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Project: ACT Acorn Feasibility Study

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mailto:[email protected]

D11 Infrastructure Re-use 10196ACTC-Rep-16-01

May 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.

D11 Infrastructure Re-use Contents

ACT Acorn Consortium of 54

Contents

Document Summary

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

Project Title Accelerating CCS Technologies: Acorn Project

Title: D11 Infrastructure Re-use

Distribution: Client & Public Domain

Date of Issue: 31st May 2018

Prepared by: Marko Maver (Bellona)

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

1 31/05/2018 1st issue Marko Maver Tim Dumenil Steve Murphy



Table of Contents

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

1.0 EXECUTIVE SUMMARY .................................................................................................................................................................................................................... 9

2.0 INTRODUCTION .............................................................................................................................................................................................................................. 11

3.0 SCOPE ............................................................................................................................................................................................................................................. 16

4.0 THE INFRASTRUCTURE RE-USE OPPORTUNITY ....................................................................................................................................................................... 17

5.0 ATLANTIC PIPELINE ...................................................................................................................................................................................................................... 21

6.0 GOLDENEYE PIPELINE .................................................................................................................................................................................................................. 29

7.0 MGS PIPELINE ................................................................................................................................................................................................................................ 33

8.0 GENERIC KEY RISKS ..................................................................................................................................................................................................................... 37

9.0 CONCLUSIONS ............................................................................................................................................................................................................................... 39

10.0 REFERENCES ................................................................................................................................................................................................................................. 40

11.0 ANNEX 1: CO2 PHASE CHANGE AND PRESSURE DROP .......................................................................................................................................................... 42

FACTSHEET 1: RE-USE OF NORTH SEA TOPSIDE INFRASTRUCTURE FOR CO2 STORAGE ......................................................................................................... 43

FACTSHEET 2: RE-USE OF NORTH SEA PRODUCTION OIL & GAS WELLS FOR CO2 STORAGE .................................................................................................. 47

FACTSHEET 3: RE-USE OF NORTH SEA TRANSPORT INFRASTRUCTURE ...................................................................................................................................... 51



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

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

FIGURES ...................................................................................................................................................................................................................................................... 8

TABLES ........................................................................................................................................................................................................................................................ 8

1.0 EXECUTIVE SUMMARY .................................................................................................................................................................................................................... 9

2.0 INTRODUCTION .............................................................................................................................................................................................................................. 11

ACT ACORN OVERVIEW................................................................................................................................................................................................................... 11

ACORN DEVELOPMENT CONCEPT ..................................................................................................................................................................................................... 14

3.0 SCOPE ............................................................................................................................................................................................................................................. 16

PURPOSE ........................................................................................................................................................................................................................................ 16

SCOPE ............................................................................................................................................................................................................................................ 16

STATEMENT OF ASSUMPTIONS ......................................................................................................................................................................................................... 16

4.0 THE INFRASTRUCTURE RE-USE OPPORTUNITY ....................................................................................................................................................................... 17

RATIONALE FOR RE-USE ................................................................................................................................................................................................................... 17

DECOMMISSIONING .......................................................................................................................................................................................................................... 17

ECONOMICS OF RE-USE ................................................................................................................................................................................................................... 18

4.3.1 Preservation ......................................................................................................................................................................................................................... 19

CASE STUDIES ................................................................................................................................................................................................................................. 20

5.0 ATLANTIC PIPELINE ...................................................................................................................................................................................................................... 21

DESCRIPTION OF ASSETS ................................................................................................................................................................................................................. 21

5.1.1 Decommissioning consideration and current status .............................................................................................................................................................. 22

5.1.2 Technical specifications and operating envelopes ................................................................................................................................................................ 22

CONVERSION AND REPURPOSING REQUIREMENTS ............................................................................................................................................................................. 24

5.2.1 Regulatory requirements ........................................................................................................................................................................................................ 25



5.2.2 Internal and external inspection ............................................................................................................................................................................................. 25

RATIONALE FOR PRESERVATION ....................................................................................................................................................................................................... 26

5.3.1 Estimates of cost .................................................................................................................................................................................................................... 26

Re-use vs. new pipeline ....................................................................................................................................................................................................................... 27

5.3.2 Key risks ................................................................................................................................................................................................................................. 28

6.0 GOLDENEYE PIPELINE .................................................................................................................................................................................................................. 29






6.3.1 Estimates of costs .................................................................................................................................................................................................................. 31

6.3.2 Key risks ................................................................................................................................................................................................................................. 32

7.0 MGS PIPELINE ................................................................................................................................................................................................................................ 33






7.3.1 Estimates of costs .................................................................................................................................................................................................................. 35

7.3.2 Key risks ................................................................................................................................................................................................................................. 36

8.0 GENERIC KEY RISKS ..................................................................................................................................................................................................................... 37

TECHNICAL AND OPERATIONAL RISKS ................................................................................................................................................................................................ 37

LEGAL AND LIABILITY CONSIDERATIONS ............................................................................................................................................................................................. 37

9.0 CONCLUSIONS ............................................................................................................................................................................................................................... 39



10.0 REFERENCES ................................................................................................................................................................................................................................. 40

11.0 ANNEX 1: CO2 PHASE CHANGE AND PRESSURE DROP .......................................................................................................................................................... 42

CO2 PHASE CHANGE ....................................................................................................................................................................................................................... 42

CO2 PRESSURE DROP ..................................................................................................................................................................................................................... 42

FACTSHEET 1: RE-USE OF NORTH SEA TOPSIDE INFRASTRUCTURE FOR CO2 STORAGE ......................................................................................................... 43

FACTSHEET 2: RE-USE OF NORTH SEA PRODUCTION OIL & GAS WELLS FOR CO2 STORAGE .................................................................................................. 47

FACTSHEET 3: RE-USE OF NORTH SEA TRANSPORT INFRASTRUCTURE ...................................................................................................................................... 51



Figures

FIGURE 2-1: ACT ACORN CONSORTIUM PARTNERS .......................................................................................................................................................................................... 11

FIGURE 2-2: KEY AREAS OF INNOVATION ......................................................................................................................................................................................................... 12

FIGURE 2-3: ACT ACORN WORK BREAKDOWN STRUCTURE .............................................................................................................................................................................. 12

FIGURE 2-4: ACORN OUTLINE MINIMUM VIABLE DEVELOPMENT PLAN ............................................................................................................................................................... 14

FIGURE 2-5: ACORN BUILD OUT SCENARIO FROM THE 2017 PCI APPLICATION ................................................................................................................................................... 15

FIGURE 4-1: REUSING PIPELINES (VALUES PER KM): (BENTON, 2015). .............................................................................................................................................................. 19

FIGURE 5-1 ATLANTIC AND CROMARTY FIELD LAYOUT (BG GROUP, 2016) ....................................................................................................................................................... 22

FIGURE 5-2 AN EXAMPLE OF AN "INTELLIGENT PIG" INSPECTING PIPELINE CONDITION (INTERTEK, 2016) ........................................................................................................... 26

FIGURE 6-1 GOLDENEYE PIPELINE FROM ST FERGUS TO GOLDENEYE PLATFORM (SHELL, 2016) ...................................................................................................................... 31

FIGURE 7-1 LOCATION OF THE MILLER PLATFORM (BP, 2011) ......................................................................................................................................................................... 34

FIGURE 7-2: LOCATION OF NORTH WEST HUTTON: (JEE, 2014) ....................................................................................................................................................................... 36

FIGURE 11-1: CO2 PHASE CHANGES (GLOBAL CCS INSTITUTE, 2013) ............................................................................................................................................................. 42

Tables

TABLE 1-1 SUMMARY OF PIPELINE SPECIFICATIONS ......................................................................................................................................................................................... 10

TABLE 2-1: ACT MILESTONES AND DELIVERABLES .......................................................................................................................................................................................... 13

TABLE 5-1 ATLANTIC PIPELINE SPECIFICATIONS .............................................................................................................................................................................................. 24

TABLE 5-2: ADDITIONAL 8KM PIPELINE SPECIFICATIONS .................................................................................................................................................................................... 24

TABLE 5-3 CAPTAIN X DEVELOPMENT - TRANSPORT CAPEX (BASE CASE) ......................................................................................................................................................... 27

TABLE 5-4 CAPTAIN X DEVELOPMENT - TRANSPORT CAPEX (NEW PIPELINE SYSTEM) ....................................................................................................................................... 27

TABLE 6-1 GOLDENEYE PIPELINE SECIFICATIONS ............................................................................................................................................................................................ 30

TABLE 7-1 MGS PIPELINE SPECIFICATIONS .................................................................................................................................................................................................... 34

TABLE 11-1: ST FERGUS TO CAPTAIN NUI PIPELINE PRESSURE DROP .............................................................................................................................................................. 42

D11 Infrastructure Re-use Executive Summary


1.0 Executive Summary

The purpose of this deliverable is to consider the rationale for the preservation

of the Atlantic, Goldeneye, and Miller Gas System (MGS) pipelines, all of which

are currently under an Interim Pipeline Regime (IPR) awaiting decommissioning.

By examining the pipeline’s operating envelopes and technical specifications,

conversion/re-purposing requirements, estimated re-purposing/conversion

costs and key risks, as well as the views and needs of key stakeholders, this

report brings awareness to the infrastructure owners and relevant authorities of

the potential future value of the three pipelines.

Considering expanded decommissioning of the infrastructure in the North Sea,

including pipelines there is now a significant, low-cost opportunity to provide

additional value to these assets through their re-use. Delaying decommissioning

and re-using existing infrastructure offers lower decommissioning costs and

significant cost savings to CCS project developers. In addition, it can enable

smaller industrial players that might otherwise not be able to justify stand-alone

projects, to take up CCS. Preservation, however, will not occur without

government support and appropriate compensation given to the asset owners

for costs incurred due to prolongation of asset life (i.e. for any changes in costs,

liabilities, tax allowance, etc.).

The potential for re-use of existing pipelines as compared to building new ones

for CCS projects is determined by the cost vs. risk trade-off. While the risks

appear higher with existing pipelines, the costs are lower. The risks are believed

to be manageable, which together with the lower associated conversion/re-

purposing costs should outweigh the higher costs of building new pipelines and

infrastructure.

Overall cost estimates for the entire North Sea infrastructure

decommissioning up to year 2050 amounts to approximately

£47bn (€53bn, in today’s money), with an uncertainty of +/- 40%

(Oil & Gas Authority, 2016).

Between 2016 and 2025, the cost of planned decommissioning of

580 pipelines, in the Central and Northern North Sea, with a length

of 3,700km is estimated at £847m (€947m), which amounts to

£1.46m (€1.63m) per pipeline (including associated infrastructure

such as umbilicals & infield lines), or £225k (€251m) per km.

Pipeline decommissioning risks losing larger future value arising

from infrastructure re-use. Preservation and re-use offers a

significant opportunity and cost savings for CCS project

developers: up to 75% lower capital expenditure costs.

Currently, the three most suitable pipelines for re-use in the North

Sea include: the Atlantic pipeline, the Goldeneye pipeline, and the

MGS pipeline. All three pipelines have been preserved in-situ and

are awaiting decommissioning.

The key path to preservation of the pipelines, as identified by the

pipeline owners/operators, has been the removal or transfer of

liabilities and/or appropriate compensation for preservation.

D11 Infrastructure Re-use Executive Summary


The Atlantic pipeline is well placed for preservation given its technical and

operational specifications, particularly its large wall thickness, which gives it a

high-pressure rating and therefore a better tolerance to the pressures needed

for CO2 transport.

Previous studies on the Goldeneye pipeline, have shown the pipeline is

suitable for dense phase CO2 transportation, within its operational parameters.

The MGS pipeline, offers potential for future high-volume CO2 transport. It is in

good condition and although other infrastructure (i.e. platforms, topsides, wells)

of the Miller field are not considered for re-use, the pipeline is re-usable.

Name Length

(km) Diameter

(m)

Design Pressure

(barg)

Capacity (up to: MT/yr)

Remaining Age (years)

Atlantic 79.2 0.46 (18”) 170 3-5 ~6-10

Goldeneye 101 0.51 (20”) 125 2-4 ~8-10

Miller 240 0.76 (30”) 174 10 ~10

Table 1-1 Summary of Pipeline Specifications

D11 Infrastructure Re-use Introduction


2.0 Introduction

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 being 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 will 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:

1. 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 (to be selected) under the North Sea.

2. 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.

3. 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

4. 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.



5. Engage with CCS and low carbon economy stakeholders in Europe

and worldwide to disseminate the lessons from the project and

encourage replication.

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

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 Re-use 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 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.

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 use 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 minimum viable 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: Acorn Outline Minimum Viable Development Plan



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

low-cost growth and incremental development 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 additional 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

D11 Infrastructure Re-use Scope


3.0 Scope

Purpose

The purpose of this deliverable is to increase awareness for owners and relevant

authorities of the infrastructure re-use potential and future value of one or more

of the three redundant oil and gas pipelines considered for CO2 transportation

from the St. Fergus Gas Terminal in northeast Scotland.

Scope

The scope of this deliverable includes:

• Literature review,

• Description of the existing assets,

• Defining operating envelopes and technical/functional specifications,

• Outlining conversion / re-purposing requirements,

• Developing, in consultation with relevant authorities and operators,

a preservation strategy for infrastructure enabling the Acorn project,

• Estimation of costs for re-use versus decommissioning,

• Assessment of key risks,

• Interview with and documentation of views/needs of key

stakeholders,

• Making a rationale for preservation.

Statement of Assumptions

The assumptions detailed in this section apply to the Acorn Project under the

ACT ERA-NET funding package. For future Acorn project development, these

assumptions may be revised.

Infrastructure

• The infrastructure re-use potential is focussed on the St. Fergus site

and three redundant oil and gas offshore pipelines: Atlantic,

Goldeneye and MGS.

Data

• The most recent data available in the public domain is considered,

including but not limited to, decommissioning programmes and

Environmental Impact Assessments (EIA’s) for the three pipelines.

• Data on cost estimates of decommissioning have been difficult to

obtain due to privacy issues. They have been provided by the

operators to BEIS in confidence. All effort was made to obtain the

most relevant and up-to-date data.

Exclusions

• The interest within this work is centred on the pipelines, and not with

any associated infrastructure (i.e. platforms, wells, umbilicals, etc.),

due to technical and commercial reasons. Wells, for example, have

either been suspended which makes them unusable, or there are

questions/issues with their design, high operating costs or limited

life.

D11 Infrastructure Re-use The Infrastructure Re-use Opportunity


4.0 The Infrastructure Re-use Opportunity

Rationale for re-use

Maturing of many major oil and gas fields, combined with the lack of significant

new discoveries and a sustained period of low oil and gas prices, has in recent

years increased interests in decommissioning of existing assets in the UK

Continental Shelf (UKCS). Furthermore, ongoing uncertainty and volatility in

commodity prices has depressed the level of new capital invested in the UKCS.

At the same time the oil and gas industry has turned towards the application of

the circular economy principles, whereby possibilities of enhancing economic

value in existing assets and reducing environmental disturbance1 generated

during decommissioning are sought. The UK’s strategy for maximising

economic recovery (MER), (Oil & Gas UK, 2016), is a formal example of the

application of such principles. Ways in which the oil and gas industry is applying

these principles, aside from recycling, includes assessing potential opportunities

for the re-use of platforms, wells and pipeline assets, including their associated

infrastructure. The re-use of platforms and wells has been part of the oil and gas

industry’s efforts for some time, re-use of pipelines, with the purpose of

transporting of CO2 for storage, is by some still considered to be in its early

development stages (Benton, 2015). Pipeline re-use in the North Sea, however,

1 Albeit it is recognized that these assets will at some point have to be decommissioned, however, the statement is based on the premise that more efficient disposal/decommissioning techniques will have been discovered/implemented by then.

2 This includes inputs provided by 34 operators for all current and proposed offshore facilities, pipelines, development wells, suspended open water exploration and appraisal wells and onshore

is still uncommon. As such, the focus of this report is on presenting the rationale

and opportunities for the re-use of pipelines for CO2 transportation and storage.

Decommissioning

Reasons for decommissioning vary: some companies delay the process due to

cash-flow constraints, while others increase field life through improvement

efficiencies, delaying decommissioning. Conversely, some companies are

expediting their decommissioning as it becomes cheaper to do so at lower

prices. In any case, decommissioning in the North Sea has been growing, with

£0.8bn (€0.9bn) in 2014, and £1.1bn (€1.4bn) spent on decommissioning in

2014 and 2015 respectively (Oil & Gas Authority, 2016). There are currently over

250 fixed installations, over 250 subsea production systems, over 3,000

pipelines and approximately 5,000 wells in the UKCS, all of which will be

required to be decommissioned.

Overall cost estimates for North Sea decommissioning up to 2050 amount to

approximately £47bn (€53bn), with an uncertainty of +/- 40% (Oil & Gas

Authority, 2016). Other studies have put these estimates at £59.7bn (€68bn) in

2016 prices2, with costs amounting to anywhere between £1.07bn (€1.2bn) and

£2.6bn (€2.9bn) per year, rising on average by 14% per year, and overall costs

terminals. The cost estimate takes into account the wide range of uncertainties of industry class 5 and 4 estimates as submitted by operators as part of the 2016 UKCS Stewardship Survey (Oil & Gas Authority, 2017). Note: The estimates made in the past, including that by CRF in 2016, have been done using different methodologies and scopes, so the results are not directly comparable.



potentially reaching over £17bn (€19bn) between now and 2020, and £47bn

(€52.4bn) by 2040.3

The current UK tax regime enables oil and gas companies operating in the

UKCS to reclaim a significant portion of their decommissioning expenditure as

tax refunds. 50% - 75% of total decommissioning costs in the UKCS could be

footed by the UK government and taxpayers (CRF, 2016). There is an interest

from government and industry to lower decommissioning costs., and the OGA’s

2016 Decommissioning Strategy and its 2017 UKCS Decommissioning Cost

Estimate Report set a target to reduce these costs by 35%. In this respect, a

strategic and comprehensive, rather than piece-meal and ad-hoc approach to

decommissioning is encouraged by the UK government (Oil & Gas Authority,

2017). Furthermore, the recently proposed changes to the UK’s

decommissioning tax relief regime, which will take effect from 1 November 2018,

are set to allow for the transfer of tax history4 onto the buyer of an existing asset,

who would then be able to utilise the transferred tax history to trigger a

repayment of tax paid by the previous owner. Put simply, the new owner of the

asset would, to an extent, be able to claim back the decommissioning costs. The

goal is to encourage investment into late-life assets in the North Sea and thereby

maximise economic recovery (Thomas, 2017).

Between 2016 and 2025, operators in the North Sea intend to decommission

around 17% of the total pipeline network from the UK and Norwegian

3 Over 85% of the decommissioning costs are associated with well abandonment and topside removal, while the rest being related to project management and monitoring, subsea and site remediation, and topside and substructure reuse/recycling. The latter amounts to only 1% of overall decommissioning costs. 4 The new owner would be able to utilize the transferred tax history to trigger a repayment of tax paid by the previous owner. The transferred tax history would apply only to the supplementary charge and the ring fence corporation tax, but not petroleum revenue tax.

Continental Shelves, or 850 pipelines with a total length of nearly 7,500 km.

While the central North Sea hosts the largest number of these pipelines (484)5,

the southern North Sea and Irish Sea will see the largest proportion of the total

pipeline length, 3,426km, be decommissioned (Oil & Gas Authority, 2016). Cost

of planned decommissioning of 580 pipelines with a length of 3,700km is

estimated at £847m (€947m), which amounts to £1.46m (€1.63m) per pipeline

(including associated infrastructure such as umbilicals & infield lines), or £225k

(€251m) per km.

The capital expenditure on decommissioning may result in fewer investments

into other value generating activities. Delaying decommissioning can also

provide opportunities for innovation, cost reduction and development of UK skills

and capabilities (Oil & Gas Authority, 2016). Preservation and re-use of the

infrastructure awaiting decommissioning for use in other projects, such as CCS,

is an opportunity that could reduce the costs, both for taxpayers and companies.

Taking advantage of such opportunities, which can be limited by the

repurposing/conversion costs and lifetime limitations can only be achieved

through a successful collaboration between the government and the

industry/operators.

Economics of re-use

Essentially, repurposing pipelines for CO2 transport would eliminate the cost of

removing/decommissioning them. Studies also show that the re-use of pipeline

5 Southern North Sea and Irish Sea includes 200 pipelines, while Northern North Sea has 96 pipelines set for decommissioning, which makes the total number of pipelines set for decommissioning in the UK by 2025 780, while in Norway this number is at 6 (Oil & Gas Authority, 2016).



could be worth five times, or more, the scrap value of the steel, if reusing the

pipelines means that new ones do not have to be built (Benton, 2015).

As an integrated transport and storage network offers a significant contribution

to cost reduction for CCS, reusing pipeline infrastructure, as part of an integrated

network would drive down costs even further. Economics of re-use also depend

on the linking up of multiple CO2 sources. In this respect, intra-industry and

government collaboration will be key (Benton, 2015).

The economics of reusing existing pipelines versus building a new one tends to

be favourable towards the former. As the Captain X CO2 storage development

(Pale Blue Dot Energy & Axis Well Technology, 2016) research has shown,

capital expenditure (Capex) for utilising the 79km 16” Atlantic and Cromarty

(Atlantic) pipeline, would amount to £37.7m (€42.8m), while construction of a

new pipeline would cost £135.4m (€152m). This included building a new 8km

pipeline from the Atlantic manifold to the Captain X NUI which were required

both in the re-use and new case scenarios (Pale Blue Dot Energy & Axis Well

Technology, 2016) (see Section 5.3.1 Estimates of cost).

It is worth noting that there is little operating cost associated with pipelines that

are currently under the IPR, apart from regular inspection. Since detailed costs

are difficult to obtain, it can be estimated that these are somewhere in the range

of £100k (€113.5k) per year. In addition, repurposing costs of an existing

pipeline only include various commissioning type duties, such as drying the

pipeline or running an intelligent pig, which could cost in ranges of £2m-3m

(€2.3m-€3.4m) and/or £2m-4m (€2.3m-€4.5m) respectively.

It is worth nothing that economics of re-use for a pipeline should be assessed

on a case-by-case basis and depends on the willingness of the pipeline owner

to transfer ownership, and the possibility of transferring tax relief on

decommissioning costs on the sale of the asset.

4.3.1 Preservation

Depending on flow rate, width, length, and material of the pipeline, as well as

other factors such as the cost of steel and current scrap value prices, re-use of

pipelines for CCS could be worth significantly more than its scrap value or re-

use for construction.

Figure 4-1: Reusing pipelines (values per km): (Benton, 2015).

Preservation is warranted if the value of preservation is greater than the value

of deferring the decommissioning of the pipeline. The cost of planned

decommissioning of 580 pipelines with a length of 3,700km in the central and

northern North Sea is estimated at £847m (€947m), which amounts to £1.46m

(€1.63m) per pipeline (including associated infrastructure such as umbilicals &

infield lines), or £225k (€251m) per km. After speaking with a number of



representatives from the oil and gas industry, such estimates are fairly

consistent.

If decommissioning is deferred, the operational costs of monitoring and

maintenance are low, at approximately £100k (€113.5k) per year. These costs

depend on the length and condition of each pipeline in particular. In addition,

operational expenditure (Opex) costs during deferral period are likely to be

higher in cases where the pipelines are connected to a platform. Deferral,

however, cannot be held in perpetuity, as with each passing year, the design life

of the pipeline decreases. If decommissioning (costs) can be avoided, small

Opex costs (of £100k/yr) would warrant preservation for some time (even when

taking into account inflation and discounting). Detailed assessments would have

to be performed on a case-by-case basis.

Case studies

The re-use of legacy assets such as topsides, wells and pipelines can offer

significant cost savings and an efficient approach to facilitating wider CCS

deployment, considering the initial cost hurdles faced by many CCS projects to

date. Failure to preserve this infrastructure and leave it to be decommissioned

could result both in a waste of public and private funds as well as further delay

in the deployment of CCS in the UK and Europe. Three factsheets, in Annexes

2, 3 and 4 have been produced to further promote the re-use of existing

infrastructure:

• Re-use of North Sea Transport Infrastructure for CO2 Storage

• Re-use of North Sea Topside Infrastructure for CO2 Storage

• Re-use of North Sea Production Oil & Gas Wells for CO2 Storage

This report focuses on the re-use potential of three existing and strategically

important pipelines: the Atlantic pipeline, the Goldeneye pipeline, and the Miller

Gas System (MGS) pipeline. All three are near St. Fergus gas terminal,

northeast of Aberdeen, Scotland, and are being considered for re-use as part of

project Acorn. This report is focused specifically on the re-use potential of the

three pipelines, and not the associated infrastructure (i.e. umbilicals, wells,

platforms, etc.), although this is considered and mentioned.

As such, the goal of this deliverable is not to select any one or more of the three

pipelines but to present a case for their preservation and potential re-use. In this

respect, the report provides a brief description of the assets, including their

history, design, specifications and status. It then goes on to examine any

potential conversion and re-purposing requirements, as well as key risks. Where

available, estimates of costs are provided as well the as views and needs of key

stakeholders.

D11 Infrastructure Re-use Atlantic Pipeline


5.0 Atlantic Pipeline

Description of assets

The 79.2km long Atlantic production pipeline6, installed in 2006, is connected to

the Atlantic manifold7 as part of the Atlantic and Cromarty (A&C) fields, which

comprises three wells (two at the Atlantic and one at the Cromarty field). The

Atlantic field is operated by a consortium BG Global Energy Limited (BG) and

the Cromarty field is operated by Hess Limited. In February 2016, BG Group

was acquired by Shell, making it the de facto owner and operator of the assets.

The fields are in the outer Moray Firth in the UK Continental Shelf (UKCS),

approximately 79km northeast from the St. Fergus gas terminal (see Figure 5-1

below). There are six pipeline crossings along the route from St. Fergus to the

Atlantic manifold.

The A&C fields and the infrastructure were installed in 2005, and production

started in 2006. Although the production was anticipated to last five years, it

ceased in 2009. Following another failed attempt to restart/re-use production

wells in 2010, a Cessation of Production (CoP) was agreed with the OGA in

2011. The three wells have not been abandoned, but have been suspended (i.e.

6 This includes the PL2029 production pipeline and a piggy - backed MEG pipeline (PL2031). The latter is not subject to reuse consideration as it is likely that a new control pipeline would be installed. The production pipeline is 0.46m (18”) in diameter from the landfall to 1.2km and thereafter 0.41m (16”) diameter. A large majority of the pipeline is buried in trenches of over 0.6m in depth, or by rock cover (BG Group, 2016). 7 The Atlantic manifold is a subsea manifold, through which gas was exported from two Atlantic Field and one Cromarty Field wells, via the Atlantic production export pipeline to the Scottish Area Gas Evacuation (SAGE) terminal at the St. Fergus gas plant. The MEG was supplied to the offshore wells via a 0.10m (4”) pipeline from St. Fergus and was injected into the export pipeline to inhibit the potential formation of hydrates. The Atlantic manifold is considered CO2 compatible. As

cement plugs are set, however with the completion, well head and tree still in

place) (BG Group, 2016) Most of the pipelines were flushed and cleaned of

hydrocarbons and disconnected from the wells in 2012, which were suspended

and plugged in June/July of 20148. Only the Atlantic export pipeline and the

monoethylene glycol (MEG) lines were placed under an Interim Pipeline Regime

(IPR)9 for a period of five years, to allow for potential re-use consideration.10

Although the initial five-year IPR period for the Atlantic pipeline ran out in

December 2016, Shell, who operate the pipeline, were given consent for an

additional five-year period under IPR, to 2021. This does not oblige them to

retain the pipeline until that date but provides flexibility as to when within that

period the pipeline is decommissioned.

The additional period under IPR was in part due to Project Acorn and successful

cooperation and coordination between Scottish Government, project operators

and other key stakeholders to retain the pipeline for CCS use.

part of the draft decommissioning programme it is also considered to be decommissioned and moved to shore for recycling (BG Group, 2016). 8 The plugging and abandonment of the three wells was completed as per DECC (now BEIS) requirements and in compliance with the Oil & Gas Guidelines on suspension and abandonment of wells (Oil & Gas UK, 2009). 9 Under section 29 of the Petroleum Act of 1998, an interim pipeline regime, essentially defers a full decommissioning programme until other options are explored that might extend the useful life of a field. 10 Reuse options explored included the use of the reservoirs for gas and CO2 storage, and the sale of the facilities and infrastructure to other oil and gas companies, none of which have been deemed commercially viable.



Figure 5-1 Atlantic and Cromarty Field Layout (BG Group, 2016)

5.1.1 Decommissioning consideration and current status

BG Group prepared an environmental impact assessment (EIA) and the

decommissioning programme11 for off-shore installations and pipelines at A&C

fields. In its comparative assessment, which considered environmental,

technical, societal and cost implications of the feasible decommissioning

options, it found that most of the pipeline and umbilicals associated with offshore

11 Decommissioning options compared included a “do nothing” option, a “total removal” option and “partial removal” options. The options were compared in terms of defined, weighted criteria for safety (40%), environmental impact (20%), technical feasibility (10%), societal disturbance (15%), and relative cost (15%) (BG Group, 2016).

development, which are trenched and buried at depth of 0.6m below the seabed

surface, should be left in place. The EIA also identified that following stakeholder

engagement with the Joint Nature Conservation Committee (JNCC) it was

suggested that disturbance of the habitat in the area where the pipeline is buried

would be undesirable because it would initiate a further recovery period12.

Removal of the sub-seabed infrastructure, including much of the Atlantic export

pipeline route which passes through possible marine protected area, would have

impacted the surrounding ecosystem and biodiversity.

If decommissioned, the pipelines would be disconnected from the Atlantic

manifold, cut and removed where they emerge from the seabed, with remedial

rock cover applied to the cut ends to mitigate the risk of snagging by other sea

users. This would effectively render the pipeline impossible to re-use. In

addition, the Atlantic manifold, which is connected to the two Atlantic wells and

one Cromarty well, is waiting to be decommissioned and brought onshore for

recycling.

While the A&C draft decommissioning plan explored re-use options for the

Atlantic pipeline and deemed them commercially unviable, the pipeline itself

remains by and large suitable and re-usable for CO2 transport. The pipeline

remains under IPR until the end of 2021.

5.1.2 Technical specifications and operating envelopes

The following section provides the technical specifications for the Atlantic export

pipeline from St. Fergus to the Atlantic Manifold.

12 Within the scope of the EIA, the relative impacts on the marine environment, atmospheric emissions, stakeholder concerns and legacy issues of leaving the pipelines in place were taken into account (BG Group, 2016).



The allowable design parameters depend on the mass flow rate – the amount

of CO2 per annum. In other words, the larger the mass flow rate, the larger the

pressure drop and operating pressure allowed. The pipeline was designed for a

pressure of up to 170barg, which with its 15.5mm wall thickness, including a

3mm corrosion allowance has a design life of 20 years. Such design pressure

allowance means the CO2 can be transported over the distance of the pipeline

in a dense phase. A study by Pale Blue Dot Energy (Pale Blue Dot Energy &

Axis Well Technology, 2016) on the re-use potential of the pipeline for use in the

Captain X field also looked at various mass flow rate scenarios and the impact

of pressure drop (see Annex 1: CO2 Phase Change and Pressure Drop)

throughout the length of the pipeline. It found that even in the case of an

increased mass flow rate of 5 MTpa, the pressure drop is 32bar, with the MOP

being close to 180. This would exceed the original design pressure, however,

given the pipelines wall thickness and the fact that it was in service for less than

four years before being suspended, the pipeline could be re-rated for CO2

service at such high pressure (i.e. 180bar). The study also found that the

pipeline was designed for a 20-year life and was given a 3mm corrosion

allowance for wet hydrocarbon transport. On the other hand, in the case of dry

CO2 transport, the corrosion allowance would likely be reduced to 1mm and

minimum required wall thickness to approximately 13.2mm. Consequently, the

design life for a new duty might be different. In this case, a full pipeline integrity

and life extension studies would have to be performed to confirm the suitability

of the pipeline for CO2 transport.

Worth noting is that an internal epoxy coating has been applied during its

installation in order to improve the flow and reduce commissioning works.

Although tests have shown that the coating is resistant to dense phase CO2,

long term testing may be required to ensure that no spalling or disbondment

have occurred.

A key advantage identified by a number of stakeholders for the Atlantic pipeline

for CO2 transportation is its wall thickness, which gives it a high pressure rating

and consequently a better tolerance to the pressures needed for CO2 transport.



Parameter Value

PL ID (DECC) PL-2029

Length 79km

Design Life 20years

Outer Diameter 406.4mm (16 in)

Installation S-Lay (Trenched and Buried/Rockdump)

Wall thickness 15.5mm

Crossings 7

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

Design Pressure 170barg

Design Temperature 60 / -10°C

Operating Temperature

50°C

Table 5-1 Atlantic Pipeline Specifications

Parameter Value

Length 8km

Outer Diameter 406.4mm (16 in)




Corrosion coating 3 Layer PP

Weight Coating Concrete weight Coating

Installation S-Lay (Surface Laid)

Crossings 1

Table 5-2: Additional 8km pipeline specifications

Conversion and repurposing requirements

CO2 can be transported in gaseous, dense or liquid phase, but must remain in

the same phase while in the pipeline. Phase change is not allowed to avoid

complications of operating a multiphase system and avoid higher risks and costs

(see Annex 1: CO2 Phase Change and Pressure Drop). This condition places

requirements on the choice of pumps, pipeline diameter and wall thickness,

which directly also impacts the costs. As such, the pipelines’ physical condition

and its design determine its conversion and re-purposing requirements.



Important to note also is that re-use of pipelines limits the choice of operating

conditions.

5.2.1 Regulatory requirements

Some pipelines, such as Atlantic, are important UKCS infrastructure, and

provide the means for future developments such as CO2 transport and storage.

As such their decommissioning can be deferred by being place under the Interim

Pipeline Regime (IPR). Once the owner submits a Disused Pipeline Notification

form to BEIS; the latter will then consult with other government departments and

issue a letter outlining the conditions under which decommissioning can be

deferred. If pipeline re-use is considered viable, suitable and sufficient

maintenance is required of the owner (Oil & Gas UK, 2013).

In the UK, a Pipeline Works Authorisation/variation (PWA) must be in place

before a pipeline or pipeline system construction/modification work can begin.

In this respect, a detailed EIA must be submitted and approved by BEIS.

Depending on the status of the pipeline, it takes approximately four to six months

from receipt of a satisfactory application to issuing the authorisation.

The newly repurposed pipeline would be subject to the same regulations as

before, including the Pipelines Safety Regulations 1996, Petroleum Act 1998,

and the Coast Protection Act 1949.

5.2.2 Internal and external inspection

If a pipeline has been decommissioned, it would render it useless for re-use as

it would not be cost effective to do so. As the Atlantic pipeline has not been

decommissioned, there is not a large amount of technical work required with

respect to conversion and repurposing since the pipeline remains installed from

end-to-end.

Before the pipeline could be used for CO2 transport, several steps would have

to be taken, including:

• integrity and life extension assessment,

• anode inspection,

• subsea external inspection (especially pipeline crossings or erosion

and impact on pipeline support),

• assessment of needs to support the pipeline in case of any stress

gaps across the ocean floor and the pipeline itself,

• drying of the pipeline.

Internal inspection

Integrity of the pipeline, for example, could be assessed using a so-called

“intelligent pig” (see Figure 5-2 below). This process, also referred to as

“pigging”, can also perform various maintenance operations, including cleaning

and repair. Previous study work from the Longannet and Peterhead CCS

projects suggests that the intelligent pig run would best be undertaken in the

Execute stage of a project prior to entering operations. Estimated costs for

running such an operation would be around £4million (Shell, 2016).

Further assessment of potential for ductile fracture due to rapid decompression

would also have to be performed during the Front-End Engineering Design

(FEED) study.



Figure 5-2 An Example of an "Intelligent pig" Inspecting Pipeline Condition (Intertek, 2016)

External inspection

External inspection of pipeline crossings, as well as any potential erosion or

impacts on pipeline supports, would be required. In addition, free span surveys

would have to be performed. A free span occurs where a pipeline spans

between two high points on the seabed. This can create additional stress on the

pipeline itself and must be corrected (i.e. by placing grout bags underneath and

filling them with liquid cement or grout), before the pipeline is washed and CO2

transported. Free span surveys can consist of preliminary stress and vibration

frequency checks, followed by detailed strain and fatigue life checks where

appropriate. (Kaye, Ingram, Galbraith, & Davies, 1995).

13 Opex was calculated based on a 20-year design life and a 30% contingency has been included throughout.

Rationale for preservation

The Atlantic pipeline, as technical and operating envelopes show, is well suited

for CO2 transport in light of its wall thickness and consequently a higher pressure

rating. This means the pipeline itself has a higher tolerance to the pressure

required for CO2 transport and injection. The pipeline has sufficient remaining

asset life to support the development of CCS projects in the UK. No substantial

risks were identified.

The Captain X CO2 storage development plan has previously identified using the

16” pipeline along with a new 8km 16” pipeline from the Atlantic manifold to a

newly installed Normally Unmanned Installation (NUI) at the Captain aquifer.

The 8km pipeline would be required in both re-use and new pipeline scenario

and would connect the existing pipeline with the NUI.

5.3.1 Estimates of cost

The Captain X CO2 storage development plan and budget has shown the

estimated capital (Capex), operating (Opex)13 and abandonment expenditures

(Abex) for the engineering, procurement, construction, installation,

commissioning, operation and decommissioning of the Captain X facilities.

Within the study, the following Capex estimates for utilising the existing Atlantic

and Cromarty pipeline from St Fergus to the Atlantic field were made:

The total subsea Capex (excluding wells), including pre- and post-Final

Investment Decision (FID), was estimated at £33.7million, while Abex

decommissioning costs were estimated at £4.8million. Opex costs, on the other



hand, were estimated at £8.8million for a 20-year design life. The transportation

Capex associated with laying a new pipeline was estimated as being just over

£100million (Pale Blue Dot Energy & Axis Well Technology, 2016).

Phase Category Total Captain X Development (£M)

Pre-FID Pre-FEED 0.4

FEED 0.6

Post-FID

Detailed Design 0.7

Procurement 5.1

Fabrication 4.9

Construction & Commissioning

22.0

Total Capex – Transportation (£M) 33.7

Table 5-3 Captain X Development - Transport Capex (Base case)

Phase Category Total Captain X Development (£M)

Pre-FID Pre-FEED 0.4

FEED 0.6

Post-FID

Detailed Design 0.7

Procurement 30.7

Fabrication 8.5

Construction & Commissioning

60.0

Total Capex – Transportation (£M) 101.7

Table 5-4 Captain X Development - Transport Capex (New Pipeline System)

It should be noted that the base case scenario (Table 5-3) consists of re-using

the existing 79km Atlantic pipeline (Table 5-1) from St. Fergus to the Atlantic

Manifold, and installation of an infield pipeline. Other options of acquiring the

pipeline should be considered in the future. If the acquisition of the pipeline

would not be possible (i.e. due to integrity or other issues) a new pipeline from

St. Fergus to Captain X NUI would have to be constructed (see Table 5-4).

Re-use vs. new pipeline

When considering reusing the pipeline versus constructing a new one, it should

again be pointed out that the 8km pipeline (see Table 5-2), from the Atlantic

manifold to Captain X NUI would have to be constructed in both scenarios.

As such, when making a true comparison, the costs to be considered are:

Re-use



• £33.7m (€38.3m) for the 8km pipeline from the Atlantic manifold to

the Captain X NUI;

• £4m (€4.5m) for the existing pipeline from St. Fergus to the Atlantic

manifold. This cost includes an estimated cost of running an

intelligent pig and other commissioning type duties (i.e. drying the

pipeline) to make the pipeline ready for CO2 transport.

New

• £33.7m (€38.3m) for the 8km pipeline from the Atlantic manifold to

the Captain X NUI;

• £101.7m (€113.7m) for the new pipeline from St. Fergus to the

Atlantic Manifold;

In this respect the comparison of costs between re-use and constructing a new

pipeline is £37.7m (€42.8m) and £135.4m (€152m).

5.3.2 Key risks

Key risks include corrosion and horizontal ductile fracture. The Atlantic pipeline,

however, is less susceptible to the latter due to increased wall thickness.

Nevertheless, while there is some uncertainty as to the exact level of corrosion

from the existing use, doing an “intelligent pig” assessment, as was pointed out

by several key stakeholders, would help with reducing that risk. Cost estimates

from the Peterhead CCS Project FEED Summary Report suggest that intelligent

pigging of the pipeline would cost somewhere around £4million (Shell, 2016).

Another option for reducing the risks of corrosion, as well as ductile fracture, and

providing flow assurance and system integrity would be via a so-called “pipe-in-

pipe” (PiP) solution. This, however, is rendered much more difficult in the re-use

of subsea pipelines as installations would be extremely technologically

challenging, as well as costly. Nevertheless, as it stands, we believe this to be

an unnecessary mitigation for the risks.

D11 Infrastructure Re-use Goldeneye Pipeline


6.0 Goldeneye Pipeline


The depleted Goldeneye gas field, whose production ran from 2004 to 2011, is

underlain by the Captain Aquifer, and is located approximately 100km offshore

from St. Fergus Gas Terminal of the northeast coast of Scotland. It is part of one

of the best studied and most suitable formations for CO2 storage in the North

Sea and is connected to St. Fergus by a 101km long and 0.508mm (20”) in

diameter carbon steel pipeline.

Shell, as the operator of the Goldeneye infrastructure (platform, wells, pipelines),

has previously said that without a CCS project all infrastructure would be

decommissioned. Because there is currently no approved decommissioning

programme for the Goldeneye field, it is believed the infrastructure could be

decommissioned within the next year without a clear case being made for the

re-use of its infrastructure.

The re-use of the platform and wells at Goldeneye offers both benefits and

certain disadvantages. One of the issues related to the Goldeneye platform is

the operating costs, which would likely be much higher if the platform was re-

used for CO2 injection. On the other hand, reusing the platform would offer the

benefit of easier re-entering/re-use of the wells. The platform is likely to require

extensive life-extension work to be done, including removal/bypassing of all

14 Storage Opex costs include: final financial mechanism payment (post-transfer obligation), lease fee, storage organization costs associated with support of the measurement, monitoring and verification activities across the full life of the project (Shell, 2016b).

production facilities and replacing them with the injection facilities required. Such

modifications tend to be quite costly.

The Peterhead CCS Project Cost Estimate and FEED Summary reports,

prepared by Shell as part of the Knowledge Deliverables for the UK CCS

Competition, provide a summary of the Capex and Opex cost estimates for the

execute phase of the project. They show, for example, that offshore Capex (i.e.

for landfall, pipeline, subsea, Goldeneye modifications, wells and subsurface)

stood at approximately £222million, of which nearly £61million was for

Goldeneye modifications, £89million for wells and surface, and £72million for

landfall, pipelines and subsurface related activities. Opex cost estimates, on the

other hand, shown that for a 15-year injection operational period, transport and

storage14 would amount to £90million and £2million respectively (Shell, 2016).

The question of equitable sharing of costs between new and future owners is an

important one in considering re-use of existing platforms. Furthermore, there are

other important technical and commercial limitations, albeit some benefits as

well, when discussing the re-use of existing wells. As mentioned, the goal of this

Report is primarily to present the necessary information and considerations for

the re-use of the Goldeneye pipeline.

The Goldeneye pipeline operated between 2006 and 2010 after which, in 2013,

it was cleaned of hydrocarbons and filled with a corrosion inhibitor and a biocide



solution, with a protection life of seven years (Shell, 2016). It is owned by the

Goldeneye Joint Venture partners and operated by Shell.

The Goldeneye pipeline has previously been assessed for re-use potential

during the Peterhead CCS Project and the Longannet CCS Project. The FEED

study of the latter also showed that the pipeline is suitable for dense phase CO2

transportation within its operational parameters (see 6.1.2 below).


There is no approved decommissioning programme for the Goldeneye field and

facilities, which include topsides, wells, and the pipeline, meaning these could

be decommissioned, and the wells abandoned, in the coming years considering

the UK oil and gas regulations, if no CCS option is progressed.

The Goldeneye pipeline operated between 2004 and 2010 after which corrosion

risk was evaluated using the Pipe RBA (Risk Based Assessment). It was flushed

free of hydrocarbons in 2013 and left mothballed with inhibited water and a

corrosion inhibitor. The pipeline has now been placed under the IPR up until

2022 and is considered suitable for dense phase CO2 transportation.


Parameter Value

PL ID (DECC) PL-1979

Length 101km

Design Life 20years

Outer Diameter 508 mm (20in)




MAOP (max. allowable operating pressure)

125barg

Design Temperature +60 / 0°C

Max. CO2 flow rate 2.4MT/yr

Operating Temperature

50°C

Capacity 2-4MT/yr

Route and crossings

Direct from Goldeneye platform to Shell-Esso terminal at St. Fergus (parallel to and south of Miller / SAGE (Scottish Area Gas Evacuation) pipeline corridor)

Five pipeline crossings

Table 6-1 Goldeneye Pipeline Secifications

Previous studies have identified no significant issues and have shown that the

pipeline, which has a carrying capacity of 2-4MT/yr, is suitable for dense phase

or liquid CO2 transportation, within the defined operational parameters (i.e. max.



and min. temperatures and CO2 water content limits). The maximum allowable

operating pressure and the pipeline diameter also govern the maximum well

injection rate (Shell, 2016).

Furthermore, when the pipeline was installed an internal epoxy coating was

applied to improve the flow and reduce commissioning works. There has been

no evidence of coating spalling or disbondment, although the Peterhead CCS

project FEED study did suggest shot blasting to remove mill scale, and special

attention to be given to dewatering the pipeline system prior to filling it with CO2,

as free water combined with high CO2 pressure could lead to extreme corrosion

rates.

Figure 6-1 Goldeneye Pipeline from St Fergus to Goldeneye Platform (Shell, 2016)


No significant conversion/repurposing changes would need to be made to the

Goldeneye pipeline. As per the Atlantic and MGS pipelines, the conversion and

repurposing requirements are inherently related to external and anode

inspection, particularly the pipeline crossings or erosion and impact on pipeline

support. In addition to running an “intelligent pig”, an assessment of potential

needs to support the pipeline in case of any stress gaps across the ocean floor

and the pipeline itself would be performed at the FEED stage.


The Goldeneye pipeline is considered to have sufficient remaining asset life to

support the development of CCS projects in the UK. The examination of

potential key risks and certain cost estimates indicate that preservation is

sensible.

6.3.1 Estimates of costs

Given the proprietary nature of the financial information, estimates of costs for

the preservation or decommissioning of the pipeline were not made available.

Nevertheless, the following costs considerations are associated with the

preservation of the Goldeneye pipeline:

• financial compensation as agreed-upon between the Goldeneye JV

and the government authority or a third-party entity;

• cost differential between decommissioning today versus in the

future;

• ongoing maintenance costs for the Goldeneye pipeline.



On the other hand, preserving the Goldeneye pipeline includes, among other

things, the following benefits:

• helps retain regional CCS opportunities (i.e. network, hub);

• costs and risks are reasonably well known;

• maximizes cost efficiency from previous investments;

• no long-term government commitment to large Capex/Opex is

required;

• demonstrates to industrial emitters that government is committed to

a near-future deployment of CCS;

• creates options for future CCS business models;

• retain skills and jobs.

Providing reliable decommissioning cost estimates has proven to be extremely

difficult, with many projects experiencing between 30% to over 100% cost

overruns. Poor cost estimates are in large part the result of lack of available

performance benchmarks and forecasting models that would serve as the basis

for developing decommissioning budgets, designing decommissioning plans,

assessing the impact of changes in project scope versus actual performance,

and monitoring execution performance (BCG, 2017).

As mentioned in the introduction, pipeline decommissioning however, does not

form a large part of the overall decommissioning cost. Given the proprietary

nature of the cost estimates, the numbers are not provided in this Report.

Please also refer to Section Estimates of costs7.3.1 of this report.

6.3.2 Key risks

Some of the key risks associated with reusing the pipeline include unexpected

corrosion and ductile fracture.

Although the Goldeneye pipeline has been flushed clear of hydrocarbons and

anti-corrosion inhibitor put in place, albeit quantified as very low, there remains

a risk that excessive levels of corrosion could have made the pipeline unsuitable

for CO2 transportation. To mitigate this risk, it has been recommended that a

survey of the full length of the pipeline is made using a so-called intelligent pig,

which, at an estimated cost of £4million, would ensure maximum cost and

schedule certainty. In addition, to mitigate risk of corrosion, an anti-corrosion

coating system should be applied.

Shell has noted in its Peterhead CCS Project Basic Design and Engineering

Package report that the risk of running ductile fracture is propagated by dense

phase CO2 decompression. CO2 dense phase transport presents low

temperature risks during depressurization. Due to decompression behaviour,

uncontrolled depressurisation presents an increased risk of brittle and/or ductile

fracture. To reduce running ductile fracture risk, the composition of the CO2 must

be controlled to prevent rapid and uncontrolled depressurisation, and a running

ductile fracture propagation control is required for the pipeline design. For the

Peterhead CCS Project, Shell conducted simulations of CO2 gas composition to

model gas decompression and saturation pressure for dense phase operation

and establish a range of maximum operating temperatures for the entire length

of the Goldeneye pipeline (Shell, 2016).

In comparison to the Atlantic and MGS pipelines, the Goldeneye pipeline is of

lesser thickness, with lower tolerance to the potential pressure needed for CO2

transport. In theory this would render it more susceptible to running ductile

fracture, but this risk could be managed through effective temperature control.

D11 Infrastructure Re-use MGS Pipeline


7.0 MGS Pipeline



The depleted Miller gas field is located 240km northeast of Aberdeen, Scotland,

in the Central North Sea, and was in operation until 2007 when the Cessation of

Production (CoP) was submitted to the OGA. The first half of the 240km and

0.762mm (30”) diameter pipeline (PL-720), which connects the St. Fergus

Terminal and the Miller field, is trenched, and the second half is surface laid.

The wells were plugged and abandoned, and the topsides are to be removed by

the end of 2018, the pipeline was flushed clear of hydrocarbons in 2009. Since

then, the pipeline has been serviced by BP, and the last service/maintenance

performed in 2013. The pipeline has been under the Interim Pipeline Regime

(IPR) for the past 10 years, which has recently been extended for a period of

further five years, until 2021.

The Miller decommissioning programme, approved in 2011, applies to the

installations (i.e. topsides, jackets) and effectively the wells, but not the pipelines

themselves. A decommissioning programme for the pipelines is yet to be

prepared. BP has taken the steps of decommissioning certain infrastructure,

including disconnecting the pipeline from the platform but the pipeline could still

be used for CO2 transport to new facilities (subsea or platform-based) at the

15 As of November 2017, given that a pipeline decommissioning program has not yet been considered, decommissioning would likely include cutting ends of the pipeline, trenching certain sections while removing others. The extent of the decommissioning also depends on the end state and what is agreed with the regulator.

Miller field. This would need to include a new oil export system, if the

development would be for EOR.

A decision as to whether the pipeline is to be decommissioned15 or preserved

for another use, would be made after the removal of other Miller field

infrastructure (i.e. platform), and after a decommissioning programme is

approved/agreed upon with the OGA and other Joint Venture partners after

2021.16 Nevertheless, the work performed thus far demonstrates the pipeline to

be in good and reusable condition, with an estimated life span into the late 2020s

or longer (Turin & Blacklaws, 2017). Furthermore, the Miller pipeline was

designed to carry gas with a high CO2 content making it well placed for CO2

transport.

While BP has identified that it is interested in finding another use of the pipeline,

it does not hold much interest in operating it, given it was installed to carry gas

from the Miller field (now being decommissioned) and as such does not provide

any value. In this respect, one of the key drivers of decommissioning is the

liability associated with the pipeline. If there was a viable business option for

reusing the MGS pipeline for something else, BP would progress the opportunity

to have the pipeline preserved and re-used. (Turin & Blacklaws, 2017).

16 The infrastructure is operated by BP (who is also the license owner for the Miller field) in partnership with ConocoPhillips and Shell. In April 2016, Petrofac was also awarded a Duty Holder contract from BP to support the late life management of the platform (BP, 2011).



Figure 7-1 Location of the Miller Platform (BP, 2011)


Parameter Value

PL ID (DECC) PL-720

Length 240km

Design Life 20years

Outer Diameter 762mm (30in)


Wall thickness 24mm


Design Pressure 174bar

Operating Temperature +75 / -10°C

Capacity 10MT/yr

Table 7-1 MGS Pipeline Specifications


Conversion and repurposing requirements would depend on the entity looking

to re-use the pipeline, however, like the Atlantic and Goldeneye pipelines, no

significant conversion/repurposing changes would be required.

In any case, a high level of confidence would need to be obtained for anyone

looking to re-use the pipeline as it has been out of service for a long time.

Assurance on the wall thickness and robustness of the pipeline, an

understanding of the consequences of failure and what evidence is needed to

prevent any failures would have to be made prior to bringing the pipeline back



in to operation. A strict process of validating the integrity and potentially updating

the protection system is likely to be required ahead of re-use of the pipeline.


The MGS pipeline is considered in good enough condition to have sufficient

remaining asset life to support the development of CCS projects in the UK. In

addition, the examination of potential key risks and certain cost estimates

indicate that preservation is sensible, given the cost of decommissioning versus

cost of constructing a new pipeline. Nevertheless, there are several important

issues to consider when making a rationale for preservation.

As mentioned, although their business strategy is focused on oil and gas, and

the pipeline itself is currently not delivering any value to BP, they are open to the

pipeline being repurposed for CO2 transport. If another organisation/entity

wanted to acquire the pipeline and its liabilities, or there was a viable business

option available for reusing the MGS pipeline, BP would be interested in

progressing the opportunity to have the pipeline preserved and re-used. An

important aspect for BP, and other JV partners, would be to not continue to own

the pipeline or retain any future liabilities associated with it. So as not to be held

liable under Section 34 of the 1988 Petroleum Act, it would be important that

sufficient due diligence is completed on the organisation/entity taking over the

ownership and liabilities, including their financial capability to operate and

manage those liabilities. In short, for BP to not proceed with their current

decommissioning plan they would require a vetted new owner to take on and

underwrite all future liabilities. (Turin & Blacklaws, 2017)

A critical issue for BP in whether to preserve or decommission the MGS pipeline

is timing. Preservation would only occur if a clear timeframe of alternative use

can be presented to them which is in line with how long BP are prepared to

retain the asset. In this respect, BP is seeking clarity on the timing and/or the

nature/level of compensation that would be provided to them to preserve the

pipeline, as opposed to decommission it.

BP has shown willingness to work with all the relevant key stakeholders,

including Bellona, Pale Blue Dot, the OGA and others, as they consider

preservation of the infrastructure important; for CCS development in the region

or other alternative uses. Nevertheless, the pipeline is currently not delivering

any value for BP, has been under IPR for the past 10 years, and no one has

presented a realisable plan to date. Time is running out. A credible plan which

relieves BP of the liabilities associated with the pipeline must be finalised and

presented before it is too late.

7.3.1 Estimates of costs

Aside from what is available in the public domain and what was provided during

consultation with BP, obtaining detailed cost estimates on the decommissioning

and/or conversion/re-purposing was difficult to obtain. Thus, lessons learned

and cost estimates are taken from a similar decommissioning project done by

BP; the North West Hutton decommissioning project. The North West Hutton

field is located approximately 130km northeast of the Shetland Islands in the

Northern North Sea (see Figure 7-2 below) and was in operation between 1983

and 2002.



Figure 7-2: Location of North West Hutton: (Jee, 2014)

The decommissioning project, completed in 2009, along with the removal of the

jackets and topsides included the decommissioning of two oil and gas export

pipelines, both of 13km in length. Decommissioning scope included cutting and

removal of exposed pipeline sections, removal of sub-sea isolation valves and

associated spools, umbilicals and concrete mattresses. The predicted

decommissioning costs for the 250mm (10”) PL-147 gas pipeline were £3million,

but the final costs reached £5million. Decommissioning costs of the 510mm

(20”) PL-148 oil pipeline were originally estimated at £3million, and the final cost

amounted to £10million. The £7million cost differential in estimated and actual

decommissioning cost of the PL-148 pipeline came as a result of initial cutting

technologies employed proving to be acceptable but inefficient for the large

number of cuts required. The difference came because of delays that had been

incurred due to the change of technique and equipment used (Jee, 2014).

These estimates show that the decommissioning of the 26km of the pipeline

infrastructure came at a cost of £15 million, or £0.6 million per kilometre.

7.3.2 Key risks

The risks arising from the re-use of existing pipeline are like the risks identified

with the Goldeneye and Atlantic pipelines. These include, in theory, horizontal

ductile fracture and corrosion. In order to mitigate the risks, a full-length survey

of the pipeline using the intelligent pig method could be performed.

Nevertheless, representatives from BP (Turin & Blacklaws, 2017) did suggest

that there is no concern with ductile fracture in the MGS pipeline because no

hydrocarbon is present anymore. BP is performing regular inspections through

which these risks of impacts on other users of the sea are mitigated.

At the same time, representatives from BP highlighted that running an intelligent

pig at this point in time would not make sense, as no alternative use option has

been presented yet. While an intelligent pig is quite an expensive option to run,

it is a tool that will yield the best integrity results over the totality of the length of

the pipeline.

D11 Infrastructure Re-use Generic Key Risks


8.0 Generic Key Risks

Technical and operational risks

Key risks associated with re-using the existing pipelines include corrosion and

ductile fracture, both of which are driven by the CO2 phase behaviour and

operating pressure of the pipelines. In managing operational risks, a key task is

to thoroughly clean and dry the pipelines before CO2 transportation begins. Such

risks, however, are by the current pipeline owners/operators considered to be

well understood and manageable. Running an intelligent pig is recommended

depending on the condition of the pipeline and previous history.

In addition, free spans, or where a pipeline spans between two high points on

the seabed, can create additional stress on the pipeline itself. Since dense

phase CO2 is likely to be denser than the fluids for which the pipelines were

designed, unsupported sections may not have sufficient strength. This must be

corrected (i.e. by placing grout bags underneath and filling them with liquid

cement or grout), before the pipeline is washed and CO2 transported. Free span

surveys, consisting of preliminary stress and vibration frequency checks,

followed by detailed strain and fatigue life checks where appropriate (OGJ,

1995), would help mitigate the risk of structural failures.

Legal and liability considerations

In the UK, the Offshore Petroleum Regulator for Environment and

Decommissioning (OPRED) within BEIS regulates the decommissioning of

offshore oil and gas pipelines, as well as other installations (UK Government,

17 The aim is to ensure that the new license holder can cover the decommissioning liabilities.

1988). Decommissioning obligations arise when the Secretary of State serves

the operator/owner of the pipeline a Section 29 notice under the Act (UK

Government, 1988), by which they are required to submit a decommissioning

programme by the date set by the Secretary of State. Once the programme,

including its costs, are approved by the Oil and Gas Authority (OGA), the Section

29 holder is obliged to carry out the tasks as set under the programme. Failure

to do so gives the Secretary of State the ability to take remedial action and

recover the costs from the Section 29 notice holder.

If, for example, a third party is to take over an asset (i.e. pipeline), the Secretary

of State may release a former licensee from its Section 29 obligations, if the

OGA is satisfied that adequate financial security arrangements (i.e.

Decommissioning Security Deed17) are in place in relation to the

decommissioning liabilities. Although the Secretary of State is not usually a party

in such industry led arrangements, also known as Decommissioning Security

Agreement (DSA), its presence may facilitate the withdrawal of a Section 29

notice on a departed licensee.

Nevertheless, the OGA may also in the case of an unsatisfactory

decommissioning programme, pursuant to Section 34 of the Petroleum Act,

serve a Section 29 notice to anyone, who, at any time since the issue of the first

Section 29 notice for the installation, was liable to have a Section 29 notice

served on them (i.e. former licensees).

D11 Infrastructure Re-use Generic Key Risks


Technically, although considered as a measure of last resort, until

decommissioning is complete, the Secretary of State has the right to require any

(current and former) licensee to be held liable for the decommissioning. When

assets are transferred/sold to a third party, a key component is ensuring that the

third party has all the underwriting and liability provisions so that the liabilities

are not rolled back onto the previous owner or former Section 29 notice holder.

In other words, establishing liability assurance between the parties is key.

Key considerations/issues:

• Is the pipeline under the Interim Pipeline Regime (IPR) and for how

long?

• CO2 is defined as a commodity when transported for commercial use

– such transport is legal. If CO2 is defined as waste and intended for

international transport special permits between import and export

countries are required.

• What is the extent of the (financial) liabilities associated with the

pipeline (decommissioning vs. preservation)?

D11 Infrastructure Re-use Conclusions


9.0 Conclusions

1. Between 2016 and 2025, operators in the North Sea intend to

decommission around 17% of the total pipeline network from the UK and

Norwegian Continental Shelves, or 850 pipelines with a total length of

nearly 7,500 km. The central North Sea hosts the largest number of these

pipelines (484), the southern North Sea and Irish Sea will see the largest

proportion of the total pipeline length, 3,426km, be decommissioned (Oil

& Gas Authority, 2016). Cost of planned decommissioning of 580

pipelines with a length of 3,700km is estimated at £847m (€947m), which

amounts to £1.46m (€1.63m) per pipeline (including associated

infrastructure such as umbilicals & infield lines), or £225k (€251m) per

km.

2. North Sea decommissioning has in some cases been delayed, principally

because of successful dialogue between the asset owners, the

government and other key stakeholders. These delays have been an

important short-term policy option allowing for the interim preservation of

the pipeline infrastructure.

3. The recently proposed changes to the UK’s decommissioning tax relief

regime on transfer of tax history, effective 1 November 2018, whereby

new asset owner would be able to, to some extent, claim back its

decommissioning costs, could encourage investment into late-life assets

in the North Sea and thereby maximise economic recovery (Thomas,

2017).

4. Repurposing existing legacy pipeline infrastructure offers significant cost

savings and an efficient approach to facilitating wider CCS deployment

(Brownsort, 2016) (Chandel, Pratson, & Williams, 2010) (Brunsvold,

Jakobson, Husebye, & Kalinin, 2011).

5. Initial cost estimates show that repurposing a pipeline would cost about

one fourth of the cost of building a new pipeline.

6. The best suited pipelines for re-use in the North Sea are currently:

Atlantic, Goldeneye, MGS. All are technically feasible for re-use and

under IPR until 2021.

7. Corrosion is identified as the largest potential technical risk. Any kind of

impurities in the CO2 could cause rapid corrosion and/or fracture. This

could be an issue when CO2 from multiple sources is combined. It will be

critical to ensure that capture plants meet the required CO2 purity levels,

which would be reconfirmed at the fence (before transported through the

existing pipeline).

8. Clarity on liability provisions, particularly when ownership of assets is

transferred is key. Public-private partnership has been identified as best

suited model, whereupon assets are transferred into public ownership,

with the government taking on all the associated risks and liabilities.

Investments in conversion/re-purposing and modifications would be paid

for by the private sector, with investments being incentivised (i.e. making

them tax deductible).

D11 Infrastructure Re-use References


10.0 References

BCG. (2017). The North Sea's $100 Billion Decommissioning Challenge.

Retrieved from https://www.bcg.com/en-be/publications/2017/energy-

environment-north-sea-decommissioning-challenge.aspx

BG Group. (2016). Atlantic and Cromarty Fields Draft Decommissioning

Programmes.

BP. (2011). Miller Decommissioning Programme. Retrieved from

https://www.bp.com/content/dam/bp-country/en_gb/united-

kingdom/pdf/Miller_Decomm_Programme.pdf

Brownsort, P. A. (2016). Reducing costs of carbon capture and storage by

shared re-use of existing pipeline - Case study of a CO2 capture cluster

for industry and power in Scotland. International Journal of Greenhouse

Gas Control 52, 130–138 .

Brunsvold, A., Jakobson, J. P., Husebye, A., & Kalinin, A. (2011). Case Studies

on CO2 Transport Infrastructure: Optimisation of Pipeline Network,

Effect of Ownership, and Political Incentives. Energy Procedia, 4, 3024-

3031.

Chandel, M. K., Pratson, L. F., & Williams, E. (2010). Potential Economies of

Scale in CO2 Transport Through Use of a Trunk Pipeline. Energy

Conversion and Management, 51(12), 2825-2834.

CRF. (2016). Status Capacity and Capability of North Sea Decommissioning

Facilities. Retrieved from

http://www.gmbscotland.org.uk/assets/media/documents/pressrelease

s/GMB-SCOTLAND-REPORT-Status-capacity-and-capability-North-

Sea-Decommissioning-Facilities-final-web-GMB-cover.pdf

Global CCS Institute. (2013). The Properties of CO2. Retrieved from Global

CCS Institute: https://hub.globalccsinstitute.com/publications/hazard-

analysis-offshore-carbon-capture-platforms-and-offshore-pipelines/21-

properties-co2

Intertek. (2016). Intelligent Pigging Pipeline Inspection Services. Retrieved from

https://www.youtube.com/watch?v=X5S48nytYJg&t=147s

Jee. (2014). North West Hutton Decommissioning Programme: Close-out

Report. Retrieved from https://www.bp.com/content/dam/bp-

country/en_gb/united-

kingdom/pdf/NWH_Decommissioning_Programme_Close_Out.pdf

Kaye, D., Ingram, J., Galbraith, D., & Davies, R. (1995). Freespan Analysis,

Correction method saves time on North Sea Project. Oil and Gas

Journal. Retrieved from http://www.ogj.com/articles/print/volume-

93/issue-8/in-this-issue/pipeline/freespan-analysis-correction-method-

saves-time-on-north-sea-project.html

Oil & Gas Authority. (2016). Decommissioning Strategy. Retrieved from

https://www.ogauthority.co.uk/media/1020/oga_decomm_strategy.pdf

Oil & Gas Authority. (2017). UKCS Decommissioning: 2017 Cost Estimate

Report. Retrieved from

https://www.ogauthority.co.uk/media/3815/ukcs-decommissioning-

cost-report-2.pdf

D11 Infrastructure Re-use References


Oil & Gas UK. (2009). Guidelines for the Suspension and Abandonment of

Wells.

Oil & Gas UK. (2013). Decommissioning of Pipelines in the North Sea Region.

Oil & Gas UK. (2016). UK MER Strategy.

Pale Blue Dot Energy & Axis Well Technology. (2016). D13 WP5D Report -

Captain X Storage Development Plan. Energy Technologies Institute.

Pale Blue Dot Energy and Axis Well Technologies. (2015). Captain X Storage

Development Plan and Budget. Energy Technologies Institute.

Pale Blue Dot Energy and Axis Well Technology. (2015). Strategic UK CO2

Storage Appraisal Project. Loughborough: Energy Technologies

Institute.

Shell. (2016). Peterhead CCS Project.

Turin, S., & Blacklaws, J. (2017, November 7). Information gathering

conversation for ACT Acorn project. (M. Maver, Interviewer)

UK Government. (1988). UK Petroleum Act. Retrieved from

http://www.legislation.gov.uk/ukpga/1998/17/section/19

D11 Infrastructure Re-use Annex 1: CO2 Phase Change and Pressure Drop


11.0 Annex 1: CO2 Phase Change and Pressure Drop

CO2 Phase Change

CO2 can be transported in gaseous, dense or liquid phase. To ensure single

phase flow within the pipeline and avoid a raise in risks and costs if phase

change occurred, a minimum operating pressure must be set. It is the fluid flow

regime and any pressure drop that determine the capacity of pipelines. This

capacity, however, can be increased with pressure boosting stations, located

along the pipeline, albeit their installation may increase the overall costs to a

level at which it would outweigh the benefits from re-using an existing pipeline

(Element Energy Limited, 2014).

Figure 11-1: CO2 phase changes (Global CCS Institute, 2013)

Figure 11-1 shows the points at which the CO2 exhibits phase change behaviour,

which is dependent on the temperature and the pressure. The “triple point” is

the point where CO2 can exist in three phases (gas, liquid, solid) simultaneously

in thermodynamic equilibrium. Above the so-called “critical point” (74barg and

31°C), the CO2 develops “supercritical” properties, where the liquid and gas

phases cannot exist as separate phases, but rather has some characteristics of

a gas and others of a liquid (Global CCS Institute, 2013).

CO2 Pressure Drop

The pressure drop throughout the length of the pipeline is one of the key

technical issues related to the re-use of pipelines, given that any severe changes

would not only affect the integrity of the pipeline but also its capacity.

Table 11-1 shows the St. Fergus to Captain NUI pipeline pressure drop

estimates based on different mass flow rates (Pale Blue Dot Energy & Axis Well

Technology, 2016)

Pipeline Width Mass Flow Rate

Length Fluid Phase Pressure Drop, per km

Pressure Drop

St. Fergus to Captain NUI

406mm (16”)

2MTPa

87km (79+8)

Liquid/Dense

0.062bar 5.3bar

3MTPa 0.139bar 12.0bar



Table 11-1: St Fergus to Captain NUI pipeline pressure drop

D11 Infrastructure Re-use Factsheet 1: Re-use of North Sea Topside Infrastructure for CO2 Storage


Factsheet 1: Re-use of North Sea Topside Infrastructure for CO2 Storage

D11 Infrastructure Re-use Factsheet 1: Re-use of North Sea Topside Infrastructure for CO2 Storage


D11 Infrastructure Re-use Factsheet 2: Re-use of North Sea Production Oil & Gas Wells for CO2 Storage


Factsheet 2: Re-use of North Sea Production Oil & Gas Wells for CO2 Storage

D11 Infrastructure Re-use Factsheet 2: Re-use of North Sea Production Oil & Gas Wells for CO2 Storage


D11 Infrastructure Re-use Factsheet 3: Re-use of North Sea Transport Infrastructure


Factsheet 3: Re-use of North Sea Transport Infrastructure

D11 Infrastructure Re-use Factsheet 3: Re-use of North Sea Transport Infrastructure


project: act acorn feasibility study acorn...1 31/05/2018 1st issue marko maver tim dumenil steve...

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