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Project: ACT Acorn Feasibility Study

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must also reference its original source. The material is made available in the interest of progressing CCS by

sharing this ACT work done on the Acorn project.

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mailto:[email protected]

D17 Feeder 10 10196ACTC-Rep-03-02

October 2017

www.actacorn.eu

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.

Acorn

D17 Feeder 10 Contents

ACT Acorn Consortium of 34

Contents

Document Summary

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

Project Title Accelerating CCS Technologies: Acorn Project

Title: D17 Feeder 10

Distribution: Client & Public Domain

Date of Issue: 12th October 2017

Prepared by: Sam Gomersall and David Pilbeam (Pale Blue Dot Energy)

Approved by: Steve Murphy, ACT Acorn Project Director

Disclaimer:

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

any representation or warranty, expressed or implied, as to the accuracy or completeness of the report. The authors assume no liability for any loss or damage arising from decisions

made on the basis of this report. The views and judgements expressed here are the opinions of the authors and do not reflect those of the client or any of the stakeholders consulted

during the course of this project.

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

University of Aberdeen, University of Edinburgh and University of Liverpool.

Amendment Record

Rev Date Description Issued By Checked By Approved By

02 12/12/17 Final Issue D Pilbeam S Gomersall S Murphy



Table of Contents

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

1.0 EXECUTIVE SUMMARY .................................................................................................................................................................................................................... 6

2.0 INTRODUCTION ................................................................................................................................................................................................................................ 7

3.0 D17 SCOPE ...................................................................................................................................................................................................................................... 12

4.0 FEEDER 10 BACKGROUND ........................................................................................................................................................................................................... 13

5.0 FEEDER 10 CHANGE OF USE ....................................................................................................................................................................................................... 15

6.0 ST FERGUS CO2 COMPRESSION ................................................................................................................................................................................................. 20

7.0 COST SUMMARY ............................................................................................................................................................................................................................ 23

8.0 VALUE AND ECONOMICS .............................................................................................................................................................................................................. 24

9.0 FUTURE CONSIDERATIONS .......................................................................................................................................................................................................... 31

10.0 CONCLUSIONS ............................................................................................................................................................................................................................... 33

11.0 REFERENCES ................................................................................................................................................................................................................................. 34



Figures

FIGURE 2-1: ACT ACORN CONSORTIUM PARTNERS ............................................................................................................................................................................................ 7

FIGURE 2-2: KEY AREAS OF INNOVATION ........................................................................................................................................................................................................... 8

FIGURE 2-3: ACT ACORN WORK BREAKDOWN STRUCTURE ................................................................................................................................................................................ 8

FIGURE 2-4: ACORN OUTLINE MINIMUM VIABLE DEVELOPMENT PLAN ............................................................................................................................................................... 10

FIGURE 2-5: ACORN BUILD OUT SCENARIO FROM THE 2017 PCI APPLICATION ................................................................................................................................................... 11

FIGURE 4-1 OVERVIEW OF NTS PIPELINE FEEDERS IN SCOTLAND .................................................................................................................................................................... 13

FIGURE 4-2 SCHEMATIC SHOWING FEEDER LINES IN SCOTLAND ....................................................................................................................................................................... 14

FIGURE 6-1 ST FERGUS TERMINALS ............................................................................................................................................................................................................... 20

FIGURE 8-1 FEEDER 10 CO2 THROUGHPUT SCENARIO .................................................................................................................................................................................... 26

FIGURE 8-2 FEEDER 10 CASH FLOW PROJECTION (£5.50/T) ........................................................................................................................................................................... 27

FIGURE 8-3 RATE OF RETURN FOR VARIOUS THROUGHPUT TARIFFS ................................................................................................................................................................ 28

Tables

TABLE 2-1 ACT ACORN MILESTONES AND DELIVERABLES ................................................................................................................................................................................. 9

TABLE 5-1 PRELIMINARY COMPOSITION FOR ACT ACORN STUDY ...................................................................................................................................................................... 15

TABLE 5-2 INVENTORY OF POTENTIAL NEW ENTRANTS AT GRANGEMOUTH ....................................................................................................................................................... 19

TABLE 8-1 FEEDER 10 DESIGN LIFE - METHANE OPERATIONS .......................................................................................................................................................................... 24

TABLE 8-2 FEEDER 10 DESIGN LIFE - CO2 OPERATIONS .................................................................................................................................................................................. 24

TABLE 8-3 FEEDER 10 INFRASTRUCTURE VALUATIONS - 2009 ......................................................................................................................................................................... 25

TABLE 8-4 FEEDER 10 INFRASTRUCTURE MEA VALUATIONS – 2017 ................................................................................................................................................................ 25

TABLE 8-5 FEEDER 10 CONVERSION - CAPITAL COST ...................................................................................................................................................................................... 27

TABLE 8-6 THROUGHPUT PRICE AND IRR........................................................................................................................................................................................................ 27

TABLE 8-7 ECONOMIC ASSUMPTIONS .............................................................................................................................................................................................................. 28

D17 Feeder 10 Executive Summary


1.0 Executive Summary

Previous studies for Scottish Power Longannet in Demo1 and CCEP have confirmed

that Feeder 10 is suitable for transporting gas phase CO2 from Central Scotland to St

Fergus. Gas phase CO2 would be compressed into high pressure dense phase at St

Fergus for direct injection offshore.

Studies such as Demo1, CCEP and the East Coast Value Study have shown that Feeder

10 can play a key part in the build out and growth of CCS in the UK, by providing an

early, low cost transport link from Central Scotland’s industrial emissions to St Fergus.

Based on existing regulatory arrangements, Feeder 10 would need to be transferred

from National Grid Gas to another entity for use in CO2 transport.

The cost of converting Feeder 10 for CO2 transport is expected to be in the range £40-

80m. The cost of compression facilities at St Fergus is expected to be in the range £90-

120m.

Whilst previous studies have shown that Feeder 10 could be re-used for CO2 transport,

several commercial and regulatory aspects would need to be addressed in order to

enable such a change; amongst the most important of these are; arrangements for

removal from the gas national transmission system; arrangements for a change of

ownership; and consequential permitting and consents.

The Reference Scenario developed for an indicative economic analysis assumes that

the infrastructure is in a regulated business such that the rate of return is between 8-

10%. This would require a transportation tariff of £5.5/T CO2 and yields a NPV8 of £20m

and a profit-investment ratio of 66%. CO2 flows commence in 2025 and runs until 2040,

when Feeder 10 is assumed to be at the end of its operational life.

Re-use of Feeder 10 is an outstanding opportunity

to support UK CCS growth, whilst employing

existing assets to create new value.

The Scottish Power Longannet FEED study

confirmed that Feeder 10 was suitable for

transporting gas phase CO2 from Central Scotland

to St Fergus.

Feeder 10 was subsequently assessed for the

Caledonia Clean Energy Project (CCEP) and

considered a key part of the East Coast CCS Value

Study looking at the build out and economic value of

CCS in the UK.

A Reference Scenario has been developed for the

infrastructure investment, assuming a regulated

asset level of return and asset transfer payment

mechanism.

D17 Feeder 10 Introduction


2.0 Introduction

2.1 ACT Acorn Overview

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

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

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

ACT Acorn is a collaborative project between seven organisations across

Europe 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 a new and emerging industry. Maturity improvements are required in the

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

each development and the policy framework.

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

summarised in Figure 2-2.

Figure 2-2: Key areas of innovation

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

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

Fergus capture plant concept; CO2 storage site assessments and development

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

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

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

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

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

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

partnerships and government to move the project forward in subsequent

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

UK and European policy around infrastructure preservation. The deliverables

are listed in Table 2-1.

Figure 2-3: ACT Acorn work breakdown structure



Milestone Deliverable

1) St Fergus Hub Design

D01 Kick-off Meeting Report

D02 CO2 Supply Options

D17 Feeder 10 Business Case

2) Site Screening & Selection

D03 Basis of Design for St Fergus Facilities

D04 Site Screening Methodology

D05 Site Selection Report

D13 Plan and Budget for FEED

3) Expansion Options D18 Expansion Options

4) Full Chain Business Case

D10 Policy Options Report

D11 Infrastructure Reuse Report

D14 Outline Environmental Impact Assessment

D15 Economic Model and Documentation

D16 Full Chain Development Plan and Budget

5) Geomechanics D06 Geomechanics Report

D07 Captain X Storage Development Plan and Budget

6) Storage Development Plans D08 Site 2 Storage Development Plan and Budget

D09 Eclipse Model Files

7) Lifecycle Assessment D12 Carbon Lifecycle Analysis

8) Project Completion

D21 Societal Acceptance Report

D19 Material for Knowledge Dissemination Events

D20 Publishable Final Summary Report

Table 2-1 ACT Acorn Milestones and Deliverables



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

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

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

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

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

Dot Energy affiliate, CO2DeepStore are providing certain input material.

2.2 Acorn Development Concept

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

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

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

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

risk.

The Acorn development concept 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. This will accelerate CCS

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

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

hub.

The seed infrastructure can be developed by adding 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

D17 Feeder 10 D17 Scope


3.0 D17 Scope

3.1 Purpose

The purpose of Deliverable D17 Feeder 10 is to summarise the current status

of Feeder 10, draw out relevant material from previous studies on re-use and

outline the potential opportunity and business case for re-purposing the pipeline

for CO2 transport. The deliverable should also look at future steps to enable the

transition.

3.2 Scope

The scope of deliverable D17 includes;

• A summary of the pipeline its current ownership and potential for re-

use

• An outline functional specification

• Summarise the cost associated with change of use

• Outline the value proposition and preliminary economics for CO2

transport through the line

• Outline potential alternatives for changes of use and ownership

• Highlight key issues, risks and challenges to the re-purposing of the

pipeline

• Make relevant recommendations for further work and next steps in

the transition process

3.3 Statement of Input and assumptions

This study has considered previous work on Feeder 10, including the FEED

study from the first UK CCS Demonstration Competition, known as “Demo1”

(ScottishPower CCS Consortium, 2010) and analysis completed for Captain

Clean Energy Project (CCEP) in the second UK CCS Demonstration

Competition, known as “Demo2” (Captain Clean Energy Limited, 2012).

Levels of CO2 which could be provided for transport by Feeder 10 are based on

conclusions from Deliverable D02 CO2 Supply Options (Pale Blue Dot Energy

Ltd., 2017). The CO2 specification was also provided for D17 from D02.

D17 Feeder 10 Feeder 10 background


4.0 Feeder 10 background

4.1 Existing pipeline summary

The National Grid Gas National Transmission System (NTS) No. 10 Feeder is a

280km long 900mm (36”) diameter buried steel pipeline which currently runs

from the existing compressor station at Avonbridge/Bathgate to the onshore

natural gas terminal facilities at St. Fergus. It is more commonly known as

Feeder 10. (ScottishPower CCS Consortium, 2011)

It can be considered as three distinct stages.

• Bathgate to Kirriemuir (approximately 141km)

• Kirriemuir to Aberdeen (approximately 75km)

• Aberdeen to St Fergus (approximately 64km).

Figure 4-1 Overview of NTS pipeline Feeders in Scotland

Feeder 10 from Kirriemuir to Bathgate is currently rated at 85barg for the

transportation of natural gas, with 85barg being the maximum allowable

pressure. From Aberdeen to Kirriemuir is rated at 84barg, and from St.Fergus

to Aberdeen it is rated at 70barg.

Feeder 10 was designed for transportation of natural gas using National Grid

(formally Transco / British Gas) and the Institute of Gas Engineers standards

and specifications applicable at the time.

It should be noted that Feeder 10 is still fully operational and inspected in

accordance with National Grid specifications.

D17 Feeder 10 Feeder 10 background


Figure 4-2 Schematic showing Feeder lines in Scotland

4.2 Current ownership

Feeder 10 is currently owned by National Grid Gas a regulated monopoly

responsible for transmission of the UK’s gas and maintenance of the National

Transmission System, (NTS).

Ofgem has responsibility for regulating the gas transmission system.

Current expectations are that a change of use would require a change of owner,

as CO2 transport is not part of the NTS.

4.3 Feeder 10 CO2 throughput capacity

Preliminary studies conducted by National Grid for CCEP during Demo 1,

showed that Feeder 10 is able to transport up to 6MT/yr CO2. With additional in

line compression along Feeder 10 potential exists to increase capacity to ~10

MT/yr whilst remaining in gas phase and within operating limits of the pipeline

(CO2DeepStore, 2012).

D17 Feeder 10 Feeder 10 Change of Use


5.0 Feeder 10 Change of Use

5.1 Functional specification

5.1.1 Composition specification

A preliminary composition for the Acorn ACT study has been defined as below;

During Demo1, National Grid Carbon defined a much more extensive

composition specification, which was linked to the plan for an amine capture

process at Longannet. It may be necessary to refine the specification above as

the Acorn project develops.

5.1.2 Phase

Feeder 10 will operate in vapour (gas) phase. The pressure rating of the existing

pipeline is insufficient to support a dense phase operation. The maximum

operating pressure is designed to avoid any phase changes along the pipeline.

At St Fergus, compression facilities will take the vapour phase CO2 and

compress it to dense phase, for offshore transport and downhole injection.

5.1.3 Flow rate

Flow rates are dependent on volumes of CO2 being captured and injected into

Feeder 10 for transport to St Fergus. It is likely that volume of CO2 through the

pipeline will increase over time. The Longannet project considered ~2MT/yr, the

Caledonia Clean Energy Project considered ~4MT/yr. The maximum capacity of

Feeder 10 is ~6MT/yr without in line compression and ~10MT/yr with additional

in line compression (P A Brownsort, 2016).

5.2 Selection of Feeder 10 Attributes

Feeder 10 provides an obvious solution to transport CO2 from the emissions

sources of the Central Belt to St Fergus. In Demo 1 this solution was selected

as the preferred transportation option after extensive studies of various

transportation options including shipping and piping permutations. The study

work undertaken concluded that the proposed solution:

• Minimises the level of capital and operational expenditure whilst

improving cost certainty by reducing the level of construction

activities required;

• Minimises the impact on the environment as existing assets are

being utilised;

• Minimises the carbon footprint of the overall project;

• Lowers the risk of the initial deployment of CCS in the UK which

benefits the UK economy as a whole by facilitating the timely

implementation of an efficient technical solution; and

Attribute Condition

CO2 > 95.5%

Water < 50ppm

O2 < 10ppm

Inlet pressure 34bar

Inlet temperature 30oC

Post compression 80-120 barg

Post compression 29oC

Table 5-1 Preliminary composition for ACT Acorn study



• Provides an opportunity for natural gas consumers to extract residual

value from existing National Grid NTS pipeline assets which are

nearing or at the end of their regulatory economic life and are

expected to be underutilised in the short to medium term.

5.3 Feeder 10 change of use

The Feeder 10 is a pipeline currently owned by National Grid Gas and is fully

operational. Due to the change in the overall flow of natural gas across the UK,

there is the potential for Feeder 10 to be decommissioned and used for other

industrial gaseous transport.

The conversion of the Feeder 10 pipeline has several aspects to consider:

• Conversion of the Feeder 10 pipeline (Dunipace to St Fergus)

• Conversion of the Feeder 10 above ground installations (AGI’s)

• Conversion of the Feeder 10 Multi Junctions

• New Compressor Station at St Fergus

The most detailed previous study of the potential re-use of Feeder 10 for CO2

transport, was developed during FEED on the Scottish Power Longannet CCS

Project and is provided as a Knowledge Transfer reports (ScottishPower CCS

Consortium, 2010). Other projects have considered using Feeder 10, including

the Captain Clean Energy Project and Caledonia Clean Energy Project, both

known as CCEP.

Based on previous studies the expectation is that local compression facilities will

inject gaseous CO2 into the Feeder 10 pipeline system at a maximum allowable

operating pressure of 34barg and maximum operating temperature of 30ºC.

(ScottishPower CCS Consortium, 2011)

Due to a pressure drop along the onshore pipeline, the expected pipeline exit

conditions for arrival at the Blackhill Compressor Station (near St Fergus) are

operating pressures between 28.5 to 31barg and likely operating temperatures

in the range of 3 to 14ºC.

As indicated, the existing NTS No.10 Feeder pipeline system between Bathgate

and St. Fergus consists of 3 main pipeline sections and each individual section

includes manually operated block valve installations at several locations along

the pipeline route. Modifications will be required to disconnect No. 10 Feeder

from the natural gas NTS pipeline network at existing multi-junction sites and

compressor sites, and to cross-connect the various pipeline sections. The

existing block valve installations will also require modifications to convert them

from natural gas to CO2 duty.

The onshore pipeline will act as a buffer to partially decouple capture operations

which are potentially variable from injection well operation which is preferably at

steady state flow conditions. Pressure in the pipeline is set by the inlet pressure

and the pressure drop through the pipeline system.

Some monitoring instruments may be required but there are not expected to be

any control systems associated directly with the pipeline system itself. Included

within the pipeline scope are the AGI, the block valves and pipeline.

Pipeline inlet will require delivery of CO2 gas at the required flow, pressure and

temperature conditions. Dehydration equipment is required to regulate the water

content of the stream. A suitable High Integrity Pressure Protection System

(HIPPS) will protect the transportation pipelines from over pressure. CO2 quality

control and measurement will also be required.

The Feeder consists of a number of block valve stations (AGIs), a multi junction

at Crieff and is integrated into the St Fergus, Aberdeen and Kirriemuir



compressor stations. The change of use from the NTS will require disconnection

from the pipeline multi-junction and modifications within Kirriemuir and

Aberdeen compressor stations. The Feeder will also be disconnected from St

Fergus and diverted round to the new CO2 compressor station at Blackhill.

Further work is required to develop the Health & Safety Executive (HSE)

considerations, especially at AGIs and compressor stations, to build upon work

previously conducted by National Grid. This includes the site-specific analysis

of CO2 release and accumulation.

The pipeline system feeds into a National Grid CO2 Blackhill Compressor

Station, adjacent to the St Fergus National Grid natural gas terminal. The

compressor delivers high pressure dense phase CO2 for transport offshore and

injection.

The pipeline and compressor ware likely to be considered an integrated system

in terms of operation, control and safeguarding.

5.4 Operating parameters

As indicated above, it is expected that Feeder 10 will operate in gaseous phase

with an operating pressure of 34barg and maximum operating temperature of

30ºC. The expected pipeline exit conditions for arrival at Blackhill Compressor

Station are operating pressures between 28.5 to 31barg and likely operating

temperatures in the range of 3 to 14ºC.

With an operating pressure of ~34barg compared to design pressures of Feeder

10 of 85, 84 and 70barg provides potential for the pipeline to be line packed

whilst remaining in gas phase, if required.

Preliminary studies conducted by National Grid for the CCEP during Demo 1,

showed that Feeder 10 is able to transport up to 6Mt/yr CO2. With additional in

line compression along Feeder 10 potential exists to increase capacity to

~10MT/yr whilst remaining in gas phase and within operating limits of the

pipeline (CO2DeepStore, 2012).

5.5 Venting

Previous work has identified the importance of having a clear venting philosophy

and design in place for Feeder 10.

The key functions of the Process Venting systems are to:

• Prevent overpressure or uncontrolled release of CO2.

• Depressurise all or part of the chain due to an emergency situation

(ESD).

• Release of CO2 in a controlled manner.

• Allow maintenance and commissioning activities to be completed

safely.

• Prevent undesirable events causing a large uncontrolled CO2

release.

• Prevent escalation of an incident past the first layer of protection.

• Minimise any domino effects on adjacent sites or facilities.

The plan for Feeder 10 is expected to be to allow for venting from either end of

Feeder 10, from permanent vent stacks located at:

• Blackhill Compressor Station

• A key source or input location



Temporary venting facilities will also be installed at several AGIs areas along

Feeder 10; this is to ease access for maintenance and operational purposes and

allow section venting of the pipeline.

One of the risks with CO2 venting is phase change during depressurisation. The

temporary vent stacks may require heating in order to mitigate the potential

hazard from low temperature during depressurisation.

Other risks include blockage of the vent by solid CO2 formed during the venting.

A minimum of 10m stack height is required in order to release and disperse CO2

at a safe level from personnel. Venting at the Multi-Junctions and AGI’s would

need to be reviewed, including dispersion modelling for loss of containment

events. Between each AGI, Block Valve, there is approximately 16 kilometres of

pipeline each around 10,000m3 of pipeline volume.

The main scenarios where CO2 would need to be vented are:

• Routine Operation: (Maintenance) (Inline Inspection/Pigging).

• Non-Routine Operation: Such as an emergency blow down situation.

• Pipeline leaks:

o Mechanical Failure

o Human Error during the use of the pipeline and compressor

station, as this could range from accidently opening a valve

or other potential human error issues.

5.6 Prior non-technical work on change of use

During Demo 1 National Grid engaged with Ofgem to explore the issues

associated with transfer of Feeder 10 from a regulated NTS gas distribution

asset owned by National Grid Gas (NGG), into a non-regulated asset for CO2

transport, in this instance, to be owned by National Grid Carbon (NGC). Part of

this process involved Ofgem issuing a consultation to industry (gas shippers,

producers, storage operators, interconnectors, gas distribution networks, other

stakeholders and other interested parties) to seek input on this potential

transition, (Ofgem, 2009).

Ofgem’s introduction was;

“National Grid Gas has approached Ofgem with an outline proposal for the

disposal and possible alternative use of some of its National Transmission

System assets for Carbon Capture and Storage (CCS) in Scotland. The

proposals may have merit because they would help to tackle climate change by

allowing faster testing of the feasibility of CCS as a means of abating carbon,

and they could benefit customers by finding an alternative (or more valuable)

use for network assets leading to lower transportation bills. There may also be

downsides if they lead to bottlenecks on the gas network in the event of new

supplies, or if the transfer of the assets does not allow others to use the capacity

to transport carbon dioxide on reasonable terms. The Authority has a role in

granting consent for this and other significant disposals of NTS assets. This

initial consultation paper highlights the key issues, regulatory concerns and

benefits associated with this proposal. It also invites comments and views on

the proposal to inform the decision on whether to grant consent. This is an early

consultation on these proposals. We envisage further consultations will be

required should the proposal be taken further.”

The consultation feedback supported an independent review of the analysis

conducted by National Grid. This resulted in two studies which were

commissioned to provide a review of the capability and capacity of the St Fergus

gas terminal and Feeder 10 and which supported the conclusion that sufficient



capacity existed in the remaining three Feeder lines for Feeder 10 to be used

for CO2 transport. (Wood Mackenzie, 2009) (Poyry, 2009)

The Demo1 competition failed to reach a project contract and as such the

transition of Feeder 10 was not progressed further.

5.7 Feeder 10 CO2 input

90% of Scotland’s CO2 emissions are within 50km of 1 or more compressor

stations along the Feeder 10 pipeline (Pale Blue Dot Energy Ltd., 2017). As such

it is feasible for a network to be developed which could connect major emissions

points with the Feeder, based on a connecting pipeline for one or two key

emissions sources, as envisaged for Longannet and CCEP. Such a network has

been described for Teesside, in order to gather industrial emissions from a

number of different locations. (Pale Blue Dot Energy Ltd., 2015) (AMEC Foster

Wheeler, 2015). The nature of such a gathering network for Central Scotland

and its costs are beyond the scope of this deliverable.

Table 5-2 lists potential future sources of CO2 that might use the Feeder 10

pipeline (Pale Blue Dot Energy Ltd., 2017).

New Entrants Raw CO2 Quantity (kT/yr)

Start Year

Longevity (years)

Capture Potential

Caledonian Clean Energy Plant

3,333 2025 40 90%

Grangemouth Biomass CHP Plant

330 2035 25 90%

Redeveloped Longannet Power Plant

2,100 2035 40 90%

Grangemouth SMR Phase 1

500 2035 30 90%

Grangemouth SMR Phase 2

500 2045 40 90%

New Grangemouth Cement Plant

500 2050 40 90%

New Grangemouth Chemical Plant

750 2050 40 45%

New Grangemouth CHP

600 2045 40 90%

Table 5-2 Inventory of Potential New Entrants at Grangemouth

D17 Feeder 10 St Fergus CO2 Compression


6.0 St Fergus CO2 Compression

6.1 New compression facilities

Two previous projects have considered the design of CO2 compression facilities

at St Fergus. These are the Longannet Project in Demo1 and the Captain Clean

Energy Project (CCEP) during Demo2 and subsequently the Summit Power

Caledonia Clean energy Project. (Pale Blue Dot Energy Ltd, 2016)

These two projects reached broadly similar conclusions regarding compression

facilities at St Fergus, whilst recognising the flowrate of CO2 was different

(~2MT/yr for Longannet and ~4MT/yr for CCEP). A summary of these projects

is provided here as a basis for considering compression requirements to enable

the re-use of Feeder 10.

The CO2 would be compressed to dense phase at a new compression station,

Blackhill, located near the St Fergus onshore natural gas terminal. The St

Fergus terminal is located approximately 64km North East of Aberdeen, is

situated on reclaimed peat bog about 1km from the coastline and receives

natural gas from the other facilities via four pipelines to the East. The St Fergus

site and the proposed area for Blackhill Compressor Station is shown in Figure

6-1.

Figure 6-1 St Fergus Terminals

Gaseous phase CO2 will be received from Feeder 10 pipeline which would be

diverted outside the St. Fergus onshore natural gas terminal to the site of the

proposed Blackhill Compressor Station. For 2MT/yr (Longannet) two 50% rated,

multiple stage, integrally geared compressor units which would have been

installed in parallel configuration were proposed to compress the CO2 from the

gaseous phase at the arrival condition at Blackhill Compressor Station to a

dense phase fluid with an outlet pressure of between 80 to 120barg. The two

primary compressors were to be electrically driven with variable speed drives



with a back-up gas turbine driven compression unit. For CCEP, the design was

for electrical variable speed drives, subject to availability of a 132kV electrical

connection/supply, to reduce emissions of CO2 and maximise efficiency. The

CCEP compression configuration for 4MT/yr was to be either 3x50% or 2x70%

rated units.

Both the Longannet and CCEP projects concluded that integrally geared

dynamic compressors were the optimum type of compression at the Blackhill

compressor station. These were chosen due to the high efficiency, flexibility,

high reliability and low Opex. The addition of interstage cooling during

compression also greatly increases compression efficiency.

For Longannet an aftercooler and refrigeration/chiller unit installed on the

outlet/discharge of the compressor station was planned to reduce the discharge

temperature of the CO2 to within a maximum allowable temperature of 29°C to

protect the subsea pipeline integrity. The refrigeration/chiller unit would have

operated during periods of relatively high ambient temperature. The CO2 would

have also required cooling between each compressor stage, for which

intercoolers would be installed. Each compressor unit would be isolated by

automatically actuated emergency shut down (ESD) valves, with a vent stack

installed in a safe area to enable the units to be depressurised as and when

required. The compressor station would be similarly isolated from the process.

Cooling for CCEP had not been finalised and includes the three options of;

conventional multi-stage compression with finfan inter-stage and discharge

cooling; conventional compression with conventional fin fan inter-stage cooling

and final discharge refrigeration cooling to mitigate pipeline ductile fracture risk

if required and conventional compression to around 30barg then liquefaction

using refrigerants and pumping to final discharge.

The inlet pressure to the new compressor station would be set by the Feeder 10

inlet pressure and the pressure drop in the pipeline. The temperature will depend

on ground and ambient temperatures but is not expected to be below +4°C. The

CO2 would then be compressed by two electrically driven, 50% compressor units

plus one 50% gas turbine driven standby compressor, installed in parallel

configuration to meet the required outlet battery limit maximum pressure of

120barg. The drives would be controlled from the control room during normal

operation with drive speeds being set in order to meet the required compression

ratios. Since the critical point for the CO2 stream is 30.1°C and 72.5barg the

working fluid would be in the supercritical phase at the compressor discharge.

Discharge cooling would be required to meet the outlet temperature requirement

of 29°C. This would bring the CO2 stream to its critical temperature downstream

of the discharge coolers so the fluid could be transported in the dense (liquid)

phase. The maximum allowable operating temperature of the Goldeneye

pipeline is imposed by design code requirements to avoid operating in a region

where running ductile fracture in the pipeline is possible. This temperature was

evaluated during the Longannet FEED to be 29ºC. A design margin between

maximum allowable and normal operating temperature would be required to

allow the implementation of the necessary high temperature alarms and trips to

protect the pipeline.

Compressor interstage and discharge cooling would be provided by air coolers.

During periods when the air temperature is too high, cooling will be augmented

with propane refrigeration.

The delivery pressure from the compressor station would be set by the subsea

pipeline pressure and injection pressure. The delivery temperature from the

compressor station would be controlled at the station using air cooling and a



refrigeration package when ambient temperatures dictate. Monitoring

instruments would be provided at the interface between the compressor station

and the offshore pipeline.

The permitted particulate level will determine required CO2 filtration levels at the

Blackhill Compressor Station. (ScottishPower CCS Consortium, 2011)

D17 Feeder 10 Cost Summary


7.0 Cost Summary

7.1 Demo 1 costs post FEED

The following costs were the result of Front End Engineering Design (FEED)

during the Scottish Power Longannet CCS Demonstration Project and were

developed by National Grid. The results are provided in Knowledge Transfer

Deliverables as Demo 1 KT (2011) Post FEED cost estimates. (ScottishPower

CCS Consortium, 2011)

Capex

Capital costs for the design and construction of the stated facilities as estimated

in 2011. Cost uncertainty was stated to be -10% to +15% excluding risk and

contingency.

• Feeder 10 £78.9m (including transfer cost)

• Compression at St Fergus £121m

Opex

System operating costs including Feeder 10 and Compression at St Fergus

• £1.2m/y fixed, £10.5m/yr variable (based on 2 MT/yr)

Abex

Asset abandonment costs

• Feeder 10 £15.8m

• Compression at St Fergus £24.2m

7.2 CCEP feasibility cost assessment

The following costs were the result of Feasibility studies conducted by Costain

and Pale Blue Dot Energy for Summit Power. The results are provided in the

Onshore Transportation Feasibility Report for Caledonia Clean Energy Project

Feasibility cost assessment. (Pale Blue Dot Energy Ltd, 2016)

Capex

Capital costs for the design and construction of the stated facilities as estimated

in 2016. Cost uncertainty was stated to be -30% to +50% excluding risk and

contingency.

• Feeder 10 £40.9 (excluding transfer cost)

• Compression at St Fergus £89.4m

Opex

System operating costs including Feeder 10 and Compression at St Fergus

• £12.9m/yr (based on ~4 MT/yr)

Abex

Asset abandonment costs

• Feeder 10 £5m

• Compression at St Fergus £6m

D17 Feeder 10 Value and Economics


8.0 Value and Economics

8.1 Value proposition

8.1.1 Value proposition for UK plc

The re-use of Feeder 10 for CO2 transport is of value to the UK:

• Given that four natural gas feeder lines currently transport natural

gas south from St Fergus to Central Scotland and

• the volume of natural gas has declined from its peak and

• that CO2 transport from Central Scotland to St Fergus would enable

decarbonisation of Scotland’s industrial emissions and

• the re-use of Feeder 10 is more cost effective and less

environmentally damaging than constructing a new pipeline

8.1.2 Value proposition for the pipeline owner

Feeder 10 could be owned by a public body, a regulated private entity or an

unregulated private entity. In either case the value proposition could be to

operate a capacity and throughput fee based revenue model to recover

acquisition, capital and operating costs and make a suitable rate of return,

depending on the nature of the business, its investments and risk undertakings.

8.2 Asset Longevity

The design life of the three pipeline elements of Feeder 10 is 50 years for the

duty of transporting methane at pressures of up to 70barg. Details are shown in

Table 8-1 (Ofgem, 2009).

Pipeline Segment First Use Operating Pressure (Barg)

Fully Depreciated

St Fergus – Aberdeen 1975 70 2025

Aberdeen – Kirriemuir 4976 84 2026

Kirriemuir - Avonbridge 1978 85 2028

Table 8-1 Feeder 10 Design Life - Methane Operations

Key determinants of pipeline longevity are fatigue due to pressure cycling and

corrosion. Previous analyses (P A Brownsort, 2016) have investigated these

issues and indicated that the design life of Feeder 10 pipeline might be extended

for lower pressure CO2 transportation to around 65 years, as summarised in

Table 8-2.

Pipeline Segment First Use Operating Pressure (Barg)

Likely Last Use

St Fergus – Aberdeen 1975 35 2040

Aberdeen – Kirriemuir 4976 35 2041

Kirriemuir - Avonbridge 1978 35 2043

Table 8-2 Feeder 10 Design Life - CO2 Operations

If CO2 transportation is required from the Scottish central belt from the mid

2020’s Feeder 10 is considered to have a useful life of approximately 15 years.



A detailed survey and analysis of the pipeline current condition and expected

future duty may extend the expected longevity of the pipeline.

8.3 Asset Valuation for Transfer

A range of legitimate methods are available to assess the value of the pipeline

infrastructure. Table 8-3 summarises the results of an asset valuation exercise

conducted by National Grid Gas (NGG) as part of the proposed transfer of

National Transmission System (NTS) assets for CO2 use (Ofgem, 2009) and

additional detail can be found in that reference document.) Any costs associated

with conversion and refurbishment are excluded from the asset valuation

estimates.

Valuation Method Value at MEA (£M, 2009 terms)

Modern Equivalent Asset (MEA) - 16yr (Demo1)

182.1

MEA - Original Design 147.7

Proportionate NTS Infrastructure 98.5

Pipeline Years 95.6

MEA - Economic Life 56.9

Depreciated Asset 0.2

Table 8-3 Feeder 10 Infrastructure Valuations - 2009

The MEA approach is one that estimates the cost to replace an old asset with a

technically up-to-date new asset with the same service capability.

At the time, Ofgem provided an initial view (Ofgem, 2009) of the valuations:

• Once the assets are full depreciated, it could be considered that the

shareholders of NGG have been fully remunerated and any benefits

arising from ownership of the assets should fall to consumers.

• The network operator should be incentivised to find another use for

the assets and increase the potential residual value.

• Ofgem must ensure that the valuation reflects fair value for

consumers and reflects the value of the assets in a n alternative use.

This current work has applied the same methodology to the assets that are now

8 years older and restated the valuations in Table 8-4 using the same monetary

terms. Note that the information required to estimate the depreciation-based

valuation is not readily available and is therefore omitted. The valuations

assume that the design life can be increased to 65 years as discussed in the

previous section and therefore are available for approximately 15 years from the

mid 2020’s.

Valuation Method Value at MEA (£M, 2009 terms)

Value at MEA (£M, 2017 terms)*

MEA - Original Design 166.1 210.4

Modern Equivalent Asset (MEA) - 15yr

131.3 166.3

MEA - Economic Life 26.3 33.3

Table 8-4 Feeder 10 Infrastructure MEA Valuations – 2017

* escalated at 3% per annum (Bank of England, 2016), excludes any market-

specific cost escalation factors.



8.4 CO2 Throughput Scenario

Section 5.7 summarises the potential future users of Feeder 10 for CO2

transportation. Based on this inventory, Scenario B (Pale Blue Dot Energy Ltd.,

2017) was chosen for the economic analysis because it represents a plausible

case for use of the asset within its remaining expected life. A total of 73.1MT of

CO2 is transported through Feeder 10 in this scenario, as illustrated in Figure

8-1.

Figure 8-1 Feeder 10 CO2 Throughput Scenario

8.5 Cost to Convert Asset to CO2 Duty

8.5.1 Transfer Cost

The authors view the estimates of transfer values in Table 8-4 to be at the very

high end of what might be achievable for three main reasons.

The MEA approach assumes that a pipeline of the same diameter would be

required and based on the scenario assumptions a much smaller pipe could be

suitable.

The transfer value needs to be balanced against obligations under the Climate

Change Act and recognise that consumers benefit from the use of the

infrastructure for CO2 transportation.

There will likely be a risk and reward allocation between the asset owner and

consumers (via Ofgem) and this will act to reduce the up-front transfer value.

This analysis has judged that a discount of 50% to the MEA 15-year amount

would be a reasonable starting place and consequently the transfer value used

in this analysis is £83.2m.

8.5.2 Capital Cost

The costs to convert the infrastructure for CO2 duty were summarised in Section

7.0 and are listed below. For the purposes of clarity in this evaluation the cost of

compression at St Fergus prior to offshore transportation has been excluded.

Intermediate compression might also be required to accommodate the 6mT/yr

throughput in years 2035 – 2040.



Item £M

Land (permitting, consents etc) 2.9

Equipment & materials 7.2

Construction & installation 27.4

Project Management 2.3

Commissioning 1.1

Total 40.9

Table 8-5 Feeder 10 Conversion - Capital Cost

8.5.3 Operating Cost

Excluding the compression costs this is estimated to be £0.5M/year.

8.5.4 Decommissioning Cost

Assumed to be £5M.

8.6 Economics

A conventional discounted cash flow (DCF) model of the investment opportunity

was built using the costs outlined previously and assumptions listed in Section

8.6.2. The cash flow chart provided as Figure 8-2 shows a characteristic

infrastructure investment shape, with relatively high up-front capex and a long

payback period (~ 10 years). The numbers in the projection are shown in Section

8.6.4.

Figure 8-2 Feeder 10 Cash Flow Projection (£5.50/T)

8.6.1 Throughput Price

A range of values for the price to be charged for transporting CO2 was evaluated

against the resulting internal rate of return (see Table 8-6 and Figure 8-3.)

Price (£/T)

2 4 5 5.5 6 8 10

PT IRR (%)

-0.3 6.4 8.6 9.6 10.6 13.8 16.5

AT IRR (%)

-0.3 5.3 7.3 8.2 9.1 12.0 14.4

Table 8-6 Throughput Price and IRR



Figure 8-3 Rate of Return for Various Throughput Tariffs

8.6.2 Analysis

A Reference Case has been defined, using a transportation tariff of £5.50/T.

This tariff results in an IRR of 8-10% (depending on tax assumptions) which is

considered reasonable for what is likely to be a regulated asset.

In the Reference Case, excluding any asset transfer payments, the

infrastructure project generates £98.3m (NPV8)

£78m (NPV8) is allocated to asset transfer payments leaving the infrastructure

owners with £22m (NPV8) and a profit-investment ration of 66%.

8.6.3 Key Assumptions

The key assumptions used in the analysis are listed in Table 8-7.

Costs

Engineering 4.09 £m

Capex 40.9 £m

Transfer Cost 83.2 £m

Abandonment Cost 5 £m

Operating Cost 0.5 £m/y

Overhead 0.5 £m/y

Payment to Ofgem 1.00% of net profit

Project

Asset Transfer 2020

Eng Start 2021

Construction Start 2022

Injection Start 2025

Duration 15 years

Capex Phasing 3 years

Macro

Inflation 0 % p.a.

Tax 20% %

Amortisation 1.75 £/T

Discount rate 0.08 fraction

CO2 Supply Profile

Source Amount Start

CCEP 3.3mT/y 2025

Grangemouth CHP 0.7mT/y 2030

New Power 2.1mT/y 2035

Table 8-7 Economic Assumptions



8.6.4 Cash Flow Projection

Feeder 10 Economic Projection

CO2 Price (£/T) 5.5

Total PV 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045

CO2 Transportation

Throughput 73.1 25.3 0.0 0.0 0.0 0.0 0.0 3.3 3.3 3.3 3.3 3.3 4.0 4.0 4.0 4.0 4.0 6.1 6.1 6.1 6.1 6.1 6.1 0.0 0.0 0.0 0.0 0.0

Revenue £m £m

Transportation 402.1 138.9 0.0 0.0 0.0 0.0 0.0 18.2 18.2 18.2 18.2 18.2 22.0 22.0 22.0 22.0 22.0 33.6 33.6 33.6 33.6 33.6 33.6 0.0 0.0 0.0 0.0 0.0

Captial Expenditure £m £m

Engineering 4.1 3.5 0.0 4.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Asset Transfer 83.2 77.0 83.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Construction 40.9 30.1 0.0 0.0 13.6 13.6 13.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Total 128.2 110.7 83.2 4.1 13.6 13.6 13.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Operating Expenditure £m £m

Pipeline 8.0 3.0 0.0 0.0 0.0 0.0 0.0 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.0 0.0 0.0 0.0 0.0

Ofgem Fee 3.9 1.3 0.0 0.0 0.0 0.0 0.0 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.0 0.0 0.0 0.0 0.0

Overhead 8.0 3.0 0.0 0.0 0.0 0.0 0.0 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.0 0.0 0.0 0.0 0.0

Total 19.9 7.4 0.0 0.0 0.0 0.0 0.0 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.3 1.3 1.3 1.3 1.3 1.3 0.0 0.0 0.0 0.0 0.0

Decommissioning £m £m

Pipeline 5.0 0.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 5.0 0.0 0.0 0.0 0.0

Cash Flow £m £m

Pre-tax net Cash Flow 249.0 20.0 -83.2 -4.1 -13.6 -13.6 -13.6 17.0 17.0 17.0 17.0 17.0 20.8 20.8 20.8 20.8 20.8 32.2 32.2 32.2 32.2 32.2 32.2 -5.0 0.0 0.0 0.0 0.0

Cumulative PT NCF 249.0 -83.2 -87.3 -100.9 -114.6 -128.2 -111.2 -94.2 -77.3 -60.3 -43.3 -22.5 -1.7 19.1 39.9 60.7 92.9 125.1 157.3 189.6 221.8 254.0 249.0 249.0 249.0 249.0 249.0

IRR 10%

After-tax net Cash Flow 198.2 2.5 -83.2 -4.1 -13.6 -13.6 -13.6 14.7 14.7 14.7 14.7 14.7 18.0 18.0 18.0 18.0 18.0 27.9 27.9 27.9 27.9 27.9 27.9 -5.0 0.0 0.0 0.0 0.0

Cumulative AT NCF 198.2 -83.2 -87.3 -100.9 -114.6 -128.2 -113.4 -98.7 -84.0 -69.2 -54.5 -36.5 -18.4 -0.4 17.7 35.7 63.6 91.5 119.4 147.4 175.3 203.2 198.2 198.2 198.2 198.2 198.2

IRR 8%



8.7 Commercial Issues

The economic analysis presented in the previous section excludes any risk

components and it is assumed that an equitable risk – reward mechanism can

be agreed between the various parties. Several of the commercial issues

considered to be key are summarised below.

• Methane flows from St Fergus continue to fall and are predicted to

continue to do so (National Grid Gas, 2016). Consequently, the

requirement for Feeder 10 as part of that transmission system is

reduced and its availability for CO2 duty increased. This may act to

reduce the transfer price of the assets.

• The assumed structure of asset transfer payments has been kept

simple at this stage to facilitate understanding. It is likely that any

arrangement that is negotiated in the future will be significantly more

sophisticated to balance the risks and rewards of each party to the

deal.

• The limited longevity of the pipeline is likely to reduce its

attractiveness to future investors who will probably be seeking

infrastructure with an operational life in line with the likely users of

the system.

D17 Feeder 10 Future Considerations


9.0 Future Considerations

9.1 Ownership options

As described in Section 4.2, Feeder 10 is currently owned by National Grid Gas

as a regulated asset. As regulations stand National Grid Gas (NGG) would be

unable to re-purpose and operate the line to transport CO2, as this activity is not

within their defined regulated set of activities. NGG would have to dispose of

Feeder 10, in order for it to be used to transport CO2.

Potential ownership options include;

• A public body such as a government CO2 transport agency

• A regulated private sector monopoly (analogous to National Grid

Gas)

• A private sector business

Exploring the potential benefits and drawbacks of each of these options is

beyond the scope of this deliverable.

9.2 Consents

For onshore pipelines, including those for CO2 transport, compliance with the

following regulations and requirements must be achieved including any

regulations enacted under them:

• Construction (Design and Management) Regulations 2008

• Deregulation (Pipelines) Order 1999

• Electricity and Pipe-lines Works (Assessment of Environmental

Effects) regulations 1990 and amendments

• Environmental Protection Act 1990

• Health and Safety at Work etc Act 1974

• Pipelines Act 1962

• Pressure Equipment Regulations 1999

• Pipeline Safety Regulations 2000 (PSR)

• Pressure Systems Safety Regulations 2000

• Town and Country Planning Act 1990.

In Demo 1 National Grid identified 16 separate consents or equivalent that would

or maybe required to enable Feeder 10 to re used for CO2 transport and to

construct a compressor station at St Fergus, (ScottishPower CCS Consortium,

2011).

• Planning consents

• Consent for change of use

• Deed of variation to change commodity on Deed of servitude under

the Gas Act

• Consent for disposal of a regulated asset

• Environmental impact assessments

• Construction consents

• Carrier of Waste (if CO2 is so defined)

• Pipeline safety regulations consents

• St Fergus compression facilities consents including Control of Major

Accident Hazards (COMAH) Regulations 2015

D17 Feeder 10 Future Considerations


9.3 Issues, risks and challenges

Risks to being able to transfer and operate Feeder 10

• Consents not provided (for CO2)

• Unable to secure change of use

• Pipeline not available

• NGG unwilling to dispose of asset

• Technical showstopper identified

• Public/stakeholder objections to CO2 transport

• No commercial basis or public funding for transport

• Need for an owner/operator

• Cross party risks and liabilities (taking CO2 and delivering CO2)

• Regulated and non-regulated activity interaction (e.g. shared land

access)

Risks to operating Feeder 10

• Pipeline corrosion issue

• Unfamiliarity with CO2 operations

• Aligning Feeder 10 input and output rates/volumes

• Unable to agree entry spec/alternative spec

• Depressurisation results in embrittlement of pipeline

• Over pressurisation of the pipeline

• Out of spec CO2

• CO2 venting issues

There is considerable experience of operating CO2 pipelines elsewhere in the

world and therefore the technical issues listed above are expected to be

resolved by thorough design during FEED or detailed design phases of a project.

The commercial issues are likely to the unique to this project and are considered

to be more material in affecting the potential for re-using Feeder 10,

(ScottishPower CCS Consortium, 2011).

9.4 Further work/next steps

To progress the potential transfer of Feeder 10 from natural gas use to CO2

transport, the following actions are required;

• Engagement with Ofgem and NGG to discuss the commercial

aspects and process by which such a transfer could take place

• Obtain an update from NGG on any operational matters which could

impact such a change of use, including; forward forecast of natural

gas transport volumes from St Fergus compared to the last time that

such a change of use was contemplated and re-assess the impact

of removal of Feeder 10 from the NTS.

• Develop the basis by which such a transfer could take place; project

details, funding model, timing, ownership etc and progress a

consultation via Ofgem with NTS stakeholders.

• Following progress on these points, then to update FEED for Feeder

10 change of use.

D17 Feeder 10 Conclusions


10.0 Conclusions

1. Previous studies for Scottish Power Longannet in Demo1 and CCEP have

confirmed that Feeder 10 is suitable for transporting gas phase CO2 from

Central Scotland to St Fergus.

2. Gas phase CO2 would be compressed into high pressure dense phase at

St Fergus for direct injection offshore.

3. Studies such as Demo1, CCEP and the East Coast Value Study have

shown that Feeder 10 can play a key part in the build out and growth of

CCS in the UK, by providing an early, low cost transport link from Central

Scotland’s industrial emissions to St Fergus.

4. Based on existing regulatory arrangements, Feeder 10 would need to be

transferred from National Grid Gas to another entity for use in CO2

transport.

5. The cost of converting Feeder 10 for CO2 transport is expected to be in the

range £40-80m

6. The cost of compression facilities at St Fergus is expected to be in the

range £90-120m

7. Whilst previous studies have shown that Feeder 10 could be re-used for

CO2 transport, several commercial and regulatory aspects would need to

be addressed in order to enable such a change; amongst the most

important of these are; arrangements for removal from the gas national

transmission system; arrangements for a change of ownership; and

consequential permitting and consents.

8. A Reference Scenario has been developed to use as a basis for indicative

economic analysis.

9. The Reference Scenario assumes that Feeder 10 is converted to CO2 duty

and begins transporting CO2 from 2025 and stops in 2040.

10. The Feeder 10 system is assumed to be capable of transporting CO2 until

2040 due to the lower pressure requirements compared to transporting

methane.

11. A transportation tariff of £5.50/T was selected for the Reference Scenario

because it results in an IRR for the project of 8-10% which is considered

reasonable for what is likely to be a regulated asset.

12. The Reference Scenario generates a pre-tax NPV8 of £20m assuming a

flat £5.50/T transportation tariff.

13. Asset transfer payments are assumed to include an upfront transfer fee

and an ongoing net profit interest payment of 1%. This amounts to £77.3m

(NPV8) over the course of the evaluation.

D17 Feeder 10 References


11.0 References

AMEC Foster Wheeler. (2015). TVU CCS Pre-FEED Study WP5 Onshore

Infrastructure.

Bank of England. (2016). Inflation Calculator.

Captain Clean Energy Limited. (2012). Captain Clean Energy Project CCS

Proposal to DECC. Aberdeen: CCEP.

CO2DeepStore. (2012). Proposal for the DECC 2012 CCS Commercialisation

Programme.

National Grid Gas. (2016). Gas 10 Year Statement - 2016.

Ofgem. (2009). Proposed Disposal of part of NTS for Carbon Capture and

Storage.

P A Brownsort, V. S. (2016). Reducing costs of CCS by shared reuse of exisiting

pipeline - case study of a CO2 capture cluster for industry and power in

Scotland. Edinburgh: University of Edinburgh.

Pale Blue Dot Energy Ltd. (2016). Onshore Transportation Feasibility Report

Caledonia Clean Energy Project.

Pale Blue Dot Energy Ltd. (2015). Industrial CCS on Teesside - The Business

Case.

Pale Blue Dot Energy Ltd. (2017). ACT Acorn Project: D02 CO2 Supply Options.

Poyry. (2009). CCS St Fergus Capability Audit, A report for National Grid.

ScottishPower CCS Consortium. (2010). Longannet ScottishPower CCS

Consortium Front End Engineering and Design (FEED).

ScottishPower CCS Consortium. (2011). Demo 1 KT: SP-SP 6.0 - RT015 Feed

Close Out Report.

ScottishPower CCS Consortium. (2011). UKCCS - KT - S10.2 - FEED - 001 Post

FEED Top 50 Risks.

ScottishPower CCS Consortium. (2011). UKCCS - KT - S11.1 - E2E - 001

Consents and Licenses Register.

ScottishPower CCS Consortium. (2011). UKCCS - KT - S5.1 - E2E – 001 Post-

FEED Cost Schedule .

ScottishPower CCS Consortium. (2011). UKCCS - KT - S7.1 - E2E - 001 Post

FEED End to End Basis of Design.

Wood Mackenzie. (2009). Nation Grid, Future Supply to St. Fergus.

project: act acorn feasibility study acorn feeder 10... · act acorn, project 271500, has received...

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