.

The Brazilian Test Jig is comprised of two blocks of mild steel that house curved

bearing platens (D2 steel, hardened to HRC 60), this curvature reduces contact

stresses on the specimen. The top block contains a hemispherical seat that

houses a chrome ball upon which sits a bearing block, this configuration

prevents asymmetric loading once in contact with the uniaxial press’ upper fixed

plate. Test specimens were comprised of 18-38 mm diameter discs with

thickness-to-diameter ratios between 0.5- 0.75, sampled from half cores rounds

of the Captain Sandstone.

Larger diameter specimens were used for the most friable material to increase

the accuracy of measurement of failure on the load cell, with smaller specimen

diameters failure occasionally occurred close to the maximum resolution of the

load cell (± 20 N). The tensile strengths of these larger diameter specimens had

a close correspondence to that of the smaller specimen diameters, once

calculated using Equation 1, and served to validate the measurements

performed on smaller diameter specimens.

The calculation of the splitting tensile strength of the test specimen is achieved

through the following equation:

σt = 2P/πLD (1)

where σt is the splitting tensile strength (STS) in MPa, P is the maximum force

applied indicated by the load cell in N, L is the length of the specimen in mm and

D is the diameter of the specimen in mm (D3967-08, 2008).



4.7.1.4.4 Results

Due to the variability in the experimentally derived splitting tensile strength

values several repeat tests for some depth intervals has been repeated. The

original conventional core analysis (CCA) porosity measurements, helium

porosity at ambient conditions, were included in this data set as porosity

indicates the degree of cementation and thus tensile strength. To check CCA

porosity analyses several porosities were measured on the test specimens using

a helium pycnometer in the University of Liverpool (UoL)-Rock Deformation

Laboratory. These porosity values matched well with the closest corresponding

CCA porosity data, which were measured approximately every foot.

Overall the tensile strength for the Captain Sandstone is low, specimens from

the gas/water-legs in the sampled wells range between <1-7.4bara, oil-saturated

specimens range between 2.7-7.4bara, and calcite-cemented specimens 32.8-

44.9bara. The specimens sampled from the gas/water-legs represent the

majority of the Captain Sandstone with core analyses showing porosities of

15.7-34.4% (average 27.45%). More cemented horizons occur throughout this

high porosity sandstone, <1.5 ft thick in the cored material, composed of calcite-

cemented sandstone with porosities ranging between 2.7-13.9% (average

5.89%).

4.7.1.4.5 Discussion

As evidenced previously, porosity and thus the degree of cementation appears

to control the tensile strength of the Captain Sandstone member. The majority

of the Captain X Sandstone is of high porosity (average 27.45%) sandstones

with low tensile strength. In a histogram of the high porosity Captain Sandstone

splitting tensile strengths (STS <7.4bara), the mean is 2 ± 0.19bara and

standard deviation is 1.6bara. Calcite-cemented doggers occur throughout the

sandstone but are of limited thickness, <1.5ft, and likely laterally discontinuous,

as such they are unlikely to influence CO2 injection operations greatly.

If, during injection, the fluid pressures exceed the least principal stress and/or

the tensile strength of the rock, tensile fracturing (hydraulic fracturing) may occur

(Zoback, 2007). This pressure/stress threshold for fracture is known as the

formation fraction pressure and may be overcome if the rate of fluid flow into the

formation away from the injection site is exceeded by the fluid supply. Such a

situation would allow pore fluid pressure to build, resulting in stresses that may

deform the rock.

The fracture gradient is the pressure/stress gradient required to fracture the rock

at a given depth, this increases with depth due to increasing overburden

pressure, (Schlumberger, 2018). There is currently no consensus in the

petroleum industry on the calculation of the fracture gradient, some use the least

principal stress gradient, and others the maximum leak-off pressure gradient

(fracture breakdown pressure gradient) or the fracture initiation pressure

gradient, (Zhang & Yin, 2017). Knowledge of the tensile strength of the rock in

a formation gives us a further constraint on the fracture gradient when used in

conjunction with the least principal stress and leak off test results.



As the Captain Sandstone is very friable and poorly cemented fracturing will

likely be accompanied by extensive disaggregation of the wellbore. This

disaggregation may hamper injection as porosity and thus permeability is lost

around the injection depth interval as loose material accumulates. Therefore,

keeping fluid injection pressures below this threshold, i.e. the fracture gradient,

is required.

4.7.1.4.6 Conclusions

The Captain Sandstone, within the formation gas and water-legs, is composed

predominantly of high porosity sandstone with low tensile strength, mean of 2 ±

0.19bara.

These tensile strengths correlate well with the porosity of the sandstone, high

porosities (average 27.45%), and thus low degrees of cementation, result in low

tensile strengths.

Stronger horizons exist throughout the sandstone, including calcite-cemented

doggers, <1.5ft thick with average porosities of ~5.89%, and oil-saturated

sandstones.

4.7.1.5 Geochemical degradation analysis and results

Geochemical modelling of the potential degradation of the cap rock lithologies

when exposed to CO2 for long periods of time is presented in Section 3.5.2.5 of

the ETI SSAP Captain X development plan, (Pale Blue Dot Energy & Axis Well

Technology, 2016). The conclusion of this work suggests that Rodby Formation

seal failure is unlikely to be induced by mineral reactions with the CO2.

4.7.2 Engineering Containment

For CO2 to be safely contained in the Captain sandstone, caprock integrity is

key. Engineering containment risks primarily include the risk of any caprock

damage through the application of excessive pressure (fracturing) or the failure

to maintain an effective seal in the wells that penetrate the caprock. A summary

of the engineering containment assessment of the Captain X area is provided in

this section. For a full description, please refer to Section 3.7.2.2 in the Strategic

UK CO2 Storage Appraisal Project Captain X development plan, (Pale Blue Dot

Energy & Axis Well Technology, 2016).

In general, abandonment practices for wells have become more rigorous over

time, and so older wells (especially pre-1984) pose a greater potential leakage

risk. Wells drilled for hydrocarbon production in the same formation as the

storage site will generally have higher abandonment practices, to ensure no

hydrocarbon movement to the seabed. Where wells are drilled for a deeper

target than the storage formation, or have found no hydrocarbons, there is a

greater chance that these will have poorer abandonment practices and

potentially less barriers between the storage reservoir and seabed.

4.7.2.1 Engineering containment assessment

For the Captain X injection area, a total of 59 wells were plugged and

abandoned. A detailed risk assessment was performed in the ETI SSAP work

using the historical well data in the CDA data base. These data include the Final

Well Reports or Abandonment Reports for the legacy wells.

A selection of 8 representative legacy wells was chosen for this review, some

from within the plume areas and some from the wider complex area. The review

is summarised in Table 4-23, extracted directly from the Captain X Storage

Development Plan (Pale Blue Dot Energy; Axis Well Technology, 2015). The

abandonment year for the 8 legacy wells ranges from 1979 to 2007 (over 25

years) and cover a range of abandonment specifications. A detailed review of

every legacy well will be undertaken prior to final investment decision.



Well UKOOA or API

Target Above/Below/In Primary Store

Specification Comments

13/24b-3 1997

Issue 0 - 1994

In store depth Meets

Cased hole well with 3 cement plugs. Lower plug across perforations in 95/8’’ casing. Second plug immediately above and lapped with annulus cement. 95/8’’ casing cut at 1369ft and shallow set cement T-plug set inside both 95/8’’ casing and 133/8’’casing. Shallow set plug lapped with annulus cement. Plugs supported with either viscous pill or bridge plug. Store depth at reservoir target and isolated 2 cement plugs. Meets spec – with 2 cement plugs above store.

13/30-1 1981

API RP 57

Below Fails

Openhole well with 3 cement plugs. Lower plug in openhole section across reservoir. Two cement plugs in 95/8’’ casing but not lapped with annulus cement. Both casing cement plugs not supported with bridge plugs. Hydrocarbon sands. Store depth above reservoir target and isolated with plugs #2, #3. Does not meet spec – no annulus cement.

13/30-2 1984

API RP 57

Below Fails

Cased hole well with 3 cement plugs. Lower plug filled bottom of well and across perforations, Middle plug supported with bridge plug and lapped annulus cement. Cement plug #3 not supported with bridge plug and no annular cement. Hydrocarbon sands. Store depth above reservoir target and isolated with 2 cement plugs. Does not meet spec – shallow set cement plug not lapped with annulus cement.

13/30a-4 1998

Issue 0 - 1994

Below Meets

Openhole well with 4 cement plugs; 3 plugs in openhole section and one cement plug at 13 3/8” casing shoe. Casing cement plug lapped with annulus cement. All plugs supported with viscous pill. Water wet sands. Store depth above reservoir target and isolated with plugs #3, #4. Meets spec with two permanent barriers above store depth.

13/30b-7 2007

Issue 2 - 2005

Below Meets Openhole well with one cement plug placed across 13 3/8” shoe and lapped with annulus cement. Water wet sands. Store depth above reservoir target and isolated with one cement plug. Meets spec with one barrier for isolation of water zone.

14/26-1 1979

API RP 57

Below Meets

Openhole well with 3 cement plugs and additional bridge plug. Shallow set cement plug lapped with annulus cement. Oil and water bearing zones. Store depth above reservoir target and isolated with cement plugs #2, #3. Meets spec with 2 cement plugs above store depth.

14/26a-6 1997

Issue 0 - 1994

In store depth Meets

Cased hole well with 3 cement plugs. Lower plug set across perforation in 7” liner and to 800ft above. Second plug in 95/8’’ casing and lapped with annulus cement. Shallow set cement plug in 95/8’’ casing and lapped with annulus cement. Meets spec with 2 cement plugs above store depth.

14/26a-7A 1999

Issue 0 - 1994

Below Meets

Openhole well with 4 cement plugs. Lower 2 cement plugs in open hole section. 3rd cement plug at 13 3/8” casing shoe. 13 3/8” casing cut at 676ft and shallow set cement T-plug set in 20” casing. Store depth above reservoir target and isolated with 2 cement plugs both lapped with annulus cement. Meets spec with 2 cement plugs above store depth.

Table 4-23: Summary of 8 Captain X area legacy wells reviewed in detail



In Table 4-23, well 13/24b-3 (1997) is an example of an abandoned well that

meets the specification. The target sands are the same as the store depth at

4,987ft MDBRT in the 95/8” casing and are isolated with 3 cement plugs. The

first plug is across the perforation and supported with viscous pill. The second

cement plug is in the 95/8” casing immediately above the first plug. The 95/8”

casing is cut at 1369ft and the shallow set cement T-plug is set inside both the

13 3/8” and 95/8” casings and supported with a bridge plug. All cement plugs are

lapped with annular cement. The second and third cement plugs have been

tagged and tested.

However, well 13/30-1 failed to meet the specification and is reliant on only one

barrier as the shallow set cement plug is not lapped with annulus cement. Well

13/30b-7 was found to be water wet and meet the spec at that time. However,

for a CO2 storage site, it is reliant on only one barrier, which presents a risk to

containment. The recent dynamic modelling results for ACT Acorn indicated that

by moving the injection site CO2 plume contact with well 13/30b-7 can be

avoided completely.

4.7.3 Containment Risk Assessment

A workshop on the containment risk assessment for the subsurface and wells

was carried out and the results are discussed in this section. The risk analysis

on CO2 leakage was conducted using a methodology which allows a fast yet

precise identification and assessment of relevant leakage scenarios. For this

workshop, the term “leakage” was used to define any undesired vertical or

horizontal flow of CO2 out of the primary reservoir (also referred to as “loss of

containment”). The storage site life span is defined as 10,000 years with an

operating life of approximately 30 years.

4.7.3.1 Methodology

The risk assessment is based on the “bow-tie” method, defining threats that may

trigger a top event occurring, which can subsequently lead to other

consequences, (Figure 4-48). Instead of threats, 11 leakage scenarios were

defined. As the top event, the loss of containment, or leakage, was chosen.

Threat barriers and methodologies to reduce the threat, and hence make the top

event less likely to occur, were also discussed. Subsequently, potential

consequences, dependent on both the pre-defined leakage scenario and on the

severity of the loss of containment, were discussed during the consequence

analysis.

Figure 4-48: Adjusted bow-tie diagram displaying the two main steps of the risk assessment: the leakage scenario analysis and the consequence analysis



The leakage scenario analysis consisted of three steps:

Definition of leakage scenarios: here, all relevant leakage

scenarios specific to the Captain X area were identified and defined.

Every identified leakage scenario can lead to a theoretical “loss of

containment”.

Identification and assessment of Features, Events and

Processes (FEPs), which relate to the possible ways in which the

system could evolve: Every leakage scenario has generic and

specific FEPs, which will either enhance or reduce both the

likelihood and the severity of the “loss of containment” to occur. A

detailed discussion of the FEPs and how they influence the risk of

leakage scenarios is the core of the leakage scenario analysis.

Identification of threat barriers: Threat barriers are active

procedures to reduce the risk of the loss of containment happening.

They are often specific to the leakage scenario. A quantitative

analysis of how much a threat barrier will reduce the risk of a

leakage scenario occurring has not been performed. Instead,

various threat barriers have been recommended.

The results of the leakage scenario analysis are displayed on a risk matrix to

quantify the likelihood and the severity of the leakage scenario occurring.

The likelihoods are in Table 4-24:

Score Likelihood Frequency

1 Very Low about once in 10,000 years

2 Low about once in 1,000 years

3 Medium about once in 100 years

4 Likely about once in 10 years

5 Very Likely about once per year or more

Table 4-24: Likelihood scale used in Leakage Workshop

The severity of the loss of containment has been defined as the volume of

leakage over the storage life span of 10,000 years relative to the CO2 present in

the storage site according to the storage plan and the scale is shown in Table

4-25. The product of the likelihood and the severity is defined as the risk.

Score Severity CO2

1 Very Low negligible

2 Low >2%

3 Medium 2.1-5%

4 High 5.1-10%

5 Very High >10%

Table 4-25: Severity scale used in the Leakage Workshop

4.7.3.2 Leakage scenario definition

Eleven relevant leakage scenarios were pre-defined for the Captain X area,

(Figure 4-49). They are subdivided into primary pathways (leakage out of the

primary reservoir into the adjacent storage unit) and secondary pathways

(leakage beyond primary pathways).



Figure 4-49: The 11 leakage scenarios considered as relevant for the area investigated

Primary Pathways:

CO2 migrating through overlying primary seal, the Rodby and the

Carrick Shale, into secondary reservoir, one of the Palaeocene

sandstone formations.

CO2 enters abandoned well and leaks to the seabed. An abandoned

well is defined as one drilled and completed before the CO2 storage

operation started, and the CO2 then leaks vertically to the seafloor.

CO2 enters a modern well, one drilled for this CO2 storage project

(injection well, monitoring well, pressure relief well, etc) or one that

has been drilled through a CO2 storage site (e.g. for future

petroleum activity) and the CO2 then leaks vertically to the seafloor.

As 2, but CO2 leaks into the secondary reservoir (Palaeocene

sandstone formations).

As 3, but CO2 leaks into the secondary reservoir (Palaeocene

sandstone formations).

CO2 leaks by migrating along the primary reservoir formation, the

Captain sandstone, out of the storage complex in a north-westerly

direction into shallower areas. Migration towards the deeper south-

east is excluded because CO2 will not migrate down-dip.

CO2 leaks by migrating into depleted, underlying Jurassic

formations under production via leakage pathways, such as wells.

Secondary Pathways:

As 1, 4 and 5 but, additionally, CO2 migrates along secondary

reservoirs (Palaeocene sandstones) out of the storage complex.

As 1, 4 and 5 but, additionally, CO2 leaks across the secondary seal

into the overburden.

As 6 and 8 but, additionally, CO2 reaches the seafloor either via a

fault cross-cutting the primary and secondary reservoir or by

migrating all the way along the primary and secondary reservoirs

until they reach the seafloor.

As 9 but, additionally, the CO2 keeps migrating through the

overburden to the seafloor.

4.7.3.3 Consequence analysis

Consequences are traditionally displayed on the right-hand side of the bow-tie

diagram. In the presented method, they are not necessarily directly related to

the severity of the top event but are strongly influenced by the definition of the



leakage scenario. Consequences are sometimes, but not always, subject to and

hence dependent on the interpretation of the outcome of a leakage scenario.

Impact Low Medium High

Storage Security

CO2 migrates inside the storage complex or does not reach shallower formations.

CO2 reaches the shallow overburden.

CO2 reaches to the seabed.

Social Acceptance

Not present in the public discussion and no coverage in the media. Covered in the scientific community.

Present in the local news; policy and industry are aware

Nationwide coverage, headline news and broad debate in the public

Environment Minor damage, no threat to the environment.

Local damage, certain threat to flora and fauna and, if any, minor restitution required.

Widespread damage with major risk for the environment; major restitution required.

Hydrocarbon Industry

Negligible impact, strategy plans of hydrocarbon industry do not need adjustment.

Small to medium adjustments may be required.

Major change of industry operations, including long delays and significant costs.

Costs Negligible costs < £10 million > £10 million

Table 4-26: Summary of categories and grades of consequences

Consequences deriving from a leakage scenario with a very low likelihood must

still be regarded as occurring within a reasonable timeframe. The impact of a

consequence is not connected to the likelihood of the leakage scenario

occurring. Consequences considered for the workshop are summarised in Table

4-26.

The impacts of consequences were displayed on a spider diagram (Annex 3:

Leakage Workshop Spider Diagrams) and have three grades: low, medium

and high, (Govindan et al., 2018).

• Impact on storage security: this consequence is pre-defined in the

leakage scenario. It defines where the CO2 leaks to.

• Impact on social acceptance: this is estimated by the assumed

media coverage, such as in print, broadcast or online news outlets,

and intensity of the debate after loss of containment has occurred.

Social uproar due to the loss of containment can be one of the main

consequences, which not only compromises ongoing projects but

also future projects.

• Impact on environment: this summarises the expected

environmental damage on flora and fauna, including the seafloor.

• Impact on hydrocarbon industry: here, the impact on all aspects of

the hydrocarbon industry, such as the production of fields nearby, is

assessed.

• Costs: costs directly related to the loss of containment, such as

remediation-actions, loss of storage licence, etc.



4.7.3.4 Results and conclusions

Risk Analysis

Figure 4-50: Summary of the risk of all leakage scenarios; primary pathways in black and secondary pathways in purple

Figure 4-50 shows the results of the risk analysis. In summary:

• No high or very high severity or high or very high likelihood events

were identified.

• 10 of the 11 scenarios have a severity less than three (medium)

which corresponds to low volumes of CO2 relative to the injected

inventory.

• Leakage scenarios with a likelihood of three (medium) or higher

include potential leakage along abandoned wells.

• Loss of containment into the Palaeocene is due to a combination of

abandoned wells and the chalk lithology.

• If the CO2 were to reach the shallower Palaeocene sandstones, it is

likely that it would migrate west and reach 800m depth. The

timescale for this is uncertain.

• Loss of containment of CO2 across geological formations (Leakage

Scenarios 1 and 6), is generally less likely than loss of containment

along wells (Leakage Scenarios 2, 3, 4, 5 and 7).

• Leakage Scenario 6 (lateral loss of containment out of the storage

complex) has the greatest potential CO2 inventory associated with

this loss of containment and hence the greatest severity.

• All leakage scenarios using secondary pathways are expected to

show rather sporadic, negligible volumes of leakage relative to the

injected volume and hence a lower severity.

Consequence Analysis

Figure 4-51 provides a summary of the consequences of all leakage scenarios.

The impact of a consequence is not necessarily connected to the severity

(defined as the volume of leakage over the storage life span of 10,000 years

relative to the CO2 present in the storage site according to the storage plan) of

a leakage scenario, but rather to the leakage scenario itself. For example, small

amounts of CO2 (low severity) to the seafloor will have higher impact on public

acceptance than moderate amounts of CO2 (moderate severity) deep in the

subsurface.



Figure 4-51: Summary of consequence impact of all leakage scenarios

The following observations can be drawn about the consequences:

• The scenarios with the greatest consequence relate to CO2 reaching

the seabed (scenarios 2, 3, 10 and 11). Some of these

consequences might involve penalties, loss of EUAs, environmental

damage and remediation costs.

• The scenarios with the lowest consequences are when CO2 remains

within the storage complex, does not impact other subsurface users

and does not require expensive remediation. Scenario 7 has the

lowest overall consequences for these reasons.

• The greatest cost relates mainly to any remediation that would be

required and any fines for loss of containment that may be incurred.

• Impact on public acceptance is directly linked to the location of the

CO2 – if it is within the subsurface but out with the storage complex,

there is still some impact. A leak of CO2 to seabed would have the

greatest impact on public acceptance.

• The consequence of environmental damage only occurs when CO2

reaches the seafloor.

• The impact of a loss of containment of CO2 on the hydrocarbon

industry is generally low. Appropriate care should be given to any

future hydrocarbon development wells penetrating a CO2 storage

site e.g. drilling a deeper target.

Some examples of mitigations include:

• Monitoring of the storage site prior, during and after injection (see

Section 4.7.4) to detect any irregularities early on.

• Limit injection to 90% of the estimated fracture pressure of the

caprock.

• Inject deeper within the reservoir to reduce plume footprint.

• High standards of drilling and completion and quality control to

ensure these standards are in place.

• Future work / research:

o A range of “worst case” modelling studies to consider known

uncertainties and knowledge gaps.

o Detailed modelling of CO2 flow along shallower secondary

containment (Palaeocene) formations.

o Fault seal analysis to assess the likelihood of fault

reactivation and faults as leakage pathways.

o Numerical modelling of sensitivities around CO2 flow along

an open well to surface.

Storage

integrity

Public

acceptanceEnvironment Cost

Hydrocarbon

industry

Scenario 1 Low Medium Low Medium Low

Scenario 2 High High Medium High Low

Scenario 3 High High Medium High High

Scenario 4 Low Medium Low High Low

Scenario 5 Low Medium Low High High

Scenario 6 Low Low Low High Low

Scenario 7 Low Low Low Low Medium

Scenario 8 Low Medium Low High Low

Scenario 9 Medium Medium Low Medium Low



Consequence



4.7.4 MMV Plan

Monitoring, measurement and verification (MMV) of any CO2 storage site in the

United Kingdom Continental Shelf (UKCS) is required under the EU CCS

Directive (The European Parliament And The Council Of The European Union,

2009) and its transposition into UK Law through amendments to the Energy Act

2008 (Energy Act, Chapter 32, 2008) in 2010 and 2011. A comprehensive

monitoring plan is an essential part of the CO2 Storage Permit.

A list and description of the offshore technologies is in the ETI SSAP Captain X

Storage Development Plan Annex 5 - MMV Technologies, (Pale Blue Dot

Energy & Axis Well Technology, 2016), which has been pulled together from two

reports, (National Energy Technology Laboratory, US Department of Energy,

2012) and (IEAGHG, 2015). Many technologies which can be used for offshore

CO2 storage monitoring are well established in the oil and gas industry.

An MMV Plan was designed for the Captain X storage site in the ETI SSAP

study and has been revised for Phase 1 of the Acorn CCS Project. The outline

corrective measures plan (CMP) discussed in Section 4.7.4.2 has been kept

consistent with previous work. For more detail, including about the purposes of

monitoring and the different monitoring phases and domains, please refer to the

ETI SSAP Captain X Storage Development Plan, (Pale Blue Dot Energy & Axis

Well Technology, 2016).

Additional work will be carried out in the Concept and FEED phases to further

refine and update the MMV plan.

4.7.4.1 Outline Base Case monitoring plan

The outline monitoring plan has been modified from the plan developed for the

ETI SSAP project. The main change is related to the frequency of the 3D seismic

surveys. Since the volumes injected in Acorn Phase 1, which start at 200kT/yr,

are small, the current plan is for 1 x baseline 3D seismic survey to be carried out

prior to injection and 1 x 4D seismic survey to be carried out once injection has

ceased. If subsequent project development phases are sanctioned, with greater

injection rates, the MMV plan will be updated during development planning.

1 x well intervention is planned for Phase 1 and a wireline logging suite will be

run at this time to provide additional data for monitoring.

A distributed temperature sensor (DTS) and pressure and temperature (P/T)

gauges are planned for the injection well. These will provide continuous data

throughout injection.

The frequency and spatial distribution of side scan sonar and sampling of both

seabed and water column will be decided during FEED.

Before the site can be handed over to the Regulator, confidence that the plume

has stabilised must be demonstrated. Due to the uncertainties that exist over

plume migration, (please see Section 4.6 for a discussion on CO2 plume

migration), it may be that the post closure injection phase is extended beyond

20 years, with more extensive monitoring during this time. The post closure

monitoring period has been kept at 20 years but noting that this could be

extended. Annual MMV reporting to the Oil and Gas Authority (OGA) will include

information about site performance and may include commentary around any

site-specific monitoring challenges that have occurred, which could include

uncertainties over plume stabilisation. An on-going dialogue with the Regulator

will be key to managing this uncertainty.

Figure 4-52 maps the selected technologies to the leakage scenarios discussed

in Section 4.7.3. The colours correspond to those in the risk matrix in Figure

4-50.



4.7.4.2 Outline corrective measures plan

The corrective measures plan will be deployed if either leakage or significant

irregularities are detected from the MMV plan data. Examples of significant

irregularities and their implications are shown in Table 3-32.

Once a significant irregularity has been detected, additional monitoring may be

carried out to gather data which can be used to more fully understand the

irregularity. A risk assessment should then be carried out to decide on the

appropriate corrective measures to deploy, if any. It may be that only further

monitoring is required.

For the leakage scenarios discussed in Section 4.7.3 and mapped to MMV

technologies in Figure 4-52, some examples of control actions and remediation

options are shown in Table 4-27.



Figure 4-52: Leakage scenario mapping to MMV technology. The colours correspond to the risk matrix in Figure 4-50



Outline Corrective Measures

Control/ Mitigation Actions Potential Remediation Options

Leak

age

Sce

nar

io

Overburden 1 Primary reservoir to secondary reservoir

Investigate irregularity, assess risk, update models if required, increased monitoring to ensure under control

Increased monitoring to ensure under control (CO2 should be trapped by additional geological barriers in the overburden)

4 Primary reservoir to secondary reservoir via abandoned well


Increased monitoring to ensure under control. Consider adjusting injection pattern if can limit plume interaction with pre-existing wellbore. Worst case scenario would require a relief well (re-entry into an abandoned well is complex, difficult and has a very low chance of success)

5 Primary reservoir to secondary reservoir via modern well

Stop injection, investigate irregularity, acquire additional shut-in reservoir data, update models

Replacement of damaged well parts (e.g. tubing or packer) by workover. Worst case scenario would be to abandon the injection well.

8 Lateral movement out of secondary reservoir after 1/4/5



9 Primary reservoir to overburden after 1/4/5



Seabed 2 Primary reservoir to seafloor via abandoned well

Stop injection, investigate irregularity via additional monitoring at seabed and acquisition of shut-in reservoir data, assess risk, update models

Re-entry into an abandoned well is complex, difficult and has a very low chance of success. A relief well would likely be required.

10 Vertical movement to seafloor after 6 and 8

Stop injection, investigate irregularity via additional monitoring at seabed and acquisition of shut-in reservoir data, assess risk, update models

If injection well - replacement of damaged well parts (e.g. tubing or packer) by workover. Worst case scenario would be to abandon the injection well. If P&A well - a relief well may be required.

3 Primary reservoir to seafloor via modern well

Stop injection, shut in the well and initiate well control procedures, investigate irregularity via additional monitoring at seabed and acquisition of shut-in reservoir data, assess risk, update models

Replacement of damaged well parts (e.g. tubing or packer) by workover. Worst case scenario would be to abandon the injection well.

11 Vertical movement from overburden to seafloor after 9

Stop injection, investigate irregularity via additional monitoring at seabed, assess risk

If injection well - replacement of damaged well parts (e.g. tubing or packer) by workover. Worst case scenario would be to abandon the injection well. If P&A well - a relief well may be required.

Lateral 6 Lateral movement out of primary reservoir


Continue to monitor, licence additional area as part of Storage Complex if required.

U'burden 7 Vertical movement into underlying reservoir


Continue to monitor, licence additional area as part of Storage Complex if required. Worst case scenario: a relief well may be required to plug 13/7-b (re-entry into an abandoned well is complex, difficult and has a very low chance of success)

Table 4-27: Outline corrective measures plan

D07 Acorn CO2 Storage Site Development Plan Appraisal Planning


5.0 Appraisal Planning

Appraisal Drilling: Whilst some uncertainties do remain regarding the

subsurface reservoir and caprock properties, the Geomechanical research

undertaken by the University of Liverpool for the ACT Acorn CCS Project (D06

Geomechanics) has provided additional insights. Any remaining uncertainties

are not considered to currently justify the expense of an additional appraisal well.

In addition, the Captain Sandstone has undergone hydrocarbon exploration and

extraction since the 1970s, with extensive drilling, logging, coring, testing, the

results of which are mostly on the CDA. Hydrocarbon production indicates that

there is hydraulic connectivity across the fairway.

Seismic Acquisition: The PGS MegaSurvey used for the interpretation over

the Acorn CO2 Storage Site does not include “offset or angle stacks” which might

improve the quality of data in some of the more challenging areas of

interpretation. As described in the site characterisation section, the Top and

Base Captain are poor seismic reflectors due to a lack of impedance contrast

over them. This feeds into a depth conversion uncertainty and therefore

uncertainty in the Top Captain structure map and ultimate plume migration.

Other 3D seismic surveys over the Acorn CO2 storage site area have “angle

stacks” which may be a data acquisition option going forward. Another option is

to acquire new (possibly broadband) seismic, which could also provide a

baseline survey for the monitoring, measurement and verification (MMV) plan,

against which all future surveys will be assessed. Broadband seismic retains

more of the lower frequencies which helps in undertaking seismic inversion.

Before making any procurement decision, it is recommended that a modern rock

physics study and seismic acquisition modelling study is completed to confirm

whether the imaging at Top Captain can be improved upon before a decision is

taken to acquire new seismic. This should also be revisited to check the

performance of a new survey in tracking plume migration. The final investment

decision on the project is not currently considered dependent on acquisition of

a new seismic survey.

Other Appraisal Activity: Further modelling work is recommended which is

fully calibrated to well by well production and pressure data from the operators

of Blake, Atlantic, Cromarty and Goldeneye. In addition, complete well

abandonment records should be sought from Operators as not all abandonment

records are on the CDA database. It is also important to work closely with all

petroleum operators in the area to ensure that wells are abandoned to maintain

maximum subsurface integrity in the light of a potential future CO2 storage

development. This is required to eliminate any further degradation of engineered

containment risk introduced through well abandonment operations.

D07 Acorn CO2 Storage Site Development Plan Development Planning


6.0 Development Planning

6.1 Description of Development

The Acorn CO2 storage site is in the Captain Sandstone Member, part of the

Captain Fairway in the outer Moray Firth.

The current base case for the Acorn CO2 storage site development is to use the

existing 18”/16” Atlantic pipeline from St Fergus to the Atlantic depleted

condensate field, (via an acquisition from Shell).

The storage site will be developed subsea rather than using a platform, with an

umbilical to shore as the base case for providing power and control to the

wellhead. Remote technology options are currently being explored, which would

eliminate the need for an umbilical to shore.

Only one subsea well will be required with the adoption of the 4” Monoethylene

Glycol (MEG) line from the Atlantic and Cromarty pipeline for start-up and restart

operations. An infield flowline will be required from the end of the Atlantic

pipeline to deliver the CO2 to the injection site.

Figure 6-1: Key elements of offshore infrastructure

6.2 CO2 Supply Profile

As indicated previously in the Storage Development Plan, the assumed initial

supply rate for the reference case, Phase 1, starts at 200kT/yr in 2023 from the

St Fergus terminal, delivered via one injection well. The profile is shown in

Figure 6-2 as Scenario 1, with the reference case resulting in a cumulative

injection of 4.2MT CO2 over 17 years. For the dynamic modelling, the range of

possible injection rates for one well was explored, up to 1.5MT/yr.

The ACT project deliverable D02 CO2 Supply Profile, (Pale Blue Dot Energy,

2017), explored several possible CO2 supply scenarios, based on possible

future build-out of the Acorn CCS Project to include emissions from central

Scotland and importation of CO2 via ship to Peterhead port. These have been

modelled for the Acorn CO2 storage site and are described below and shown in

Figure 6-2:



one subsea injection well in the injection site between the Atlantic

and Cromarty depleted fields, starting in 2023.





2.7MT/yr.


5MT/yr (259mmscfd) via four injection wells at several injection sites,



including one near the Goldeneye depleted gas field, and brine

production for pressure management. Emissions include those in the


CO2 captured from hydrogen generation, importation of CO2 via

Peterhead Harbour (from shipping) and importation of Grangemouth

emissions via the Feeder 10 pipeline to St Fergus.

Figure 6-2: Three different CO2 supply scenarios envisaged for the Acorn project

6.3 Well Development Plan

The well engineering aspects of the Acorn storage site were provided by Axis

Well Technology, (Axis Well Technology, 2017).

For the Acorn CCS Project, the most economical development strategy is a

subsea development. The advantage of a subsea well over a platform well is

that it does not require expensive superstructure and it therefore carries

considerably lower capital costs for single well projects. If no maintenance is

expected on the well during its lifetime, the cost savings can be considerable.

One additional cost carried by a subsea well is that of the control umbilical.

Options for remote control and monitoring or reducing the umbilical length (e.g.

via a nearby platform vs shore) will be explored during Concept.

For a CCS development, the primary risks from a single subsea well

development are filtration and single-well downtime risk.

Filtration - For some injection wells, the removal of fine particulates from the

injection stream can be critical. If this is not done, then it can lead to a rapid

degeneration of injectivity as the rock pore throats are plugged with fines.

Platform wells can incorporate a filter pod on the upstream injection line,

removing any particulates carried from the pipeline. These filters can be

replaced or cleaned out on a regular basis. At present, there is no equivalent

subsea filter system. Particulate debris remains a residual risk for subsea wells

and therefore for the project. A pipeline pigging (cleaning) programme may

reduce the initial particulate loading but is unlikely to prevent long term damage

from continuous corrosion products. It is recommended this is explored more

fully in the Concept work and has been assumed every 5 years at this stage.

Downtime - Should the well suffer any problems, including temporary or

permanent plugging issues, integrity issues or control issues, the well may need

to be shut-in for a period. As a single-well development (no redundancy), this

means that no injection can take place and may require storage in temporary

tankage.



With a subsea well, the wellhead will be located close to the reservoir injection

point than for a platform well, meaning that a lower cost vertical well can be

drilled. It is preferred that the well profile through the reservoir is at a moderate

angle of 60° to increase the reservoir contact and to provide some offset of the

point of injection from the caprock penetration point. A modest build rate of 3°

per 30m has been assumed, to achieve a 60° angle through the reservoir. This

results in a kick-off point at around 1,500m and a lateral offset of around 400m

at the bottom of the well. Note that no drilling engineering has been done to

verify the suitability of this kick-off point. However, there is confidence that this

well profile can be delivered as there are several ways in which the same profile

can be achieved.

6.3.1 Well Design

The well design described in this section is for a dual completion single subsea

well, which would be suitable for both Phase 1 of the Acorn CCS storage project

(with a maximum CO2 supply rate of 281kT/year captured at the St Fergus gas

processing plant) and subsequent phases. During subsequent phases,

additional wells will be required to match the CO2 supply profile. These are likely

to be single bore wells and not dual completion wells like the initial one.

The key design criteria for the Phase 1 subsea injection well is that it must be

capable of a large range of injection capacities, starting from a relatively low

injection rate of 0.1MT/yr during start-up, ramping up to 2MT/yr over a period of

time as further injection capacity is required as subsequent CO2 sources come

on-line. Please see Sections 4.6.1 for results of the well performance modelling

and key inputs for the well design.

6.3.2 Well Construction

The following preliminary reservoir target was used for the well design, as the

proposed injector coordinates had not yet been finalised (Table 6-1):

Target Name TVDSS

(m) UTM North

(m) UTM East

(m)

GI-01 Top Captain (preliminary)

2,014 6,440,148 265,001

Table 6-1: Preliminary well location used in well design

The revised well location for the primary injector following the dynamic modelling

work is shown in Table 6-2.

Target Name

TVDSS (m)

UTM North (m)

UTM East (m)

G2 Top Captain

2,005 6,440,286 264,946

Table 6-2: Well location as determined from dynamic modelling

The conceptual directional plan for the CO2 injector has been designed on the

following basis:

• The well will be drilled as a slant well.

• The well will be drilled vertically to around 1,500m TVD.



• The well will be kicked off at around 1,500m TVD, with a planned

modest build rate of 3° per 30m, to achieve a 60° angle through the

reservoir.

• A build section will be drilled from the kick-off depth to the depth at

which inclination is sufficient to reach the identified reservoir target.

• The reservoir section will be drilled as a tangent section, holding

inclination at 60° to TD.

A deviation survey plot is provided in Figure 6-3.

Figure 6-3: Well profile to the reservoir

6.3.2.1 Well completion

Lower Completion:

The lower completion would consist of 51/2’’ stand-alone sand screens. Any

shale sections can be isolated by blank pipe (with or without external isolation

packers). This will allow the formation sands to “relax” and form a pack around

the screens. Open hole gravel pack could be considered, but as it is a more

expensive and technically complex installation operation, it is felt that the risk of



poor clean-up or inefficient installation outweighs the benefits. Note that reactive

shales are unlikely to be a risk in CO2 injection wells.

The 95/8’’ shoe would be set around 40ft to 80ft into the Captain Sandstone

formation at an angle of 60°, thereby providing some offset from the top injection

point through the screens to the penetration point. This also provides a vertical

stand-off of 20 to 40ft TVD between the top injection depth and the caprock for

thermal and fracture initiation moderation.

Upper Completion:

The upper completion consists of a dual completion 27/8’’ / 41/2’’ tubing string,

anchored at depth by a production packer in the 95/8’’ production casing, just

above the 51/2’’ lower completion hanger. Components include:

• 27/8’’ 13Cr tubing (weight to be confirmed with tubing stress analysis

work)

• 4½’’ 13Cr tubing (weight to be confirmed with tubing stress analysis

work)

• 95/8’’ Production Packer

• ‘Y’ piece connector above packer depth

• Deep Set Surface-controlled Tubing-Retrievable Isolation Barrier

Valve (wireline retrievable, if available), on the 41/2’’ ‘long string’

• Permanent Downhole Gauge (PDHG) for pressure and temperature

above the production packer

• Optional DTS (Distributed Temperature Sensing) installation

• Tubing Retrievable Sub Surface Safety Valve (TRSSSV) x 2

• Dual bore subsea production tree

The DTS installation will give a detailed temperature profile along the injection

tubulars and can enhance integrity monitoring (leak detection) and give some

confidence in injected fluid phase behaviour. The value of this information

should be further assessed, if confidence has been gained in other projects

(tubing leaks can be monitored through annular pressure measurements at

surface, leaks detected by wireline temperature logs and phase behaviour

modelled with appropriate software).

A summary well construction illustration (without DTS) is included in Figure 6-4.



Figure 6-4: Well construction illustration

The outline drilling, casing and mud programme for the well, based on the

assumption that the drilling parameters are similar to the ones considered in the

ETI SSAP study, (Pale Blue Dot Energy & Axis Well Technology, 2016), is

provided in Table 6-3. Note that the ETI SSAP study assumed platform (and

therefore dry) wells.

Section Casing Drilling Mud Comment

Surface (driven)

26" Conductor, 60m below mudline

Surface hole (20")

20’’ x 133/8’’ Cemented to the mudline

10.0ppg (seawater and viscous sweep)

Casing should be set directly below the top of the Chalk Formation

Intermediate hole (12¼”)

95/8’’ Cemented to 1000m below the 133/8’’ shoe

11.5ppg (oil-based mud)

Casing should be set 12 to 25m MD below the top of the Captain Sandstone

Production hole (8½”)

51/2‘’ Stand-alone sand screens

9.5ppg (oil-based mud)

Table 6-3: Outline well construction programme

6.3.3 Injection Forecast

For the Acorn CCS Project Phase 1, injection would commence in 2023 and

continue for approximately 17 years. The final year of injection would be 2039.

The injection forecast for the reference case starts at 200kT/yr and builds to



281kT/yr. This forecast results in a cumulative injection of 4.2MT of CO2 which

would be delivered by one injection well.

Year Rate

(kT/yr) Total (kT) Year

Rate (kT/yr)

Total (kT)

2022 0 0 2032 281 2647

2023 199 199 2033 281 2929

2024 199 398 2034 281 3210

2025 281 679 2035 281 3491

2026 281 960 2036 281 3772

2027 281 1241 2037 281 4053

2028 281 1523 2038 82 4136

2029 281 1804 2039 82 4218

2030 281 2085 Total 4218

2031 281 2366

Table 6-4: Injection profile

6.4 Offshore Infrastructure Development Plan

This chapter reviews the recommended facility to transport CO2 from St Fergus

for injection into the Acorn CO2 storage site. A review of the current CO2 injection

in offshore applications is also briefly covered.

6.4.1 Offshore CO2 Injection Facilities

The one subsea well required initially to meet the proposed injection rates will

be drilled by a semi-sub drill rig. A subsea manifold will be installed to allow CO2

to be distributed to future injection well(s). The manifold houses the subsea

umbilical termination unit (SUTU) and would also function as the subsea

distribution assembly (SDA). Control and monitoring of the manifold would come

via the subsea control module (SCM) mounted on the injection tree, which would

also control the actuated valves and monitors on the tree itself. The subsea

manifold will have a piled fishing friendly structure (shaped to minimise damage

to and from fishing gear). A subsea well is considered as both the most

economical and technically suited development concept.

The 4” Monoethylene Glycol (MEG) line from the Atlantic and Cromarty fields

may be adopted for start-up and restart operations. A new umbilical to shore is

the base case for providing control and monitoring of the tree. As mentioned

previously, remote technology options are currently being explored.

6.4.2 Overview of Pipeline Facilities

For the Acorn CCS Project, the CO2 supply will come from St Fergus where

gathered CO2 will be transported via existing pipeline to the Acorn CO2 storage

site. Figure 6-5, (BG Group, 2016), shows the target storage site along with the

available transportation facilities in its vicinity. The proposed injection site is

approximately 80km from St Fergus and approximately 8km from the end of the

Atlantic Pipeline.

The development plan will use the Atlantic pipeline and for future build out

scenarios, the Goldeneye pipeline may be required (for Phase 3).

Atlantic Pipeline

The Atlantic Pipeline (also referred to as the A&C pipeline), connected the

Atlantic and the Cromarty (A&C) fields to the St Fergus gas terminal. The

Atlantic pipeline is 78km long and 16” in diameter apart from the initial 1.2km

from the beach at St Fergus which is 18” (BG Group, 2016). The pipeline was



designed with the aim that it could serve other potential users well beyond the

CoP of the A&C fields in 2009. The nominal capacity of the Atlantic pipeline was

circa 232mmscfd, (Apache, 2017). During operation, gas and gas condensate

produced from the two Atlantic wells and single Cromarty well were routed to

the Atlantic manifold and then, via the Atlantic pipeline to the Scottish Area Gas

Evacuation (SAGE) terminal at the St Fergus gas processing plant. Section

6.4.2 shows that the pipeline can handle a rate of 5MT/yr of CO2

The statutory and public consultation on the draft decommissioning programme

for the field’s facilities took place in the autumn of 2016 with responses being

explored further pending submission of the final decommissioning programme

in 2017, (UK Government, 2017). Within the decommissioning programme, the

pipeline itself and its associated piggy-backed monoethylene glycol (MEG) lines

will be cut, flooded and remain in the place to corrode away whilst the Atlantic

manifold will be removed and brought onshore for recycling, (BG Group, 2016).

The Goldeneye Pipeline

The Goldeneye Pipeline connected the Goldeneye field to the St Fergus gas

Terminal. The Goldeneye pipeline is a 20” 130km pipeline used to transport

produced fluid from the Goldeneye field located in Block 14/29a of the UK sector

of the North Sea for onshore processing.

Goldeneye ceased production in March 2011 and has been considered for CO2

storage by its owner Shell. However, following cancellation of the Peterhead

CCS project in 2015, Shell is now progressing decommissioning plans, (UK

Government, 2017). The nominal capacity of this pipeline is around

1100mmscfd, (Apache, 2017).

The Atlantic pipeline and its respective facilities have been prioritised over the

Goldeneye pipeline for the following reasons:

• The Goldeneye field is located 30km further west of the Captain X

area which requires additional pipeline construction from Goldeneye

to the Captain X storage area.

• The maximum operating pressure (MOP) of the Goldeneye pipeline

is 132barg (compared to 170barg of the Atlantic pipeline) which is

less than the maximum Acorn CCS Project injection pressure

requirement of 160barg, (Pale Blue Dot Energy & Axis Well

Technology, 2016).

However, both remain potential options at this stage.

It is assumed that a new flowline will be required to connect the end of the

Atlantic Pipeline with the injection manifold.



Figure 6-5: transportation Infrastructure overivew

Overview of the available transportation infrastructures near the Captain X area.

Yellow area shows the approximate extent of the Captain X area

Figure 6-6, (BG Group, 2016), shows the A&C facilities.

Atlantic Pipeline Asset Status

Decommissioning plans for the A&C facilities are advanced with the

decommissioning programme submitted by BG (the operator of the A&C fields)

to the Department of Business Energy and Industrial Strategy (BEIS), (UK

Government, 2017). Since the acquisition of BG by Shell, Shell have become

operator of the Atlantic facilities.

Figure 6-6: Atlantic and Cromarty field layout

Several options were investigated by BG for reusing the A&C facilities. These

include gas storage, CO2 storage (2012-13 discussion with DECC) and sale of

facilities and infrastructure to other companies, (BG Group, 2016). According to

BG, none of these discussions have progressed, although there remains interest

by third parties in the possibility of continued preservation of the Atlantic pipeline

for transporting CO2 for offshore storage.

6.4.3 The Atlantic Pipeline

Table 6-5 shows the design parameters of the Atlantic pipeline, (Pale Blue Dot

Energy & Axis Well Technology, 2016). After formal cessation of production

(CoP) (2011), the Atlantic pipeline was cleaned and put into the Interim Pipeline

Regime (IPR) pending investigation of options to extend the useful life of this



facility. The export and MEG pipelines are trenched and mostly buried along

their length, apart from a short section at the shore approach, close to the

Atlantic manifold and at crossings which are rock covered, (BG Group, 2016).

Based on the outcome of the comparative assessment of feasible options, the

recommendation for decommissioning the offshore pipelines and umbilicals is

to leave these in place with minimum intervention, i.e. to disconnect them from

the Atlantic manifold and Goldeneye platform, cutting and removing them where

they emerge from burial and applying remedial rock cover to the cut ends to

mitigate against the risk of snagging by other sea users, (UK Government,

2017).



Parameter Value

PL ID (BEIS) PL2029

Design life 20 years

Outer diameter 16”

Wall thickness 0.61”

Material X65 Carbon Steel HFW (high frequency welded)

Corrosion allowance 3mm

External coating Concrete weight coating 40-60mm thick

Internal coating 0.075mm internal thin film epoxy coating

Cathodic protection Coating and cathodic protection (CP) anodes

Design pressure 170barg

MOP 170barg

Operating pressure 82barg

Design temperature 60/-10°C

Operating temperature 50°C

Table 6-5: Atlantic pipeline design parameters

The pipeline has been designed for a 20-year service life of which less than 4

years has been used (from 2005 to 2009) which means considerable service life

remains. The pipeline has an internal epoxy layer which further protects it from

corrosion and erosion.

Should the pipeline be reused for CO2 transportation, a full pipeline inspection

to check its integrity will be required to ensure the pipeline is suitable for CO2

transportation. This may include ROV inspection to visually inspect the status of

the pipeline, intelligent pigging, end to end testing, hydrostatic pressure testing

and finally drying. The DNV RP J202 ‘Design and Operation of CO2 Pipelines’

demonstrates the recommended requalification process for using pipelines for

CO2 transportation, (Veritas, Det Norske, 2010).

Onshore experience shows that if a CO2 leakage occur from a pipeline, the CO2

pressure and temperature will rapidly decrease, (IEAGHG, 2017). This may

impose significant thermal stress to the pipeline making it brittle. Since the

Atlantic pipeline is located offshore the situation may be different to onshore

experience, but impact of potential leaks must be thoroughly considered.

Assuming the Atlantic pipeline will be reused for CO2 storage in the Acorn

Storage Site, Section 6.4.4 investigates the expected operating condition along

the Atlantic pipeline.

6.4.4 Expected operating conditions along the Atlantic pipeline

ACT Acorn Deliverable D02 CO2 Supply Options provides a description of the

likely CO2 supply profiles for CO2 injection into the Acorn CO2 storage site. Using

the scenarios, the expected operating conditions along the Atlantic pipeline for

different supply scenarios was calculated.

6.4.4.1 Inputs and assumptions

Some assumptions have been made before estimating the actual profiles along

the Atlantic pipeline. For pipeline trajectory, it was assumed that the whole

pipeline length from St. Fergus to the Captain X area (injection site) of 87.6km

is divided into three main sections, (BG Group, 2016):



An onshore first section of 1.6km (18”) from St. Fergus terminal

(+15m elevation) to beach (0m elevation).

An offshore second section of 78km from beach (0m elevation) to

the end of Atlantic pipeline (-115m depth). The pipeline diameter for

this section is 16” except for the first 1.2km of the pipeline where it

is 18”. The pipeline resides on the seabed. Over the first 45km of

pipeline the seabed depth below sea level is assumed to drop

linearly from 0m to -90m. From the 45km mark to the 78km mark

the sea bed flattens out and the depth is assumed to drop linearly -

90m to -115m, the latter being at the end of the Atlantic pipeline.

A final third 8km 16” section of pipeline which delivers CO2 from the

end of the Atlantic pipeline to the Phase 1 injection well G02 is

assumed to lie flat.

The seabed mean temperature was assumed to be 8°C for this modelling work,

(BG Group, 2016). The CO2 temperature at the St Fergus terminal compressor

discharge was assumed to be between 10-30°C with a base case temperature

of 20°C. The Longannet FEED close out report references keeping the CO2

temperature below 29°C to avoid ductile fracture formation, (ScottishPower CCS

Consortium, 2010). Similarly, in their 2016 Basic Design and Engineering

Package report for the Peterhead CCS project, Shell referenced 124barg gas

being cooled to below 25°C to reduce ductile fracture risk, (Shell, 2016).

The pipeline has been assumed to be coated with a heat transfer coefficient of

2BTU/h.deg°F.ft2. Other extremes of heat transfer scenarios were also

investigated; a completely bare pipeline without any insulation with a heat

transfer coefficient of 20Btu/h.deg°F.ft2 and a completely insulated pipeline with

a heat transfer coefficient of 0.2Btu/h.deg°F.ft2. The CO2 stream is assumed to

be completely pure. A delivery pressure of 130barg at the injection manifold has

also been assumed. The Schlumberger software Pipesim has been used to

generate the profiles shown in Figure 6-7.

The modelling investigated the following parameters for all three injection

scenarios (discussed in the dynamic modelling section 4.6.5):

• Bare pipe

• Insulated pipe

• Discharge Temp 10oC

• Discharge Temp 30oC

For each scenario, the following plots are shown in Figure 6-7:

• Pressure vs pipeline length

• Temperature vs pipeline length

• Velocity vs pipeline length

• Pressure vs temperature

6.4.4.2 Results

Figure 6-7 shows profiles for pressure and temperature along the pipeline under

different CO2 supply scenarios. The top row of images illustrates pressure

profiles along the length of the pipeline. Starting from the St Fergus terminal

(furthest left), it can be seen that pressure increases all the way through the

pipeline toward the subsea injection site (where pipeline elevation primarily

decreases i.e. the inlet pressure is less than the outlet pressure) due to different

hydrostatic head between the two ends of the pipeline.

At the lowest injection rate (Phase 1), the frictional pressure drop component is

considerably smaller than the hydrostatic pressure increase through the

pipeline. As the supply rate increases, the extent of this observation becomes

smaller and finally, at 5MT/yr (Phase 3) scenario, the frictional pressure drop



component dominates. Now, apart from a small section of the pipeline, it can be

seen that the pressure decreases for the rest of pipeline length, all the way to

the injection site. Nevertheless, all the profiles follow the same footprint in that

no distinction can be made between different sensitivity analysis scenarios that

have been simulated.

The maximum pressure along the pipeline of 145barg was observed for the

5MT/yr scenario just at the location where the pipeline diameter decreases. This

is still well below the maximum operating pressure of 170barg, (Table 6-6).

Inspection of temperature profiles in the second row of images in Figure 6-7

show that unless the pipeline is completely insulated, the CO2 stream

temperature finally reaches the ambient water temperature (8°C). Depending on

the CO2 flow rate, this will happen in between the first 10-60km of the pipeline

length. Note that at lower CO2 supply rates, more time will be available for heat

transfer to occur between CO2 and water at the periphery of the pipeline, thus

temperature drops earlier in the pipeline length.



Figure 6-7: Operating conditions along the Atlantic pipeline

Shown for all CO2 supply scenarios. The region to the left of the dashed line in the P/T graphs (last row) show the potential hydrate formation regions



Inspection of velocity profiles on the third row of images shows that for all the

scenarios, the maximum velocity occurs at the inlet of the 16” pipeline where the

diameter of the pipeline decreases (from 18” to 16”). Except for the fully

insulated scenario (shown in green), the velocities converge to the same value

depending on the CO2 supply rate. Note that there is correlation between

velocity and temperature profiles in that as soon as temperature drops along the

pipeline, CO2 density increases and velocity decreases. For the fully insulated

scenario, since heat transfer is relatively small, the temperature does not drop

considerably and thus velocity does not decrease notably either. The maximum

observed velocity is for the 5MT/yr CO2 supply scenario which is almost 1.6m/s

(5.8km/h). For the 5MT/yr scenario, it was originally anticipated that CO2 velocity

would increase along the pipeline because of pressure drop and CO2 expansion.

However, since the CO2 temperature effect is more dominant than CO2

expansion, this phenomenon may not be observed.

Finally, the last row of images in Figure 6-7 shows the P/T cross plot along the

pipeline. Except for the fully insulated pipeline scenario, nearly all scenarios

terminate at 130barg and 8°C. The grey dashed vertical line in these figures

show the hydrate formation boundary discussed later. For now, note that the

area to the left of the vertical grey dashed line is the region where hydrate

formation is probable if water content within the CO2 stream increases

significantly.

Table 6-6 shows the inlet pressure and the maximum operating pressure

observed for each CO2 supply scenario under the base case pipeline

parameters described earlier. Note that the inlet pressure is usually the pressure

for which the CO2 compression facilities should be designed.

Overall, these profiles together with the design parameters of the Atlantic

pipeline in Table 6-5 show that all the foreseen CO2 supply scenarios can be

effectively handled by the current 16” Atlantic pipeline.

Scenario

Maximum Injection Quantity (kT/yr)

Inlet Pressure (barg)

Maximum Observed Pressure (barg)

Outlet Pressure (barg)

1 281 118.3 130 130

2 2,682 125.4 131 130

3 5,000 142.2 143.3 130

Table 6-6: Maximum operating pressure under different CO2 supply scenarios

6.4.5 Flow Assurance Considerations

Figure 6-8 shows the Pressure/Temperature (P/T) profile along the Atlantic

pipeline for the base case supply scenarios investigated in the previous section.

The data in this figure can be used to infer the likelihood of several flow

assurance considerations. This includes CO2 hydrate formation and phase

shifting between gaseous and liquid phases. Having a proper understanding of

the potential flow assurance issues helps avoid large and complex expenditures

that could occur in future.



Figure 6-8: Pressure/Temperature profile observed in the Atlantic pipeline for different supply scenarios. Arrows show the direction of the profile from St Fergus to injection site on the left. The red region is the likely hydrate formation region

6.4.5.1.1 Hydrate and ice formation

Formation of CO2 hydrate may affect the safe pipeline operation and therefore,

must and can be avoided by ensuring a CO2 quality specification is maintained.

The formation of hydrate is described and controlled by the hydrate phase

boundary.

Figure 6-8 shows the hydrate phase boundary generated for a pure CO2 stream.

The data depicted in Figure 6-8 may be used to assess the probability of hydrate

formation along the Atlantic pipeline under different CO2 supply scenarios. For

this, the red area in Figure 6-8 shows the hydrate formation phase envelope.

Although it appears that only a small portion of the P/T regions may fall in the

hydrate formation region, it must be considered that this small P/T region

corresponds to a large physical distance along the pipeline where CO2

temperature has fallen to ambient sea water. The profile shown in Figure 6-8

illustrates the worst likely scenario that could occur if free phase water for

whatever reason appears in the pipeline along the CO2 stream. Given the extent

of hydrate formation depends on the water content of the CO2 stream, the risk

of hydrate formation can be effectively managed by ensuring appropriate drying

of the CO2 prior to the CO2 entering the pipeline, e.g. to below 200ppm water

content.

6.4.5.1.2 Corrosion and erosion

Cooling and drying the CO2 stream before injecting into the pipeline also protects

the pipeline from corrosion, particularly at the pipeline inlet where CO2

temperature may be at its highest. During evaluation of the Peterhead CCS

project, Shell concluded that the pipeline inlet temperature should be maintained

below 29°C, (Shell, 2016). Injecting MEG could be a possible mitigation strategy,

however, since the direction of the flow is now reversed (i.e. is from shore to

sea), this may require MEG gathering facilities at the injection site, otherwise,

the CO2 stream mixed with MEG may be injected directly and provide further

corrosion inhibition for the wellbore and the injection facilities.

As with the corrosion, erosion is expected to be particularly important in the first

few kilometres of the pipeline since CO2 density is lower which means that CO2

velocity is higher.

6.4.5.1.3 CO2 shifting between gaseous and liquid phases

CO2 phase shifting between gaseous and liquid conditions may cause significant

sudden volume change; this is not safe and should be avoided. To minimise the

chance of phase change occurring in the pipeline, the CO2 discharge

temperature will be kept below 30°C which is less than the CO2 critical



temperature (31°C). Temperature further decreases along the pipeline due to

heat transfer between CO2 and the periphery seawater and this coupled with the

CO2 pressure remaining above the CO2 critical pressure (74bar; Figure 6-8)

means that the CO2 will always remain at dense phase throughout the pipeline

and thus the risk of phase change is minimal.

6.4.6 Conclusions on Pipeline Reuse

Several redundant hydrocarbon pipelines exist within the vicinity of the Acorn

CO2 storage site. The preferred option is to transport CO2 through the Atlantic

pipeline due to the shallower depth of the reservoir at its seaward location and

its higher anticipated throughput afforded by a higher operating pressure.

Furthermore, the line is buried for over 90% of its length and therefore protected

from scour and free span development.

The Atlantic pipeline is expected to effectively handle the anticipated CO2 profile

under all supply scenarios.

The likelihood of erosion and corrosion of the pipeline is expected to be highest

near the inlet of the Atlantic pipeline (at the shore and near shore zone) where

gas temperature is still high. This can be managed by ensuring CO2 post

compression is cooled to below 29°C prior to the pipeline inlet to avoid running

ductile fracture (RDF). No issue regarding phase change between CO2 gaseous

state and CO2 liquid is expected as the operating pressure along the pipeline is

always higher than the CO2 critical pressure.

6.4.7 A&C Manifold

The Atlantic manifold, the largest item of subsea equipment which connects the

A&C wells to the export pipeline and to the control umbilicals, is still in place, but

does not form part of this development plan and is expected to be removed as

part of the BG decommissioning programme.

The A&C manifold is a production manifold and consequently there is little

opportunity for reusing the A&C manifold unless it is recovered onshore and

converted into an injection manifold which would be costly and difficult to justify

versus the construction of a new purpose-built injection manifold.

6.4.8 A&C Umbilical

Re-use of the original umbilical does not form part of this development plan.

6.5 Operations

The Acorn CCS Project development will inject CO2 at an initial rate of 200kT/yr

in phase 1, with potentially up to 5MT/yr in subsequent phases. The number of

injection wells will vary depending on the phase of the project, ranging from one

well to four wells in later phases.

The pipeline and any infield flowlines will require regular inspection, including

surveys by remotely operated vehicles (ROV) to confirm integrity and ensure no

spans have formed.

6.6 Decommissioning

The decommissioning philosophy for Acorn will be confirmed by comparative

assessment but for the Acorn CO2 storage site is assumed to be:

• Well(s) plugged and abandoned

• Subsea infrastructure recovered and taken ashore for recycling

(manifold, Xmas tree)



• Pipeline cleaned and left in place, part end recovery and ends

protected by burial

• Pipeline spools and flowlines recovered

• Umbilical and jumpers recovered

Note that decommissioning will be in line with legal requirements at the time.

6.7 Post Closure Plan

The aim of post-injection/closure monitoring is to show that all available

evidence indicates that the stored CO2 will be completely and permanently

contained. Once this has been shown the site can be transferred to the UK

Competent Authority.

In the Captain aquifer, this translates into the following performance criteria:

1. The CO2 has not migrated laterally or vertically from the storage

complex

2. The CO2 within the structural containment storage site has reached

a gravity stable equilibrium. Any CO2 in an aquifer storage

containment site is conforming to dynamic modelling assumptions

– i.e. its size and rate of motion match the modelling results.

3. The above is proven by a post closure survey.

The post closure period is assumed to last for a minimum of 20 years after the

cessation of injection. During this time monitoring will be required.

6.8 Handover to Authority

Immediately following the completion of the post closure period, the

responsibility for the Acorn CO2 storage site will be handed over to the UK

Competent Authority. It is anticipated that a fee, estimated at ten times the

annual cost of post closure monitoring will accompany the handover.

6.9 Development Risk Assessment

This chapter will summarise new and open research questions that are of

importance for the development of the Acorn CO2 storage site. These questions

have evolved during the technical work on the Acorn CO2 storage site and are

therefore seen as recommendations for future work.

6.9.1 Key Uncertainties Regarding CO2 storage in the Acorn CO2

storage site

Abandoned wells: As is the case with many CO2 storage projects, the main risk

is related to abandoned wells. Well 13/30b-7 poses a greater risk than other

abandoned wells due to uncertainty over its abandonment state. The modelling

work has indicated that direct CO2 contact with well 13/30b-7 can be avoided

with careful injection well placement and this should be investigated further

during FEED.

Uncertainty regarding top structure map: A major source of uncertainty is

related to the seismic resolution of the top of the Captain Sandstone. The lack

of acoustic impedance contrast between the Rodby/Carrack Shale and the

Captain Sandstone results in a variable seismic response and poor seismic

resolution, which in turn results in imprecise picking of the reservoir-seal

boundary. The high acoustic impedance of the overlying Chalk can also induce

frequent multiple reflections, which adds difficulty to the interpretation of the top

reservoir. The resulting uncertainty in the top reservoir pick has a significant

impact on the accuracy of the CO2 flow modelling and plume migration.



Remaining light gas volume in the A&C fields and its saturation

distribution: Uncertainty exists with regards to the accurate saturation (i.e.

remaining volume) and distribution of remaining light gas within the gas fields

present in the Captain X area. This remaining gas may occupy a fraction of pore

volume, which could otherwise be used for CO2 storage.

6.9.2 Uncertainties Regarding CO2 Injection and Migration within

the Reservoir

6.9.2.1 Uncertainty with regards to the pressure response of the system

Pressure response is mostly important during the CO2 injection period. After the

CO2 injection terminates, the pressure build-up reduces, and buoyancy-driven

plume migration will dominate. Several uncertainties could affect the pressure

evolution during CO2 injection; the magnitude of fracturing pressure gradient,

rock compressibility and the degree of hydraulic communication between the

storage site and the greater Captain Fairway area. Experimental rock mechanics

studies, being conducted by the University of Liverpool for D06 ACT Acorn

Geomechanics, (Pale Blue Dot Energy and University of Liverpool, 2018), could

reduce this uncertainty by updating the rock compressibility and fracture

pressure in the Acorn CO2 Storage Site dynamic model. This should be explored

in the next development phase. The uncertainty related to pressure response

within the system during CO2 injection can be addressed by investigating the

effect using offset brine production wells to reduce injection-related pressure

increase. This will be of particular importance during future phases of the project,

with possible injection to the east of the Grampian Arch.

6.9.2.2 Uncertainty with regards to geological data

The storage performance post CO2 injection is mostly controlled by buoyancy-

driven CO2 migration towards the boundaries of the storage complex coupled

with the effectiveness of trapping mechanisms i.e. residual and solubility

trapping. The important parameters affecting any gravity dominated

displacement are fluid properties (i.e. density contrast between CO2 and other

phases), formation characteristics, formation tilt and, lastly, the effectiveness of

trapping mechanisms at larger time scales. CO2 trapping mechanisms may

compete with CO2 plume migration and make the plume migration slightly

slower. A list of major uncertainties in this regard, which could affect the results,

is also presented below.

Brine properties: A certain degree of uncertainty regarding true brine properties

exists in this modelling study. There is no experimental measurement of brine

in-situ properties i.e. brine density and viscosity, either in the ETI SSAP study or

the current modelling study. They have been estimated using correlations with

no supporting experimental evidence.

Formation characteristics: The Acorn CO2 storage site in general and Captain

Sandstone in particular are significantly large storage complexes. There is a

degree of uncertainty with regards to the heterogeneity of the formation

properties away from wells, which may affect the extent of plume migration post

CO2 injection.

Relative permeability data: There are elements of uncertainty regarding

relative permeability data; the base set of relative permeability data taken from

the Goldeneye field may not be representative for the entire Acorn CO2 storage

site. Additionally, core flood experiments are usually conducted in viscous-

dominated conditions. However, the CO2 flow pattern in the Captain Formation

is gravity dominated. Therefore, there is added uncertainty related to the validity

of these curves for Acorn CO2 storage site displacement conditions.



Residual trapping: The derived residual trapping fraction of 0.3 is from a

viscous core flood experiment. The dependence of residual trapping on flow

rates, especially for gravity dominated displacement, is still uncertain.

Experimental measurement of relative permeability and residual trapping under

different flow conditions on Captain Sandstone reservoir samples is required to

improve the accuracy of the modelling results.

Migration along Palaeocene formations: Uncertainty remains about possible

CO2 migration pathways within the secondary store, the Palaeocene

Sandstones. This scenario has not been addressed in detail and requires more

insight into the structure and the lithology of the Palaeocene formations as well

as a numerical analysis to quantify the consequences of this scenario.

6.9.2.3 Uncertainties with regards to modelling CO2 flow

CO2-brine interaction: There is no empirical measurement of CO2-brine

interactions in the ambient conditions of the Captain Formation. Again, CO2-

brine interaction in the Acorn CO2 storage site has been estimated using

correlations from the Eclipse300 CO2SOL model. It can be argued that, if the

simulation is repeated with another CO2 solubility model, then a different set of

results could be expected. Simulations using alternative software packages (e.g.

Tough, CMG) to benchmark the existing results is recommended.

Numerical dispersion: The impact of numerical dispersion in exaggerating the

CO2 plume migration and CO2 dissolution in the brine phase can be significant

for large reservoir models, such as the Acorn CO2 storage site. Identifying an

appropriate gridding strategy for a gravity-dominated process like one observed

in the Captain Formation could decrease the effect of numerical dispersion and

reduce the model run time.

6.9.3 Uncertainties Relating to Hydrocarbon Industry and

Infrastructure

Pipeline: Uncertainty exists over particulates (rust, organics and produced

sand) residing in the Atlantic pipeline, which could be a risk to injection. These

may need to be evaluated by remote camera and pipe condition inspection. A

pipeline pigging (cleaning) programme may reduce the initial particulate loading

but there may still be a risk around long-term damage from continuous corrosive

products. However, the pipeline is lined and so this further reduces the risk.

Additional investigation of solutions should be carried out during FEED,

including options for subsea filtration systems.

Alternative storage plan: For the unlikely scenario that the Acorn CO2 storage

site is either unavailable for CO2 storage at all or is not suitable for Phase 2

injection plans, alternative storage plans should be assessed. A key alternative

option is a more extensive evaluation of the East Mey location being undertaken

for the ACT Acorn study as a potential back-up plan.

Hydrocarbon industry: Uncertainty exists over possible future hydrocarbon

exploration in a region with CO2 storage, however on-going dialogue with OGA

will ensure best practice is carried out to minimise risk.

6.9.4 The Assessment of Leakage Risk and Appropriate

Remediation Strategies

Quantifying leakage rates: The risk analysis involved the quantification of

actual CO2 leakage rates for leakage scenarios based on expert elicitation. This

process can be subjective and suffer bias. To improve the quality of the risk

assessment, the numerical simulation of leakage scenarios is required including

sensitivity studies to assess the impact of uncertain parameters.



Mitigation and remediation strategies: Although mitigation strategies to

reduce the threat of potential leakage scenarios have been briefly discussed in

Section 4.7.3, a detailed analysis of the impact of different strategies using

numerical simulations will reduce the risk of leakage scenarios occurring.

Additionally, remediation strategies to reduce the severity and consequence

impact of leakage, such as those touched on in Table 4-27, should be explored

using simulations. A detailed corrective measures plan is an essential part of

any Storage Permit application.

6.9.5 Advanced Selection Criteria

Predicting storage development costs: Storage efficiency can have a major

indirect contribution to the cost of operations of a project: a site that appears

very suitable in principle (e.g. located close to the existing infrastructures, at an

appropriate depth and with a great capacity), but with a very low storage

efficiency, may require extra injection wells and/or water withdrawal operations

in order to reach its full potential, increasing overall costs dramatically. An

accurate assessment of storage efficiency is required to calculate the levelised

cost (i.e. the cost per stored tonne of CO2) from which storage sites maybe

selected or dismissed. However, the way in which storage efficiency is

calculated is currently not standardised. Future research efforts should focus on

determining effective methods for the calculation of storage efficiency factors.

6.9.6 Risk Assessment

The containment risk assessment considered 11 potential leakage scenarios

(Section 4.7.3). Following are the main conclusions and potential further work.

Risk Assessment Conclusions

• No high or very high severity or high or very high likelihood events

were identified.

• 10 of the 11 scenarios have a severity less than three (medium),

corresponding to low volumes of CO2 relative to injected inventory.

• Leakage scenarios with a likelihood of three (medium) or higher

include potential leakage along abandoned wells.

• Loss of containment into the Palaeocene is due to a combination of

abandoned wells and the chalk lithology.

• If the CO2 were to reach the shallower Palaeocene sandstones, it is

likely that it would migrate west and reach 800m depth. The

timescale for this is uncertain.

• Loss of containment of CO2 across geological formations (Leakage

Scenarios 1 and 6), is generally less likely than loss of containment

along wells (Leakage Scenarios 2, 3, 4, 5 and 7).

• Leakage Scenario 6 (lateral loss of containment out of the storage

complex) has the greatest potential CO2 inventory associated with

this loss of containment and hence the greatest severity.

• All leakage scenarios using secondary pathways are expected to

show rather sporadic, negligible volumes of leakage relative to the

injected volume and hence a lower severity.

Further work / research:

• A range of “worst case” modelling studies to consider known


• Detailed modelling of CO2 flow along shallower secondary




• Fault seal analysis to assess the likelihood of fault reactivation and

faults as leakage pathways.

• Numerical modelling of sensitivities around CO2 flow along an open

well to surface.

D07 Acorn CO2 Storage Site Development Plan Budget & Schedule


7.0 Budget & Schedule

7.1 Cost Estimating Basis

7.1.1 Introduction

An overview of the cost estimation process is presented in this section. This

provides context for the project cost estimate information for both capital

expenditure (Capex), operating expenditure (Opex) and abandonment

expenditure (Abex).

7.1.2 Cost Estimate Accuracy

Cost estimates are prepared throughout the various phases of a large project

development process. Estimate types are based on a standard international

approach, (AACE International, 2016), and range from Type 5 (least accurate)

to Type 1 (most accurate) as the definition of each project increases and

matures through the process as summarised in Table 7-1.

As the project moves through phases of maturation, the cost estimate should

mature in line with the project. Typically, the base estimate increases as the risk

mitigations are incorporated in to the design, the contingency becomes less as

the risks are understood and engineered out and the cost accuracy improves.

Class Project Definition (%)

Purpose Estimating Accuracy

Basis

5 0 - 2 Concept Screening

L: -20% to -50%

H: +30% to +100%

Capacity factored, Judgement, parametric models

4 1 - 15 Feasibility L: -15% to -30%

H: +20% to +50%

Equipment factored, parametric models

3 10 - 40 Budget L: -10% to -20%

H: +10% to +30%

Semi-detailed unit costs

Major equipment list

2 30 - 75 Control L: -5% to -15%

H: +5% to +20%

Detailed unit cost and material take-off

1 65 - 100 Check L: -3% to -10%

H: +3% to +15%

Detailed unit cost and material take-off

Table 7-1: Cost Estimate Class Definitions (AACEI 18R-97)

7.1.3 Cost Estimate Components and Terminology

The components of a cost estimate generally include the following items:

• Base scope costs;

• Contingency;

• Market factors; and

• Inflation



The same principles are generally applied when defining Capex and Opex

estimates.

Market factors include allowance for market escalation, i.e. experience of a Real

Terms cost increase (or decrease) because of the market volatility, over and

above the impact of Inflation. Each activity within the estimate also needs to be

uplifted to account for inflation and to estimate an equivalent cost at the time of

Project Execution.

7.1.4 Cost Uncertainty

When preparing cost estimates, contingencies are assessed to arrive at a

validity of the estimate with an accepted confidence level. Contingencies are

assigned to raise the estimate to achieve a 50% confidence level, i.e. there is

an equal chance that the 'as built' cost of the project will show an over or under

expenditure. This figure is usually referred to as the P50 estimate and is, in

statistical terms, the median of the range of possible final expenditure outcomes.

The accuracy band for a cost estimate is defined by the range of costs from the

P10 (10% probability that the project will come in on or under budget) to P90

(90% probability that the project will come in on or under budget).

7.1.5 Contingency

Contingency is added to a cost estimate to allow for further scope definition

emerging in subsequent phases, and risks which have not been identified in the

present project phase. It also covers minor design and field changes but does

not include major scope changes, such as increased throughput/concept/layout.

Pale Blue Dot Energy uses commercially available simulation tools for cost risk

analysis which apply an industry standard Monte Carlo simulation approach.

This method generates a full range of possible outcomes and their associated

probability of occurrence and is based on:

• Deterministic cost inputs and ranges;

• Probability distribution curves;

• Risks;

• Opportunities; and

• Levels of effort.

The output from the cost uncertainty modelling process provides an overall

project contingency figure and a cost uncertainty range, bounded by the P10

and P90 cost estimates.

7.2 Capital Expenditure Estimate

7.2.1 Methodology

Capital cost estimates have been taken from existing work wherever applicable

or pro-rated from similar work to give an appropriate estimate at this stage of

development. For additional detail, please see D16 ACT Acorn Full Chain

Development Plan and Budget, (Pale Blue Dot Energy, 2016).

7.2.2 Capex Estimate

The Class 4 estimate of capital required to develop Acorn Phase 1 is

summarised in Table 7-2.



Work area Net

Cost (£M)

Contingency (£M)

Gross Cost (£M)

Offshore

Concept & FEED (including inspection pig)

16.9 1.0 17.9

MMV 9.0 0.1 9.2

Pipeline 16.1 6.0 22.1

Umbilical 60.2 24.1 84.3

Subsea 11.0 4.4 15.4

Well 20.7 6.9 27.6


Onshore Onshore plant 76.5 23.5 99.9

Full Chain Total Full Chain 210.3 66.0 276.4

Table 7-2: Capex estimate

7.3 Operating Expenditure Estimate

7.3.1 Methodology

Opex has been estimated by factoring the relevant Capex estimate. The post

closure and handover costs have been included in the Abex cost estimate.

7.3.2 Opex Estimate

The estimate of operating cost required to run the Acorn project over a 20-year

period is summarised in Table 7-3.

The post closure and handover costs have been included in the Abex cost

estimate.

Work area Net

Cost (£M)

Contingency (£M)

Gross Cost (£M)

Offshore

Subsurface monitoring (MMV) 1.1 0.5 1.6

Transport and subsea 1.9 0.7 2.5

Total (per annum) 3 1.2 4.1

Total over life of the project 60 24 82

Onshore Onshore 11.9 3.6 15.5

Full Chain

Total full chain (per annum) 14.9 4.7 19.6

Total full chain over project life 298.5 94.0 392.5

Table 7-3: Opex estimate

7.4 Abandonment Expenditure Estimate

7.4.1 Methodology

These costs are assumed to be 10% of the incurred capital cost of the project

installed infrastructure and 25% of the capital cost of the well for the well

abandonment.

7.4.2 Post-closure MMV

The post closure and handover costs have been included in the Abex cost

estimate.

Post closure monitoring of the Acorn CO2 storage site is expected to be required

for a minimum of 20 years. The post-closure requirements are assumed to be



4D seismic initially after injection has ceased and seabed monitoring and

sidescan sonar every 5 years for the post closure monitoring period.

7.4.3 Handover to authority

Immediately following the completion of the post closure period, the

responsibility for the Acorn CO2 storage site will be handed over to the UK

Competent Authority. It is anticipated that a fee, estimated at ten times the

annual cost of post closure monitoring will accompany the handover.

7.4.4 Abex Estimate

The Abex estimate is shown in Table 7-4. These figures have not been adjusted

for inflation.

Work area Net

Cost (£M)

Contingency (£M)

Gross Cost (£M)

Offshore

Well P&A 5.2 2.1 7.2

Subsea, pipeline, umbilical 8.7 3.5 12.2

Post Closure 10.2 0.3 10.5

Handover 5.2 1.0 6.3


Onshore Onshore 7.6 3.1 10.7

Full Chain Total Full Chain

37.0 9.9 46.9

Table 7-4: Abex estimate

7.5 Uncertainty of Cost Estimates

The estimating accuracy associated with a Class 4 estimate is -30% / + 40%.

7.6 Schedule

The Acorn CCS Project schedule is shown in Figure 7-1.

Figure 7-1: Development schedule

2019 2020 2023 20242018 2021 2022

Concept

ACT

FEED

Final investment decision (FID)

Appraisal and planning

Start injection

Operations

Commissioning

Well operations

Subsea construction and pre-commissioning

Onshore construction and precommissioning

Engineering and procurement

D07 Acorn CO2 Storage Site Development Plan Conclusions & Recommendations


8.0 Conclusions & Recommendations

8.1 Conclusions

The work undertaken for the ACT study shows that the Acorn CO2 storage site

and corresponding development plan offers a low cost, flexible and scalable

solution for the Acorn CCS Project due to:

• Pipeline optionality - Two existing and redundant pipelines, Atlantic

and Goldeneye, both run from St Fergus to the Acorn CO2 storage

site storage complex. These can be re-used and offer cost savings

over a new-build pipeline. The re-use of the Atlantic pipeline is the

reference case for the Acorn CCS Project.

• Low cost flexible well design - A single dual completion subsea

injection well provides lower capital cost than a platform well and is

designed to handle a range of injection rates, from 0.1MT to 2MT/yr,

meaning it can be used in subsequent phases of the project.

• Scalable storage resource - Up to 152MT can be securely stored

within the Acorn CO2 storage site storage complex, providing

scalability and additional storage resource beyond the initial

(200kT/yr) Phase 1 of the project.

Data

• The work undertaken for the ETI Strategic UK CO2 Storage Appraisal

Project (ETI SSAP) was drawn heavily from and built on for the ACT

Acorn CCS Project Study.

• The seismic 3D dataset used for the evaluation of Captain Aquifer

was the PGS UK CNS Mega Survey (1990-2003), tiles F04 and F05.

It covers over 95% of the storage complex.

• There is good regional well coverage and good well data available

within the storage complex, including modern logs and core data.

• Data from 78 wells. The well data used (including well-logs,

completion and abandonment reports) were obtained from the UK

Oil & Gas CDA database.

• The core data analysed was obtained from 15 wells, mainly from the

Blake, Cromarty, Atlantic, Solitaire and Goldeneye fields.

• The geomechanical analysis (ACT Acorn D06 Geomechanics, (Pale

Blue Dot Energy and University of Liverpool, 2018)) was conducted

on wells 14/26-1; 14/26a-6; 14/26a-7, 7A; and 14/26a-8, near the

proposed primary CO2 injection site.

• Limited pressure data from operators were also used in the ETI

SSAP work, on which the Acorn reservoir engineering work has been

based.

Containment

• The primary seal is provided by the marls and mudstones of the

Rodby Formation, which is a proven seal for many hydrocarbon

fields in the area. Over the Acorn storage site it is about 90-100m

thick and in the ETI SSAP work it was mapped across the fairway.

• The storage complex has been defined as the subsurface volume

between the Top Lista Formation and Base Cretaceous, and



between the east of Goldeneye to the south east and beyond the

Blake oilfield in the north west. This has been extended since the

ETI SSAP study.

• The base seal is provided by the Valhall Formation, which consists

of shales and marls.

• In addition to a high degree of confidence that the Phase 1 reference

case of 4.2MT CO2 can be safely and fully contained within the

storage complex, there is confidence that up to 152MT of CO2 can

be contained within the Captain Sandstone in the Acorn CO2 storage

site complex for subsequent injection phases. This may require a

single pressure relief well.

• The Acorn CO2 storage site complex includes the Atlantic, Cromarty,

Blake and Goldeneye hydrocarbon fields in addition to the saline

aquifer beneath and between them. This may provide a degree of

structural containment.

• 1000 years after the cessation of injection the CO2 plume is still

contained within the Storage Complex.

• The Captain Sandstone reservoir quality is excellent and the CO2

plume is gravity dominated, due to the high vertical permeability and

low heterogeneity.

• The pattern of plume migration has been shown to be sensitive to

the structure depth map of the Top Captain Sandstone in the ETI

SSAP work, due to poor seismic imaging of the Top Captain event

and the complex velocity field in the overburden.

• A containment workshop was carried out, which determined that loss

of containment of CO2 along abandoned wells is the greatest risk for

long term CO2 storage.

• In addition, no high or very high severity or high or very high

likelihood events were identified and 10 of the 11 scenarios have a

severity less than three (medium), corresponding to low volumes of

CO2 relative to injected inventory.

• Dynamic modelling results indicate that by modifying the injection

strategy, CO2 contact with well 13/30b-7 (which has some residual

uncertainty over its abandonment state) can be avoided completely.

Site Characterisation

• The Acorn CO2 storage site complex covers an area of 971km2 of

the Captain aquifer in UKCS quadrants 13, 14 and 20, approximately

100km from Aberdeen.

• The Captain Sandstone of the Acorn storage site is a sand-rich

turbidite fan system deposited along the southern edge of the Halibut

Horst in the Central North Sea. Also known as the Captain sandstone

“pan handle”, it ranges from 5 to 10km wide.

• The rock quality of the Captain Sandstone is assessed to be

excellent. The average modelled porosity within the main Captain D

sand is 27%. The average permeability is over 1400mD and

permeability shows a strong positive correlation with the porosity. A

sand proportion of 82% is estimated in the Captain D sand.

• The vertical permeability is smaller than the horizontal permeability,

but in general no flux barriers are anticipated.

• The net to gross reduces at the edges of the Captain fairway, but this

has little or no impact on the capacity or on containment.

• The seismic characteristics of the reservoir and caprock increase the

difficulty of carrying out the depth conversion and interpretation

processes. The Top Captain Sandstone has a lack of acoustic



impedance contrast across it, which makes it challenging to interpret.

This challenge has been one of the primary issues for petroleum

developments in the area and the remaining uncertainty over the top

structure map feeds into an uncertainty in modelling plume

migration. The seismic interpretation challenges experienced on this

project have also been reported by others, (Shell, 2015).

• The depth conversion in the ETI SSAP Project was performed by

generating synthetic seismograms from 12 wells spread across the

storage complex, with eight horizons interpreted, from deeper than

the reservoir up to the seabed.

• There is no evidence of significant faulting in the reservoir or primary

caprock.

• The Top Captain Sandstone dips gently at 1-2o to the southeast, and

up to 15o in the area to the west of the injection site.

• The well density is relatively high within the site and therefore the

degree of confidence about the reservoir quality across the site is

high. Core data is available for the primary caprock, which is studied

in a parallel Geomechanics work package of the ACT Acorn Project.

• The dynamic modelling results indicate the importance of using

compositional simulation (versus black oil simulation) in correctly

addressing the mixing effect between CO2 and hydrocarbons.

Storage Resource

• The main storage unit is the Captain Sandstone of the Lower

Cretaceous Cromer Knoll Group.

• In addition to the Phase 1 reference minimum viable development

case of 4MT CO2 stored, significant volumes (up to 5MT/yr modelled)

of CO2 can be injected into the Acorn CO2 storage site, with 152MT

safely and fully contained within the Storage Complex. To store

152MT would require 4 wells and 1 pressure relief well.

• 1000 years after Phase 1 injection stops, 13% of the injected

inventory is structurally trapped, 35% residually trapped, 33% in

solution and the remaining 20% continues to be mobile, travelling at

less than 10m/year.

• Strategies for increasing storage efficiency were modelled using a

range of techniques regularly deployed in the petroleum industry.

Dynamic storage efficiency in the ETI SSAP study was limited at 1-

2% and predominantly controlled by the high vertical permeability

and structure mapping. Dynamic storage efficiency in the ACT Acorn

CCS Project could be increased to a little over 2%, but none of the

techniques modelled has significant impact. This is due to the gravity

dominated flow within the Captain sandstone.

• The Acorn CO2 storage site is an open boundary storage site.

Upward plume migration, due to gravity effects, and lack of physical

boundaries on the north west side of the storage site make additional

storage capacity improvements quite challenging in the Acorn CO2

storage site.

• The fundamental challenge for improving CO2 storage efficiency in

the Acorn CO2 storage site is the significantly gravity dominated

displacement flow pattern that facilitates vertical migration of the CO2

plume.

Appraisal

• With nearly 100 wells drilled into the Captain Sandstone aquifer, it is

considered to be widely appraised. In addition, years of hydrocarbon

production indicates that there is connectivity throughout the fairway.



• The key outstanding uncertainties are around the plume migration,

due to uncertainties in the top Captain structure map (discussed in

previous sections). This will not be resolved by appraisal drilling.

• Additional production and pressure data from operators would help

build a more thorough understanding of the regional connectivity.

Development

• Final Investment Decision needs to be in 2020 in order to achieve

the first injection date of 2023.

• The planning work indicates that approximately 2 years are required

to appraise and develop the store.

• A single subsea injection well is proposed for Phase 1 (200kT/yr),

with a dual completion (common in oil and gas operations) capable

of handling injection rates from 0.1MT/yr up to 2MT/yr as additional

CO2 sources come online. In the modelling, only the dual 3 ½’’ and

the 4 ½’’ tubing can achieve a target rate of 2MT/yr under initial

reservoir conditions. However, neither provide an option for the low

range of 0.1MT/yr.

• The dual completion has two injection tubulars run into the same

wellbore. One tubular might be considered for low injection rates, the

other for intermediate rates and both together for high injection rate.

A dual completion consisting of a 27/8“ tubing string and a 4½’’ tubing

string achieves the target injection range; however, this may require

a 103/4’’ casing.

• The existing 16” 170barg maximum operating pressure Atlantic

pipeline that runs from St Fergus to the Acorn Phase 1 injection area

can effectively handle all the envisaged CO2 supply scenarios. Flow

assurance is not a significant consideration for CO2 transportation

along the Atlantic pipeline if CO2 is dried sufficiently. The Atlantic

pipeline was installed in 2006 and ceased use in 2009 so has only

been used for a small amount of its 20-year design life.

• A £177 million capital investment is required to design, build, install

and commission the pipeline and wells for Phase 1. The operating

cost is £82 million over the 20-year project life, with an average of

£4 million per year.

Operations

• The maximum allowable reservoir pressure within the simulation

model has been constrained to 90% of the fracture pressure, which

is 283bara at the top of the perforations.

• The design assumption is 130bara arrival pressure of the CO2 supply

at the wellhead to enable injection through the life of the project. This

would require a discharge pressure of between 118bara and

142bara from the pump station at St Fergus for Phase 1 and for the

152MT (5MT/yr) cases.

8.2 Recommendations

Appraisal Programme (including Concept and FEED)

• Explore pipeline particulate debris risk.

• Explore Goldeneye pipeline as the back-up option to the Atlantic

pipeline if the Atlantic pipeline decommissioning plan progresses.

• Obtain well by well production and pressure data from the operators

of Blake, Atlantic, Cromarty and Goldeneye. Use this data to fully

calibrate the reservoir simulation model.



• Obtain full abandonment records from operators and conduct a more

comprehensive study and risk assessment of the abandoned wells

in the planned storage complex.

• Detailed well design: explore the possibility of 10¾’’ casing for the

dual completion. Although the well design was based on 95/8’’ casing

for the purposes of this study, 10¾’’ casing may be required.

Investigate including stand-alone-screens to reduce chance of sand

failure in the reservoir.

• Further investigation of transient pressure variations in the wellbore.

If significant issues are identified, a combined deep-set shut-in valve

/ choke valve, could provide the solution to the variable rates (high

injection range) required for this development.

• Explore suitable mechanism to perform downhole shut-in function

which would mitigate transient effects. However, further work is

required in the pre-FEED to substantiate this approach, or to provide

alternate solutions.

• Investigation of thermal fracturing and the effect of increasing

fracture pressure with increased pore pressure throughout the

injection process to define fracture limits,

• Evaluate the TGS-Nopec seismic volume over the Acorn CO2

storage site area. This dataset includes offset (angle) stacks that are

often useful in creating improved data quality in challenging areas.

• Undertake a modern rock physics study and seismic acquisition

modelling study to confirm whether the imaging at Top Captain can

be improved upon before a decision is taken to acquire new seismic.

This should also be revisited to check the performance of a new

survey in tracking plume migration. The final investment decision on

the project is not currently considered dependent on acquisition of a

new seismic survey.

• Further modelling work that can be fully calibrated to well by well

production and pressure data from the operators of Blake, Atlantic,

Cromarty and Goldeneye.

• Perform a full evaluation of a dual completion in GAP software.

Operational Planning

• Identify and quantify opportunities for cost and risk reduction across

the whole development, including operational efficiencies.

• Identify synergies with other offshore operations.

Development Planning

• Incorporate the regulatory licensing and permitting requirements into

the development schedule and plan.

• Work with the petroleum operators of nearby hydrocarbon fields and

the Regulator to ensure that the wells are abandoned using all best

practice to secure the CO2 integrity of the site.

• Work with the Regulator to ensure best practice in place for any

future exploration drilling near the CO2 storage site.

Future Study

This section highlights areas which require further study which could be useful

for broader industry research.

• A range of “worst case” modelling studies to consider known


• Detailed modelling of CO2 flow along shallower secondary




• Fault seal analysis to assess the likelihood of fault reactivation and

faults as leakage pathways.

• Numerical modelling of sensitivities around CO2 flow along an open

well to the overburden or surface and impact of any mitigation and

remediation strategies.

• Standardisation of calculating storage efficiency factors.

D07 Acorn CO2 Storage Site Development Plan References


9.0 References

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Captain Subsea CO2 Injector.

BG Group. (2016). Atlantic & Cromarty Decommissioning Programmes

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BG Group. (2016). Atlantic & Cromarty Fields Decommissioning Programmes

Stakeholder Engagement Report.

BG Group. (2016). Atlantic and Cromarty Fields Draft Decommissioning

Programmes.

Colley, N. M. (1999). Blake Field Petrophysics Report. BG International.

Copestake, P., Sms, A. P., Crittenden, S., Hamar, G. P., Ineson, J. R., Rose, P.

T., & and Tringham, M. E. (2003). Lower Cretaceous. Evans, D;

Graham, C; Armour, A and Bathurst, P (eds.) The Millenium Atlas:

Petroleum Geology of the Central and Northern North Sea, pp. 191-211.

D3967-08, A. (2008). Standard test method for splitting tensile strength of intact

rock core specimens. ASTM International, 3. West Conshohocken, PA.

Du, K., Pai, S., Brown, J., Moore, R., & Simmons, M. (2000). Optimising the

development of Blake Field under tough economic and environmental

conditions. International Oil and Gas Conference and Exhibition in

China. Society of Petroleum Engineers.

Eclipse 300 Reference Manual. (2016).

(2008). Energy Act, Chapter 32. Retrieved from

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n.pdf

Guariguata-Rojas, G., & Underhill, J. (2017, November). Implications of Early

Cenozoic Uplift and Fault Reactivation for Carbon Storage in the Moray

Firth Basin. Interpretation, 5(4), SS1-SS21.

IEAGHG. (2015). CCS Deployment in the Context of Regional Development in

Meeting Long-Term Climate Change Objectives.

IEAGHG. (2017). CO2 Pipeline Infrastructure. Retrieved from IEAGHG:

http://ieaghg.org/docs/General_Docs/Reports/2013-18.pdf

Jin, M., Mackay, E. J., Quinn, M., Hitchen, K., & Akhurst, M. (2012). Evaluation

of the CO2 Storage Capacity of the Captain Sandstone Formation. SPE

Europec/EAGE Annual Conference, 4-7 June. Copenhagen, Denmark:

Society of Petroleum Engineers.



National Energy Technology Laboratory, US Department of Energy. (2012).

Best Practices for Monitoring, Verfication and Accounting of CO2 Stored

in Deep Geologic Formations.

Pale Blue Dot Energy & Axis Well Technology. (2016). Captain X Storage

Development Plan - Strategic UK CO2 Storage & Appraisal Project.

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A summary of Results from the Strategic UK CO2 Storage Appraisal

Project. Energy Technologies Institute.

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Pale Blue Dot Energy. (2016). D16 ACT Acorn Full Chain Development Plan

and Budget. ACT Acorn Consortium.

Pale Blue Dot Energy. (2017). ACT Acorn D02 CO2 Supply Profile. ACT Acorn

Consortium.

Pale Blue Dot Energy and University of Liverpool. (2018). ACT Acorn

Geomechanics. ACT Acorn Consortium.

Pale Blue Dot Energy; Axis Well Technology. (2015). D05: Due Diligence and

Portfolio Selection - Strategic UK CO2 Storage & Appraisal Project. The

Energy Technologies Institute.

PBDE and Axis WT. (2016). Captain X Storage Development Plan. Energy

Technologies Institute.

PGS. (2015). The PGS Mega surveys. Retrieved from

http://www.pgs.com/upload/31007/MegaSurvey%20(1366Kb).pdf

Pham, T. H., Maast, T. E., Hellevang, H., & Aagaard, P. (2011). Numerical

modeling including hysteresis properties for CO2 storage in Tubaen

formation, Snøhvit field, Barents Sea. Energy Procedia, 4, 3746–3753.

Pinnock, S., & Clitheroe, A. (2003). The Captain Field, Block 13/22a, UK North

Sea. Gluyas, JG & Hichens, HM (eds.) United Kingdom Oil and Gas

Fields, Commemorative Millenium Volume. Geological Society, London,

Memoir, 20, pp. 431-441.

Schlumberger. (2014). Eclipse 300 Reference Manual.

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Oil Field Glossary:

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ScottishPower CCS Consortium. (2010). Longannet FEED work, UK Carbon

Capture and Storage Demonstration Competition, FEED Close Out

Report, SP-SP 6.0 - RT015.

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00002.

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(K05). DECC 11.003 KKD Technical.



Shell, The Crown Estate, Scottish Government, Scottish Enterprise and

Vattenfall. (2015). CO2Multistore: Optimising CO2 storage in geological

formations; a case study offshore Scotland.

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Directive 2009/31/Ec Of The European Parliament And Of The Council

On The Geological Storage Of Carbon Dioxide. Official Journal of the

European Union, 114-135.

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Storage Permit Application. Energy Procedia, 114, 7466-7479.

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and pipelines. Retrieved from gov.uk: https://www.gov.uk/guidance/oil-

and-gas-decommissioning-of-offshore-installations-and-pipelines

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and Operation of CO2 Pipelines. Retrieved from

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improved method. Petroleum Science, 14(4), 720–730.

Zoback, M. D. (2007). Reservoir Geomechanics. Cambridge: Cambridge

University Press.

D07 Acorn CO2 Storage Site Development Plan Annexes


10.0 Annexes

10.1 Annex 1 – Data inventory

10.1.1 Seismic data summary

The seismic 3D dataset used for the evaluation of Captain Aquifer was the PGS

UK CNS Mega Survey:

• Survey: MC3D_NSEA (CNS)_MEGA (UK Sector)

o Final Merged Migration (53 Tiles)

The data was supplied as SEG-Y on a USB hard drive and has the following

survey datum and map projections:

Setting Value

Survey Datum ED50

Ellipsoid International 1924

Semi Major Axis 6378388

1/Flattening 297

Map Projection UTM 31N

Central Meridian 3 EAST

Scale Factor or Central Meridian 0.9996

Latitude of Origin 0.00N

False Northing 0

False Easting 500000

Table 10-1: SEG-Y survey datum and map projections

The following tiles of SEG-Y data were used for the Captain site selection and

evaluation:

File Name Format Tile Media IL Range

XL Range

OS0445_MC3D_

NSEA_MEGA_F

04_MAR2014

SEG-Y F04 27395002 15001-20000

120001-

124000

MC3D_NSEA_M

EGA_F05 SEG-Y F05 27395002

20001-25000

120001-

124000

Table 10-2: SEG-Y tiles for Captain Aquifer evaluation

Figure 10-1: PGS Mega Survey time slice showing the seismic data extent and tiles used in the Captain Aquifer evaluation



10.1.2 Well data summary

The table below shows a summary of the well log data for the Acorn CO2 storage

site, downloaded from CDA (table extracted from (PBDE and Axis WT, 2016)).



Well Date E/A/D DLIS or las?

GR Neutron Density DT/ Sonic

SP Comp Log

Geological Report/Final Well Report

Digital Checkshots

Deviation Data

Well Tops

Core Data over Captain

13/21b- 2 1990 E y n n y n n y n y y n

13/22b- 19 1993 A y n n y y y y n y y n

13/22b- 20 1993 E y n n y y y y n y y n

13/22b- 4 1990 E y n n y y n y n y y n

13/22c- 30 2006 E y y y n n y y n y y n

13/23- 1 1991 E y n y n n n y n y y n

13/23a- 4 1999 E y y y n n y y n y y n

13/23b- 5 2005 E DLIS y y n n y y y n y y y

13/23b- 6 2008 A LAS y n n n n y y n y y n

13/24- 1 1974 E y n y y n y y n n n n

13/24a- 4 1997 A y y y y y y y y y y y

13/24a- 5 1998 A y y y y y y y y y

13/24a- 6 1998 A y n y y n y y y y y y

13/24a-7 2000 D n n n n n y y n y y n

13/24a- 7Z 2000 D n n n n n y y n y y n

13/24A-8 2001 A n n n n n y y n y y n

13/24A-8Y 2001 A n n n n n y y n y y n

13/24a- 8Z 2001 A n n n n n y y n y y n

13/24b- 10 2010 D n n n n n y y n y y n

13/24b- 3 1997 E y n y n n y y n y y y

13/24b- 9 2003 D DLIS y n n n n y y n y y n





SP Comp Log


Digital Checkshots

Deviation Data

Well Tops


13/29b- 5 1995 E y n n n n y y n y y n

13/29b- 6 1999 A y y n y n y y n y y y

13/29b- 7 2001 E LAS n n n n n y y n y y n

13/29b- 8 2001 D y n n n n y y y y y n

13/29b- 9 2004 E DLIS n n n n n y n n y y n

13/30- 1 1981 E y y y y y y y n y y n

13/30- 2 1984 E n n n n n n y n y y n

13/30- 3 1986 E y y y y y n y n y y y

13/30a- 4 1998 E LAS y n y y y y y n y y y

13/30a- 6 2005 D DLIS n n n n n y y n y y n

13/30b- 5 1999 E n n n n n y y n y y n

13/30b- 7 2007 E y y n y n y y n y y n

14/26- 1 1979 E y y y y y n y n y n n

14/26- 2 1982 E y y y y y n y n y n n

14/26- 3 1983 E y y y y y n y n y n n

14/26a- 6 1997 E y y y y y y y n y y y

14/26a- 7 1999 A n n n n n n n n n n n

14/26a- 7A 1999 A y y y n n y y n y y y

14/26a- 8 2000 A DLIS y y n y y y y y y y y

14/26a- 9 2011 A n y y n n y y y y y n

14/26b- 5 1997 E y y y y y y y y y y n





SP Comp Log


Digital Checkshots

Deviation Data

Well Tops


14/27a- 1 1990 E y n y n y n y n y y n

14/27a- 2 2006 E n n n n n y y n y y n

14/28a- 3A 2000 E y n n n n y y y y y n

14/28b- 2 1997 E y y y y y y y y y y y

14/28b- 4 2006 E DLIS y y y y y y y n y y n

14/29a- 2 1980 E y y y y y y y y y y n

14/29a- 3 1996 E DLIS y n y y n y y n y y y

14/29a- 5 1999 E DLIS y y y y n y y n y y y

20/02b- 10 2010 E DLIS y y y n n y y n y y n

20/04b- 6 1997 E y y y y y y y n y y y

20/04b- 7 1999 E y n n n n y y y y y y

20/01-11 2009 A n y y n n y y y y y n

20/01-11Z 2009 A y n y n n y y y y y n

20/01-6 2006 D y y y n n y y n y y n

20/01-8 2009 E y y y n n y y n y y n

Table 10-3: Summary of well data used in the Captain Aquifer evaluation



10.1.3 Core data summary

The table below show a summary of the core data available over the Acorn CO2

storage site.

Field Well Core Depth (MD)

13/23b- 5 4240.3-4261.2

BLAKE 13/24a- 4 5295.1-5450.1

BLAKE 13/24a- 5 5207.2-5400.6

BLAKE 13/24a- 6 5177.4-5409.1

BLAKE 13/24b- 3 4990.0-5302.0

BLAKE 13/29b- 6 5203.85-5375.0

CROMARTY 13/30- 3 6577.0-6702.85

13/30a- 4 6364.2-6461.0

ATLANTIC 14/26a- 6 6467.1-6541.9

ATLANTIC 14/26a- 7A 6540.1-6577.8

SOLITAIRE 14/26a- 8 6428.9-6658.9

14/28b- 2 8248.0-8331.0

GOLDENEYE 14/29a- 3 9727.0-10188.9

GOLDENEYE 14/29a- 5 8473.1-8680.0

GOLDENEYE 20/04b- 6 8644.2-8777.9

GOLDENEYE 20/04b- 7 8639.2-8812.0

Table 10-4: List of core data used in the characterisation of the Acorn CO2 Storage Site

The core data used in the geomechanical rock strength analysis was carried out

on wells: 14/26-1; 14/26a-6; 14/26a-7, 7A; and 14/26a-8, near the proposed

primary CO2 injection site. The depth intervals chosen for sampling for each

respective well were chosen according to several parameters, including:

availability of core, depth, occurrence in the oil/water-leg; porosity; and general

lithological variation, as determined from hand specimen observations, gamma

ray and density wireline logs.

10.1.4 Data from operators

Limited pressure data from Operators in the area were provided as input to the

Acorn CO2 storage site work.



10.2 Annex 2: Risk Register

Attached separately.



10.3 Annex 3: Leakage Workshop Spider Diagrams

The leakage scenarios investigated during the leakage workshop are shown in

Figure 10-2 with the categories and grades of consequences highlighted in

Table 10-5.

Figure 10-2: The 11 leakage scenarios considered as relevant for the area investigated

Impact Low Medium High

Storage Security

CO2 migrates inside the storage complex or does not reach shallower formations.

CO2 reaches the shallow overburden.

CO2 reaches to the seabed.

Social Acceptance

Not present in the public discussion and no coverage in the media. Covered in the scientific community.

Present in the local news; policy and industry are aware

Nation-wide coverage, headline news and broad debate in the public

Environment Minor damage, no threat to the environment.

Local damage, certain threat to flora and fauna and, if any, minor restitution required.

Widespread damage with major risk for the environment; major restitution required.

Hydrocarbon Industry

Negligible impact, strategy plans of hydrocarbon industry do not need adjustment.

Small to medium adjustments may be required.

Major change of industry operations, including long delays and significant costs.

Costs Negligible costs < £10 million > £10 million

Table 10-5: Summary of categories and grades of consequences



10.3.1 Leakage Scenario 1

10.3.1.1 Scenario Description

CO2 migrating through overlying primary seal, the Rodby and the Carrick Shale,

into secondary reservoir, one of the Palaeocene sandstone formations.

10.3.1.2 Consequence Analysis

Figure 10-3: Spider diagram showing the impact of consequences

Impact on storage security – Low

CO2 is still within the storage complex.

Impact on social acceptance – Med

CO2 leaking into shallower formations will be of concern to the public. Although

the severity of the leakage event is expected to be low, CO2 leaving the storage

complex may compromise faith in carbon capture and storage (CCS) operations.

Impact on environment – Low

The CO2 is still deep in the subsurface, no impact on the environment expected.

Costs – Med

Some remediation strategies expected if fault reactivation or CO2 migrating

through the caprock occurs. The CO2 storage operation will require either a new

storage development plan (SDP) or operations to cease entirely.

Impact on hydrocarbon industry – Low

There are no significant hydrocarbon accumulations present in the shallower

strata above the injection site.



CO2 enters abandoned well and leaks to seabed. This is generally seen as one

of the more serious risks to CO2 storage operations and involves complicated

and expensive remediation procedures.





Impact on storage security – High

CO2 leaks to the seabed, which is a worst-case scenario.

Impact on social acceptance – High

CO2 leaking to the seabed will be alarming for the public as well as regulators

and policy makers. This will have nationwide, probably global, effect on the

public perception of CO2 storage.

Impact on environment – Med

Although the volume of leaking CO2 is relatively small, local damage to the

seafloor near the well is likely.

Costs – High

The remediation of an abandoned well is costly.


No impact expected.



CO2 enters a modern well or leaks along pathways opened due to drilling or the

operation process of the modern well, most likely during the drilling process or

during/after completion problems, and then leaks vertically to seafloor. A modern

well is defined as a well drilled for this CO2 storage project (injection well,

monitoring well, pressure relief well, etc) or any well that is drilled through a CO2

storage site (e.g. for future petroleum activity).









and policy makers. This will have, probably global, effect on the public

perception of CO2 storage.



seafloor near the well is likely.

Costs – High

The remediation of a failed drilling campaign, including leakage to surface, is

costly. The well may be lost.

Impact on hydrocarbon industry – High (*)

*Only when drilled through CO2 storage site for deeper targets; but negligible

otherwise.



CO2 enters abandoned well and leaks into the secondary reservoir, a

Palaeocene sandstone.




CO2 leaks within the storage complex into shallower formations.

Impact on social acceptance – Medium

CO2 leaking into shallower formations will be of concern for the public as well as

regulators and policy makers. This will be heavily discussed in the industry and

research community.


No impact on the environment expected.

Costs – High

The remediation of a leaky abandoned well is extremely costly.




No impact on the environment expected.



CO2 enters a modern well, most likely during the drilling process or during/after

completion problems, and then leaks into Palaeocene sandstone formations. A

modern well is defined as a well drilled for this CO2 storage project (injection

well, monitoring well, pressure relief well, etc.) or that is drilled through a CO2

storage site (e.g. for future petroleum activity).




CO2 leaks out of the storage complex into shallower formations.


CO2 leaking into shallower formations will be of concern for the public as well as

regulators and policy makers. This will be heavily discussed in the industry and

research community.


No impact expected.

Costs – High

The remediation of a failed drilling campaign, including leakage, is extremely

costly. The well will probably be lost. Additionally, the remediation procedure for

this leakage scenario will be technically extremely challenging.

Impact on hydrocarbon industry – High (*)

*Only when drilled through CO2 storage site for deeper targets; but negligible

otherwise.



CO2 migrates along the primary reservoir formation, the Captain Sandstone, out

of the storage complex in a north-westerly direction. Migration towards the

deeper south-east is excluded because CO2 is not expected to migrate

significantly down-dip.






CO2 is outside the storage complex but has not leaked into shallower strata.

Impact on social acceptance – Low

2-5% of CO2 migrating to the west of the Blake field but still inside the Captain

Sandstone will be of little concern.


Whether the CO2 is within the storage complex or outside makes no difference

for the environment as long it is still in the Captain Sandstone deep under the

seabed.

Costs – High

CO2 injection will be stopped if lateral leakage occurs during the injection

process; some remediation actions, such as back production, might be required

to reduce leakage. A new measuring, monitoring and verification (MMV) strategy

will be introduced.


If CO2 escapes laterally, it may flow into currently unknown hydrocarbon fields.

Although it may result in the heavy oil produced to become less viscous (CO2-

EOR), the net CO2 emission impact will need to be considered for the

exploration, the development, the production and the decommissioning of these

fields.



CO2 leaks into depleted, underlying Jurassic formations under production via

leakage pathways, such as wells.






CO2 leaks out of the storage complex but into deeper strata.

Impact on social acceptance – Low

Less than 2% of CO2 migrating to a deeper horizon will be of little concern to the

public.



for the environment as long it is still deep under the seabed.

Costs – Low

CO2 injection will be reduced or stopped if downward migration occurs during

the injection process; some remediation actions, such as back production, might

be required to reduce leakage.

Impact on hydrocarbon industry – Medium

If CO2 escapes downwards, it may flow into known hydrocarbon fields. If it

contaminates a producing field, it could lead to corrosion in the production

infrastructure.



As per 1, 4 and 5 but additionally, CO2 leaks along secondary reservoirs

(Palaeocene sandstones) out of the storage complex.






CO2 leaks laterally out of the storage complex.


CO2 leaking into shallower formations out of the storage complex will be of

concern for the public as well as regulators and policy makers. This will be

heavily discussed in the industry and research community.



for the environment as long it is still deep under the seabed.

Costs – High

In addition to the costs of dealing with the CO2 leaking into the Palaeocene

sandstone, further costs might be required to deal with Scenario 8.


If CO2 escapes laterally, it may flow into currently unknown hydrocarbon fields.

Although it may result in the heavy oil produced to become less viscous (CO2-

EOR), the net CO2 emission impact will need to be considered for the

exploration, development, production and decommissioning of these fields.

However, no such fields are known to date.



As per 1, 4 and 5 but, additionally, CO2 leaks across the secondary seal, the

Lista Shale, into the overburden.



Impact on storage security – Medium

CO2 leaks out of the storage complex into the shallower overburden formations.


CO2 leaking into shallower formations out of the storage complex will be of

concern for the public as well as regulators and policy makers. This will be

heavily discussed in the industry and research community.


No impact expected.

Costs – Medium

The costs are similar to Scenario 1.




No impact expected.



As per 6 and 8 but, additionally, CO2 reaches the seafloor either via a fault

crosscutting the primary and secondary reservoir or by migrating all the way

along the primary and secondary reservoirs until they reach the seafloor.







and policy makers. This will have nationwide effect on the public perception of

CO2 storage.



seafloor can occur where CO2 leaks out.

Costs – High


sandstone, further costs for widespread remediation will be required because

CO2 leaks to the surface. The new European Union Allowance (EUA) will be

required.


No impact expected.



As per 9 but, additionally, CO2 leaks through the overburden to the seafloor.









and policy makers. This will have nationwide effect on the public perception of

CO2 storage.

Impact on environment – Medium


seafloor can occur where CO2 leaks out.

Costs – High


sandstone and into the overburden, additional costs for widespread remediation

will be required because CO2 leaks to the surface. The new European Union

Allowance (EUA) will be required.


No impact expected.

Documents

Project: ACT Acorn Feasibility Study Acorn - Acorn... · 2019. 2. 25. · D07 Acorn CO2 Storage Site Development Plan 10196ACTC-Rep-27-01 August 2018 Acorn ACT Acorn, project 271500,